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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, 1999
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
------------------------------------
THE HOUSTON EXPLORATION COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
<TABLE>
<S> <C>
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)
</TABLE>
(713) 830-6800
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
-------------------------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
<TABLE>
<S> <C>
NAME OF EACH
TITLE OF EACH CLASS EXCHANGE ON WHICH REGISTERED
---------------------------------------- ----------------------------
Common Stock, $.01 par value New York Stock Exchange
85/8% Senior Subordinated Notes due 2008 New York Stock Exchange
</TABLE>
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 $151,525,825 as of March 22, 2000, based on the
closing sales price of the registrant's common stock on the New York Stock
Exchange on such date of $17.5625 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, 2000, 23,923,020 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 2000 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, 1999, 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 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 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 of the Gulf of Mexico, and its onshore
properties are located in South Texas, South Louisiana, the Arkoma Basin, East
Texas and the Appalachian Basin in West Virginia. The Company has utilized its
geological and geophysical expertise to grow its reserve base through a
combination of (i) high potential exploratory drilling in the Gulf of Mexico;
(ii) lower risk, high impact exploitation and development drilling onshore; and
(iii) selective opportunistic acquisitions both offshore and 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 believes that its primary strengths are its high quality
reserve base, its substantial inventory of high potential offshore exploration
prospects, its onshore portfolio of high impact exploitation and development
opportunities, its expertise in generating new prospects, the geographic focus
of its operating areas and its low-cost operating structure. At December 31,
1999, net proved reserves were 541 Bcfe with a discounted present value of cash
flows before income taxes ("PV-10%") of $530 million. The Company's focus is
natural gas and approximately 97% of its net proved reserves at December 31,
1999 were natural gas and approximately 75% were classified as proved developed.
The Company operates approximately 90% of its production.
Houston Exploration began exploring for natural gas and oil in December
1985 on behalf of The Brooklyn Union Gas Company ("Brooklyn Union") and in
September 1996 the Company completed an initial public offering ("IPO") of its
common stock. Brooklyn Union became an indirect wholly-owned subsidiary of
KeySpan Corporation ("KeySpan") in May 1998 through the combination of Brooklyn
Union's parent company KeySpan Energy Corporation and Long Island Lighting
Company. As of December 31, 1999, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 64% of the outstanding shares of
Houston Exploration's common stock. KeySpan is a diversified energy provider
that (i) distributes natural gas to a customer base of 1.6 million New Yorkers
in Brooklyn, Long Island, Queens and Staten Island; (ii) is contracted by Long
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Island Power Authority to manage electricity service to about 1 million
customers 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 through the application of a three-pronged approach
that combines (i) high potential offshore exploration; (ii) lower risk, high
impact exploitation and development drilling onshore; and (iii) selective
opportunistic acquisitions. From January 1, 1994 through December 31, 1999, the
Company increased its proved reserve base at a compound annual growth rate of
29% and increased its annual production at a compound annual growth rate of 34%.
During the past five years, the Company produced a total of 239 Bcfe and added
637 Bcfe of net proved reserves of which 325 Bcfe were added through
acquisitions and 312 Bcfe were added through exploration and development. In
total, the Company replaced 266% of production through drilling and
acquisitions, with 130% replaced through the drillbit alone. At the close of
1999 daily production averaged 213 MMcfe per day.
The Company focuses on the following elements in implementing this
strategy:
High Potential Exploratory and Development Drilling in the Gulf of Mexico
The Company holds interests in 106 lease blocks, representing 527,279
gross (286,953 net) acres, in federal and state waters in the Gulf of Mexico, of
which 74 blocks are undeveloped. The Company believes it has assembled a
four-year inventory of offshore prospects and of its undeveloped leases, 20 have
been evaluated, permitted and are ready to drill. The Company plans to drill
approximately six exploratory wells in the Gulf of Mexico in 2000. 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 21
successful exploratory wells and 18 successful development wells in the Gulf of
Mexico, representing a historical success rate of 71%. The Company anticipates
that approximately $63 million of its $125 million 2000 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 remains attractive for
future exploration and development activities due to the availability of
geologic data, remaining reserve potential and the infrastructure of gathering
systems, pipelines, platforms and providers of drilling services and equipment.
Offshore properties account for 44% of the Company's net proved reserves as of
December 31, 1999. At the end of 1999, average net production from the Company's
Gulf of Mexico properties was approximately 91 MMcfe per day.
Lower Risk, High Impact Exploitation and Development Drilling Onshore
The Company owns significant onshore natural gas and oil properties in the
Lobo trend in South Texas, the South Lake Arthur and Lake Pagie Fields in South
Louisiana, the Arkoma Basin of Oklahoma and Arkansas, East Texas and the
Appalachian Basin in West Virginia. These properties favor exploitation and
development drilling and generate the cash flow for offshore exploration and
growth. Onshore properties account for 56% of net proved reserves at December
31, 1999. Complementing the offshore properties, the Company's onshore
properties are typically characterized by relatively longer reserve lives, more
predictable production streams and lower operating cost structures. Over the
past five years, the Company has drilled or participated in the drilling of 108
successful development wells and nine successful exploratory wells onshore
representing a historical drilling success rate of 80%. The Company has
identified an extensive inventory of more than 200 potential onshore drilling
locations, of which approximately 90 are located in the Charco Field in South
Texas. The Company anticipates that approximately $62 million of its $125
million 2000 capital expenditure budget (excluding acquisitions) will be spent
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on onshore projects, including the drilling of approximately 50 development
wells. At the end of 1999, average net production from the Company's onshore
properties was approximately 122 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 the reserves acquired.
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 3-D seismic data, covering
approximately 98% of its undeveloped offshore lease blocks and other possible
lease and acquisition prospects in the Gulf of Mexico, 148 square miles covering
the Charco Field and approximately 100 square miles in South Louisiana. The
Company has 14 geologists and geophysicists with a combined industry experience
averaging 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.
High Percentage of Operated Properties
Acquiring operating positions is a key component of the Company's
strategy. Properties operated by the Company account for approximately 90% of
its production. 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. 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 $0.08 per Mcfe) of $0.26 per
Mcfe of production and net general and administrative expense of $0.06 per Mcfe
of production for the year ended December 31, 1999. The Company believes that
these expense levels are among the lowest within its peer group
Geographically Focused Operations
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. The geographic focus of the Company's operations in six
core 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. 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.
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RECENT ACQUISITIONS
West Cameron 587 Acquisition
In November 1999, the Company completed the acquisition of a 64%
working interest in the West Cameron 587 Field (the "West Cameron 587
Acquisition") for $21 million in cash. The acquisition was financed by
borrowings under the Company's revolving bank credit facility and represents
interests in two undeveloped wells. Net proved undeveloped reserves for the
natural gas and oil interests acquired are estimated at 21 Bcfe as of December
31, 1999.
KEYSPAN JOINT VENTURE
In March 1999, the Company entered into a joint exploration agreement (
the "KeySpan Joint Venture") with KeySpan Exploration & Production, LLC, a
subsidiary of KeySpan, to explore for natural gas and oil over a term of three
years expiring December 31, 2001. Either party may terminate the KeySpan Joint
Venture at the end of the then current calendar quarter by giving thirty days
prior written notice. Houston Exploration is joint venture manager and operator.
Effective January 1, 1999, KeySpan agreed to commit up to $100 million per
calendar year and Houston Exploration agreed to commit its proportionate share
of the funds per calendar year necessary to fund a joint exploration and
development drilling program. Houston Exploration contributed all of its
undeveloped offshore leases as of January 1, 1999 to the joint venture. 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 pays 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 are paid
51.75% by KeySpan and 48.25% by Houston Exploration. In addition, Houston
Exploration receives reimbursement of a portion of its general and
administrative costs during the term of the joint venture.
During 1999, the Company, together with KeySpan, completed the drilling
of eight wells under the KeySpan Joint Venture, six of which were successful.
KeySpan incurred approximately $35.6 million in drilling costs during 1999 and
the Company received $4.8 million in general and administrative reimbursements.
KeySpan has agreed to commit approximately $30 million during 2000 for the
drilling of six exploratory wells and the development of discoveries made in
1999. The $30 million commitment will include approximately $18 million for
exploration, $10 million for development and the balance for general and
administrative reimbursements.
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GULF OF MEXICO PROPERTIES
The Company holds interests in 106 offshore blocks, of which 30 are
currently producing. The Company operates 21 of these producing blocks,
accounting for approximately 90% of the Company's offshore production. The
following table lists the Company's net proved reserves, average working
interest and the operator for the Company's ten largest offshore properties as
of December 31, 1999. These properties represent over 80% of the Company's Gulf
of Mexico proved reserves and approximately 85% of its offshore production
during 1999:
<TABLE>
<CAPTION>
NET PROVED RESERVES AT DECEMBER 31, 1999
---------------------------------------- AVERAGE
GAS OIL TOTAL WORKING
OFFSHORE FIELDS (MMCF) (MBBLS) (MMCFE) INTEREST OPERATOR
--------------- ------- ------- ------- -------- ------------
<S> <C> <C> <C> <C> <C>
Mustang Island Blocks A-31/32 ........ 82,546 214 83,830 100% Company
East Cameron Blocks 82/83 ............ 26,401 304 28,225 98% Company
West Cameron Blocks 76/77/60/61 ...... 22,767 152 23,679 12% Third Party
West Cameron Block 587 ............... 20,601 -- 20,601 64% Third Party
Mustang Island Blocks 858/868 ........ 13,581 214 14,865 74% Company
Matagorda Island Blocks 651/671/672... 11,875 7 11,917 61% Company
High Island Blocks 38/39 ............. 11,137 71 11,563 45% Company
Mustang Island Block 807 ............. 6,643 19 6,757 100% Company
East Cameron Block 84 ................ 5,199 151 6,105 14% Third Party
Mustang Island Block 759 ............. 5,221 9 5,275 25% Third Party
All Other Gulf of Mexico (13 fields).. 18,937 797 23,719
------- ----- -------
Total Gulf of Mexico ................. 224,908 1,938 236,536
======= ===== =======
</TABLE>
During 1999, the Company drilled 14 successful wells (six exploratory
and eight development) and two unsuccessful exploratory wells on its Gulf of
Mexico properties. KeySpan participated in five of the six successful
exploratory wells, the two unsuccessful exploratory wells and one of the
successful development wells. Discoveries were made at West Cameron 76, East
Cameron 84, Galveston 190, Galveston 389, Vermilion 408 and South Timbalier 316.
Three development wells were drilled at Mustang A-31 and two development wells
were drilled at West Cameron 76 to further delineate the discovery well at West
Cameron 76 which was completed in early 1999. At December 31, 1999, two
exploratory wells were in progress: Matagorda 704 and North Padre Island 883-L.
KeySpan is participating in both of these wells and both have been determined
successful and will be completed during 2000. Capital spending associated with
the Company's Gulf of Mexico properties during 1999 was $104.6 million,
including $8.5 million for exploratory drilling, $53.9 million for development
and $42.2 million for property acquisition and leasehold costs which includes
$21 million for the acquisition of the West Cameron 587 Field.
During 2000, the Company plans to drill approximately six exploratory
wells in the Gulf of Mexico and complete the development of discoveries made
during 1999 at Galveston 190, Galveston 389, Matagorda 704, Vermilion 408 and
North Padre 883. In addition, the Company plans to complete the installation of
facilities at Galveston 144 where a successful exploratory well was drilled in
1998 and to begin development at West Cameron 587 which was acquired in November
1999. All six of the exploratory wells planned for 2000 will be drilled under
the terms of the KeySpan Joint Venture. As of March 22, 2000, the Company had
three offshore wells in progress: Matagorda 704, North Padre Island 883-L, and
East Breaks 167. In early January 2000, a second exploratory well was spud at
East Cameron 84 to test the fault block to the south of the discovery made in
1999. Both the Company and KeySpan were participating in the well which was
drilled by a third party. The well was logged and determined to be unproductive
in mid-March 2000.
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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 (779.1 net) producing wells, approximately 90% of which the Company
is the operator of record, and 166,450 gross (116,639 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,
1999, representing all of the Company's onshore reserves:
<TABLE>
<CAPTION>
NET PROVED RESERVES AT
DECEMBER 31, 1999
AVERAGE ------------------------------
WORKING GAS OIL TOTAL
ONSHORE OPERATING AREAS INTEREST (MMCF) (MBBLS) (MMCFE)
- ----------------------- -------- ------ ------- -------
<S> <C> <C> <C> <C>
Charco Field (South Texas) ............................. 95% 142,971 56 143,307
South Lake Arthur and Lake Pagie (South Louisiana) ..... 55% 46,006 357 48,148
Chismville/Massard Field (Arkansas) .................... 73% 71,889 -- 71,889
Wilburton, Panola and Surrounding Fields (Oklahoma) .... 23% 8,000 -- 8,000
Willow Springs and Surrounding Fields (East Texas) ..... 53% 10,526 68 10,934
Appalachian Area (West Virginia) ....................... 60% 21,885 51 22,191
------- ------- -------
Total Onshore .......................................... 301,277 532 304,469
======= ======= =======
</TABLE>
The Company drilled or participated in the drilling of 31 successful
development wells and two successful exploratory wells on its onshore properties
during 1999. During this same period, the Company drilled or participated in the
drilling of six development wells that were not successful. Capital spending
associated with the Company's onshore drilling program during 1999 was
approximately $43.0 million, including $34.0 million for development, $3.8
million for exploration and $5.2 million for leasehold acquisition costs. The
Company did not acquire any onshore properties during 1999.
For 2000 the Company has budgeted funds to drill approximately 50
onshore development wells: 24 in the Charco Field, four wells in South
Louisiana, 18 wells in the Arkoma Basin and four wells in East Texas. The
Company believes it 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. The Company
owns a 95% working interest in the approximately 214 active wells in the Charco
Field, all of which are operated by the Company. Since the acquisition of the
Charco Field in July 1996, the Company has used an active drilling and workover
program to increase production and reserves from the field. Production has more
than doubled since July 1996, from an average of 38 MMcfe per day, net to the
Company's interest, to 85 MMcfe per day, net to the Company's interest, in
December 1999. The Company has drilled 62 successful wells, added 114 Bcfe in
reserves and produced 85 Bcfe since the acquisition of the Charco Field. During
1999 the Company successfully drilled 22 development wells and drilled one
unsuccessful development well. 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 successfully drilled and
completed four development wells and is currently in the process of drilling two
new development wells.
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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 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 48 producing wells, of which it
operates 10 wells. Working interests in these wells range from 2% to 70% and
average 55%. During 1999, the Company participated in two wells located in Lake
Pagie: one successful exploratory well with a working interest of 60%, and one
unsuccessful development well with a working interest of 30%. At the end of
1999, production from the South Louisiana properties averaged approximately 13
MMcfe/d, net to the Company's interest. Subsequent to year end 1999, the Company
spud its first well in South Lake Arthur. Houston Exploration is operator and
holds a 52% working interest. The well is a deep development well and the
Company is drilling the well under a turnkey contract. The well is scheduled to
reach its target objective of 17,000 feet during the second quarter of 2000.
Chismville/Massard Field. The Chismville/Massard Field is located in
Logan and Sebastian Counties, Arkansas. The Company owns working interests in
approximately 161 active wells, of which it operates 84 wells. Working interests
in these wells range from 11% to 100% and average approximately 73%. During
1999, the Company successfully completed six gross (3.2 net) development wells
and participated in the drilling of four (1.8 net) unsuccessful development
wells. Subsequent to year end 1999, the Company successfully drilled and
completed two (1.0 net) wells. At the end of 1999, production averaged 13.5
MMcfe/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 35 active wells,
of which it operates 31 wells. Working interests in these wells range from 3% to
100% and average approximately 53%. At the end of 1999, production averaged 2.2
MMcfe/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 51 active wells, of which it operates 16 wells. Working interests in
these wells range from 1% to 63% and average approximately 23%. During 1999, the
Company participated in the successful drilling of three (0.2 net) development
wells. At year end 1999, production averaged 3 MMcfe/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 668 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 1999, production averaged
5.3 MMcfe/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 74 undeveloped
blocks representing 379,065 gross (198,591 net) acres. Of these undeveloped
leases, 20 have been evaluated by the Company's geologists and geophysicists and
are considered ready to drill. The Company plans to continue active
participation in upcoming state and federal lease sales. In addition, the
Company continues to actively pursue farm-ins from other companies, interests in
joint ventures and potential acquisitions of proved properties. 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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NATURAL GAS AND OIL RESERVES
The following table summarizes the estimates of the Company's
historical net proved reserves as of December 31, 1999, 1998 and 1997, and the
present values attributable to these reserves at such dates. The reserve data
and present values were prepared by Netherland, Sewell & Associates, Inc.
("NSA") and Miller and Lents, Ltd. ("Miller and Lents"), independent petroleum
engineering consultants.
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
----------------------------------
1999 1998 1997
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Net Proved Reserves(1):
Natural gas (MMcf) ................................. 526,185 470,447 330,601
Oil (MBbls) ........................................ 2,470 1,650 1,077
Total (MMcfe) ...................................... 541,005 480,347 337,063
Present value of future net revenues before income
taxes(2) ........................................... $529,671 $412,933 $377,065
Standardized measure of discounted future net cash
flows(3) ........................................... $469,225 $396,060 $315,380
</TABLE>
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(1) NSA and Miller and Lents prepared reserve data and present values with
respect to properties comprising approximately 76% and 24%,
respectively, of the present values attributable to the Company's
proved reserves as of December 31, 1999; 71% and 29%, respectively, of
the present values attributable to proved reserves as of December 31,
1998; and 76% and 24%, respectively, of the present values attributable
to proved reserves as of December 31, 1997.
(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, 1999, 1998 and 1997
were $2.01, $1.83 and $2.31, respectively. Average prices per Bbl of
oil used in making such present value determinations as of December 31,
1999, 1998 and 1997 were $22.80, $10.65 and $17.23, respectively. Such
amounts reflect the effects of the Company's hedging contracts.
(3) The standardized measure of discounted future net cash flows represents
the present value of future net revenues after income tax discounted at
10% per annum. Such amounts reflect the effects of the Company's
hedging contracts.
In accordance with applicable requirements of the Securities and
Exchange Commission, estimates of the Company's proved reserves and future net
revenues are made using sales prices estimated to be in effect as of the date of
such reserve estimates and are held constant throughout the life of the
properties (except to the extent a contract specifically provides for
escalation). Estimated quantities of proved reserves and future net revenues
therefrom are affected by gas prices, which have fluctuated widely in recent
years. There are numerous uncertainties inherent in estimating natural gas and
oil reserves and their estimated values, including many factors beyond the
control of the producer. The reserve data set forth in this Annual Report on
Form 10-K represent only estimates. Reservoir engineering is a subjective
process of estimating underground accumulations of natural gas and oil that
cannot be measured in an exact manner. The accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates of different engineers,
including those used by the Company, may vary. In addition, estimates of
reserves are subject to revision based upon actual production, results of future
development and exploration activities, prevailing natural gas and oil prices,
operating costs and other factors, which revision may be material. Accordingly,
reserve estimates are often different from the quantities of natural gas and oil
that are ultimately recovered and are highly dependent upon the accuracy of the
assumptions upon which they are based. The Company's estimated proved reserves
have not been filed with or included in reports to any federal agency.
-8-
<PAGE> 10
DRILLING ACTIVITY
The following table sets forth the drilling activity of the Company on
its properties for the years ended December 31, 1999, 1998 and 1997.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------
1999 1998 1997
--------------------- ---------------------- --------------------
GROSS NET GROSS NET GROSS NET
------- -------- ------- -------- -------- -------
<S> <C> <C> <C> <C> <C> <C>
OFFSHORE DRILLING ACTIVITY:
Exploratory:
Productive..................... 6 1.4 2 1.3 6 3.7
Non-Productive................. 2 1.0 5 4.2 3 2.3
------- -------- ------- -------- -------- -------
Total..................... 8 2.4 7 5.5 9 6.0
Development:
Productive..................... 8 5.5 1 1.0 1 0.2
Non-Productive................. -- -- 1 0.8 1 0.8
------- -------- ------- -------- -------- -------
Total..................... 8 5.5 2 1.8 2 1.0
ONSHORE DRILLING ACTIVITY:
Exploratory:
Productive..................... 2 1.2 1 0.3 2 0.1
Non-Productive................. -- -- -- -- 2 0.6
------- -------- ------- -------- -------- -------
Total..................... 2 1.2 1 0.3 4 0.7
Development:
Productive..................... 31 24.3 23 18.2 33 29.1
Non-Productive................. 6 3.1 4 3.8 8 7.7
------- -------- ------- -------- -------- -------
Total..................... 37 27.4 27 22.0 41 36.8
</TABLE>
PRODUCTIVE WELLS
The following table sets forth the number of productive wells in which
the Company owned an interest as of December 31, 1999.
<TABLE>
<CAPTION>
COMPANY
OPERATED
PLATFORMS COMPANY OPERATED WELLS NON-OPERATED WELLS TOTAL PRODUCTIVE WELLS
--------- ----------------------- -------------------- ----------------------
GROSS NET GROSS NET GROSS NET
-------- -------- -------- -------- -------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
OFFSHORE
Gas............ 21 56 43.8 12 1.9 68 45.7
Oil............ -- -- -- 4 0.5 4 0.5
------- -------- -------- -------- -------- -------- ---------
Total.......... 21 56 43.8 16 2.4 72 46.2
======= ======== ======== ======== ======== ======== =========
ONSHORE
Gas............ 1,008 741.2 167 35.5 1,175 776.7
Oil............ 2 1.9 2 0.5 4 2.4
-------- -------- -------- -------- -------- ---------
Total.......... 1,010 743.1 169 36.0 1,179 779.1
======== ======== ======== ======== ======== =========
</TABLE>
Productive wells consist of producing wells capable of production,
including gas wells awaiting connections. Wells that are completed in more than
one producing horizon are counted as one well.
-9-
<PAGE> 11
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, 1999. 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) ........ 148,214 88,362 379,065 198,591
Onshore ............ 151,493 105,977 14,957 10,662
------- ------- ------- -------
Total ..... 299,707 194,339 394,022 209,253
======= ======= ======= =======
</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 a relatively 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 for the year ended
December 31, 1999 to Adams Resources and Energy, Inc. (successor to H&N Gas
Ltd.) (22.5%); for the year ended December 31, 1998 to H&N Gas Ltd. (27%) and
Columbia Energy Services Corporation (12%); and for the year ended December 31,
1997 to H&N Gas Ltd. (38%).
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 ability 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, 1999, total undiscounted abandonment costs
estimated to be incurred through the year 2011 were approximately $9.2 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.
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<PAGE> 12
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 farm-out 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 intense competition from other oil and gas
companies in all areas of its operations, including the acquisition of producing
properties and proved undeveloped acreage. 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.
-11-
<PAGE> 13
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:
o regulation of natural gas and oil production;
o federal and state regulations governing environmental quality and
pollution control;
o state limits on allowable rates of production by a well or proration
unit;
o the supply of natural gas and oil available for sale; o the
availability of adequate pipeline and other transportation and
processing facilities; and
o 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. Legislation affecting the oil and gas
industry is under constant review for amendment or expansion, frequently
increasing the regulatory burden. Also, 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. Although the regulatory
burden on the oil and gas industry increases the Company's cost of doing
business and, consequently, affects its profitability, generally, these burdens
do not appear to affect the Company any differently or to any greater or lesser
extent than other companies in the industry with similar types, quantities and
locations of production.
State statutes and regulations require permits for drilling operations,
drilling bonds and reports concerning operations. Most states in which the
Company operates also have statutes and regulations governing the conservation
of oil and natural gas and the prevention of waste, including the unitization or
pooling of oil and natural gas properties and rates of production from oil and
natural gas wells. Rates of production may be regulated through the
establishment of maximum daily production allowables on a market demand or
conservation basis or both.
In addition to regulatory oil and gas production, numerous states have
implemented statutory and regulatory initiatives requiring local distribution
companies ("LDCs") to develop to various degrees unbundled transportation and
related service options and rates. Typically, these programs are designed to
allow the LDCs' commercial, industrial, and, with increasing frequency,
residential customers to have access to transportation service on the LDC,
coupled with an ability to select third-party city-gate gas suppliers.
Similarly, several states are also addressing the
-12-
<PAGE> 14
unbundling of the retail electric markets, ranging from the consideration of
initial unbundling proposals to permitting, in varying degrees, the
implementation of programs allowing direct retail access. These developments
have already led a number of industry participants to redirect significant
marketing resources to these emerging energy markets.
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 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.
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 its
natural gas. Commencing in 1985 and continuing with the issuance of Order No.
636 in 1992, the FERC promulgated a series of orders and regulations that
significantly fostered competition in the business of transporting and marketing
gas. These orders and regulations induced, and ultimately required, interstate
pipeline companies to provide nondiscriminatory transportation services to
producers, marketers and other shippers, regardless of whether shippers were
affiliated with an interstate pipeline company. The FERC's initiatives have led
to the development of a competitive, unregulated, open access market for gas
purchases and sales that permits all purchasers of gas to buy gas directly from
third-party sellers other than pipelines.
All pipeline operations on or across the Outer Continental Shelf are
regulated under the Outer Continental Shelf Lands Act ("OCSLA"). Under the
FERC's current regulatory regime, transmission services must be provided on an
open-access, non-discriminatory basis, while gathering services are treated as
non-jurisdictional activities not subject to the FERC's jurisdiction. The FERC
continues to consider changes regarding the application of its jurisdiction over
facilities operating on the Outer Continental Shelf. It is not clear whether a
revised FERC policy regarding its jurisdiction over offshore natural gas
pipeline facilities would have a material effect on producers such as the
Company and the Company cannot predict what a revised 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.
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 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
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<PAGE> 15
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."
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. Furthermore, 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. Finally, under CERCLA, crude oil and fractions thereof are expressly
exempt from coverage as a "hazardous waste," and so generally speaking, the oil
and gas the Company produces is not subject to CERCLA. However, some products
used in the exploration and production of oil and gas do constitute CERCLA
"hazardous substances" when disposed of, and therefore could subject the Company
to some degree of CERCLA liability. Notwithstanding that, given the fact that
the Company has only been engaged in the exploration for oil and gas since 1985,
any potential CERCLA liability is not anticipated to have a material adverse
impact on the Company.
The Resource Conservation and Recovery Act ("RCRA") affects oil and gas
production activities by imposing requirements for the generation,
transportation, treatment, storage, disposal and cleanup of "hazardous wastes."
However, pursuant to regulations promulgated under RCRA, drilling fluids,
produced waters, and other wastes associated with the exploration, development,
or production of crude oil, natural gas, or geothermal energy do not constitute
"hazardous wastes" subject to RCRA regulation. Nonetheless, such wastes
constitute "solid wastes" and are subject to less stringent regulation under
RCRA's non-hazardous waste provisions which are administered by the states and
typically apply to solid waste disposal facilities.
The Oil Pollution Act of 1990, 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-
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<PAGE> 16
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. Parties responsible
for more than one offshore facility are required to provide OSFR only for their
offshore facility requiring the highest OSFR. Regulations promulgated by the MMS
have established the amount of OSFR to be required for particular facilities,
dependent on the volume of a facility's worst-case oil spill. 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, but less than 70,000 barrels, $70 million will be required;
for worst-case spills of over 70,000 barrels, but not more than 105,000 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 regulations have had no material
adverse effect of the Company, the impact of unknown 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 natural resource 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.
The Federal Water Pollution Control Act ("FWPCA") imposes restrictions
and strict controls regarding the discharge of pollutants, including produced
waters, sands and other oil and gas wastes into navigable waters. Permits must
be obtained to discharge such 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. After January 1, 1997, with few exceptions, the U.S. Environmental
Protection Agency ("EPA") general permit applicable to coastal waters in
Louisiana and Texas prohibits the discharge of produced water and produced sand
derived from oil and gas point source facilities. In addition, 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.
The Federal Clean Air Act ("CAA") and similar state laws that regulate
emissions of pollutants to the air, affect oil and gas production. Specifically,
the OCSLA has required MMS to promulgate and administer regulations that comply
with the National Ambient Air Quality Standards ("NAAQS") pursuant to the CAA,
and to the extent that authorized activities significantly affect the air
quality of any state. In addition, pursuant to the CAA, for Outer Continental
Shelf air emission sources located within 25 miles of a state's seaward
boundaries, the requirements are the same as the requirements that would be
applicable if the source were located in the corresponding onshore area. For
sources located beyond the 25 miles of a state's boundaries, the sources are
subject to federal requirements of
-15-
<PAGE> 17
the CAA's Prevention of Significant Deterioration ("PSD") program. The costs of
compliance with these CAA requirements have not and are not anticipated to have
a material adverse impact on the Company's financial conditions and operations.
Finally, 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.
RISK FACTORS AFFECTING OUR BUSINESS
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 domestic and foreign supply of natural gas and oil;
o the price of foreign imports;
o overall domestic and global economic conditions;
o political and economic conditions in oil producing countries;
o the level of consumer product demand;
o weather conditions;
o domestic and foreign governmental regulations; and
o the price and availability of alternative fuels.
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.
WE MAY BE REQUIRED TO TAKE ADDITIONAL WRITEDOWNS IF NATURAL GAS AND OIL
PRICES DECLINE.
There is a risk that we will be required under full cost accounting
rules to write down the carrying value of our natural gas and oil properties
when natural gas and oil prices are low or if we have substantial downward
adjustments to our estimated proved reserves, increases in our estimates of
development costs or deterioration in our exploration results.
Primarily as a result of weak natural gas prices, we recorded a
writedown in the carrying value of our natural gas and oil properties for the
year ended December 31, 1998 in the amount of $130 million ($84.5 million after
tax). Although prices have recently recovered, we cannot make assurances that we
will not be required to take additional writedowns in future periods.
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 and will continue to make substantial capital expenditures to find,
develop, acquire and produce
-16-
<PAGE> 18
natural gas and oil reserves. Our capital expenditure budget for exploration,
development and leasehold acquisitions for 2000 is estimated at approximately
$125 million. This budget excludes potential property acquisitions. Our
management believes that we will have sufficient cash provided by operating
activities and borrowings under our bank credit facility to fund planned capital
expenditures in 2000. 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 unless we raise additional funds through debt or equity
financings. Without continued employment of capital, our oil and gas reserves
will decline. We cannot make assurances that debt or equity financing, cash
generated by operations or our borrowing capacity under our revolving bank
credit facility will be available to meet our capital requirements.
THE AMOUNT OF OUR OUTSTANDING INDEBTEDNESS IS SUBSTANTIAL AND COULD
HAVE ADVERSE CONSEQUENCES.
Our outstanding indebtedness at December 31, 1999 was $361 million,
which includes $80 million in current maturities under the KeySpan credit
facility, and as of March 22, 2000 has remained unchanged. Our outstanding
indebtedness is expected to decrease by $80 million upon the planned conversion
of the outstanding borrowings under the KeySpan credit facility on March 31,
2000 into shares of the Company's common stock.
Our level of indebtedness affects our operations in a number of ways.
Our bank credit facility and the indenture governing our senior subordinated
notes 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, engineering, geological
interpretation and judgment and the assumptions used regarding quantities of
recoverable natural gas and 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.
Our future success depends on our ability to find, develop and acquire
natural gas and oil 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.
-17-
<PAGE> 19
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
the benefit to revenues is limited when natural gas prices increase; and
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 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.
-18-
<PAGE> 20
POTENTIAL CONFLICTS OF INTEREST WITH KEYSPAN.
KeySpan currently owns 64% of our common stock and is expected to own
approximately 70% of our common stock upon the planned conversion of the $80
million outstanding under the KeySpan credit facility on March 31, 2000.
Conflicts of interest may arise in the future between us and KeySpan 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 or properties;
o transfers of assets;
o insurance matters;
o financial commitments;
o registration rights; and
o issuances and sales of 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 to
Mr. Catell, two of our seven other 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 a
majority 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, 1999, the Company had 109 full time employees, 73 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."
-19-
<PAGE> 21
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.
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 the Company's
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, 1999.
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, 1998 through December
31, 1999 as reported on the New York Stock Exchange:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1999 HIGH LOW
--------- --------
<S> <C> <C>
First Quarter......................................... $ 20.500 $ 12.000
Second Quarter........................................ 20.625 16.625
Third Quarter......................................... 23.125 18.500
Fourth Quarter........................................ 22.875 17.688
YEAR ENDED DECEMBER 31, 1998 HIGH LOW
--------- --------
First Quarter......................................... $ 23.000 $ 14.875
Second Quarter........................................ 24.563 20.000
Third Quarter......................................... 24.250 14.125
Fourth Quarter........................................ 19.875 16.375
</TABLE>
As of March 22, 2000, 23,923,020 shares of common stock were
outstanding and the Company had approximately 49 stockholders of record and
approximately 1,500 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
85/8% Senior 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."
-20-
<PAGE> 22
ITEM 6. SELECTED FINANCIAL DATA
The following table shows selected financial data derived from the
Company's consolidated financial statements for each of the five years in the
period ended December 31, 1999. 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.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------------------------------------
1999 1998 1997 1996 1995
------------ ------------ ----------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
CONSOLIDATED STATEMENT OF OPERATIONS DATA:
Revenues:
Natural gas and oil revenues.............. $ 150,580 $ 127,124 $ 116,349 $ 64,864 $ 39,431
Other..................................... 1,147 1,123 1,297 1,040 1,778
------------ ------------ ----------- ----------- -----------
Total revenues...................... 151,727 128,247 117,646 65,904 41,209
Expenses:
Lease operating........................... 18,406 16,199 14,146 10,800 5,005
Severance tax............................. 5,444 4,967 4,233 1,401 463
Depreciation, depletion and amortization.. 74,051 79,838 59,081 33,732 21,969
Writedown in carrying value............... -- 130,000 -- -- --
General and administrative, net........... 4,150 6,086 5,825 6,249 3,486
Nonrecurring charge(1).................... -- -- -- -- 12,000
------------ ------------ ----------- ----------- -----------
Total operating expenses............ 102,051 237,090 83,285 52,182 42,923
Income (loss) from operations............... 49,676 (108,843) 34,361 13,722 (1,714)
Interest expense, net....................... 13,307 4,597 938 2,875 2,398
------------ ------------ ----------- ----------- -----------
Income (loss) before income taxes........... 36,369 (113,440) 33,423 10,847 (4,112)
Income tax provision (benefit).............. 11,748 (40,754) 10,173 2,205 (3,809)
------------ ------------ ----------- ----------- -----------
Net income (loss)........................... $ 24,621 $ (72,686) $ 23,250 $ 8,642 $ (303)
============ ============ =========== =========== ===========
Net income (loss) per share................. $ 1.03 $ (3.05) $ 1.00 $ 0.49 $ (0.02)
============ ------------ =========== =========== ===========
Net income (loss) per share--diluted........ $ 0.95 $ (3.05) $ 0.97 $ 0.49 $ (0.02)
============ ============ =========== =========== ===========
Weighted average shares..................... 23,906 23,768 23,337 17,532 15,295
Weighted average shares--diluted............ 28,310 23,768 24,028 17,687 15,295
</TABLE>
<TABLE>
<CAPTION>
AT YEAR END DECEMBER 31,
-------------------------------------------------------------------
1999 1998 1997 1996 1995
------------ ------------ ----------- ----------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
CONSOLIDATED BALANCE SHEET DATA:
Property, plant and equipment, net.......... $ 610,116 $ 536,582 $ 443,738 $ 359,124 $ 216,678
Total assets................................ 678,483 569,452 491,391 401,285 247,496
Long-term debt and notes.................... 281,000 313,000 113,000 65,000 71,862
Stockholders' equity........................ 217,590 192,530 256,187 233,300 103,236
</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.
-21-
<PAGE> 23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion is intended to assist in an understanding of
the Company's historical financial position and results of operations for each
year in the three-year period ended December 31, 1999. 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.
GENERAL
Houston Exploration 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 operations are currently
focused offshore in the Gulf of Mexico and onshore in South Texas, South
Louisiana, the Arkoma Basin, East Texas and West Virginia. Houston Exploration's
strategy is to utilize its geological and geophysical expertise to grow its
reserve base through a combination of exploratory drilling in the Gulf of Mexico
and lower risk, exploitation and development drilling onshore. At December 31,
1999, the Company had net proved reserves of 541 Bcfe, 97% of which were natural
gas and 75% of which were classified as proved developed.
Houston Exploration began exploring for natural gas and oil in December
1985 on behalf of The Brooklyn Union Gas Company ("Brooklyn Union") and in
September 1996 the Company completed an initial public offering ("IPO") of its
common stock. Brooklyn Union became an indirect wholly-owned subsidiary of
KeySpan Corporation ("KeySpan") in May 1998 through the combination of Brooklyn
Union's parent company KeySpan Energy Corporation and Long Island Lighting
Company. As of December 31, 1999, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 64% of the outstanding shares of
Houston Exploration's common stock. KeySpan is a diversified energy provider
that (i) distributes natural gas to a customer base of 1.6 million New Yorkers
in Brooklyn, Long Island, Queens and Staten Island; (ii) is contracted by Long
Island Power Authority to manage electricity service to about 1 million
customers 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.
Full Cost Accounting. 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 writedown 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.
At December 31, 1999, the Company estimated, using a wellhead price of
$2.01 per Mcf, that a $99.2 million (after tax) full cost ceiling "cushion"
existed whereby the carrying value of the full cost pool was less than the
ceiling limitation imposed under full cost accounting.
-22-
<PAGE> 24
As of December 31, 1998, the Company estimated, 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 estimated, using a February 1999 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.
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, including certain derivative instruments embedded in
other contracts, be recorded in 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. In
June 1999, the FASB issued SFAS No. 137, which extends the adoption requirement
of SFAS No. 133 from January 1, 2000 to January 1, 2001. The Company plans to
adopt SFAS No. 133 effective January 1, 2001. Currently, the Company cannot
quantify 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
systems, software programs or computerized equipment with embedded data chips to
accurately calculate, store or use a date beyond December 31, 1999. Typically
the year 2000 is represented as the year 1900. The problem of an erroneous date
could result in a system failure or possible miscalculations causing disruptions
of operations, including, among other things, a temporary inability to process
transactions, send invoices or engage in normal business.
The Company established a year 2000 project plan that, together with
external consultants, developed a process for addressing the year 2000 issue.
The project plan included performing an inventory, an assessment, the
remediation and testing of its all critical financial and operational systems
and equipment that contain embedded technology, as well as obtaining assurances
from all key third parties as to their own year 2000 preparedness. For the years
ended December 31, 1999 and 1998, the Company spent approximately $75,000 and
$20,000, respectively, for system and equipment remediation and replacement. The
Company does not expect to incur any material costs relating to year 2000 issues
subsequent to December 31, 1999.
As of March 22, 2000, all of the Company's critical financial and
operational systems and equipment have been tested for year 2000 compliance and
the Company has not experienced any significant problems with its critical
systems or with any key third parties. Although the Company has not experienced
any significant year 2000 problems to date, the Company plans to monitor its
critical systems closely. The Company cannot be sure that it will be completely
successful in its efforts to address the year 2000 issue or that problems
arising from the year 2000 issue will not cause a material adverse effect on the
Company's operating results or financial condition. The Company believes,
however, that the most reasonably likely worst-case scenario would relate to
problems with the systems of third parties rather than its with internal
systems. The Company is limited in its efforts to address the year 2000 issue as
it relates to third parties and relies solely on the assurances of these third
parties as to their year 2000 preparedness.
As part of the Company's year 2000 project plan, the Company has
established a contingency plan in the event its financial or operational systems
experience failure or malfunction due to year 2000 issues. The Company's
contingency plan will allow employees to manually complete otherwise automated
tasks or calculations. The Company believes that the potential impact, if any,
of a system failure or malfunction due to year 2000 issues will not affect the
Company's ability to continue oil and gas exploration, drilling, production and
sales activities.
-23-
<PAGE> 25
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.
Recent Developments
Review of Strategic Alternatives. In September 1999, the Company and
KeySpan, the Company's majority shareholder, announced their intention to review
strategic alternatives for KeySpan's investment in Houston Exploration. A full
range of strategic transactions was considered including the sale of all or a
portion of Houston Exploration. On February 25, 2000, the Company and KeySpan
jointly announced that the strategic review process was complete and that
KeySpan plans to retain its equity interest in Houston Exploration for the
foreseeable future.
KeySpan Credit Facility. On February 25, 2000, the Company and KeySpan
announced their intention to convert the outstanding borrowings of $80 million
under the $150 million subordinated revolving credit facility with KeySpan (the
"KeySpan Facility") into shares of common stock of the Company on March 31,
2000. The conversion price will be calculated by averaging the closing prices of
the Company's common stock on the 20 consecutive trading days ending three
trading days prior to March 31, 2000. The Company estimates that between 4
million and 5 million shares of its common stock will be issued to KeySpan and
that KeySpan's ownership interest will increase from approximately 64% to
approximately 70%. Once the planned conversion is complete, the KeySpan Facility
will terminate and the Company will have no further borrowing capacity under the
KeySpan Facility.
KeySpan Joint Venture. On February 25, 2000, the Company and KeySpan
agreed to amend their joint exploration agreement (the "KeySpan Joint Venture").
The amendment will be effective January 1, 2000 and will provide a commitment by
KeySpan for the year 2000 of approximately $30 million and a reduction to the
amount the Company will receive during 2000 for general and administrative
expense reimbursements. The $30 million commitment will include approximately
$18 million for exploratory drilling, $10 million for development of 1999
discoveries and the balance for general and administrative reimbursements.
Revolving Credit Facility. Chase Bank of Texas has completed its
semi-annual borrowing base redetermination for the Company's revolving credit
facility and has recommended to the syndicate of lenders that the borrowing base
be set at $210 million, effective March 29, 2000. The Company anticipates that
the borrowing base will be set at $210 million. The Company's borrowing
threshold amount will be equal to the new borrowing base which will be in effect
from March 29, 2000 until the next scheduled redetermination on September 1,
2000. As of March 22, 2000, outstanding borrowings and letters of credit under
the revolving bank credit facility have remained unchanged at $181.4 million.
-24-
<PAGE> 26
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,
---------------------------
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
PRODUCTION:
Natural gas (MMcf).......................... 69,679 61,479 50,310
Oil (MBbls)................................. 258 225 171
Total (MMcfe)............................... 71,227 62,829 51,336
AVERAGE SALES PRICES:
Natural gas (per Mcf) realized(1)........... $ 2.10 $ 2.02 $ 2.25
Natural Gas (per Mcf) unhedged.............. 2.14 1.96 2.45
Oil (per Bbl)............................... 16.41 12.18 18.33
EXPENSES (PER MCFE):
Lease operating............................. $ 0.26 $ 0.26 $ 0.28
Severance tax............................... 0.08 0.08 0.08
Depreciation, depletion and amortization 1.04 1.27 1.15
Writedown in carrying value of
natural gas and oil properties........ -- 2.07 --
General and administrative, net............. 0.06 0.10 0.11
</TABLE>
- ---------------------------
(1) Reflects the effects of hedging.
RECENT FINANCIAL AND OPERATING RESULTS
COMPARISON OF THE YEAR ENDED DECEMBER 31, 1999 AND 1998
Production. Houston Exploration's production increased 13% from 62,829
MMcfe for the year ended December 31, 1998 to 71,227 MMcfe for the year ended
December 31, 1999. The increase in production was primarily attributable to
production added from the acquisition of producing properties at Mustang Island
A-31/32 in November 1998 and the South Louisiana properties acquired in late
April 1998 offset in part by a production decline at the Company's Charco Field.
The production decline at Charco reflects the Company's decision to curtail
capital spending in South Texas during the fourth quarter of 1998 due to
depressed natural gas prices. Developmental drilling resumed at Charco in the
first quarter of 1999 with two rigs running and during the second quarter the
Company added a third drilling rig to expedite developmental drilling. The third
rig was released during the third quarter of 1999 and drilling resumed with two
rigs. As a result, sixteen new wells were brought on-line in the Charco Field
during the second half of 1999 compared to six new wells in the first half of
the year, causing average daily production to increase from 74 MMcfe/day during
the first half of 1999 to an average of 85 MMcfe/day during the second half of
1999.
Natural Gas and Oil Revenues. Natural gas and oil revenues increased
18% from $127.1 million for the year ended December 31, 1998 to $150.6 million
for the year ended December 31, 1999 as a result of the 13% increase in
production and a 4% increase in average realized natural gas prices, from $2.02
per Mcf in 1998 to $2.10 per Mcf in 1999.
As a result of hedging activities, the Company realized an average gas
price of $2.10 per Mcf, which was 98% of the unhedged natural gas price of $2.14
per Mcf that otherwise would have been received, resulting in a $2.6
-25-
<PAGE> 27
million decrease in natural gas revenues for 1999. During 1998, the average
realized gas price was $2.02 per Mcf, which was 103% of the unhedged average gas
price of $1.96, resulting in an increase to natural gas revenues of $3.8 million
for the year ended December 31, 1998.
Lease Operating Expenses and Severance Tax. Lease operating expenses
increased 14% from $16.2 million in 1998 to $18.4 million in 1999. On an Mcfe
basis, lease operating expenses remained unchanged at $0.26 for both 1998 and
1999. The increase in lease operating expenses during 1999 is attributable to
the continued expansion of the Company's operations primarily through the 1998
acquisitions of the Mustang Island A-31/32 properties and the South Louisiana
properties. Severance tax, which is a function of volume and revenues generated
from onshore production, increased from $5.0 million in 1998 to $5.4 million in
1999. The increase in 1999 expense is due to the combination of an increase in
onshore production and an increase in price during 1999 as compared to 1998. On
an Mcfe basis, severance tax remained unchanged at $0.08 per Mcfe for both 1998
and 1999.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense decreased 7% from $79.8 million in 1998 to $74.1 in 1999.
Depreciation, depletion and amortization expense per Mcfe decreased 18% from
$1.27 in 1998 to $1.04 in 1999. The decrease in depreciation, depletion and
amortization expense was primarily a result of a lower depletion rate. The lower
depletion rate is primarily a result of the $130 million ($84.5 million net of
tax) writedown in natural gas and oil properties that was taken in the fourth
quarter of 1998 due to weak natural gas prices; combined with an increase in
reserves for the year ended December 31, 1999.
General and Administrative Expenses. General and administrative
expenses, net of overhead reimbursements received from other working interest
owners of $1.1 million and $5.7 million in 1998 and 1999, respectively,
decreased 31% from $6.1 million in 1998 to $4.2 million in 1999. Included in
reimbursements received from working interest owners during 1999 were
reimbursements totaling $4.8 million received from KeySpan pursuant to the
KeySpan Joint Venture (see Note 6 -- Related Party Transactions). The Company
capitalized general and administrative expenses directly related to oil and gas
exploration and development activities of $7.5 million and $5.5 million,
respectively, in 1998 and 1999. The decrease in capitalized general and
administrative expenses is a result of the KeySpan reimbursements. On an Mcfe
basis, general and administrative expenses decreased 40% from $0.10 in 1998 to
$0.06 in 1999. The lower rate per Mcfe during 1999 reflects a combination of an
increase in production and the effect of the KeySpan Joint Venture
reimbursements offset in part by an increase in aggregate general and
administrative expenses. Aggregate general and administrative expenses increased
in 1999 as a result of an increase in incentive compensation and expenses
incurred during the fourth quarter related to the review of strategic
alternatives for KeySpan's investment in the Company. See Note 6 -- Related
Party Transactions.
Interest Expense, Net. Interest expense, net of capitalized interest,
increased from $4.6 million during 1998 to $13.3 million during 1999.
Capitalized interest increased from $9.8 million in 1998 to $11.9 million in
1999. The increase in aggregate interest expense was attributable to higher
average debt levels during 1999 as a result of the additional borrowings of $48
million on the revolving bank credit facility in 1999, the implementation of the
KeySpan Facility in November 1998 and the issuance of $100 million of 85/8%
senior subordinated notes in March 1998.
Income Tax Provision. The provision for income taxes increased from a
benefit of $40.7 million in 1998 to an expense of $11.7 million for 1999 due to
the increase in pretax income in 1999. The income tax benefit in 1998 was
attributable to the $45.5 million tax effect of the $130 million writedown in
natural gas and oil properties the Company was required to take under full cost
accounting rules as a result of weak natural gas prices. The tax benefit from
the utilization of Section 29 tax credits was approximately $1.0 million for
both 1998 and 1999.
Operating Income and Net Income. During 1998, both operating income and
net income were adversely affected by weak natural gas prices and the non-cash
charge of $130 million ($84.5 million after tax) taken to write down the
carrying value of natural gas and oil properties. During 1999 natural gas prices
recovered and the combined effect of an increase in natural gas revenues and a
decrease in operating expenses caused operating income
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<PAGE> 28
for the year ended December 31, 1999 to increase to $49.7 million in 1999 from
an operating loss of $108.8 million in 1998. Net income increased to $24.6
million in 1999 from a loss of $72.7 million in 1998.
COMPARISON OF YEARS ENDED DECEMBER 31, 1998 AND 1997
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, increased approximately 52% from an average of 54 MMcfe per
day during 1997, to an average of 82 MMcfe per day 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 per day, 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 per day during 1997 to
56 MMcfe per day 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.
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, 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.
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<PAGE> 29
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.
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
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%.
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 its 1996 initial public offering of
common stock, capital contributions from KeySpan. On March 2, 1998, the Company
issued $100 million of 85/8% senior subordinated notes. Net proceeds of
approximately $97 million were used to repay a portion of the outstanding
borrowings 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 with KeySpan (the "KeySpan Facility") and
borrowed $80 million under this facility to fund a portion of the November 1998
acquisition of producing natural gas and oil properties in the Gulf of Mexico
from Chevron U.S.A. Inc. (the "Chevron Acquisition").
On February 25, 2000, the Company and KeySpan announced their intention
to convert the outstanding borrowing of $80 million under the KeySpan Facility
into shares of common stock of the Company on March 31, 2000. The conversion
price will be calculated by averaging the closing prices of the Company's common
stock on the 20 consecutive trading days ending three trading days prior to
March 31, 2000. The Company estimates that between 4 million and 5 million
shares of its common stock will be issued to KeySpan and that KeySpan's
ownership interest will increase from approximately 64% to approximately 70%.
Once the planned conversion is
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<PAGE> 30
complete, the KeySpan Facility will terminate and the Company will have no
further borrowing capacity under the KeySpan Facility.
As of December 31, 1999, the Company had a working capital deficit of
$71.2 million, which includes current maturities of $80 million outstanding
under the KeySpan Facility which are due March 31, 2000. As of December 31,
1999, the Company had $58.6 million of borrowing capacity available under the
Credit Facility. Net cash provided by operating activities for the year ended
December 31, 1999 was $110.1 million compared to $102.4 million for
corresponding period of 1998. The increase in working capital during 1999 is
primarily related to the timing of cash receipts and payments. Receivables are
higher due to the increase in natural gas revenues caused by an increase in both
natural gas price and production volume, and payables are higher due to an
increase in drilling activity. The Company's cash position was increased during
1999 by a net increase in borrowings under the Credit Facility of $48 million.
Funds used in investing activities consisted of $147.7 million for investments
in property and equipment, which includes $21 million for the acquisition of a
64% working interest in West Cameron 587. As a result of these activities, cash
and cash equivalents increased $10.9 million from $4.6 million at December 31,
1998 to $15.5 million at December 31, 1999. The Company's available cash balance
at December 31, 1999 of $15.5 million is relatively higher than normal due to
interest payments due in January 2000 on the $100 million 8 5/8% senior
subordinated notes and on the Credit Facility.
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,
----------------------------------
1999 1998 1997
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Net cash provided by operating activities........ $110,072 $102,378 $ 97,292
Net long-term borrowings......................... 48,000 200,000 48,000
Proceeds from sale of common stock, net.......... 439 207 297
</TABLE>
Natural Gas and Oil Capital Expenditures. Over the past three years,
the Company has spent $594 million (including $21 million in 1999 for an
interest in West Cameron Block 587 and $162.9 million in 1998 for the Chevron
and South Louisiana Acquisitions with no acquisitions in 1997) to add 405 Bcfe
of net proved reserves, representing a three-year average finding and
development cost of $1.37 per Mcfe.
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<PAGE> 31
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,
------------------------------
1999 1998 1997
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
OFFSHORE:
Acquisitions and leasehold........................... $ 42,246 $109,209 $ 30,700
Development.......................................... 53,941 15,983 19,826
Exploration.......................................... 8,450 55,381 42,219
-------- -------- --------
104,637 180,573 92,745
ONSHORE:
Acquisitions and leasehold........................... $ 5,196 $ 86,677 $ 9,920
Development.......................................... 34,024 35,063 39,418
Exploration.......................................... 3,807 230 1,900
-------- -------- --------
43,027 121,970 51,238
-------- -------- --------
Total................................................ $147,664 $302,543 $143,983
======== ======== ========
</TABLE>
Future Capital Requirements. The Company's capital expenditure budget
for 2000 has been set at $125 million including $15 million for exploration, $90
million for development and facility construction and $20 million for leasehold
acquisition costs. The Company does not include property acquisition costs in
its capital expenditure budget as the size and timing of capital requirements
for acquisitions are inherently unpredictable. The capital expenditure budget
includes development costs associated with recent discoveries and newly acquired
properties and amounts that are contingent upon drilling success. No significant
abandonment or dismantlement costs are anticipated in 2000. The Company will
continue to evaluate its capital spending plans throughout the year. 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 intends to continue to selectively seek
acquisition opportunities for proved reserves with substantial exploration and
development potential both offshore and onshore although, there can be no
assurance that the Company will be able to identify and make acquisitions of
proved reserves on terms it considers favorable.
In March 1999, the Company entered into a joint exploration agreement
(the "KeySpan Joint Venture") with KeySpan Exploration & Production, LLC, a
subsidiary of KeySpan, to explore for natural gas and oil over a term of three
years expiring December 31, 2001. Either party may terminate the KeySpan Joint
Venture at the end of the then current calendar quarter by giving thirty days
prior written notice. Houston Exploration is joint venture manager and operator.
Effective January 1, 1999, KeySpan agreed to commit up to $100 million per
calendar year and Houston Exploration agreed to commit its proportionate share
of the funds per calendar year necessary to fund a joint exploration and
development drilling program. Houston Exploration contributed all of its
undeveloped offshore leases as of January 1, 1999 to the joint venture. 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 pays 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 are paid
51.75% by KeySpan and 48.25% by Houston Exploration. In addition, Houston
Exploration receives reimbursement of a portion of its general and
administrative costs during the term of the joint venture.
During 1999, the Company, together with KeySpan, completed the drilling
of eight wells under the KeySpan Joint Venture, six of which were successful. At
December 31, 1999, two additional joint venture wells were drilling, and during
the first quarter of 2000, three new wells were spud. KeySpan incurred
approximately $35.6 million in drilling costs in 1999 and the Company received
$4.8 million in general and administrative reimbursements. During 2000, the
Company plans to drill approximately six offshore exploratory wells under the
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<PAGE> 32
terms of the KeySpan Joint Venture and to complete the development and facility
installation of the successful exploratory wells drilled in 1999.
On February 25, 2000, the Company and KeySpan agreed to amend the
KeySpan Joint Venture. The amendment will be effective January 1, 2000 and will
provide a commitment by KeySpan for the year 2000 of approximately $30 million
and a reduction to the amount the Company will receive during 2000 for general
and administrative expense reimbursements. The $30 million commitment will
include approximately $18 million for exploratory drilling, $10 million for
development and the balance for general and administrative reimbursements.
On May 20, 1999, the Company filed a "shelf" registration with the
Securities and Exchange Commission to offer and sell in one or more offerings up
to a total offering amount of $250 million in securities which could include
shares of the Company's common stock, shares of preferred stock or unsecured
debt securities or a combination thereof. Depending on market conditions and the
Company's capital needs, the Company may utilize the shelf registration in order
to raise capital. The Company would use the net proceeds received from the sale
of any securities for the repayment of debt and/or to fund an acquisition. There
can be no assurance that the Company will be able to consummate such offering on
acceptable terms.
Capital Structure
Revolving Bank Credit Facility. The Company has entered into a
revolving bank credit facility with a syndicate of lenders led by Chase Bank of
Texas, National Association ("Chase"). The Credit Facility, as amended, provides
a maximum commitment of $250 million, subject to borrowing base limitations. At
December 31, 1999, the conforming portion of the borrowing base or threshold
amount was $175 million. The Company has the option to borrow in excess of the
threshold amount up to a borrowing base of $240 million by paying an incremental
interest rate. The borrowing base will remain at $240 million until March 28,
2000. From March 29, 2000 to the next scheduled redetermination on September 1,
2000, the borrowing base will be equal to the threshold amount, which the
Company anticipates will be redetermined and set at $210 million. Up to $2.0
million of the borrowing base is available for the issuance of letters of credit
to support performance guarantees. The Credit Facility matures on March 1, 2003
and is unsecured. At December 31, 1999 and as of March 22, 2000, $181 million
was outstanding under the Credit Facility and $0.4 million was outstanding in
letter of credit obligations.
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 that
increases from 0.875% to 1.625%, 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 0.25% and 0.375% per annum on the unused portion of the Designated
Borrowing Base, and (ii) an unavailable commitment fee equal to 33% of the
commitment fee in (i) above on the difference between the lesser of the Facility
Amount or the Borrowing Base and the Designated Borrowing Base or the Threshold
Amount. The weighted average interest rate was 6.59%, 6.44% and 6.90%,
respectively, for the years ended December 31, 1999, 1998 and 1997.
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;
(ii) a total debt to capitalization ratio of less than 60%, exclusive of
non-cash charges; and (iii) sets a maximum limit of 70% on the amount of natural
gas production the Company can hedge during any 12 month period. 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, 1999, the Company was in compliance with all such covenants.
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
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<PAGE> 33
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%, exclusive of non-cash charges. 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."
KeySpan Credit Facility. The KeySpan Facility established by the
Company and KeySpan in November 1998 provides a maximum loan commitment of $150
million. The KeySpan Facility ranks subordinate to the revolving bank credit
facility and equal in right of payment with the $100 million 8 5/8% senior
subordinated notes. Pursuant to a subordination agreement among the Company,
KeySpan and Chase, the Company may not repay any outstanding principal under the
KeySpan Facility prior to payment in full of all outstanding principal and
interest under the Credit Facility. Borrowings under the KeySpan Facility are
unsecured. On October 27, 1999, the KeySpan Facility was amended to extend the
maturity from January 1, 2000 to March 31, 2000. Any principal amount that
remains outstanding under the KeySpan Facility on March 31, 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 March 31, 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 accrued under the KeySpan Facility is payable
monthly and borrowings bear interest at LIBOR plus 1.4%. In addition, the
Company incurs a quarterly commitment fee of 0.125% on the unused portion of the
maximum commitment and has incurred front fees of $72,000. As of December 31,
1999, outstanding borrowings under the KeySpan Facility were $80 million, all of
which were classified as current liabilities. For the years ended December 31,
1999 and 1998, the Company incurred a total $5.5 million and $0.5 million,
respectively in interest and fees to KeySpan. Borrowings were used to finance a
portion of the November 1998 acquisition of the Mustang Island A-31 Field from
Chevron USA, Inc. See Note 11 -- Acquisitions to the Company's Consolidated
Financial Statements.
Senior Subordinated Notes. On March 2, 1998, the Company issued $100
million of 8 5/8% Senior Subordinated Notes (the "Notes") due January 1, 2008.
The Notes bear interest at a rate of 8 5/8% per annum with interest payable
semi-annually on January 1 and July 1. 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, at 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 in the indenture governing the Notes), 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 including the
KeySpan Facility.
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<PAGE> 34
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 March 22, 2000, 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 February 2000 was 6,184 MMcf (6,390 MMMbtu).
<TABLE>
<CAPTION>
COLLARS
-------------------------------------------
NYMEX
VOLUME CONTRACT PRICE
PERIOD (MMMBTU) AVERAGE FLOOR AVERAGE CEILING
- -------------------------------------------- -------- ------------- ---------------
<S> <C> <C> <C>
January 2000................................ 1,860 $2.550 $3.648
February 2000............................... 1,740 2.450 3.433
March 2000.................................. 3,720 2.425 2.943
April 2000.................................. 4,500 2.400 2.959
May 2000.................................... 4,650 2.400 2.959
June 2000................................... 4,500 2.400 2.959
July 2000................................... 4,650 2.400 2.959
August 2000................................. 4,650 2.400 2.959
September 2000.............................. 4,500 2.400 2.959
October 2000................................ 4,650 2.640 3.191
November 2000............................... 3,000 2.840 3.549
December 2000............................... 3,100 2.840 3.549
January 2001............................... 1,860 3.000 3.630
February 2001............................... 1,680 3.000 3.630
March 2001.................................. 1,860 3.000 3.630
</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 or the NYMEX price on
the final trading day of the month (the "settlement price").
For the months October 2000 through March 2001 the Company has 60,000
MMbtu/day hedged under no-cost collars with floating floors. The floating floor
structure allows for a higher floor price in exchange for a lower ceiling. For
example, during January 2001, if the settlement price is up to $2.50 the Company
will receive the settlement price plus $0.50. If the settlement price is between
$2.50 and $3.00 the Company will receive $3.00. If the settlement price is
between $3.00 and $3.63, the Company will receive the settlement price and if
market price is above $3.63, the Company will receive $3.63 (the ceiling).
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
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<PAGE> 35
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. The Company is not required to
make or receive any payment in connection with a collar transaction if the
settlement price is between the floor and the ceiling. 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.
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, 1999.
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, 1999. 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, 1999.
-34-
<PAGE> 36
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, 1999.
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, 1999 and 1998........................................... F-3
Consolidated Statements of Operations for the Years Ended December 31, 1999, 1998 and 1997............. F-4
Consolidated Statement of Stockholders' Equity for the Period from December 31, 1999 to
December 31, 1997....................................................................................
F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997............. F-6
Notes to Consolidated Financial Statements............................................................. F-7
Supplemental Information on Natural Gas and Oil Exploration, Development and F-23
Production Activities
Quarterly Financial Information (Unaudited)............................................................. F-27
</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:
See Index of Exhibits on page F-28 for a description of the exhibits
filed as a part of this report.
-35-
<PAGE> 37
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, 2000 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, 2000
- ------------------------------------- (Principal Executive Officer)
James G. Floyd
/s/ JAMES F. WESTMORELAND Vice President, Chief Accounting Officer, March 22, 2000
- ------------------------------------- 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, 2000
- -------------------------------------
Robert B. Catell
/s/ GORDON F. AHALT Director March 24, 2000
- -------------------------------------
Gordon F. Ahalt
/s/ RUSSELL D. GORDY Director March 20, 2000
- -------------------------------------
Russell D. Gordy
/s/ DAVID G. ELKINS Director March 22, 2000
- -------------------------------------
David G. Elkins
/s/ CRAIG G. MATTHEWS Director March 24, 2000
- -------------------------------------
Craig G. Matthews
/s/ JAMES Q. RIORDAN Director March 27, 2000
- -------------------------------------
James Q. Riordan
/s/ DONALD C. VAUGHN Director March 22, 2000
- -------------------------------------
Donald C. Vaughn
</TABLE>
-36-
<PAGE> 38
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.
G-1
<PAGE> 39
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.
G-2
<PAGE> 40
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.
G-3
<PAGE> 41
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Independent Public Accountants.............................................................. F-2
Consolidated Balance Sheets as of December 31, 1999 and 1998.......................................... F-3
Consolidated Statements of Operations for the Years Ended December 31, 1999, 1998 and 1997............ F-4
Consolidated Statement of Stockholders' Equity for the Years Ended
December 31, 1999, 1998 and 1997.................................................................... F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997........... F-6
Notes to Consolidated Financial Statements............................................................ F-7
</TABLE>
F-1
<PAGE> 42
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 KeySpan Corporation) as of December 31, 1999 and 1998, and the
related consolidated statements of operations, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1999. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with 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, 1999 and 1998, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1999, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New York, New York
January 27, 2000
F-2
<PAGE> 43
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1999 1998
----------- -----------
(IN THOUSANDS)
<S> <C> <C>
ASSETS:
Cash and cash equivalents ..................................................... $ 15,502 $ 4,645
Accounts receivable ........................................................... 34,917 23,050
Accounts receivable-- Affiliate ............................................... 12,315 137
Inventories ................................................................... 969 915
Prepayments and other ......................................................... 1,082 754
----------- -----------
Total current assets ................................................ 64,785 29,501
Natural gas and oil properties, full cost method
Unevaluated properties ...................................................... 164,377 145,317
Properties subject to amortization .......................................... 956,484 828,168
Other property and equipment .................................................. 9,744 9,464
----------- -----------
1,130,605 982,949
Less: Accumulated depreciation, depletion and amortization .................... (520,489) (446,367)
----------- -----------
610,116 536,582
Other assets .................................................................. 3,582 3,369
----------- -----------
TOTAL ASSETS ........................................................ $ 678,483 $ 569,452
=========== ===========
LIABILITIES:
Accounts payable and accrued expenses ......................................... $ 56,004 $ 32,743
Subordinated note-- Affiliate ................................................. 80,000 --
----------- -----------
Total current liabilities ........................................... 136,004 32,743
Long-term debt and notes ...................................................... 281,000 233,000
Subordinated note-- Affiliate ................................................. -- 80,000
Deferred federal income taxes ................................................. 43,736 31,027
Other deferred liabilities .................................................... 153 152
----------- -----------
TOTAL LIABILITIES ................................................... 460,893 376,922
COMMITMENTS AND CONTINGENCIES (SEE NOTE 10)
STOCKHOLDERS' EQUITY:
Common Stock, $.01 par value, 50,000 shares authorized and 23,923 shares issued
and outstanding at December 31, 1999 and 23,897 shares issued and outstanding
at December 31,
1998 ........................................................................ 239 239
Additional paid-in capital .................................................... 231,370 230,931
Retained earnings (deficit) ................................................... (14,019) (38,640)
----------- -----------
TOTAL STOCKHOLDERS' EQUITY .......................................... 217,590 192,530
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY .......................... $ 678,483 $ 569,452
=========== ===========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
F-3
<PAGE> 44
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------
1999 1998 1997
--------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
REVENUES:
Natural gas and oil revenues ................................. $ 150,580 $ 127,124 $ 116,349
Other ........................................................ 1,147 1,123 1,297
--------- --------- ---------
Total revenues ....................................... 151,727 128,247 117,646
OPERATING COSTS AND EXPENSES:
Lease operating .............................................. 18,406 16,199 14,146
Severance tax ................................................ 5,444 4,967 4,233
Depreciation, depletion and amortization ..................... 74,051 79,838 59,081
Writedown in carrying value of natural gas and oil properties -- 130,000 --
General and administrative, net .............................. 4,150 6,086 5,825
--------- --------- ---------
Total operating expenses ............................. 102,051 237,090 83,285
Income(loss) from operations ................................... 49,676 (108,843) 34,361
Interest expense, net .......................................... 13,307 4,597 938
--------- --------- ---------
Income(loss) before income taxes ............................... 36,369 (113,440) 33,423
Provision(benefit) for federal income taxes .................... 11,748 (40,754) 10,173
--------- --------- ---------
NET INCOME(LOSS) ............................................... $ 24,621 $ (72,686) $ 23,250
========= ========= =========
Net income(loss) per share ..................................... $ 1.03 $ (3.05) $ 1.00
========= ========= =========
Net income(loss) per share-- assuming dilution ................. $ 0.95 $ (3.05) $ 0.97
========= ========= =========
Weighted average shares outstanding ............................ 23,906 23,768 23,337
Weighted average shares outstanding-- assuming dilution ........ 28,310 23,768 24,028
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements
F-4
<PAGE> 45
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
ADDITIONAL RETAINED TOTAL
COMMON PAID IN EARNINGS STOCKHOLDERS'
STOCK CAPITAL (DEFICIT) EQUITY
--------- --------- --------- ---------
(IN THOUSANDS, EXCEPT SHARE PRICE)
<S> <C> <C> <C> <C>
Balance January 1, 1997 .............. $ 233 $ 222,271 $ 10,796 $ 233,300
Other(1) ............................. -- (660) -- (660)
Common stock, net of issue costs(2) .. 1 296 -- 297
Net income ........................... -- -- 23,250 23,250
--------- --------- --------- ---------
Balance January 1, 1998 .............. $ 234 $ 221,907 $ 34,046 $ 256,187
Common stock, net of issue costs(2)(3) 5 9,024 -- 9,029
Net loss ............................. -- -- (72,686) (72,686)
--------- --------- --------- ---------
Balance January 1, 1999 .............. $ 239 $ 230,931 $ (38,640) $ 192,530
Common stock, net of issue costs(2) .. -- 439 -- 439
Net income ........................... -- -- 24,621 24,621
--------- --------- --------- ---------
Balance at December 31, 1999 ......... $ 239 $ 231,370 $ (14,019) $ 217,590
========= ========= ========= =========
</TABLE>
- ---------------------------
(1) Non-cash charge relating to the February 1996 reorganization of KeySpan's
natural gas and oil assets.
(2) Common stock issued through the exercise of stock options. See Note 4--
Stock Option Plans.
(3) Includes 520,777 shares issued in March 1998 to Smith Offshore Exploration
Company ("Soxco") in connection with the Company's acquisition of the
natural gas and oil assets of Soxco. See Note 3-- Stockholders' Equity.
The accompanying notes are an integral part of these
consolidated financial statements.
F-5
<PAGE> 46
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------
1999 1998 1997
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net income(loss) ..................................................... $ 24,621 $ (72,686) $ 23,250
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and amortization ........................... 74,051 79,838 59,081
Writedown in carrying value of natural gas and oil properties ...... -- 130,000 --
Deferred income tax expense(benefit) ............................... 12,709 (39,714) 13,601
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable ........................ (24,045) 16,014 (3,356)
(Increase) decrease in inventories ................................ (54) 350 (273)
(Increase) decrease in prepayments and other ...................... (328) (109) 279
(Increase) decrease in other assets and liabilities ............... (143) (1,626) (62)
Increase (decrease) in accounts payable and accrued expenses ...... 23,261 (9,689) 4,772
--------- --------- ---------
Net cash provided by operating activities ............................ 110,072 102,378 97,292
INVESTING ACTIVITIES:
Investment in property and equipment ................................. (147,943) (302,685) (145,055)
Dispositions and other ............................................... 289 -- 1,360
--------- --------- ---------
Net cash used in investing activities ................................ (147,654) (302,685) (143,695)
FINANCING ACTIVITIES:
Proceeds from long-term borrowings ................................... 64,000 312,000 79,000
Repayments of long-term borrowings ................................... (16,000) (112,000) (31,000)
Proceeds from issuance of common stock, net of costs ................. 439 207 297
--------- --------- ---------
Net cash provided by financing activities ............................ 48,439 200,207 48,297
Increase (decrease) in cash and cash equivalents ..................... 10,857 (100) 1,894
Cash and cash equivalents, beginning of year ......................... 4,645 4,745 2,851
--------- --------- ---------
Cash and cash equivalents, end of year ............................... $ 15,502 $ 4,645 $ 4,745
========= ========= =========
Cash paid for interest ............................................... $ 23,970 $ 9,452 $ 6,001
========= ========= =========
Cash paid for taxes .................................................. $ -- $ -- $ --
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
F-6
<PAGE> 47
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Organization
Houston Exploration 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 operations are currently
focused offshore in the Gulf of Mexico and onshore in South Texas, South
Louisiana, the Arkoma Basin, East Texas and West Virginia. Houston Exploration's
strategy is to utilize its geological and geophysical expertise to grow its
reserve base through a combination of exploratory drilling in the Gulf of Mexico
and lower risk, exploitation and development drilling onshore. At December 31,
1999, the Company had net proved reserves of 541 Bcfe, 97% of which were natural
gas and 75% of which were classified as proved developed.
Houston Exploration began exploring for natural gas and oil in December
1985 on behalf of The Brooklyn Union Gas Company ("Brooklyn Union") and in
September 1996 the Company completed an initial public offering ("IPO") of its
common stock. Brooklyn Union became an indirect wholly-owned subsidiary of
KeySpan Corporation ("KeySpan") in May 1998 through the combination of Brooklyn
Union's parent company KeySpan Energy Corporation and Long Island Lighting
Company. As of December 31, 1999, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 64% of the outstanding shares of
Houston Exploration's common stock. KeySpan is a diversified energy provider
that (i) distributes natural gas to a customer base of 1.6 million New Yorkers
in Brooklyn, Long Island, Queens and Staten Island; (ii) is contracted by Long
Island Power Authority to manage electricity service to about 1 million
customers 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 of prior years have been made to conform with current year
presentation.
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, as adjusted, by the sum of the weighted
average number of shares of common stock outstanding plus all potentially
dilutive securities.
F-7
<PAGE> 48
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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,
-----------------------------------
1999 1998 1997
-------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
Net income (loss) ..................................................... $ 24,621 $(72,686) $ 23,250
Interest savings on convertible debt ................................ 2,398 -- --
-------- -------- --------
Net income (loss), as adjusted ........................................ $ 27,019 $(72,686) 23,250
======== ======== ========
Weighted average shares outstanding ................................... 23,906 23,768 23,337
Add dilutive securities:
Options ............................................................. 206 -- 153
Convertible debt .................................................... 4,198 -- --
Contingent shares ................................................... -- -- 538
-------- -------- --------
Total weighted average shares outstanding and dilutive securities ..... 28,310 23,768 24,028
======== ======== ========
Net income (loss) per share ........................................... $ 1.03 $ (3.05) $ 1.00
Net income (loss) per share-- assuming dilution ....................... $ 0.95 $ (3.05) $ 0.97
</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, 1999 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
F-8
<PAGE> 49
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
restorations, net of related accumulated depreciation, depletion and
amortization and related deferred income taxes, exceed the full cost ceiling.
At December 31, 1999, the Company estimated, using a wellhead price of
$2.01 per Mcf, that a $99.2 million (after tax) full cost ceiling "cushion"
existed whereby the carrying value of the full cost pool was less than the
ceiling limitation imposed under full cost accounting.
As of December 31, 1998, the Company estimated, using a December 1998
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 estimated, 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.
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 $5.7 million, $1.1
million and $0.9 million for the years ended December 31, 1999, 1998 and 1997,
respectively, were allocated as reductions to general and administrative
expenses. Included in reimbursements received during 1999 is $4.8 million in
general and administrative reimbursements received from KeySpan pursuant to the
KeySpan Joint Exploration Agreement ("KeySpan Joint Venture"), see Note 6 --
Related Party Transactions. The capitalized general and administrative costs
directly related to the Company's acquisition, exploration and development
activities, during 1999, 1998 and 1997, aggregated $5.5 million, $7.5 million
and $7.2 million, respectively.
F-9
<PAGE> 50
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 1999, 1998 and 1997
interest costs of $11.9 million, $9.8 million and $5.9 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, 1999 and
1998.
Financial Instruments
The estimated fair value of financial instruments is the amount at
which the instrument could be exchanged currently between willing parties. 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 and available market information is used to estimated fair values.
In the consolidated balance sheet, the Company reports cash and cash
equivalents, accounts receivable and accounts payable 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 SFAS No. 80, "Accounting for Futures
Contracts". 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 the
underlying hedged transaction. If hedging instruments cease to meet the criteria
for deferral accounting, any subsequent gains or losses would be currently
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 currently recognized in the financial statements.
Natural gas revenues were decreased by $2.6 million in 1999, increased by $3.8
million in 1998 and decreased by $9.9 million during 1997, relative to these
contracts. See Note 8 -- Hedging Transactions.
From time to time the Company 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. As of December 31,
1999, the Company had no interest rate swaps in place.
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
F-10
<PAGE> 51
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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 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,
including certain derivative instruments embedded in other contracts, be
recorded in 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. In June 1999, the FASB issued SFAS
No. 137, which extends the adoption requirement of SFAS No. 133 from January 1,
2000 to January 1, 2001. The Company plans to adopt SFAS No. 133 effective
January 1, 2001. Currently, the Company cannot quantify 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,
1999 1998
-------- --------
(IN THOUSANDS)
<S> <C> <C>
SENIOR DEBT:
Bank revolving credit facility .............. $181,000 $133,000
SUBORDINATED DEBT:
85/8% Senior Subordinated Notes due 2008 .... 100,000 100,000
Subordinated Note-- KeySpan due 2000 ........ -- 80,000
-------- --------
Total long-term debt and notes .......... $281,000 $313,000
======== ========
</TABLE>
As of December 31, 1999, outstanding borrowings of $80 million under
the KeySpan note were classified as current liabilities, as the note matures
March 31, 2000. The carrying amount of borrowings outstanding under the
revolving bank credit facility and the KeySpan note approximate fair value as
interest rates are tied to current market rates. At December 31, 1999, the
quoted market value of the 85/8% senior subordinated notes was 96% of the $100
million carrying value or $96 million.
Credit Facility
The Company has entered into a revolving bank credit facility (the
"Credit Facility") with a syndicate of lenders led by Chase Bank of Texas,
National Association ("Chase"). The Credit Facility, as amended, provides a
maximum commitment of $250 million, subject to borrowing base limitations. At
December 31, 1999, the conforming portion of the borrowing base or threshold
amount was $175 million. The Company has the option to
F-11
<PAGE> 52
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
borrow in excess of the threshold amount up to a borrowing base of $240 million
by paying an incremental interest rate. The borrowing base will remain at $240
million until March 28, 2000. From March 29, 2000 to the next scheduled
redetermination on September 1, 2000, the borrowing base will be equal to the
threshold amount, which the Company anticipates will be redetermined and set at
$210 million. Up to $2.0 million of the borrowing base is available for the
issuance of letters of credit to support performance guarantees. The Credit
Facility matures on March 1, 2003 and is unsecured. At December 31, 1999, $181
million was outstanding under the Credit Facility and $0.4 million was
outstanding in letter of credit obligations. As of March 22, 2000, the Company's
outstanding borrowings and letters of credit under the Credit Facility have
remained unchanged at $181.4 million.
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 0.875% to
1.625%, 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 0.25%
and 0.375% per annum on the unused portion of the Designated Borrowing Base, and
(ii) an unavailable commitment fee equal to 33% of the commitment fee in (i)
above on the difference between the lesser of the Facility Amount or the
Borrowing Base and the Designated Borrowing Base. The weighted average interest
rate was 6.59%, 6.44% and 6.90%, respectively, for the years ended December 31,
1999, 1998 and 1997.
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;
(ii) a total debt to capitalization ratio of less than 60%, exclusive of
non-cash charges; and (iii) sets a maximum limit of 70% on the amount of natural
gas production the Company may hedge during any 12 month period. 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, 1999, the Company was in compliance with all such covenants.
Senior Subordinated Notes
On March 2, 1998, the Company issued $100 million of 85/8% senior
subordinated notes (the "Notes") due January 1, 2008. The Notes bear interest at
a rate of 85/8% per annum with interest payable semi-annually on January 1 and
July 1. 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, at 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 equal
in right of payment to all existing and future subordinated indebtedness
including the KeySpan Facility.
F-12
<PAGE> 53
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 equal in right of payment with the Subordinated Notes. Pursuant to
a subordination agreement among the Company, KeySpan and Chase, the Company may
not repay any outstanding principal under the KeySpan Facility prior to payment
in full of all outstanding principal and interest under the Credit Facility.
Borrowings under the KeySpan Facility are unsecured. On October 27, 1999, the
KeySpan Facility was amended to extend the maturity from January 1, 2000 to
March 31, 2000. Any principal amount that remains outstanding under the KeySpan
Facility on March 31, 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 March
31, 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 accrued under the
KeySpan Facility is payable monthly and borrowings bear interest at LIBOR plus
1.4%. In addition, the Company incurs a quarterly commitment fee of 0.125% on
the unused portion of the maximum commitment and has incurred upfront fees of
$72,000. As of December 31, 1999, outstanding borrowings under the facility were
$80 million, all of which were classified as current liabilities. For the years
ended December 31, 1999 and 1998, the Company incurred a total $5.5 million and
$0.5 million, respectively in interest and fees to KeySpan. Borrowings were used
to finance a portion of the November 1998 acquisition of the Mustang Island A-31
Field from Chevron USA, Inc., see Note 11 -- Acquisitions.
On February 25, 2000, the Company and KeySpan announced their intention
to convert the outstanding borrowings of $80 million under the KeySpan Facility
into shares of common stock of the Company on March 31, 2000. The conversion
price will be calculated by averaging the closing prices of the Company's common
stock on the 20 consecutive trading days ending three trading days prior to
March 31, 2000. The Company estimates that between 4 million and 5 million
shares of its common stock will be issued to KeySpan and that KeySpan's
ownership interest will increase from approximately 64% to approximately 70%.
Once the planned conversion is complete, the KeySpan Facility will terminate and
the Company will have no further borrowing capacity under the KeySpan Facility.
NOTE 3 -- STOCKHOLDERS' EQUITY
Concurrent with the completion of the IPO in September 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 agreed to pay
Soxco, in shares of the Company's common stock, 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 were 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.
F-13
<PAGE> 54
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 4 -- STOCK OPTION PLANS
1996 Stock Option Plan
At the completion of the IPO in September 1996, the Company adopted the
1996 Stock Option 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.
Options granted under the 1996 Stock Option 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 Stock Option 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 non-qualified. As of
December 31, 1999, substantially all options currently authorized under the 1996
Stock Option Plan had been granted, of which 979,330 of the options "ISOs") and
the balance of 1,354,608 are non-qualified stock options ("NQSOs"). Common stock
issued through the exercise of non-qualified 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.
1999 Stock Option Plan
On October 26, 1999, the Company adopted the 1999 Non-Qualified Stock
Option Plan (the "1999 Stock Option Plan"). Under the 1999 Stock Option Plan,
400,000 options were authorized of which 111,800 options were granted during
1999. All options under the 1999 Stock Option Plan are non-qualified, expire 10
years from the grant date and vest in one-fifth increments on each of the first
five anniversaries of the grant date, with the exception of options granted to
non-employee directors which vest on the date of grant.
The table below sets forth a summary of activity during the respective
years for both the 1996 and 1999 Stock Option Plans.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------------------------------------------------
1999 1998 1997
---------------------- ---------------------- ----------------------
SHARES PRICE* SHARES PRICE* SHARES PRICE*
<S> <C> <C> <C> <C> <C> <C>
Options outstanding January 1 ............... 2,083,038 $17.17 1,669,598 $16.67 1,239,638 $15.53
Granted ................................... 321,300 18.87 426,700 19.07 458,100 19.69
Exercised ................................. (28,080) 15.56 (13,260) 15.70 (28,140) 15.50
Forfeited ................................. (5,700) 18.56 -- --
---------- --------- ---------
Options outstanding December 31 ............. 2,370,558 $17.41 2,083,038 $17.17 1,669,598 $16.67
========== ========= =========
Exercisable December 31 ..................... 1,001,343 $16.87 599,275 $16.58 268,788 $16.49
Options available for grant ................. 293,238 208,838 635,538
Weighted average fair value of options
granted ..................................... $ 8.45 $ 8.54 $ 8.71
</TABLE>
- ------------------
* Weighted average price.
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 1999, 1998 and 1997, the Company
made payments of $0.6 million, $0.6 million and $0.8 million, respectively for
the vested portion of PSRs. As of December 31, 1999, 66,635 PSRs remain
outstanding.
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
F-14
<PAGE> 55
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
tied to the market price of the Common Stock on the date services are performed.
Phantom stock rights are exchanged for a cash distribution upon retirement.
Fair Value of Employee Stock-Based Compensation
The Company accounts for the incentive stock plans using the intrinsic
value method prescribed under Accounting Principles Board ("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, 1999, 1998 and 1997:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------
1999 1998 1997
------- -------- -------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
Net income (loss) - as reported ................................. $24,621 $(72,686) $23,250
Net income (loss) - pro forma ................................... 21,915 (74,985) 21,499
Net income (loss) per share - as reported ....................... $ 1.03 $ (3.05) $ 1.00
Net income (loss) per share - assuming dilution--as reported .... 0.95 (3.05) 0.97
Net income (loss) per share - pro forma ......................... $ 0.92 $ (3.15) $ 0.92
Net income (loss) per share - assuming dilution-- pro forma ..... 0.77 (3.15) 0.89
</TABLE>
The effects of applying SFAS No. 123 in this pro forma disclosure are
not indicative of future amounts. SFAS No. 123 does not apply to awards prior to
1995. The fair value of each option grant was estimated on the date of grant
using the Black-Scholes option pricing model with the following assumptions used
for grants in 1999, 1998 and 1997: (i) average risk-free interest rate of 5.96%,
5.97%, and 6.30%, 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:
F-15
<PAGE> 56
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------
1999 1998 1997
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Current ................. $ (961) $ (1,040) $ (3,428)
Deferred ................ 12,709 (39,714) 13,601
-------- -------- --------
Total ......... $ 11,748 $(40,754) $ 10,173
======== ======== ========
</TABLE>
The credit in the current provision represents Section 29 tax credits
(see Note 6 -- Related Party Transactions). As of December 31, 1999, the Company
had net operating loss ("NOL") carryforwards for federal income tax purposes of
approximately $43 million that may be used in future years to offset taxable
income.
The following is a reconciliation of statutory federal income tax
expense (benefit) to the Company's income tax provision:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------
1999 1998 1997
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Income (loss) before income taxes .......................... $ 36,369 $(113,440) $ 33,423
Statutory rate ............................................. 35% 35% 35%
Income tax expense (benefit) computed at statutory rate .... 12,729 (39,704) 11,698
Reconciling items:
Section 29 tax credits ................................ (961) (1,040) (1,200)
Percentage depletion .................................. (16) (12) (14)
Other ................................................. (4) 2 (311)
--------- --------- ---------
Tax expense (benefit) ...................................... $ 11,748 $ (40,754) $ 10,173
========= ========= =========
</TABLE>
Deferred Income Taxes
The components of net deferred tax liabilities pursuant to SFAS No. 109
for the years ended December 31, 1999 and 1998 primarily represent temporary
differences related to depreciation of natural gas and oil properties.
NOTE 6 -- RELATED PARTY TRANSACTIONS
Review of Strategic Alternatives
In September 1999, the Company and KeySpan, the Company's majority
stockholder, announced their intention to review strategic alternatives for
KeySpan's investment in Houston Exploration. KeySpan was assessing the role of
Houston Exploration within its future strategic plan, and was considering a full
range of strategic transactions including the sale of all or a portion of
Houston Exploration. J.P. Morgan Securities Inc. was retained by KeySpan as
financial advisor to assist in the strategic review on behalf of KeySpan. The
Company's Board of Directors appointed a special committee comprised of outside
directors to assist in the review process. The Company and the special committee
retained Goldman, Sachs and Co. as financial advisor.
On February 25, 2000, KeySpan and the Company jointly announced that
the review of strategic alternatives for Houston Exploration was complete and
that KeySpan plans to retain its equity interest in Houston Exploration for the
foreseeable future.
F-16
<PAGE> 57
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
KeySpan Joint Venture
In March 1999, the Company entered into a joint exploration agreement
(the "KeySpan Joint Venture") with KeySpan Exploration & Production, LLC, a
subsidiary of KeySpan, to explore for natural gas and oil over a term of three
years expiring December 31, 2001. Either party may terminate the KeySpan Joint
Venture at the end of the then current calendar quarter by giving thirty days
prior written notice. Houston Exploration is the joint venture manager and
operator. Effective January 1, 1999, KeySpan agreed to commit up to $100 million
per calendar year and Houston Exploration agreed to commit its proportionate
share of the funds per calendar year necessary to fund a joint exploration and
development drilling program. Houston Exploration contributed all of its
undeveloped offshore leases as of January 1, 1999 to the joint venture. 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 pays 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 are paid
51.75% by KeySpan and 48.25% by Houston Exploration. In addition, Houston
Exploration receives reimbursement of a portion of its general and
administrative costs during the term of the joint venture. During the year ended
December 31, 1999, KeySpan incurred approximately $35.6 million in drilling
costs and the Company received approximately $4.8 million in general and
administrative reimbursements pursuant to the KeySpan Joint Venture.
On February 25, 2000, the Company and KeySpan agreed to amend the joint
exploration agreement. The amendment will be effective January 1, 2000 and will
provide a commitment by KeySpan for the year 2000 of approximately $30 million
and a reduction to the amount the Company will receive during 2000 for general
and administrative expense reimbursements. The $30 million commitment will
include approximately $18 million for exploratory drilling, $10 million for
development and the balance for general and administrative reimbursements.
Subordinated KeySpan Facility. (See Note 2 -- Long-Term Debt and Notes
and Note 12 -- Subsequent Events).
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, 1999,
1998 and 1997 was a reduction to income tax expense of approximately $1.0
million, $1.0 million and $1.2 million, respectively, representing benefits
received from the Section 29 tax credits.
Employment Contracts
Prior to the IPO the Company maintained an employment agreement (the
"Initial Employment Agreement") with its President and Chief Executive Officer,
Mr. James G. Floyd, which provided him with the option to participate in up to a
5% working interest in certain prospects of the Company. During 1999, 1998 and
1997,
F-17
<PAGE> 58
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
affiliates of the Company's President paid $2.5 million, $2.7 million and $3.3
million, respectively, in costs and expenses attributable to working interests
owned in properties operated by the Company, and received $4.7 million, $4.7
million and $3.9 million, respectively, in distributions attributable to such
working interests.
The Initial Employment Agreement also provided for the assignment to
the Company's 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 Company's 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 Initial Employment
Agreement was terminated and replaced with a new employment agreement, which
does not provide the Company's 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.
Pursuant to the Initial Employment Agreement, the Company's President
and his affiliates opted to acquire a 5% working interest in the Charco Field
properties acquired by the Company in July 1996 and the right to participate
with a 5% working interest in any future wells drilled by the Company in the
Charco Field. The Company loaned its President the $3.1 million purchase price
for his purchase of a 5% working interest in the Charco Field properties
acquired by the Company. In addition, the Company agreed to loan its President,
on a revolving basis, the amounts required to fund the expenses attributable to
his working interest. The Company's President is required to repay amounts owed
under the loan in the amount of 65% of all distributions received in respect to
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. Obligations under the agreement are secured
by a pledge of the President's working interest in, and the production from,
such properties. As of December 31, 1999 and 1998, the outstanding balance owed
by the Company's President under the loan agreement was $2.8 million and $3.5
million, respectively. The loan will mature on July 2, 2006.
In January 2000, the Company and Mr. Floyd agreed to exchange all of
the working interests and net profits interests Mr. Floyd had acquired in
properties of the Company pursuant to the Initial Employment Agreement for an
overriding royalty interest in those same properties. The exchange, which will
be effective October 1, 1999, will be structured such that the net present value
to be earned by the Company and Mr. Floyd would be approximately the same
regardless of the nature of Mr. Floyd's participation in the earning from such
properties. As of October 1, 1999, the net present value, discounted at 10%, of
the properties to be exchanged was approximately $13.5 million. Mr. Floyd will
continue to paydown outstanding borrowings on his loan with the Company from
monthly proceeds received from his overriding royalty interests in the Charco
Field. The loan will be secured by Mr. Floyd's overriding royalty interests in
the Charco Field properties.
F-18
<PAGE> 59
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
$1.00 for each $1.00 of employee deferral, subject to limitations imposed by the
401(k) Plan and the Internal Revenue Service. The amounts contributed under the
401(k) Plan are held in a trust and invested among various investment funds in
accordance with the directions of each participant. An employee's salary
deferral contributions under the 401(k) Plan are 100% vested. The Company's
matching contributions vest at the rate of 20% per year of service. Participants
are entitled to payment of their vested account balances upon termination of
employment. The Company made contributions to the 401(k) Plan of $0.2 million in
each of the three years ended December 31, 1999, 1998 and 1997.
Supplemental Executive Plan
The Company maintains an unfunded, non-qualified Supplemental Executive
Retirement Plan (the "SERP"). Currently, the only beneficiary is 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, 1999, 1998 and
1997 related to the SERP.
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. As of
December 31, 1999, the Company had no interest rate swaps in place. 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, the estimated fair
value of the interest rate swap agreements was $0.4 million, in a payable
position.
F-19
<PAGE> 60
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Natural Gas Price Swaps, Options and Collars
As of December 31, 1999, the Company had entered into commodity price
hedging contracts with respect to its production for 2000 as follows:
<TABLE>
<CAPTION>
FIXED PRICE SWAPS COLLARS FAIR VALUE
---------------------- ---------------------------------- ------------
NYMEX NYMEX
VOLUME CONTRACT VOLUME CONTRACT PRICE
PERIOD (MMMBTU) PRICE (MMMBTU) FLOOR CEILING ($ THOUSANDS)
- ------------------ -------- -------- -------- -------- -------- -------------
<S> <C> <C> <C> <C> <C> <C>
January 2000 -- -- 1,860 $ 2.55 $ 3.65 $ 394
February 2000 -- -- 1,740 $ 2.45 $ 3.43 $ 325
March 2000 -- -- 1,860 $ 2.35 $ 3.11 $ 313
April 2000 -- -- 900 $ 2.20 $ 2.70 $ 57
May 2000 -- -- 930 $ 2.20 $ 2.70 $ 57
June 2000 -- -- 900 $ 2.20 $ 2.70 $ 50
July 2000 -- -- 930 $ 2.20 $ 2.70 $ 42
August 2000 -- -- 930 $ 2.20 $ 2.70 $ 31
September 2000 -- -- 900 $ 2.20 $ 2.70 $ 20
</TABLE>
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 FAIR VALUE
---------------------- ---------------------------------- ------------
NYMEX NYMEX
VOLUME CONTRACT VOLUME CONTRACT PRICE
PERIOD (MMMBTU) PRICE (MMMBTU) FLOOR CEILING ($ THOUSANDS)
- ------------------ -------- -------- -------- -------- -------- -------------
<S> <C> <C> <C> <C> <C> <C>
January 1999 755 $ 2.50 -- -- -- $ 534
February 1999 355 -- 280 $ 2.40 $ 2.90 $ 126
</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 or the NYMEX price on
the final trading day of the month (the "settlement price"). With respect to any
particular swap transaction, the counterparty is required to make a payment to
the Company in the event that the settlement price for any settlement period is
less than the swap price for such transaction, and the Company is required to
make payment to the counterparty in the event that the settlement price for any
settlement period is greater than the swap price for such transaction. For any
particular collar transaction, the counterparty is required to make a payment to
the Company if the settlement price for any settlement period is below the floor
price for such transaction, and the Company is required to make payment to the
counterparty if the settlement price for any settlement period is above the
ceiling price for such transaction. The Company is not required to make or
receive any payment in connection with a collar transaction if the settlement
price is between the floor and the ceiling. Fair market value is calculated for
the respective months using prices derived from NYMEX futures contract prices
existing at December 31, 1999 and 1998.
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
F-20
<PAGE> 61
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 1999 to
Adams Resources and Energy, Inc. (successor to H&N Gas Ltd.) (22.5%); for the
year ended December 31, 1998 to H&N Gas Ltd. (27%) and Columbia Energy Services
Corporation (12%); and for the year ended December 31, 1997 to H&N Gas Ltd.
(38%). 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.
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 2003. Minimum rental commitments under the terms of the leases are as
follows (in thousands):
<TABLE>
<CAPTION>
Year ended December 31,
<S> <C>
2000................................................... $ 392
2001................................................... 392
2002................................................... 460
2003................................................... 554
2004................................................... 323
Thereafter............................................. --
</TABLE>
Net rental expense related to these leases was $0.3 million for each of
the years ended December 31, 1999, 1998 and 1997.
NOTE 11 -- ACQUISITIONS
West Cameron 587 Acquisition
On November 1, 1999, the Company completed the acquisition of a 64%
working interest in the West Cameron 587 Field (the "West Cameron 587
Acquisition") for $21 million in cash. The acquisition was financed by
borrowings under the Credit Facility and represents interests in two undeveloped
wells. Net proved undeveloped reserves for the natural gas and oil interests
acquired are estimated at 21 Bcfe as of December 31, 1999.
F-21
<PAGE> 62
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. At the
time of acquisition, the field had 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 KeySpan Facility.
South Louisiana Acquisition
In April 1998, the Company completed the first phase of its 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 at the time of acquisition contained 57
producing wells. The net purchase price of $53.2 million was paid in cash,
financed with borrowings under the Company's Credit Facility. In October and
November 1999, the Company completed the second phase of its South Louisiana
Acquisition by purchasing 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%.
NOTE 12 -- SUBSEQUENT EVENTS
Review of Strategic Alternatives
In September 1999, the Company and KeySpan, the Company's majority
stockholder, announced their intention to review strategic alternatives for
KeySpan's investment in Houston Exploration. A full range of strategic
transactions was considered including the sale of all or a portion of Houston
Exploration. On February 25, 2000, the Company and KeySpan jointly announced
that the strategic review process was complete and that KeySpan plans to retain
its equity interest in Houston Exploration for the foreseeable future.
KeySpan Facility
On February 25, 2000, KeySpan announced its intention to convert the
outstanding borrowings of $80 million under the KeySpan Facility into shares of
common stock of the Company on March 31, 2000. The conversion price will be
calculated by averaging the closing prices of the Company's common stock on the
20 consecutive trading days ending three trading days prior to March 31, 2000.
The Company estimates that between 4 million and 5 million shares of its common
stock will be issued to KeySpan and that KeySpan's ownership interest will
increase from approximately 64% to approximately 70%. Once the planned
conversion is complete, the KeySpan Facility will terminate and the Company will
have no further borrowing capacity under the KeySpan Facility.
KeySpan Joint Venture
On February 25, 2000, the Company and KeySpan agreed to amend the
KeySpan Joint Venture. The amendment will be effective January 1, 2000 and will
provide a commitment by KeySpan for the year 2000 of approximately $30 million
and a reduction to the amount the Company will receive during 2000 for general
and administrative expense reimbursements. The $30 million commitment will
include approximately $18 million for exploratory drilling, $10 million for
development and the balance for general and administrative reimbursements.
F-22
<PAGE> 63
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Credit Facility
Chase has completed its semi annual borrowing base redetermination for
the Credit Facility and has recommended to the syndicate of lenders that the
borrowing base be set at $210 million, effective March 29, 2000. The Company
anticipates that the borrowing base will be set at $210 million. The new
borrowing base will be equal to the Company's borrowing threshold amount which
will be in effect from March 29, 2000 until the next scheduled redetermination
on September 1, 2000. As of March 22, 2000, outstanding borrowings and letters
of credit under the revolving bank credit facility have remained unchanged at
$181.4 million.
NOTE 13-- SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
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, 1999, 1998 and 1997, the Company's capitalized costs
of natural gas and oil properties are as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------------
1999 1998 1997
------------ ----------- ------------
(IN THOUSANDS)
<S> <C> <C> <C>
Unevaluated properties, not amortized.......................... $ 164,377 $ 145,317 $ 104,075
Properties subject to amortization............................. 956,484 828,168 566,868
------------ ----------- ------------
Capitalized costs.............................................. 1,120,861 973,485 670,943
Accumulated depreciation, depletion and amortization........... (512,465) (438,974) (229,776)
------------ ----------- ------------
Net capitalized costs................................ $ 608,396 $ 534,511 $ 441,167
============ =========== ============
</TABLE>
The following is a summary of the costs (in thousands) which are
excluded from the amortization calculation as of December 31, 1999, 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, 1999 will be fully evaluated within five
years.
<TABLE>
<S> <C>
1999................................. $ 29,894
1998................................. 66,148
1997................................. 30,691
Prior................................ 37,644
--------
$164,377
</TABLE>
F-23
<PAGE> 64
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Costs incurred for natural gas and oil exploration, development and
acquisition are summarized below. Costs incurred during the years ended December
31, 1999, 1998 and 1997 include interest expense and general and administrative
costs related to acquisition, exploration and development of natural gas and oil
properties, of $17.4 million, $17.3 million and $13.1 million, respectively.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------------
1999 1998 1997
----------- ------------ -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition:
Unevaluated(1)............................................... $ 10,337 $ 33,803 $ 16,613
Proved....................................................... 37,105 162,083 24,007
Exploration costs.............................................. 12,257 55,611 44,119
Development costs.............................................. 87,965 51,046 59,244
----------- ------------ -----------
Total costs incurred................................. $ 147,664 $ 302,543 $ 143,983
=========== ============ ===========
</TABLE>
- ---------------------------
(1) These amounts represent costs incurred by the Company and excluded from
the amortization base until proved reserves are established or
impairment is determined.
Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Natural Gas and Oil Reserves (unaudited)
The following summarizes the policies used by the Company in the
preparation of the accompanying natural gas and oil reserve disclosures,
standardized measures of discounted future net cash flows from proved natural
gas and oil reserves and the reconciliations of such standardized measures from
year to year. The information disclosed, as prescribed by the Statement of
Financial Accounting Standards No. 69 is an attempt to present such information
in a manner comparable with industry peers.
The information is based on estimates of proved reserves attributable
to the Company's interest in natural gas and oil properties as of December 31 of
the years presented. These estimates were principally prepared by independent
petroleum consultants. Proved reserves are estimated quantities of natural gas
and crude oil which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
The standardized measure of discounted future net cash flows from
production of proved reserves was developed as follows:
1. Estimates are made of quantities of proved reserves and
future periods during which they are expected to be produced based on
year-end economic conditions.
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.
F-24
<PAGE> 65
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. Future income tax expenses are based on year-end statutory
tax rates giving effect to the remaining tax basis in the natural gas
and oil properties, other deductions, credits and allowances relating
to the Company's proved natural gas and oil reserves.
5. Future net cash flows are discounted to present value by
applying a discount rate of 10 percent.
The standardized measure of discounted future net cash flows does not
purport, nor should it be interpreted, to present the fair value of the
Company's natural gas and oil reserves. An estimate of fair value would also
take into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs and a
discount factor more representative of the time value of money and the risks
inherent in reserve estimates.
The standardized measure of discounted future net cash flows relating
to proved natural gas and oil reserves is as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-----------------------------------------
1999 1998 1997
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows ......................... $ 1,113,844 $ 878,448 $ 781,336
Future production costs ..................... (190,900) (153,567) (135,437)
Future development costs .................... (120,071) (103,915) (84,658)
Future income taxes ......................... (155,641) (89,032) (124,510)
----------- ----------- -----------
Future net cash flows ....................... 647,232 531,934 436,731
10% annual discount for estimated timing of
cash flows .................................. (178,007) (135,874) (121,351)
----------- ----------- -----------
Standardized measure of discounted future net
cash flows ................................ $ 469,225 $ 396,060 $ 315,380
=========== =========== ===========
</TABLE>
Discounted future cash inflows include the effect of hedges in place at
year end December 31, 1999, 1998 and 1997. At December 31, 1999 and 1998 the
effect of the hedges in place is an increase of $1.3 million and $0.4 million,
respectively to future cash inflows. As of December 31, 1997, the effect of the
hedges in place is a reduction to future cash inflows of $0.5 million.
F-25
<PAGE> 66
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes changes in the standardized measure of
discounted future net cash flows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-----------------------------------
1999 1998 1997
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Beginning of the year ...................................... $ 396,060 $ 315,380 $ 452,582
Revisions to previous estimates:
Changes in prices and costs .............................. 47,330 (104,137) (223,169)
Changes in quantities .................................... 51,375 (4,982) (23,156)
Changes in future development costs ...................... (25,730) (6,656) (20,499)
Development costs incurred during the period ............... 40,563 15,891 16,154
Extensions and discoveries, net of related costs ........... 91,383 72,333 114,893
Sales of natural gas and oil, net of production costs ...... (126,730) (105,958) (97,968)
Accretion of discount ...................................... 41,293 37,706 57,700
Net change in income taxes ................................. (43,572) 44,812 62,733
Purchase of reserves in place .............................. 20,973 156,122 2,463
Sale of reserves in place .................................. (2,194) (863) (608)
Production timing and other ................................ (21,526) (23,588) (25,745)
--------- --------- ---------
End of year ................................................ $ 469,225 $ 396,060 $ 315,380
========= ========= =========
</TABLE>
F-26
<PAGE> 67
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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,
1999, 1998 and 1997.
<TABLE>
<CAPTION>
NATURAL GAS CRUDE OIL AND CONDENSATE
(MMCF) (MBBLS)
-------------------------------- --------------------------------
1999 1998 1997 1999 1998 1997
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Proved developed and
undeveloped reserves: ............... 470,447 330,601 320,474 1,650 1,077 1,131
Revisions of previous estimates ........ 45,510 (4,656) (18,743) 237 (105) (62)
Extensions and discoveries ............. 62,700 67,272 75,651 909 249 184
Production ............................. (69,679) (61,479) (50,310) (258) (225) (171)
Purchase of reserves in place .......... 20,699 139,994 3,778 1 665 1
Sales of reserves in place ............. (3,492) (1,285) (249) (69) (11) (6)
-------- -------- -------- -------- -------- --------
End of year ............................ 526,185 470,447 330,601 2,470 1,650 1,077
======== ======== ======== ======== ======== ========
Proved developed reserves:
Beginning of year ...................... 369,931 256,632 236,544 1,498 914 1,013
End of year ............................ 397,343 369,931 256,632 1,796 1,498 914
</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>
1999
Total revenues ........................................ $ 26,865 $ 35,137 $ 42,477 $ 47,248
Income from operations ................................ 3,817 10,725 16,194 18,940
Net income ............................................ 746 5,189 8,528 10,158
Net income per share .................................. $ 0.03 $ 0.22 $ 0.36 $ 0.42
Net income per share-- assuming dilution .............. $ 0.03 $ 0.21 $ 0.32 $ 0.38
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) from operations(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-- assuming dilution ....... $ 0.20 $ 0.22 $ 0.08 $ (3.55)
</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-27
<PAGE> 68
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).
10.1(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).
10.2(2) -- 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(2) -- 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).
10.4(2) -- 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).
10.5 -- 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).
10.6 -- 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).
10.7(2) -- 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).
10.8(2) -- 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).
10.9(2) -- 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).
10.10(2) -- 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).
10.11(2) -- 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).
10.12 -- 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)).
10.13(2) -- 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).
</TABLE>
<PAGE> 69
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBITS DESCRIPTION
- -------- -----------
<S> <C>
10.14(2) -- 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).
10.15 -- Subordinated Loan Agreement dated November 30, 1998 between The Houston Exploration
Company and MarketSpan Corporation d/b/a KeySpan Energy Corporation (filed as Exhibit
10.30 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998
and incorporated by reference herein).
10.16 -- 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 (filed as Exhibit 10.31 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1998 (File No. 001-11899) and
incorporated by reference herein).
10.17(1) -- First Amendment to Subordinated Loan Agreement and
Promissory Note between KeySpan Corporation and The Houston
Exploration Company dated effective as of October 27, 1999.
10.18 -- Exploration Agreement between The Houston Exploration Company and KeySpan
Exploration and Production, L.L.C., dated March 15,1999, (filed as Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1999 (File No.
001-11899) and incorporated by reference herein).
10.19(1) -- First Amendment to the Exploration Agreement between The Houston Exploration Company
and KeySpan Exploration and Production, L.L.C. dated November 3, 1999.
10.20 -- Amended and Restated Credit Agreement among The Houston Exploration Company and
Chase Bank of Texas, National Association, as agent, dated March 30,1999, (filed as Exhibit
10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1999
(File No. 001-11899) and incorporated by reference herein).
10.21 -- First Amendment and Supplement to Amended and Restated Credit Agreement dated May 4,
1999 by and among The Houston Exploration Company and Chase Bank of Texas, National
Association, as agent, (filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-
Q for the quarter ended June 30, 1999 (File No. 001-11899) and incorporated by reference
herein).
10.22 -- Second Amendment to Amended and Restated Credit Agreement between The Houston
Exploration Company and Chase Bank of Texas, National Association, as agent, dated
October 6, 1999, (filed as Exhibit 10.32 to the Company's Quarterly Report on Form 10-Q
for the quarter ended September 30, 1999 (File No. 001-11899) and incorporated by reference
herein).
10.23(1) -- Third Amendment and Supplement to Amended and Restated
Credit Agreement between The Houston Exploration Company and
Chase Bank of Texas, National Association, as agent, dated
December 9, 1999.
10.24(1)(2) -- 1999 Non-Qualified Stock Option Plan dated October 26, 1999.
10.25(1)(2) -- Change of Control Plan dated October 26, 1999.
12.1(1) -- Computation of ratio of earnings to fixed charges.
21.1(1) -- Subsidiaries of the Company.
23.1(1) -- Consent of Arthur Andersen LLP.
23.2(1) -- Consent of Netherland, Sewell & Associates.
23.3(1) -- Consent of Miller and Lents.
27.1(1) -- Financial Data Schedule.
</TABLE>
- ---------------------------
(1) Filed herewith.
(2) Management contract or compensation plan.
<PAGE> 1
EXHIBIT 10.17
FIRST AMENDMENT TO
SUBORDINATED LOAN AGREEMENT
AND PROMISSORY NOTE
THIS FIRST AMENDMENT TO SUBORDINATED LOAN AGREEMENT AND
PROMISSORY NOTE (this "First Amendment") dated effective as of October 27, 1999
is entered into by and between HOUSTON EXPLORATION COMPANY, a Delaware
corporation (the "Company"), and KEYSPAN CORPORATION d/b/a KeySpan Energy (as
successor to MarketSpan Corporation d/b/a KeySpan Energy) (the "Lender").
PRELIMINARY STATEMENT
The Lender and the Company are parties to that certain
Subordinated Loan Agreement dated as of November 30, 1998 (as same may be
further amended, restated and extended herein, the "Credit Agreement") under
and subject to the terms of which the Lender has committed to make Advances
through January 1, 2000, not to exceed $150,000,000.00 in aggregate amount
outstanding, and that certain Promissory Note dated November 30, 1998 executed
by the Company to the order of Lender (the "Note").
The Company and the Lender desire to amend the Credit
Agreement for the sole purpose of extending the maturity date.
NOW THEREFORE, in consideration of the premises and the
mutual agreements, representations and warranties herein set forth and for
other good and valuable consideration, the Company and the Lender hereby agree
as follows:
SECTION 1. Definitions. Unless otherwise defined in this
First Amendment, each capitalized term used in this First Amendment has the
meaning assigned to such term in the Credit Agreement.
SECTION 2. Amendments to the Credit Agreement. (a) The Credit
Agreement and the Note are hereby amended such that all references to "Maturity
Date" or "Termination Date," and all references to "January 1, 2000" within the
definitions of Maturity Date and Termination Date, whether in the Credit
Agreement, the schedules thereto or in the Note, shall mean and be a reference
to the date of March 31, 2000.
(b) Specifically, the section of the Credit Agreement on page
one thereof entitled "Maturity Date" and the identical provision under the same
title on page one of Schedule I to the
<PAGE> 2
Credit agreement are hereby amended by deleting same in their entirety and
replacing same with the following:
Maturity Date: All outstanding principal, unpaid accrued
interest and fees will be repaid at Maturity,
March 31, 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
Transaction Reports" in the Wall Street Journal
during the 20 consecutive trading days ending three
trading days prior to March 31, 2000. Because the
market value represents an average of the Company's
common stock over twenty consecutive trading days
ending three trading 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. Notwithstanding
the foregoing, upon any sale, transfer or other
disposition of the stock or substantially all of the
assets of the Company prior to March 31, 2000,
all outstanding principal and unpaid accrued
interest and fees will be paid in cash on the
consummation of such sale, transfer or other
disposition.
(c) The Credit Agreement is hereby amended to reflect the
fact that, as consideration for the extension of the Maturity Date as evidenced
by, and as a condition to the effectiveness of, this First Amendment, the
Company shall pay to the Lender an up-front fee of Twelve Thousand and No/100
Dollars ($12,000.00).
SECTION 3. Ratification. The agreements and obligations of
the Company under the Credit Agreement, the Note and any and all other Loan
Documents, are hereby brought forward, renewed and extended until the
indebtedness evidenced by the Credit Agreement and the Note shall have been
fully paid and discharged. The Credit Agreement and the Note, and all terms
thereof shall remain in full force and effect. The Lender hereby preserves all
of its rights against the Company, and the Company hereby agrees that all such
rights are ratified and brought forward for the benefit of the Lender.
SECTION 4. Representations True; No Default. The Company and
the Lender represent and warrant that this First Amendment has been duly
authorized, executed and delivered on behalf of the Company and the Lender,
respectively, and the Credit Agreement, as amended hereby, constitutes the
valid and legally binding agreement of the Company and the Lender, enforceable
in accordance with its terms, except as enforceability thereof may be limited
by bankruptcy, insolvency, reorganization or moratorium or other similar law
relating to creditors' rights and by general equitable principles which may
limit the right to obtain equitable remedies (regardless of whether such
enforceability is considered in a proceeding, in equity or at law);
-2-
<PAGE> 3
SECTION 5. No Obligation. This First Amendment shall not
create a course of dealing among or between the parties hereto, and no further
obligation of any kind in excess of those expressly set forth herein shall be
inferred from this First Amendment.
SECTION 6. Conditions of Effectiveness. This First Amendment
shall become effective on the date upon which this First Amendment shall have
been duly executed and delivered by the Company and the Lender, together with a
certificate of the Company certifying as to (i) the incumbency of the officer
executing this First Amendment, (ii) the truth of the representations and
warranties in the Credit Agreement, and (iii) the absence of any defaults under
the Credit Agreement.
SECTION 7. Reference to the Agreement. (a) Upon the
effectiveness of this First Amendment, each reference in the Credit Agreement
to "hereunder," "herein," "hereof" or words of like import shall mean and be a
reference to the Agreement, as affected and amended hereby.
(b) Upon effectiveness of this First Amendment, each
reference in the Credit Agreement shall mean and be a reference to the Credit
Agreement, as affected and amended hereby.
SECTION 8. Miscellaneous Provisions. (a) This First Amendment
may be signed in any number of counterparts, each of which shall be deemed an
original, but all of which together shall constitute one and the same
instrument.
(b) The headings herein shall be accorded no significance
in interpreting this First Amendment.
SECTION 9. Governing Law. This First Amendment shall be
governed by and construed in accordance with the laws of the State of New York
and applicable federal law.
SECTION 10. FINAL AGREEMENT OF THE PARTIES. THIS FIRST
AMENDMENT, THE CREDIT AGREEMENT, THE NOTES AND THE OTHER LOAN DOCUMENTS
CONSTITUTE A "LOAN AGREEMENT" AS DEFINED IN SECTION 26.02(A) OF THE TEXAS
BUSINESS AND COMMERCE CODE AND REPRESENT THE FINAL AGREEMENT BETWEEN THE
PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR
SUBSEQUENT AGREEMENTS OF THE PARTIES.
THERE ARE NO ORAL AGREEMENTS BETWEEN THE PARTIES.
[SIGNATURE PAGES FOLLOW]
-3-
<PAGE> 4
IN WITNESS WHEREOF, the parties have caused this First
Amendment to be executed by their respective duly authorized officers to be
effective as of the date first written above.
KEYSPAN CORPORATION,
D/B/A KEYSPAN ENERGY
By: /s/ Robert R. Wieczorek
-----------------------
Name: Robert R. Wieczorek
Title: VP, Secretary and Treasurer
Address: One MetroTech Center
Brooklyn, NY 11201
THE HOUSTON EXPLORATION COMPANY
By: /s/ Thomas W. Powers
--------------------
Thomas W. Powers
Senior Vice President
1100 Louisiana, Suite 2000
Houston, Texas 77002
-4-
<PAGE> 1
EXHIBIT 10.19
FIRST AMENDMENT TO EXPLORATION AGREEMENT
This First Amendment to Exploration Agreement ("Amendment") is made
and entered into this the third day of November 1999, between THE HOUSTON
EXPLORATION COMPANY, a Delaware corporation, of 1100 Louisiana Street, Suite
2000, Houston, Texas 77002 ("THEC") and KEYSPAN EXPLORATION AND PRODUCTION,
L.L.C., a Delaware limited liability company, of One Metro Tech Centre, 18th
Floor, Brooklyn, New York 11201 ("KE&P").
W I T N E S S E T H:
A. THEC and KE&P have entered into that certain Exploration
Agreement dated the 15th day of March 1999 between The Houston Exploration
Company and KeySpan Exploration and Production, L.L.C. ("Exploration
Agreement"); and
B. THEC and KE&P desire to amend the Exploration Agreement as
set forth in this Amendment.
NOW, THEREFORE, for valuable consideration, THEC and KE&P agree as
follows:
I.
Section 1.15 of the Exploration Agreement is amended so that the
existing language becomes Section 1.15(a) and the following is inserted as
Section 1.15(b):
1.15(b) KE&P's Quarterly Commitment. The sum of (a) 25 million dollars
per calendar quarter during the Primary Term plus (b) that portion of prior
quarters' Quarterly Commitments that have not been expended or committed for
expenditure under this Agreement which sum shall be used to pay all costs
attributable to to KE&P under this Agreement, including G and A Costs, during
the relevant quarter.
<PAGE> 2
II.
Section 1.28 of the Agreement is deleted and the following new Section
1.28 is substituted therefor:
1.28 Program Year. Each calendar year (or portion of a calendar year
if the Primary Term ends at the end of any calendar quarter during such year
other than December 31 of such year) during the Primary Term of this Agreement.
A cost under this Agreement for purposes of Payout shall be attributable to the
Program Year in which the first Exploratory Well is spudded on the Lease to
which such cost relates. If an Exploratory Well is not spudded on a Lease
during the Primary Term of this Agreement, the costs relating to such Lease
shall be used in the calculation of Payout for the Program Year in which they
were incurred. Net Proceeds shall be attributable to the Program Year in which
the first Exploratory Well is spudded on the Lease to which such proceeds
relate.
III.
Section 2.1 of the Agreement is deleted and the following new Section
2.1 is substituted therefor:
2.1 Primary Term. This Agreement shall be for a primary term
(the "Primary Term") commencing on January 1, 1999 ("Commencement Date") and
ending on the earliest to occur of the following:
(a) December 31, 2001;
(b) the end of any calendar quarter if either party notifies
the other party in writing on or before thirty (30) days before the end of such
quarter of its election to terminate the Primary Term at the end of such
quarter; or
(c) the mutual agreement of the parties.
2
<PAGE> 3
IV.
Section 5.1 of the Agreement is deleted and the following new Section
5.1 is substituted therefor:
5.1 Allocation of IDCs. Subject to Section 5.4, during each year of
the Primary Term, KE&P shall pay one hundred percent (100%) of all Intangible
Costs attributable to THEC's Original Working Interests in the Leases until
KE&P has paid Intangible Costs for such year totaling 20.725 million dollars
and, thereafter during such year KE&P shall pay fifty one and seventy five one
hundredths percent (51.75%) of all Intangible Costs attributable to THEC's
Original Working Interests in the Leases and THEC shall pay forty eight and
twenty five one hundredths percent (48.25%) of all Intangible Costs
attributable to THEC's Original Working Interest in the Leases. If during any
of such years, one hundred percent (100%) of the Intangible Costs attributable
to THEC's Original Working Interests in the Leases are less than 20.725 million
dollars, the shortage shall be added to the following year and KE&P shall pay
during such following year one hundred percent (100%) of all Intangible Costs
attributable to THEC's Original Working Interests in the Leases until KE&P has
paid Intangible Costs for such year totaling 20.725 million dollars plus the
shortage from the preceding year(s); provided that, during the first calendar
quarter of the 2000 Program Year, KE&P's obligation to pay one hundred percent
(100%) of such Intangible Costs shall be limited to 5.18 million dollars and,
further provided, if the Primary Term ends on March 31, 2000 KE&P's obligation
to pay one hundred percent (100%) of Intangible Costs shall terminate. Subject
to the preceding sentence, during the Secondary Term, KE&P shall pay all
Intangible Costs attributable to THEC's Original Working Interest in the Leases
until such shortage from the Primary Term, if any, is
3
<PAGE> 4
expended and thereafter shall pay fifty one and seventy five one hundredths
percent (51.75%) of all Intangible Costs attributable to THEC's Original
Working Interest in the Leases and THEC shall pay forty eight and twenty five
one hundredths percent (48.25%) of all Intangible Costs attributable to THEC's
Original Working Interest in the Leases; provided that, KE&P shall have no
obligation to pay Intangible Costs to the extent such costs relate to a Lease
reassigned to THEC under Section 6.5 and such costs accrue after such
reassignment.
V.
Section 5.3 of the Agreement is deleted and the following new Section
5.3 is substituted therefor:
5.3 Allocation of Remaining Costs. Subject to Section 5.4 and 5.8,
during the Primary Term and the Secondary Term, KE&P shall pay forty five
percent (45%) of all Drilling Costs, Development Costs, Seismic Costs,
Leasehold Costs, Abandonment Costs and Operating Costs attributable to THEC's
Original Working Interest in the Leases and THEC shall pay fifty five percent
(55%) of all Drilling Costs, Development Costs, Seismic Costs, Leasehold Costs,
Abandonment Costs and Operating Costs attributable to THEC's Original Working
Interest in the Leases; provided that, KE&P shall have no obligation to pay
any of such costs to the extent such costs relate to a Lease reassigned to THEC
under Section 6.5 and such costs accrue after such reassignment.
VI.
Section 5.4 of the Agreement is amended so that the existing language
becomes Section 5.4A and the following is inserted as 5.4B:
4
<PAGE> 5
5.4B Primary Term Commitment. Notwithstanding the foregoing Section
5.4A, for the period commencing January 1, 2000, this Section 5.4B shall apply
prospectively in lieu of Section 5.4A. KE&P's obligation to pay the costs
specified in Sections 5.1 to 5.3 incurred during any quarter of the Primary
Term is limited to KE&P's Quarterly Commitment subject to the following:
(a) If THEC determines that the allocation to KE&P of its share of the
Drilling Costs and Intangible Costs of the first Exploratory Well on a Lease
will result in KE&P's Quarterly Commitment being exceeded, THEC shall notify
KE&P in writing of such fact prior to commencing such Well. Within fifteen (15)
days (or such lesser period specified in the notice if the proposed spud date
of such Well is less than thirty (30) days from the date of such notice) after
receiving such notice, KE&P shall notify THEC in writing whether or not it
approves such Well. If KE&P approves such Well, KE&P's share of the Drilling
Costs and Intangible Costs of such Well shall be deemed "Excess
Costs" and, to the extent the Excess Costs result in KE&P's Quarterly
Commitment being exceeded, such commitment shall be increased accordingly for
such quarter. If KE&P does not approve such Well or fails to notify THEC of its
decision, KE&P shall forfeit its interests in such Well and the Lease on which
it is located.
(b) Except as provided in Section 5.4(a), if KE&P is not obligated to
pay a portion of its share of the costs specified in Sections 5.1 to 5.3 during
any quarter of the Primary Term, because its share exceeds in whole or in part
KE&P's Quarterly Commitment, and THEC pays such costs, KE&P shall reimburse
THEC for such costs out of KE&P's Quarterly Commitment for the following
quarter on or before thirty days after the end of the
5
<PAGE> 6
quarter in which THEC paid such costs or, if the Primary Term has ended, THEC
shall receive KE&P's share of Net Proceeds from all Wells drilled under this
Agreement until such time as THEC has received a sum of money (exclusive of all
Burdens, Marketing Costs and Taxes) out of such share equal to KE&P's share of
costs which were paid by THEC, provided, however, that the amount to be paid by
KE&P as contemplated above shall not exceed twenty percent (20%) of KE&P's
Quarterly Commitment without its written consent.
(c) KE&P's Quarterly Commitment shall first be applied to G and A
Costs, Seismic Costs, Leasehold Costs and Operating Costs and the remainder to
the Intangible Costs, Drilling Costs, Development Costs and Abandonment Costs.
(d) All Drilling Costs, Intangible Costs and Development Costs for
purposes of applying the limitations of KE&P's Quarterly Commitment shall, at
the election of THEC, be deemed to have been incurred entirely on the date THEC
submits to KE&P the information set forth in Section 7.3 relating to the
applicable operation or the date of the AFE relating to the expenditure of such
costs, rather than on the dates such costs are actually incurred.
(e) Such portion of KE&P's Yearly Commitment for the year 1999 not
expended or committed for expenditure by December 31, 1999 shall be available
for use during the Primary Term only for Development Costs and Intangible Costs
related to Development Operations on Leases on which the first Exploratory Well
was spudded during the 1999 Program Year.
(f) Such portion of KE&P's Quarterly Commitment, for any calendar
quarter, not
6
<PAGE> 7
expended or committed for expenditure by the last day of such quarter shall be
available for use in subsequent quarters during the Primary Term only for
Development Costs and Intangible Costs related to Development Operations on
Leases on which the first Exploratory Well was spudded during the quarter to
which the unused portion of the quarterly Commitment relates, or any previous
quarter, including the 1999 Program Year.
VII.
Section 10.4 of the Exploration Agreement is amended so that the
existing language becomes Section 10.4(a) and the following is inserted as
Section 10.4(b):
10.4(b) Budgets. Notwithstanding the foregoing Section 10.4(a), for
the period commencing January 1, 2000, this Section 10.4(b) shall apply
prospectively in lieu of Section 10.4(a). THEC shall submit quarterly to the
Management Committee THEC's Program Budget and a quarterly budget setting forth
the anticipated financial
requirements of KE&P under this Agreement. Such budgets for the first quarter
of the year 2000 shall be submitted on or before January 1, 2000 and the
budgets for the following quarters during the terms on or before the first day
of such quarters.
Except as herein amended, the parties do hereby ratify and confirm the
Exploration Agreement.
Executed on the day set forth above, but to be effective as of
January 1, 2000.
THE HOUSTON EXPLORATION COMPANY
By: /s/ James Westmoreland
----------------------------------
James Westmoreland, Vice President
KEYSPAN EXPLORATION AND
PRODUCTION, L.L.C.
By: /s/ Zain Mirza
-----------------------------------
Zain Mirza, Vice President
7
<PAGE> 1
EXHIBIT 10.23
THIRD AMENDMENT TO AMENDED AND
RESTATED CREDIT AGREEMENT
This THIRD AMENDMENT AND SUPPLEMENT TO AMENDED AND RESTATED CREDIT
AGREEMENT (this "Third Amendment") executed effective as of December 9, 1999
(the "Effective Date"), is by and among THE HOUSTON EXPLORATION COMPANY, a
Delaware corporation ("Company"); CHASE BANK OF TEXAS, NATIONAL ASSOCIATION (in
its individual capacity, "Chase"), as agent (in such capacity, "Agent") for
each of the lenders that is a signatory hereto or which becomes a signatory
hereto and to the hereinafter described Credit Agreement as provided in Section
12.06 of the Credit Agreement (individually, together with its successors and
assigns, "Lender" and collectively, "Lenders").
R E C I T A L S
A. The Company, the Agent and the Lenders (other than the hereinafter
defined "Additional Lenders") are parties to that certain Amended and Restated
Credit Agreement dated as of March 30, 1999 (said Amended and Restated Credit
Agreement, as amended and supplemented by First Amendment to Amended and
Restated Credit Agreement dated as of May 4, 1999, and as further amended by
Second Amendment to Amended and Restated Credit Agreement dated as of October
6, 1999, "Credit Agreement"), pursuant to which the Lenders agreed to make
loans and issue Letters of Credit to and for the account of the Company.
B. The Company, the Lenders and the Agent mutually desire to
amend certain aspects of the Credit Agreement relating to, among other things,
the Borrowing Base and Threshold Amount.
C. In view of the foregoing, the Company, the Agent and the
Lenders hereby agree to amend the Credit Agreement in the particulars
hereinafter provided.
NOW, THEREFORE, in consideration of the premises and other good and
valuable consideration and the mutual benefits, covenants and agreements herein
expressed, the parties hereto now agree as follows:
Section 1. Certain Terms. All capitalized terms used in this Third
Amendment and not otherwise defined herein shall have the meanings ascribed to
such terms in the Credit Agreement.
Section 2. Amendments and Supplements to Credit Agreement. The
Credit Agreement is hereby amended and supplemented as follows:
2.1 Definitions.
(a) The following terms defined in Section 1.02 of the Credit
Agreement are hereby amended as follows:
<PAGE> 2
(i) The term "Agreement" is hereby amended in its
entirety to read as follows:
"Agreement" shall mean this Credit Agreement, as
amended by the First Amendment, as further amended by the
Second Amendment, as further amended by the Third Amendment,
and as the same may be further amended or supplemented from
time to time.
(ii) The term "Applicable Margin" is hereby amended
in its entirety to read as follows:
"Applicable Margin" shall mean at the time of calculation, with
respect to any Loan, calculated as a function of the type of such Loan, the
following rate per annum as applicable:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------
THRESHOLD AMOUNT FIXED RATE LOAN APPLICABLE BASE RATE LOAN APPLICABLE
UTILIZATION MARGIN PERCENTAGE MARGIN PERCENTAGE
- --------------------------------------------------------------------------------------------
<S> <C> <C>
Less than 33% 0.875% 0%
Greater than or equal to 33% 1.125% 0%
but less than 66%
Greater than or equal to 66% 1.375% 0%
but less than 100%
Greater than or equal to 1.625% 0%
100%
- --------------------------------------------------------------------------------------------
</TABLE>
(iii) The Term "Threshold Amount" is hereby amended
in its entirety to read as follows:
"Threshold Amount" shall mean (i) during
the period from and including the Effective Date of
the Third Amendment to and including the date of the
redetermination by the Agent and the Lenders of the
Threshold Amount scheduled to occur March 1, 2000,
an amount equal to $175,000,000, (ii) during the
period from and including March 2, 2000 to and
including September 1, 2000, an amount equal to the
amount of the March 1, 2000 redetermined Threshold
Amount, and (iii) thereafter, the amount equal to
the Borrowing Base in effect from time to time. The
redetermination of the Threshold Amount on March 1,
2000, shall be made using the same criteria used by
the Agent and the Lenders prior to the Closing Date
to determine the Threshold Amount.
(b) Section 1.02 of the Credit Agreement is hereby
supplemented, where alphabetically appropriate, with the addition of
the following definition:
-2-
<PAGE> 3
"Third Amendment" shall mean that certain Third
Amendment to Amended and Restated Credit Agreement dated
effective as of December 9, 1999, between the Company, the
Agent and the Lenders.
2.2 Fees. Section 2.04 of the Credit Agreement is hereby
amended as follows:
(a) The table found in Section 2.04(a)(i) is hereby amended in
its entirety to read as follows:
- ------------------------------------------------------------------------------
THRESHOLD AMOUNT
UTILIZATION COMMITMENT FEE
- ------------------------------------------------------------------------------
Less than 33% 0.25%
Greater than or equal to 33% but less than 66% 0.30%
Greater than or equal to 66% but less than 100% 0.30%
Greater than or equal to 100% 0.375%
(b) The table found in Section 2.04(b) is hereby amended in its
entirety to read as follows:
- ------------------------------------------------------------------------------
THRESHOLD AMOUNT
UTILIZATION ISSUANCE FEE
- ------------------------------------------------------------------------------
Less than 33% 0.875%
Greater than or equal to 33% but less 1.125%
than 66%
Greater than or equal to 66% but less 1.375%
than 100%
Greater than or equal to 100% 1.625%
- ------------------------------------------------------------------------------
2.3 Prepayments. Section 2.08(b) of the Credit Agreement is
hereby amended and modified to provide that, if on March 29, 2000, the
sum of the outstanding aggregate principal amount of the Loans and the
LC Exposure exceeds the lesser of the then effective Borrowing Base or
the aggregate amount of the Commitments, then the Company shall
immediately pay or prepay the amount of such excess amount for
application first, towards the reduction of all amounts previously
drawn under Letters of Credit, but not yet funded as a Revolving
Credit Loan pursuant to Section 4.07(b) or reimbursed, second, if
necessary, towards reduction of the outstanding principal balance of
the Notes by prepaying Base Rate Loans, if any, then outstanding, and
third, if necessary, at the election of the Company, either toward a
reduction of the outstanding principal balance of the Notes by
prepaying Fixed Rate Loans, if any, then outstanding or by paying such
amount to the Agent as cash collateral for outstanding Letters of
Credit, which amount shall be held by the Agent as cash collateral to
-3-
<PAGE> 4
secure the Company's obligation to reimburse the Agent and the Lenders
for drawing under the Letters of Credit.
2.4 MarketSpan Credit Facility. Section 8.07 of the Credit
Agreement is hereby amended in its entirety to read as follows:
"Section 8.07 MarketSpan Credit Facility. The
Company shall maintain an unused and available commitment
under the MarketSpan Credit Facility equal to or greater than
the amount by which the Borrowing Base exceeds the Threshold
Amount until (i) such time as the Borrowing Base is equal to
the Threshold Amount, (ii) such time as any and all
prepayments required under Section 2.08(b) have been made in
full, and (iii) such time as no Default exists hereunder."
Section 3. Borrowing Base; Threshold Amount. Notwithstanding anything
to the contrary contained in the Credit Agreement including, without
limitation, the provisions of Section 2.09:
(a) The amount of the Borrowing Base shall be (i)
$240,000,000 for the period from and including the Effective Date of
this Third Amendment to but not including March 29, 2000, and (ii) an
amount equal to the Threshold Amount in effect on March 29, 2000, for
the period from and including March 29, 2000 to and including
September 1, 2000, at which time and from time to time thereafter the
Borrowing Base shall be redetermined in accordance with Section 2.09
of the Credit Agreement.
(b) Any unscheduled redetermination of the Borrowing Base or
the Threshold Amount which occurs on or before March 29, 2000, must be
approved by all of the Lenders.
Section 4. Conditions. In addition to any and all other applicable
conditions precedent contained in Article VI of the Credit Agreement, this
Third Amendment shall become binding upon receipt by the Agent of the following
documents, each of which shall be satisfactory to the Agent in form and
substance:
(a) Counterparts of this Third Amendment duly executed by
the Company.
(b) Photocopies of all duly completed and executed
documentation evidencing the extension of the final maturity of the
MarketSpan Credit Facility from January 1, 2000 to March 31, 2000.
(c) Such other documents as the Agent or its counsel may
reasonably request.
Section 5. Extent of Amendments. The parties hereto hereby acknowledge
and agree that, except as specifically supplemented and amended, changed or
modified hereby, the Credit Agreement shall remain in full force and effect in
accordance with its terms.
-4-
<PAGE> 5
Section 6. Reaffirmation. The Company hereby reaffirms that as of the
date of this Third Amendment, the representations and warranties made by the
Company in Article VII of the Credit Agreement are true and correct on the date
hereof as though made on and as of the date of this Third Amendment.
Section 7. Governing Law. This Third Amendment shall be governed by,
and construed in accordance with, the laws of the State of Texas.
Section 8. Counterparts. This Third Amendment may be executed in two
or more counter parts, and it shall not be necessary that the signatures of all
parties hereto be contained on any one counterpart hereof; each counterpart
shall be deemed an original, but all of which together shall constitute one and
the same instrument.
Section 9. Final Agreement. THE CREDIT AGREEMENT, AS AMENDED HEREBY,
THIS THIRD AMENDMENT, THE NOTES AND THE SECURITY INSTRUMENTS REPRESENT THE
FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF
PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE
NO UNWRITTEN OR ORAL AGREEMENTS BETWEEN THE PARTIES.
[SIGNATURE PAGES BEGIN ON NEXT PAGE]
-5-
<PAGE> 6
IN WITNESS WHEREOF, the parties hereto have caused this Third
Amendment to be duly executed effective as of the date first above written.
COMPANY:
THE HOUSTON EXPLORATION COMPANY
By: /s/ Thomas W. Powers
--------------------------------
Name: Thomas W. Powers
Title: Senior Vice President
Business Development
Finance and Treasurer
Address: 1100 Louisiana
Suite 2000
Houston, Texas 77002
Telecopier No.: 713/830-6885
Telephone No.: 713/830-6853
[Third Amendment to Amended and
Restated Credit Agreement
Signature Page 1]
<PAGE> 7
LENDERS AND AGENTS:
------------------
CHASE BANK OF TEXAS, NATIONAL
ASSOCIATION, individually as a
Lender and as Administrative Agent
By: /s/ Russell Johnson
-------------------------------
Name: Russell Johnson
Title: Vice President
Applicable Lending Office for Base
Rate Loans:
Address: 712 Main Street
Houston, Texas 77002
Applicable Lending Office for Fixed
Rate Loans:
Address: 712 Main Street
Houston, Texas 77002
Telecopier: 713/216-8870
Telephone: 713/216-5617
Address for Notices:
Loan and Agency Services
The Chase Manhattan Bank
1 Chase Manhattan Plaza, 8th Floor
New York, New York 10081
Telecopier No.: 212/552-7490
Telephone No.: 212/552-7943
Attention: Muniram Appanna
[Third Amendment to Amended and
Restated Credit Agreement
Signature Page 2]
<PAGE> 8
HE BANK OF NOVA SCOTIA,
individually as a Lender and as Syndication
Agent
By: /s/F.C.H. Ashby
----------------------------------
Name: F.C.H. Ashby
Title: Senior Manager Loan Operations
Applicable Lending Office for Base Rate Loans:
Address: 600 Peachtree Street N.E.
Suite 2700
Atlanta GA 30308
Applicable Lending Office for Fixed Rate Loans:
Address: 600 Peachtree Street N.E.
Suite 2700
Atlanta GA 30308
Address for Notices:
1100 Louisiana, Suite 3000
Houston, Texas 77002
Telecopier No.: 713/752-2425
Telephone No.: 713/759-3441
Attention: Mark Ammerman
with a copy to:
Address: 600 Peachtree Street N.E.
Suite 2700
Atlanta GA 30308
Telecopier: 404/888-8998
Telephone: 404/877-1552
Attention: Phyllis Walker
[Third Amendment to Amended and
Restated Credit Agreement
Signature Page 3]
<PAGE> 9
FIRST UNION NATIONAL BANK,
Individually as a Lender and as
Documentation Agent
By: /s/ Robert R. Wetteroff
----------------------------------
Name: Robert R. Wetteroff
Title: Senior Vice President
Applicable Lending Office for Base Rate Loans:
Address: 301 South College Street
Charlotte, North Carolina 28288
Applicable Lending Office for Fixed Rate
Loans:
Address: 301 South College Street
Charlotte, North Carolina 28288
Address for Notices:
1001 Fannin Street
Houston, Texas 77002
Telecopier: 713/650-6354
Telephone No. 713/346-2727
Attention: Jay Chernosky
with a copy to:
1001 Fannin Street
Houston, Texas 77002
Telecopier: 713/650-6354
Telephone No. 713/346-2727
Attention: Debbie Blank
[Third Amendment to Amended and
Restated Credit Agreement
Signature Page 4]
<PAGE> 10
PNC BANK NATIONAL ASSOCIATION,
Individually as a Lender and as Managing
Agent
By: /s/ Thomas A. Maleski
--------------------------------
Name: Thomas a. Maleski
Title: Vice President
Applicable Lending Office for Base Rate Loans:
Address: 249 Fifth Avenue, 3rd Floor
Mail Stop P1-POPP-03-1
Pittsburgh, Pennsylvania 15222
Applicable Lending Office for Fixed Rate
Loans:
Address: 249 Fifth Avenue, 3rd Floor
Mail Stop P1-POPP-03-1
Pittsburgh, Pennsylvania 15222
Address for Notices:
249 Fifth Avenue, 3rd Floor
Mail Stop P1-POPP-03-1
Pittsburgh, Pennsylvania 15222
Telecopier: 412/762-2571
Telephone No. 412/762-3025
Attention: Thomas A. Majeski
with a copy to:
620 Liberty Avenue
Mail Stop P2-PTPP-03-1
Pittsburgh, Pennsylvania 15222
Telecopier: 412/762-5271
Telephone No. 412/762-3025
Attention: Stephanie Angelini
[Third Amendment to Amended and
Restated Credit Agreement
Signature Page 5]
<PAGE> 11
COMERICA BANK - TEXAS
By: /s/ Martin W. Wilson
---------------------------------
Name: Martin W. Wilson
Title: Vice President
Applicable Lending Office for Base Rate Loans:
Address: 1601 Elm Street, 2nd Floor
Dallas, Texas 75201
Applicable Lending Office for Fixed Rate
Loans:
Address: 1601 Elm Street, 2nd Floor
Dallas, Texas 75201
Address for Notices:
1601 Elm Street, 2nd Floor
Dallas, Texas 75201
Telecopier: 214/969-6561
Telephone No. 214/969-6563
Attention: Martin W. Wilson
with a copy to:
Livonia Operations Center
39200 Six Mile Road, 4th Floor
Livonia, Michigan 48152
Telecopier: 734/632-7050
Telephone No. 734/632-3063
Attention: Nancy Lee
[Third Amendment to Amended and
Restated Credit Agreement
Signature Page 6]
<PAGE> 12
THE BANK OF NEW YORK
By: /s/ Peter Keller
--------------------------
Name: Peter Keller
Title: Vice President
Applicable Lending Office for Base Rate
Loans:
Address: One Wall Street
Energy Division, 19th Floor
New York, New York 10286
Telecopier No.:212/635-7924
Telephone No.: 212/635-7550
Attention: Kathy D'Elena
Applicable Lending Office for Fixed
Rate Loans:
Address: One Wall Street
Energy Division, 19th Floor
New York, New York 10286
Telecopier No.:212/635-7924
Telephone No.: 212/635-7550
Attention: Kathy D'Elena
Address for Notices:
The Bank of New York
One Wall Street
Energy Division, 19th Floor
New York, NY 10286
Telecopier No.: 212/635-7924
Telephone No.: 212/635-7550
Attention: Kathy D'Elena
[Third Amendment to Amended and
Restated Credit Agreement
Signature Page 7]
<PAGE> 13
with a copy to:
Address:
The Bank of New York
One Wall Street
Energy Division, 19th Floor
New York, NY 10286
Telecopier No.: 212/635-7924
Telephone No.: 212/635-7861
Attention: Peter Keller
[Third Amendment to Amended and
Restated Credit Agreement
Signature Page 8]
<PAGE> 14
NATEXIS BANQUE
By: /s/ N. Eric Ditges
-----------------------------
Name: N. Eric Ditges
Title: Vice President
By: /s/ Louis P. Laville, III
-----------------------------
Name: Louis P. Laville, III
Title: Vice President and Group Manager
Applicable Lending Office for Base
Rate Loans:
Address: 645 5th Avenue, 20th Floor
New York, New York
Telecopier No.:212/872-5045
Applicable Lending Office for Fixed
Rate Loans:
Address: 645 5th Avenue, 20th Floor
New York, New York
Telecopier No.:212/872-5045
Address for Notices:
Natexis Banque, Southwest
Representative Office
333 Clay Street, Suite 4340
Houston, Texas 77002
Telecopier No.: 713/759-9908
Telephone No.: 713/759-9401
Attention: Tanya McAllister
with a copy to:
Address:
Natexis Banque, New York Branch
645 5th Avenue, 20th Floor
New York, New York
Telecopier No.: 212/872-5045
Attention: Joan Rankine
[Third Amendment to Amended and
Restated Credit Agreement
Signature Page 9]
<PAGE> 15
Natexis Banque, Southwest
Representative Office
333 Clay Street, Suite 4340
Houston, Texas 77002
Telecopier No.: 713/759-9908
Telephone No.: 713/759-9401
Attention: Eric Ditges
[Third Amendment to Amended and
Restated Credit Agreement
Signature Page 10]
<PAGE> 16
BANK ONE, TEXAS, N.A.
By: /s/ Christine M. Macan
-----------------------------------------
Name: Christine M. Macan
Title: Vice President
Applicable Lending Office for Base
Rate Loans:
Address: 910 Travis, TX2-4330
Houston, Texas 77002
Applicable Lending Office for Fixed
Rate Loans:
Address: 910 Travis, TX2-4330
Houston, Texas 77002
Address for Notices:
Bank One Center
910 Travis, TX2-4330
Houston, Texas 77002
Telecopier No.: 713/751-3544
Telephone No.: 713/751-3484
Attention: Christine Macan
with a copy to:
Address: Bank One Center
910 Travis, TX2-4375
Houston, Texas 77002
Telecopier No.: 713/751-3982
Telephone No.: 713/751-6174
Attention: Jeanie Harman
and
[Third Amendment to Amended and
Restated Credit Agreement
Signature Page 11]
<PAGE> 17
Address: 500 Throckmorton
West Complex PG6
Fort Worth, Texas 76102
Telecopier No.: 817/884-4651
Telephone No.: 817/884-4399
Attention: Carol Peacock
[Third Amendment to Amended and
Restated Credit Agreement
Signature Page 12]
<PAGE> 18
HIBERNIA NATIONAL BANK
By: /s/ David R. Reid
-----------------------------------------
Name: David R. Reid
Title: Senior Vice President
Applicable Lending Office for Base
Rate Loans:
Address: 313 Carondelet Street
New Orleans, Louisiana 70130
Applicable Lending Office for Fixed
Rate Loans:
Address: 313 Carondelet Street
New Orleans, Louisiana 70130
Address for Notices:
213 W. Vermilion
Lafayette, Louisiana 70501
Telecopier No.: 318/268-4566
Telephone No.: 318/268-4582
Attention: David Reid
with a copy to:
Address: 313 Carondelet Street
New Orleans, Louisiana 70130
Telecopier No.: 504/533-5434
Telephone No.: 504/533-5717
Attention: Spencer Gagnet
[Third Amendment to Amended and
Restated Credit Agreement
Signature Page 13]
and
<PAGE> 19
Address: 313 Carondelet Street
New Orleans, Louisiana 70130
Telecopier No.: 504/533-5434
Telephone No.: 504/533-5352
Attention: Virginia Bell Cowart
<PAGE> 1
EXHIBIT 10.24
THE HOUSTON EXPLORATION COMPANY
1999 NON-QUALIFIED STOCK OPTION PLAN
ARTICLE I
PLAN
Section 1.1 Purpose. This Plan is for non-employee directors
of the Company and employees, consultants and advisors of the Company and its
Affiliates, other than officers who are subject to Section 16(b) of the
Securities Exchange Act of 1934, as amended, and is intended to advance the
best interests of the Company, its Affiliates, and its stockholders by
providing those persons who have substantial responsibility for the management
and growth of the Company and its Affiliates with additional incentives and an
opportunity to obtain or increase their proprietary interest in the Company,
thereby encouraging them to continue as directors or in the employ of the
Company or any of its Affiliates.
Section 1.2 Effective Date of Plan. This Plan is effective
October 26, 1999 (the "Effective Date"). No Option shall be granted pursuant to
this Plan after October 26, 2009.
ARTICLE II
DEFINITIONS
The words and phrases defined in this Article shall have the
meaning set out in these definitions throughout this Plan, unless the context
in which any such word or phrase appears reasonably requires a broader,
narrower, or different meaning.
"Affiliate" means any parent corporation and any subsidiary
corporation. The term "parent corporation" means any corporation
(other than the Company) in an unbroken chain of corporations ending
with the Company if, at the time of the action or transaction, each of
the corporations other than the Company owns stock possessing 50% or
more of the total combined voting power of all classes of stock in one
of the other corporations in the chain. The term "subsidiary
corporation" means any corporation (other than the Company) in an
unbroken chain of corporations beginning with the Company if, at the
time of the action or transaction, each of the corporations other than
the last corporation in the unbroken chain owns stock possessing 50%
or more of the total combined voting power of all classes of stock in
one of the other corporations in the chain.
"Board" means the board of directors of the Company.
<PAGE> 2
"Change of Control" means:
(i) the acquisition by any individual, entity or
group (within the meaning of Section 13(d)(3) or 14(d)(2) of the
Securities Exchange Act of 1934, as amended) (a "Person") of
beneficial ownership of 20 percent or more of either (i) the then
outstanding shares of common stock of the Company (the "Outstanding
Common Stock") or (ii) the combined voting power of the then
outstanding voting securities of the Company entitled to vote
generally in the election of directors (the "Outstanding Voting
Securities"), provided that for purposes of this subsection (i), the
following acquisitions shall not constitute a Change of Control: (A)
any acquisition directly from the Company, (B) any acquisition by the
Company, (C) any acquisition by any employee benefit plan (or related
trust) sponsored or maintained by the Company, or (D) any acquisition
by any corporation pursuant to a transaction which complies with
clauses (A), (B) and (C) of subsection (iii) hereof; or
(ii) the individuals, who, as of the Effective Date,
constitute the Board (the "Incumbent Board") cease for any reason to
constitute at least a majority of the Board provided that any
individual becoming a director subsequent to the Effective Date whose
election, or nomination for election by the Company's stockholders,
was approved by a vote of at least a majority of the directors then
comprising the Incumbent Board shall be considered as though such
individual was a member of the Incumbent Board, but excluding, for
this purpose, any such individual whose initial assumption of office
occurs as a result of an actual or threatened election contest with
respect to the election or removal of directors or other actual or
threatened solicitation of proxies or consents by or on behalf of a
Person other than the Board; or
(iii) the consummation after the Effective Date of a
reorganization, merger or consolidation or sale or other disposition
of all or substantially all of the assets of the Company (a "Corporate
Transaction") unless, in each case, following such Corporate
Transaction, (A) (1) all or substantially all of the persons who were
the beneficial owners of the Outstanding Common Stock immediately
prior to such Corporate Transaction beneficially own, directly or
indirectly, more than 60% of the then outstanding shares of common
stock of the corporation resulting from such Corporate Transaction,
and (2) all or substantially all of the persons who were the
beneficial owners of the Outstanding Voting Securities immediately
prior to such Corporate Transaction beneficially own directly or
indirectly, more than 60% of the combined voting power of the then
outstanding voting securities entitled to vote generally in the
election of directors of the corporation resulting from such Corporate
Transaction (including, without limitation, a corporation which as a
result of such transaction owns the Company or all or substantially
all of the company's assets either directly or through one or more
subsidiaries) in substantially the same proportions as their ownership
of the Outstanding Common Stock and the outstanding Voting Securities
immediately prior to such Corporate Transaction, as the case may be,
(B) no Person (excluding (1) any corporation resulting form such
Corporate Transaction or any employee benefit plan (or related trust)
of the Company or such corporation resulting from
-2-
<PAGE> 3
such Corporate Transaction and (2) any Person approved by the
Incumbent Board) beneficially owns, directly or indirectly, 20% or
more of the then outstanding shares of common stock of the corporation
resulting from such Corporate Transaction or the combined voting power
of the then outstanding voting securities of such corporation except
to the extent that such ownership existed prior to such Corporate
Transaction and (C) at least a majority of the members of the board of
directors of the corporation resulting from such Corporate Transaction
were members of the Incumbent board at the time of the execution of
the initial agreement or of the action of the Board providing for such
Corporate Transaction.
"Committee" means the Compensation Committee of the Board or
such other committee designated by the Board. The Committee shall be
comprised solely of at least two members who are Outside Directors.
"Company" means The Houston Exploration Company, a Delaware
corporation.
"Disability" means a physical or mental infirmity which, in
the opinion of a physician selected by the Committee, shall prevent
the Employee from earning a reasonable livelihood with the Company or
any Affiliate and which can be expected to result in death or which
has lasted or can be expected to last for a continuous period of not
less than 12 months and which: (a) was not contracted, suffered or
incurred while the Employee was engaged in, or did not result from
having engaged in, a felonious criminal enterprise; (b) did not result
from alcoholism or addition to narcotics; and (c) did not result from
an injury incurred while a member of the Armed Forces of the United
States for which the Employee receives a military pension.
"Employee" means an employee of the Company or any Affiliate.
"Fair Market Value" of the Stock as of any date means (a) the
closing sales price of the Stock on that date (or, if there was no
sale on such date, the next preceding date on which there was such a
sale) on the principal securities exchange on which the Stock is
listed; or (b) if the Stock is not listed on a securities exchange,
the average of the high and low sale prices of the Stock on that date
(or, if there was no sale on such date, the next preceding date on
which there was such a sale) as reported on the Nasdaq Stock Market;
or (c) if the Stock is not listed on the Nasdaq Stock Market, the
average of the high and low bid quotations for the Stock on that date
as reported by the National Quotation Bureau Incorporated; or (d) if
none of the foregoing is applicable, an amount at the election of the
Committee equal to (x) the average between the closing bid and ask
prices per share of Stock on the last preceding date on which those
prices were reported or (y) an amount as determined by the Committee
in its sole discretion.
"Non-Employee Director" means a member of the Board of
Directors who is not an employee, consultant or advisor of the Company
or its subsidiaries.
-3-
<PAGE> 4
"Option" means a nonqualified option granted under this Plan
to purchase shares of Stock.
"Option Agreement" means the written agreement which sets out
the terms of an Option.
"Optionee" means a person who is granted an Option under this
Plan.
"Outside Director" means a member of the Board of Directors
serving on the Committee who satisfies the criteria of Section 162(m)
of the Internal Revenue Code of 1986, as amended.
"Plan" means The Houston Exploration Company 1999
Nonqualified Stock Option Plan, as set out in this document and as it
may be amended from time to time.
"Stock" means the common stock of the Company, $.01 par value
or, in the event that the outstanding shares of common stock are later
changed into or exchanged for a different class of stock or securities
of the Company or another corporation, that other stock or security.
ARTICLE III
ELIGIBILITY
The individuals who shall be eligible to receive Options
shall be (i) those employees, consultants and advisors of the Company or any of
its Affiliates as the Committee shall determine from time to time, but
excluding any such individual who is a senior managing officer of the Company,
and (ii) those individuals who are Non-Employee Directors; provided, however,
that Non- Employee Directors shall be eligible only to receive Options pursuant
to Section 5.6.
ARTICLE IV
GENERAL PROVISIONS RELATING TO OPTIONS
Section 4.1 Authority to Grant Options. The Committee may
grant to those eligible individuals (other than Non-Employee Directors), as it
shall from time to time determine, Options under the terms and conditions of
this Plan. Subject only to any applicable limitations set out in this Plan, the
number of shares of Stock to be covered by any Option to be granted to an
Employee, consultant or advisor of the Company or any of its Affiliates shall
be as determined by the Committee. Non-Employee Directors shall automatically
receive grants of Options as provided in Section 5.6.
-4-
<PAGE> 5
Section 4.2 Dedicated Shares. The total number of shares of
Stock with respect to which Options may be granted under the Plan shall be
400,000 shares of Stock; provided, however, in the event that any outstanding
Option shall expire or terminate for any reason other than exercise or any
Option is surrendered unexercised, the shares of Stock allocable to the
unexercised portion of that Option may again be subject to an Option under the
Plan. The shares may be treasury shares or authorized but unissued shares. The
number of shares stated in this Section 4.2 shall be subject to adjustment in
accordance with the provisions of Section 4.5.
Section 4.3 Non-Transferability. Options shall not be
transferable by the Optionee otherwise than by will or under the laws of
descent and distribution, and shall be exercisable during the Optionee's
lifetime only by him.
Section 4.4 Requirements of Law. The Company shall not be
required to sell or issue any Stock under any Option if issuing that Stock
would constitute or result in a violation by the Optionee or the Company of any
provision of any law, statute, or regulation of any governmental authority.
Specifically, in connection with any applicable statute or regulation relating
to the registration of securities, upon exercise of any Option, the Company
shall not be required to issue any Stock unless the Committee has received
evidence satisfactory to it to the effect that the holder of that Option will
not transfer the Stock except in accordance with applicable law, including
receipt of an opinion of counsel satisfactory to the Company to the effect that
any proposed transfer complies with applicable law. The determination by the
Committee on this matter shall be final, binding and conclusive. The Company
may, but shall in no event be obligated to, register any Stock covered by this
Plan pursuant to applicable securities laws of any country or any political
subdivision. In the event the Stock issuable on exercise of an Option is not
registered, the Company may imprint on the certificate evidencing the Stock any
legend that counsel for the Company considers necessary or advisable to comply
with applicable law. The Company shall not be obligated to take any other
affirmative action in order to cause the exercise of an Option and the issuance
of shares thereunder, to comply with any law or regulation of any governmental
authority.
Section 4.5 Changes in the Company's Capital Structure. The
existence of outstanding Options shall not affect in any way the right or power
of the Company or its stockholders to make or authorize any adjustments,
recapitalizations, reorganizations or other changes in the Company's capital
structure or its business, or any merger or consolidation of the Company, or
any issue of bonds, debentures, preferred or prior preference stock ahead of or
affecting the Stock or its rights, or the dissolution or liquidation of the
Company, or any sale or transfer of all or any part of its assets or business,
or any other corporate act or proceeding, whether of a similar character or
otherwise.
If the Company shall effect a subdivision or consolidation of
shares or other capital readjustment, the payment of a stock dividend, or other
increase or reduction of the number of shares of the Stock outstanding, without
receiving compensation for it in money, services or property then (a) the
number, class, and per share price of shares of Stock subject to outstanding
Options under this
-5-
<PAGE> 6
Plan shall be appropriately adjusted in such a manner as to entitle an Optionee
to receive upon exercise of an Option, for the same aggregate cash
consideration, the equivalent total number and class of shares he would have
received had he exercised his Option in full immediately prior to the event
requiring the adjustment; and (b) the number and class of shares of Stock then
reserved to be issued under the Plan shall be adjusted by substituting for the
total number and class of shares of Stock then reserved, that number and class
of shares of Stock that would have been received by the owner of an equal
number of outstanding shares of such class of Stock as result of the event
requiring the adjustment.
If the Company is merged or consolidated with another
corporation and the Company is not the surviving corporation, or if the Company
is liquidated or sells or otherwise disposes of all or substantially all its
assets while unexercised Options remain outstanding under this Plan, (a)
subject to the provisions of clause (c) below, after the effective time of the
merger, consolidation, liquidation, sale or other disposition, as the case may
be, each holder of an outstanding Option shall be entitled, upon exercise of
the Option, to receive, in lieu of shares of Stock, the number and class or
classes of shares of stock or other securities or property to which the holder
would have been entitled if, immediately prior to the merger, consolidation,
liquidation, sale or other disposition, the holder had been the holder of
record of a number of shares of Stock equal to the number of shares as to which
the Option shall be so exercised; (b) the Committee shall waive any limitations
set out in or imposed under this Plan so that all Options, from and after a
date prior to the effective date of the merger, consolidation, liquidation,
sale or other disposition, as the case may be, specified by the Committee,
shall be exercisable in full; and (c) all outstanding Options may be canceled
by the Committee as of the effective date of any merger, consolidation,
liquidation, sale or other disposition, if (i) notice of cancellation shall be
given to each holder of an Option and (ii) each holder of an Option shall have
the right to exercise that Option in full (without regard to any limitations
set out in or imposed under this Plan or the Option Agreement granting that
Option) during a period set by the Committee preceding the effective date of
the merger, consolidation, liquidation, sale or other disposition and, if in
the event all outstanding Options may not be exercised in full under applicable
securities laws without registration of the shares of Stock issuable on
exercise of the Options, the Committee may limit the exercise of the Options to
the number of shares of Stock, if any, as may be issued without registration
and the method of choosing which Options may be exercised, and the number of
shares of Stock for such Options may be exercised, shall be solely within the
discretion of the Committee.
The issue by the Company of shares of stock of any class, or
securities convertible into shares of stock of any class, for cash or property,
or for labor or services either upon direct sale or upon the exercise of rights
or warrants to subscribe for them, or upon conversion of shares or obligations
of the Company convertible into shares or other securities, shall not affect,
and no adjustment by reason of such issuance shall be made with respect to, the
number, class, or price of shares of Stock then subject to outstanding Options.
Section 4.6 Changes of Control. In the event of a Change
of Control, the Committee may, in its discretion, at the time an Option is
granted or any time thereafter: (i) provide
-6-
<PAGE> 7
for the acceleration of any time period relating to the exercise of the Option,
(ii) provide for the purchase of the Option upon the Optionee's request for an
amount of cash or other property that could have been received upon the
exercise of the Option had the Option been then currently exercisable, (iii)
adjust the terms of the Option in a manner determined by the Committee to
reflect the Change of Control, (iv) cause the Option to be assumed, or new
rights substituted therefore, by another entity, or (v) make such other
provisions as the Committee may consider equitable and in the best interest of
the Company. Any transaction described in this Section that is approved by the
Committee will be effective only if a committee of the Board that is composed
solely of two or more Non-Employee Directors approves of the transaction,
unless the transaction would not otherwise subject the Optionee to potential
liability under Section 16(b) of the Securities Exchange of 1934, as amended.
ARTICLE V
OPTIONS
Section 5.1 Option Price. The price at which Stock may be
purchased under an Option shall not be less than the greater of: (a) 100% of
the Fair Market Value of the shares of Stock on the date the Option is granted
or (b) the aggregate par value of the shares of Stock on the date the Option is
granted.
Section 5.2 Duration of Options. No Option shall be
exercisable after the expiration of 10 years from the date the Option is
granted.
Section 5.3 Amount Exercisable. Except as provided in Section
5.5 below, each Option may be exercised from time to time, in whole or in part,
in the manner and subject to the conditions the Committee, in its sole
discretion, may provide in the Option Agreement, as long as the Option is valid
and outstanding.
Section 5.4 Exercise of Options. Each Option shall be
exercised by the delivery of written notice to the Committee setting forth the
number of shares of Stock with respect to which the Option is to be exercised,
together with: (a) cash, certified check, bank draft, or postal or express
money order payable to the order of the Company for an amount equal to the
option price of the shares, (b) if approved by a Committee, Stock at its Fair
Market Value on the date of exercise, and/or any other form of payment which is
acceptable to such Committee, or (c) through a "cashless broker" exercise
procedure approved by the Company, and specifying the address to which the
certificates for the shares are to be mailed. Subject to Section 8.3, as
promptly as practicable after receipt of written notification and payment, the
Company shall, deliver to the Optionee certificates for the number of shares
with respect to which the Option has been exercised, issued in the Optionee's
name. If shares of Stock are used in payment of the exercise price, the
aggregate Fair Market Value of the shares of Stock tendered (which may be a
"constructive" tender) must be equal to or less than the aggregate exercise
price of the shares being purchased upon exercise of the Option, and any
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<PAGE> 8
difference must be paid by cash, certified check, bank draft, or postal or
express money order payable to the Company. Delivery of the shares shall be
deemed effected for all purposes when a stock transfer agent of the Company
shall have deposited the certificates in the United States mail, addressed to
the Optionee, at the address specified by the Optionee.
Section 5.5 No Rights as Stockholder. No Optionee shall have
any rights as a stockholder with respect to Stock covered by his Option until
the date a stock certificate is issued for the Stock.
Section 5.6 Director Options.
(a) Each individual who becomes a Non-Employee Director upon
his or her first election to the Board after the Effective Date shall
automatically receive an Option for 5,000 shares of Stock on the date of his or
her election as a Non-Employee Director.
(b) On September 20 of each year that this Plan is in effect
(commencing with September 20, 2000), each individual who is a Non-Employee
Director on such date shall automatically receive an Option for 2,000 shares of
Stock on such date; provided, however, that if September 20 of any year in
which such Option share to be granted falls on a day which is not a business
day, such Options shall be granted on the next following business day.
(c) Each Option granted to a Non-Employee Director pursuant
to this Section 5.6 will be subject to the following provisions:
(i) Each such Option shall be fully vested and
exercisable on its date of grant; and
(ii) Each such Option shall have a term of 10 years
from the date the Option is granted; provided, however, that if the
Non-Employee Director ceases to serve as a director of the Company for
any reason, including death, each such Option shall terminate on the
earlier to occur of (A) the first anniversary of the date on which
such Non-Employee Director ceased to serve as a director of the
Company and the (B) 10th anniversary of the date of grant of such
Option.
(d) In the event that the number of shares of Stock available
for grant under this Plan is insufficient to make all automatic grants provided
for in this Section 5.6 on the applicable date, then each Non-Employee Director
shall receive an Option for his or her pro rata share of the total number of
shares of Stock then available for grant under this Plan and shall have no
right to receive a grant with respect to the deficiencies in the number of
available shares, and all future grants under this Section 5.6 shall terminate.
-8-
<PAGE> 9
ARTICLE VI
ADMINISTRATION
This Plan shall be administered by the Committee. All
questions of interpretation and application of this Plan and Options shall be
subject to the determination of the Committee. A majority of the members of the
Committee shall constitute a quorum. All determinations of the Committee shall
be made by a majority of its members. Any decision or determination reduced to
writing and signed by a majority of the members shall be as effective as if it
had been made by a majority vote at a meeting properly called and held. In
carrying out its authority under this Plan, the Committee shall have full and
final authority and discretion, including but not limited to the following
rights, powers and authorities, to:
(a) determine the persons to whom and the time or times at
which Options will be made,
(b) determine the number of shares and the purchase price of
Stock covered in each Option, subject to the terms of the Plan,
(c) determine the terms, provisions and conditions of each
Option, which need not be identical,
(d) accelerate the time at which any outstanding Option may
be exercised,
(e) define the effect, if any, on an Option of the death,
disability, retirement, or termination of employment of the Optionee,
(f) prescribe, amend and rescind rules and regulations
relating to administration of this Plan, and
(g) make all other determinations and take all other actions
deemed necessary, appropriate, or advisable for the proper administration of
this Plan.
The actions of the Committee in exercising all of the rights, powers, and
authorities set out in this Article and all other Articles of this Plan, when
performed in good faith and in its sole judgment, shall be final, conclusive
and binding on all parties.
-9-
<PAGE> 10
ARTICLE VII
AMENDMENT OR TERMINATION OF PLAN
The Board may amend, terminate or suspend this Plan at any
time, in its sole and absolute discretion.
ARTICLE VIII
MISCELLANEOUS
Section 8.1 No Establishment of a Trust Fund. No property
shall be set aside nor shall a trust fund of any kind be established to secure
the rights of any Optionee under this Plan. All Optionees shall at all times
rely solely upon the general credit of the Company for the payment of any
benefit which becomes payable under this Plan.
Section 8.2 No Employment Obligation. The granting of any
Option shall not constitute an employment contract, express or implied, nor
impose upon the Company or any Affiliate any obligation to employ or continue
to employ any Optionee. The right of the Company or any Affiliate to terminate
the employment of any person shall not be diminished or affected by reason of
the fact that an Option has been granted to him.
Section 8.3 Tax Withholding. The Company or any Affiliate
shall be entitled to deduct from other compensation payable to each Optionee
any sums required by federal, state, or local tax law to be withheld with
respect to the grant or exercise of an Option. In the alternative, the Company
may require the Optionee (or other person exercising the Option) to pay the sum
directly to the employer corporation. If the Optionee (or other person
exercising the Option) is required to pay the sum directly, payment in cash or
by check of such sums for taxes shall be delivered within ten days after the
date of exercise or lapse of restrictions. The Company shall have no obligation
upon exercise of any Option until payment has been received, unless withholding
(or offset against a cash payment) as of or prior to the date of exercise is
sufficient to cover all sums due with respect to that exercise. The Company and
its Affiliates shall not be obligated to advise an Optionee of the existence of
the tax or the amount which the employer corporation will be required to
withhold.
Section 8.4 Written Agreement. Each Option shall be embodied
in a written Option Agreement which shall be subject to the terms and
conditions of this Plan and shall be signed by the Optionee and by a member of
the Committee and an officer of the Company on behalf of the Committee and the
Company. The Option Agreement may contain any other provisions that the
Committee in its discretion shall deem advisable which are not inconsistent
with the terms of this Plan.
Section 8.5 Indemnification of the Committee and the Board of
Directors. With respect to administration of this Plan, the Company shall
indemnify each present and future member
-10-
<PAGE> 11
of the Committee and the Board against, and each member of the Committee and
the Board shall be entitled without further action his part to indemnity from
the Company for, all expenses (including attorneys' fees, the amount of
judgments and the amount of approved settlements made with a view to the
curtailment of costs of litigation, other than amounts paid to the Company
itself) reasonably incurred by him in connection with or arising out of any
action, suit, or proceeding in which he may be involved by reason of his being
or having been a member of the Committee and/or the Board, whether or not he
continues to be a member of the Committee and/or the Board at the time of
incurring the expenses--including, without limitation, matters as to which he
shall be finally adjudged in any action, suit or proceeding to have been found
to have been negligent in the performance of his duty as a member of the
Committee or of the Board. However, this indemnity shall not include any
expenses incurred by any member of the Committee and/or the Board in respect of
matters as to which he shall be finally adjudged in any action, suit or
proceeding to have been guilty of gross negligence or willful misconduct in the
performance of his duty as a member of the Committee or the Board. In addition,
no right of indemnification under this Plan shall be available to or
enforceable by any member of the Committee or the Board unless, within 60 days
after institution of any action, suit or proceeding, he shall have offered the
Company, in writing, the opportunity to handle and defend same at its own
expense. This right of indemnification shall inure to the benefit of the heirs,
executors or administrators of each member of the Committee and the Board and
shall be in addition to all other rights to which a member of the Committee and
the Board may be entitled as a matter of law, contract, or otherwise.
Section 8.6 Gender. If the context requires, words of one
gender when used in this Plan shall include the others and words used in the
singular or plural shall include the other.
Section 8.7 Headings. Headings of Articles and Sections are
included for convenience of reference only and do not constitute part of this
Plan and shall not be used in construing the terms of this Plan.
Section 8.8 Other Compensation Plans. Except as provided
below, the adoption of this Plan shall not affect any other stock option,
incentive or other compensation or benefit plans in effect for the Company or
any Affiliate, nor shall this Plan preclude the Company from establishing any
other forms of incentive or other compensation for employees of the Company or
any Affiliate. Notwithstanding the foregoing, on and after the Effective Date
Non-Employee Directors shall not be eligible to receive option grants under the
Company's 1996 Stock Option Plan and this Section 8.8 shall operate as an
amendment to that plan.
Section 8.9 Other Options. The grant of an Option shall not
confer upon an Optionee the right to receive any future or other Options under
this Plan, whether or not Options may be granted to similarly situated
Optionees, or the right to receive future Options upon the same terms or
conditions as previously granted.
Section 8.10 Arbitration of Disputes. Any controversy
arising out of or relating to the Plan or an Option Agreement shall be resolved
by arbitration conducted pursuant to the
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<PAGE> 12
arbitration rules of the American Arbitration Association. The arbitration
shall be final and binding on the parties.
Section 8.11 Governing Law. The provisions of this Plan
shall be construed, administered, and governed under the laws of the State of
Texas.
-12-
<PAGE> 1
EXHIBIT 10.25
THE HOUSTON EXPLORATION COMPANY
CHANGE OF CONTROL PLAN
1. Purpose. The Houston Exploration Company Change of Control Plan (the
"Plan") is hereby established effective as of October 26, 1999 (the
"Effective Date"). The Plan sets forth the severance benefits and
certain "stay on" bonuses provided by The Houston Exploration Company
(the "Company", which term shall include any successor) for certain
employees upon and following a Change of Control of the Company (as
defined below).
2. Definitions.
"Annual Base Salary" means the Eligible Employee's annual base salary
as in effect immediately prior to the effective date of the Change of
Control.
"Benefits" means the Severance Benefits, Stay-on Bonus and/or vesting
in the Company stock options, as applicable.
"Bonus Amount" means, with respect to an Eligible Employee, an amount
equal to 125% of the Eligible Employee's annual target bonus
percentage as in effect immediately prior to the Change of Control
multiplied by the Eligible Employee's Annual Base Salary.
"Cause" means:
(i) the Eligible Employee's gross negligence in the
performance of the Eligible Employee's duties and
responsibilities;
(ii) a material violation of any material Company policy,
including, without limitation, the theft,
embezzlement or misappropriation of Company funds
or property;
(iii) the conviction of the Eligible Employee for a felony
involving moral turpitude; or
(iv) the Eligible Employee's willful and continued
failure, after receipt of written notice from the
Company, to perform substantially the Eligible
Employee's duties and responsibilities (excluding
any such failure due to injury or illness).
<PAGE> 2
"Change of Control" means:
(i) the acquisition by any individual, entity or
group (within the meaning of Section 13(d)(3) or 14(d)(2) of
the Securities Exchange Act of 1934, as amended) (a "Person")
of the beneficial ownership of 20 percent or more of either
(i) the then outstanding shares of common stock of the
Company (the "Outstanding Common Stock") or (ii) the combined
voting power of the then outstanding voting securities of the
Company entitled to vote generally in the election of
directors (the "Outstanding Voting Securities"), provided
that for purposes of this subsection (i), the following
acquisitions shall not constitute a Change of Control: (A)
any acquisition directly from the Company, (B) any
acquisition by the Company, (C) any acquisition by any
employee benefit plan (or related trust) sponsored or
maintained by the Company or any corporation controlled by
the Company, or (D) any acquisition by any corporation
pursuant to a transaction which complies with clauses (A),
(B) and (C) of subsection (iii) hereof; or
(ii) the individuals who, as of the Effective Date,
constitute the Board of Directors of the Company (the
"Incumbent Board") cease for any reason to constitute at
least a majority of the Board of Directors of the Company
(the "Board") provided that any individual becoming a
director subsequent to the Effective Date whose election, or
nomination for election by the Company's stockholders, was
approved by a vote of at least a majority of the directors
then comprising the Incumbent Board shall be considered as
though such individual was a member of the Incumbent Board,
but excluding, for this purpose, any such individual whose
initial assumption of office occurs as a result of an actual
or threatened election contest with respect to the election
or removal of directors or other actual or threatened
solicitation of proxies or consents by or on behalf of a
Person other than the Board; or
(iii) the consummation after the Effective Date of a
reorganization, merger or consolidation or other disposition
of all or substantially all of the assets of the Company (a
"Corporate Transaction") unless, in each case, following such
Corporate Transaction, (A) (1) all or substantially all of
the persons who were the beneficial owners of the Outstanding
Common Stock immediately prior to such Corporate Transaction
beneficially own, directly or indirectly, more than 60
percent of the then outstanding shares of common stock of the
corporation resulting from such Corporate Transaction, and
(2) all or substantially all of the persons who were the
beneficial owners of the Outstanding Voting Securities
immediately prior to such Corporate Transaction beneficially
own directly or indirectly, more than 60 percent of the
combined voting power of the then outstanding voting
securities entitled to vote generally in the election of
directors of the corporation resulting from such Corporate
Transaction (including, without limitation, a corporation
which as a result of such transaction owns the Company or all
or substantially all of the Company's assets either directly
or through one or more subsidiaries) in substantially the
same
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<PAGE> 3
proportions as their ownership of the Outstanding Common
Stock Corporate Transaction, as the case may be, (B) no
Person (excluding (1) any corporation resulting from such
Corporation Transaction or any employee benefit plan (or
related trust) of the Company or such corporation resulting
from such Corporate Transaction and (2) any Person approved
by the Incumbent Board) beneficially owns, directly or
indirectly, 20 percent or more of the then outstanding shares
of common stock of the corporation resulting from such
Corporate Transaction or the combined voting power of the
then outstanding voting securities of such corporation except
to the extent that such ownership existed prior to such
Corporate Transaction and (C) at least a majority of the
members of the board of directors of the corporation
resulting from such Corporate Transaction were members of the
Incumbent Board at the time of the execution of the initial
agreement or of the action of the Board providing for such
Corporation Transaction.
"Eligible Employee" means an individual who on the date of the Change
of Control is an employee of the Company.
"Good Reason" means, without the Eligible Employee's written consent,
(i) a significant adverse change in the Eligible Employee's
authorities, duties, or responsibilities as in effect immediately
prior to the date of the Change of Control, (ii) a reduction in the
Eligible Employee's Annual Base Salary when compared with the same as
in effect immediately prior to the date of the Change of Control, or
(iii) the assignment of the Eligible Employee to a place of work that
is more than 30 miles from the Eligible Employee's place of work
immediately prior to the date of the Change of Control, excluding
temporary assignments that are reasonably consistent with past
practices of the Company.
"Monthly Base Salary" means 1/12th of the Eligible Employee's Annual
Base Salary.
"Period of Severance" means the number of whole and fractional months
equal to the quotient of (i) the sum of the amounts payable to the
Eligible Employee pursuant to paragraph (a) of Attachment B, divided
by (ii) the Eligible Employee's Monthly Base Salary.
"Qualified Termination" means the Eligible Employee's employment with
the Company is terminated on or within 12 months following the date of
the Change of Control (a) for any reason other than: (i) death or a
disability entitling the Eligible Employee to benefits under the
Company's long term disability plan, (ii) a voluntarily termination by
the Eligible Employee (excluding for a Good Reason), or (iii) by the
Company for Cause; or (b) by the Eligible Employee for a Good Reason
within 30 days after the date on which such Good Reason event occurs.
"Release and Waiver" means a release and waiver of the Eligible
Employee's employment related claims against the Company substantially
in the form of such release adopted by the Company prior to the date
of the Change of Control.
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<PAGE> 4
"Severance Benefits" means the benefits provided in Attachment B
hereto.
"Stay-on Bonus" means the payment of the cash bonus amount as provided
in Attachment A hereto.
"Year of Service" means an Eligible Employee's full and fractional
years of continuous employment with the Company, its predecessors and
any affiliates, including any "contract employee" service, as of the
Eligible Employee's date of termination of employment.
3. Eligibility for Benefits. Subject to the provisions of Section 4
below, each Eligible Employee who (i) incurs a Qualified Termination
shall be eligible to receive Severance Benefits and (ii) is an
Eligible Employee on the date of the Change of Control (x) shall be
entitled to receive a Stay-on Bonus and (y) automatically shall be
100% vested immediately prior to the Change in Control in all Company
stock options granted to such person. For purposes of the Plan,
employment with the Company shall also include employment with any
affiliate of the Company.
4. Benefit Limitations.
(a) Notwithstanding any provision in this Plan to the
contrary, it is an express condition precedent to an Eligible
Employee's entitlement to receive Severance Benefits that
such Eligible Employee execute, and not revoke, a Release and
Waiver. Each Eligible Employee shall be afforded not less
than 45 days to consider such Release and Waiver. In
addition, each Eligible Employee who executes any such
Release and Waiver shall have seven days following the
execution of the Release and Waiver to revoke the same by
delivering written notice of revocation to the Company's
designee at the Company's executive offices or such other
address as may be designated by the Company in writing. Any
such Release and Waiver which has not been revoked in the
time and manner prescribed above shall be effective as of the
eighth day following its execution.
(b) If an Eligible Employee is entitled to receive similar
severance benefits under another severance plan, program or
policy of the Company or an affiliate, the Severance Benefits
under this Plan shall be reduced by the similar severance
benefits provided to the Eligible Employee under such other
plan, program or policy.
5. Administration of the Plan.
(a) The Plan Administrator shall be the Company. The duties of
the Company shall be performed by the individual who,
immediately prior to the Change of Control, is the Vice
President-Chief Accounting Officer of the Company (the
"VP-CAO"), without regards to whether his employment
terminates on or following the Change of Control. In the
event of the death or incapacity of the VP-CAO, these duties
shall
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<PAGE> 5
be performed by any officer of the Company. The VP-CAO shall
have the authority to control and manage the operation and
administration of the Plan. The Company shall fully indemnify
the VP-CAO against any and all liabilities arising by reason
of any act or failure to act made in good faith pursuant to
the provisions of the Plan, including expenses reasonably
incurred in the defense of any claim relating thereto.
(b) Subject to the terms of the Plan, the VP-CAO may from time to
time adopt such procedures, rules and regulations as it deems
appropriate for the administration of the Plan. In this
regard, the VP-CAO shall have such powers as may be necessary
to discharge its duties under the Plan, including the power:
(i) to administer, interpret and construe the Plan and
to determine all questions with regard to
employment, eligibility, Benefits and other matters
for the purpose of administering the Plan, provided
that all such actions shall be applied in a
nondiscriminatory manner;
(ii) to prescribe procedures to be followed and the forms
to be executed by Eligible Employees filing
application for Benefits under the Plan;
(iii) to appoint or employ individuals to assist in the
administration of the Plan and any other agents it
deems advisable, including legal counsel, who may be
the legal counsel to the Company on other matters;
and
(iv) to delegate to others any administrative or
ministerial duties as it may deem necessary or
appropriate for the administration of the Plan.
(c) Each Eligible Employee who claims Severance Benefits
under the Plan shall be required to apply therefor on the
form designated and provided by the Company. If any
application for a Severance Benefit is denied, the Company
shall notify the claimant within a reasonable time of such
denial setting forth the specific reasons therefor, and
afford such claimant a reasonable opportunity for a full and
fair review of the decision denying his claim. Notice of such
denial shall set forth, in addition to the specific reasons
for the denial, the following: (i) reference to pertinent
provisions of the Plan; (ii) such additional information as
may be relevant to denial of the claim; (iii) an explanation
of the claims review procedure; (iv) advice that such
claimant may request the opportunity to review pertinent Plan
documents and submit a statement of issues and comments. The
claimant will have 60 days to request a review of the denial
by the Company, which will provide a full and fair review.
The request shall be in writing. The claimant may review
pertinent Plan documents and submit comments in writing. The
Company shall render a decision within 60 days after
claimant's request for review (which may be extended to 120
days if circumstances so require) and shall advise claimant
in writing of its decision on such review specifying its
reasons and identifying appropriate provisions of the Plan.
-5-
<PAGE> 6
(d) Notwithstanding anything herein to the contrary, the
Eligible Employee may (but shall not be required) to elect
that his or her claim for Severance Benefits be settled by
arbitration in the city in which the Eligible Employee
resides at such time in accordance with the rules of the
American Arbitration Association then in effect. Judgment may
be entered on the arbitrator's award in any court having
jurisdiction. All reasonable legal fees and costs incurred by
the Eligible Employee in connection with the resolution of
any claim shall be paid by the Company unless the arbitrator
finds the Eligible Employee brought the claim in bad faith.
(e) When it is determined that an Eligible Employee entitled to
Severance Benefits is legally incompetent, Severance Benefits
may be paid or provided to the spouse, legal guardian or
custodian of such person and such payment shall constitute a
complete discharge of all liability of the Company and the
Plan with respect to such payment.
7. Amendment and Termination of the Plan.
The Company, by action of the Board, reserves the right, at any time
and from time to time, to amend in whole or in part any or all
provisions of the Plan; provided, however, no such termination of the
Plan or any amendment (or any part thereof) shall be effective with
respect to an Eligible Employee that either (i) on or within six
months prior to the Change of Control or (ii) 12 months after the
Change of Control would reduce the Benefits such Eligible Employee
would have received under the Plan but for such termination or
amendment of the Plan.
8. General
(a) Except to the extent preempted by applicable federal law,
this Plan shall be governed by the laws of the State of
Texas.
(b) The Plan is intended to conform with, and be administered in
conformance with, all applicable requirements of the Employee
Retirement Income Security Act of 1974, as amended. Should
any provision herein be inconsistent with any such a
requirement, the Company shall construe such provision in a
manner that is consistent with such requirement, but also is
as nearly consistent as is practical with the original
intention of such provision.
(c) This Plan does not constitute a contract or guarantee of
employment to any Eligible Employee.
(d) Benefits may not be assigned or alienated by an Eligible
Employee other than by will or the laws of descent and
distribution.
-6-
<PAGE> 7
(e) The Company shall be entitled to withhold from all payments
or other compensation due an Eligible Employee all taxes
required by applicable law to be withheld by the Company with
respect to the Benefits.
THE HOUSTON EXPLORATION COMPANY
By:
Name: James G. Floyd
Title: President and Chief Executive Officer
-7-
<PAGE> 8
ATTACHMENT A
STAY-ON BONUS
(a) On or as soon as reasonably practical following the date of
the Change of Control, the Company shall pay to each Eligible
Employee a lump sum amount in cash equal to 50% of the
Eligible Employee's Bonus Amount, less any taxes required to
be withheld therefrom by the Company.
(b) On or as soon as reasonably practical following the earlier
of (i) 60 days after the date of the Change of Control or
(ii) the Eligible Employee's termination of employment (for
any reason), the Company shall pay to each Eligible Employee
a lump sum amount in cash equal to 50% of the Eligible
Employee's Bonus Amount, less any taxes required to be
withheld therefrom by the Company.
(c) The Stay-On Bonus payable to an Eligible Employee as provided
in paragraphs (a) and (b) above shall be in addition to the
regular performance bonus payable to the Eligible Employee
for 1999, which if earned, will be paid in early 2000 in
accordance with past Company practices.
-i-
<PAGE> 9
ATTACHMENT B
SEVERANCE BENEFITS
(a) On or as soon as reasonable practical following an Eligible
Employee's Qualified Termination, but excluding any Eligible
Employee who has a written employment agreement with the
Company on the date of the Change of Control, the Company
shall pay such Eligible Employee a lump sum amount in cash
equal to the sum of:
(i) his or her Monthly Base Salary multiplied by 3,
(ii) 1/2 of his or her Monthly Base Salary multiplied by
the Eligible Employee's Years of Service, and
(iii) 1/2 of her or her Monthly Base Salary multiplied by
each full and partial $10,000 increment of the
Eligible Employee's Annual Base Salary;
provided, however, the sum of (i), (ii) and (iii) may not
exceed the Eligible Employee's Annual Base Salary.
(b) Each Eligible Employee, but excluding any Eligible
Employee who has a written employment agreement with the
Company on the date of the Change of Control, will continue
to be provided, without charge, during his or her Period of
Severance continued coverage under the Company's group health
(medical, dental and vision), life insurance, and long-term
disability plan(s) in which he or she participated on the
date his or her employment terminates (or in any successor
plan(s) thereto); provided, however, the continuation of
coverage under the Company's group health plan(s) without
charge (i) shall be conditioned on the Eligible Employee
timely electing following his or her termination of
employment continuation of coverage benefits under such group
health plan(s) pursuant to the Consolidated Omnibus Budget
Reconciliation Act of 1985 ("COBRA") and (ii) shall terminate
upon the end of the Eligible Employee's COBRA continuation
period if that period ends prior to the termination of his or
her Period of Severance.
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<PAGE> 10
ATTACHMENT C
VESTING OF STOCK OPTIONS
Immediately prior to the Change of Control, all Company stock
options of each Eligible Employee automatically shall become 100% vested
(exercisable). This Attachment C shall constitute an amendment to each Company
stock option plan.
-iii-
<PAGE> 1
EXHIBIT 12.1
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------------------------
1999 1998 1997 1996 1995
-------- -------- --------- --------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
FIXED CHARGES:
Gross interest expense $ 25,167 $ 14,414 $ 6,811 $ 6,365 $ 5,297
Interest portion of
rent expense 28 39 32 29 25
-------- --------- -------- --------- --------
25,195 14,453 6,843 6,395 5,322
EARNINGS:
Income (loss) before
taxes 36,369 (113,440) 33,423 10,847 (4,112)
Plus: fixed charges 25,195 14,453 6,843 6,394 5,322
Less: capitalized interest (11,860) (9,817) (5,873) (3,490) (2,899)
-------- --------- -------- --------- --------
$ 49,704 $(108,804) $ 34,393 $ 13,751 $ (1,689)
RATIO OF EARNINGS TO FIXED 2.0x N/M 5.0x 2.2x N/M
</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
As independent public accountants, we hereby consent to the incorporation
by reference of our report included in this Annual Report on Form 10-K for the
year ended December 31, 1999 into the Company's previously filed Registration
Statements on Form S-3, file number 333-78843 dated May 25, 1999 and Form S-8,
file number 333-36977 dated October 1, 1997.
ARTHUR ANDERSEN LLP
New York, New York
March 22, 2000
<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, 1999 and incorporated by reference into the Company's previously
filed Registration Statements on Form S-3, file number 333-78843 dated May 25,
1999 and Form S-8, file number 333-36977 dated October 1, 1997.
NETHERLAND, SEWELL & ASSOCIATES, INC.
Houston, Texas
March 22, 2000
<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 Item 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, 1999 and incorporated by reference into the Company's previously
filed Registration Statements on Form S-3, file number 333-78843 dated May 25,
1999 and Form S-8, file number 333-36977 dated October 1, 1997.
MILLER AND LENTS, LTD.
Houston, Texas
March 22, 2000
<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, 1999 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-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 15,502
<SECURITIES> 0
<RECEIVABLES> 47,232
<ALLOWANCES> 0
<INVENTORY> 969
<CURRENT-ASSETS> 64,785
<PP&E> 1,130,605
<DEPRECIATION> 520,489
<TOTAL-ASSETS> 678,483
<CURRENT-LIABILITIES> 136,004
<BONDS> 281,000
0
0
<COMMON> 239
<OTHER-SE> 217,351
<TOTAL-LIABILITY-AND-EQUITY> 678,483
<SALES> 150,580
<TOTAL-REVENUES> 151,727
<CGS> 0
<TOTAL-COSTS> 102,051
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 13,307
<INCOME-PRETAX> 36,369
<INCOME-TAX> 11,748
<INCOME-CONTINUING> 24,621
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 24,621
<EPS-BASIC> 1.03
<EPS-DILUTED> 0.95
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