##### Table of Contents



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 10-K þANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2004
OR
 o 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)
 Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
    
    22-2674487
(IRS Employer
Identification No.)
 1100 Louisiana, Suite 2000
Houston, Texas
(Address of Principal Executive Offices)
    
    77002-5215
(Zip Code)
 (713) 830-6800
(Registrants Telephone Number, including Area Code)  Securities Registered Pursuant to Section 12(b) of the Act: Name of EachTitle of Each Class
    
    Exchange on Which RegisteredCommon Stock, $.01 par value
    
    New York Stock Exchange7% Senior Subordinated Notes due 2013
 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
þ No o Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K
is not contained herein, and will not be contained, to 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. Yes þ No o Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of
the Act). Yes þ No o The aggregate market value of the voting stock held by non-affiliates of the registrant was
approximately $1,112,109,212, based on the closing sales price of $51.84 per share of the
registrants common stock as reported by on the New York Stock Exchange as of June 30, 2004, the
last business day of the registrants most recently completed second fiscal quarter. For purposes
of the preceding sentence only, all directors, executive officers and beneficial owners of ten
percent or more of the common stock are assumed to be affiliates. As
of February 22, 2005,
28,457,804 shares of common stock were outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrants Proxy Statement for the Annual Meeting of Stockholders to be held
April 26, 2005 are incorporated by reference into Part III of this Form 10-K.




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TABLE OF CONTENTS Forward-Looking
Statements and Other Information
    
    
    2Part I.
    
    
    4Items 1. and 2. Business and Properties
    
    
    4Item 3. Legal Proceedings
    
    
    21Item 4. Submission of Matters to a Vote of Security Holders
    
    
    21Part II.
    
    
    21Item 5. Market for the Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
    
    
    21Item 6. Selected Financial Data
    
    
    22Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    23Item 7A. Quantitative and Qualitative Disclosures About Market Risk
    
    
    37Item 8. Financial Statements and Supplemental Data
    
    
    38Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
    
    
    38Item 9A. Controls and Procedures
    
    
    38Item 9B. Other Information
    
    
    38Part III.
    
    
    39Item 10. Directors and Executive Officers of the Registrant
    
    
    39Item 11. Executive Compensation
    
    
    39Item 12. Security Ownership of Beneficial Owners and Management
    
    
    39Item 13. Certain Relationships and Related Transactions
    
    
    39Item 14. Principal Accounting Fees and Services
    
    
    40Part IV.
    
    
    40Item 15. Exhibits, Financial Statement Schedules
    
    
    40Signatures
    
    
    41Glossary of Natural Gas and Oil Terms
    
    
    G-1Index to Financial Statements
    
    
    F-1Amended Employment Agmt - Steven L. MuellerAmended Employment Agmt - John H. KarnesAmended Employment Agmt - James F. WestmorelandAmended Employment Agmt - Roger B. RiceCompensation Table for Officers and DirectorsComputation of Ratio of Earnings to Fixed ChargesConsent of Deloitte & Touche LLPConsent of Netherland, Sewell & AssociatesConsent of Miller and LentsCertification of CEO Pursuant to Section 302Certification of CFO Pursuant to Section 302Certification of CEO Pursuant to Section 906Certification of CFO Pursuant to Section 906
  -1-




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Forward-Looking Statements and Other Information This Annual Report on Form 10-K (Annual Report) and the documents we have incorporated by
reference into this Annual Report contain forward-looking statements as that term is defined in
Section 27A of the Securities Act of 1933, as amended (the Securities Act) and Section 21E of the
Securities Exchange Act of 1934, as amended (the Exchange Act). These statements use
forward-looking words such as anticipate, believe, continue, expect, estimate, intend,
may, plan, potential, predict, project, should, target, goal, objective or other
similar expressions and discuss forward-looking information. Forward-looking statements include
all statements under the caption Item 7. Managements Discussion and Analysis of Financial
Condition and Results of Operations involving the discussion of the following:  
    business strategy;
    natural gas and oil reserves;
    future production;
    expected realized natural gas and oil prices;
    expected costs and expenses;
    anticipated capital expenditures;
    future operating results;
    future cash flows and borrowings;
    pursuit of potential future acquisition opportunities;
    identified drilling locations; and
    sources of funding and the timing of exploration and development activities. Although we believe that these forward-looking statements are based on reasonable assumptions, our
expectations may not occur and we cannot guarantee that the anticipated future results will be
achieved. A number of factors could cause our actual future results to differ materially from
those anticipated or implied in the forward-looking statements. These factors include, among other
things:  
    the volatility of natural gas and oil prices;
    the requirement to take writedowns if natural gas and oil prices decline or if
our finding and development costs continue to increase;
    the relatively short production lives of our reserves;
    our ability to find, replace, develop and acquire natural gas and oil reserves;
    maturity of North American gas basins;
    acquisition and investment risks;
    our ability to meet our substantial capital requirements;
    our outstanding indebtedness;
    the uncertainty of estimates of natural gas and oil reserves and production rates;
    the inherent hazards and risks involved in our operations;
    dependence upon operations concentrated in three primary areas;
    drilling risks;
    our hedging activities;
    compliance with environmental and other governmental regulations;
    the competitive nature of our industry;
    weather risks and other natural disasters; and
    our customers ability to meet their obligations. -2-




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For additional discussion of these and other 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. We undertake no obligation
to publicly update or revise any forward-looking statements. In this Annual Report, unless the context requires otherwise, when we refer to we, us and
our, we are describing The Houston Exploration Company and our former sole subsidiary on a
consolidated basis. If you are not familiar with the natural gas and oil terms used in this Annual Report, please refer
to the explanations of the terms under the caption Glossary of Natural Gas and Oil Terms included
on pages G-1 through G-2. When we refer to equivalents, we are doing so to compare quantities of
oil with quantities of natural gas or to express these different commodities in a common unit. In
calculating equivalents, we use a generally recognized standard in which one barrel of oil is equal
to six thousand cubic feet of natural gas. -3-




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Part I. 
 Items 1. and 2. Business and Properties Overview of Our Business We are an independent natural gas and oil producer concentrating on growing reserves and production
through the exploration, development, exploitation and acquisition of natural gas and oil reserves
in North America. Approximately 94% of our proved reserves as of December 31, 2004 were natural
gas. Our principal operations are located in the following areas:  
    South Texas, where we are one of the largest natural gas producers along the
prolific Lobo Trend in Zapata, Webb and Jim Hogg Counties;
    Offshore in the Gulf of Mexico, where we pursue a range of activities with
exploration targeting predominantly deep shelf prospects below 15,000 feet on the Outer
Continental Shelf and exploitation focusing on development opportunities intended to
increase production from acquired properties;
    Arkoma Basin, of Arkansas and Oklahoma, where we have doubled production since
the end of 2002 through an active in-field drilling program enabled by a series of
successful, field-wide downspacing initiatives; and
    Rocky Mountains, where we commenced an aggressive lease acquisition campaign in
2003, with an initial focus in the Uinta Basin of Northeastern Utah and the DJ Basin in
Eastern Colorado, and where we currently are conducting exploration programs to test several
prospective natural gas fields. At December 31, 2004,
net proved reserves were 793 billion cubic feet equivalent or
Bcfe, with a
standardized measure of future net cash flows including income taxes, discounted at 10% per annum,
of $1.4 billion. Our reserves are fully engineered on an annual basis by independent petroleum
engineers. Approximately 63% of our proved reserves at December 31, 2004, were classified as
proved developed. As of December 31, 2004, we operated approximately 77% of our producing wells.
Daily production averaged 339 million cubic feet of natural gas equivalent or MMcfe in 2004. We were founded in December 1985 as a Delaware corporation and began exploring for natural gas and
oil on behalf of KeySpan Corporation. KeySpan, a member of the Standard & Poors 500 Index, is a
diversified energy provider whose principal natural gas distribution and electric generation
operations are located in the Northeastern United States. In September 1996, we completed our
initial public offering and sold approximately 31% of our shares to the public. Through three
separate transactions, the first in February 2003 and last in November 2004, KeySpan completely
divested of its investment in the common stock of our company. As of December 31, 2004, KeySpan no
longer owned any common stock of our company. Our corporate offices are located at 1100 Louisiana Street, Suite 2000, Houston, Texas 77002. Our
telephone number is (713) 830-6800. Business Strategy We strive to maximize shareholder value by growing reserves, production, cash flow and net asset
value on a per share basis while maintaining our financial flexibility and discipline. We
incorporate the following operating philosophies in executing our strategy:  
    Pursue a Balanced Growth Strategy.We pursue a strategy of exploiting our
existing reserves, exploring for new reserves and acquiring new properties. We invest in
exploitation and development projects intended to generate cash flows from which we can fund
future expansion opportunities. Founded as an exploration company, we supplement our
exploitation activities by continuing to invest in exploratory prospects. We enhance our
exploitation and exploration activities with acquisitions of new properties that we believe
offer significant unexploited reserve potential and that conform to our operating
philosophy.
    Focus on Natural Gas.By design, our assets are concentrated in natural gas
prone areas in the United States, and our production and reserve base is heavily weighted
toward natural gas. As of December 31, 2004, approximately 94% of our proved reserves were
natural gas and, for the year ended December 31, 2004, approximately 93% of our production
was natural gas. As a commodity, natural gas is more difficult to import into the United
States than oil and is therefore better insulated than oil from the competition of foreign
imports and geopolitical instability. Lease operating expense is typically lower for gas
properties than oil, allowing a higher cash margin. While we believe -4-




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that the growing demand for natural gas in the United States, measured against the maturing
domestic natural resource base, provides attractive pricing fundamentals for natural gas in
the foreseeable future, we have explored and intend to continue to explore opportunities to
balance our asset portfolio with additional oil reserves. Such activities depend on the
relative pricing outlook for the commodities, acquisition opportunities, and operational
considerations, including our objectives of shifting a greater portion of our operations
onshore, lowering our finding and development costs, and lengthening our reserve life.
    Maintain Significant Operating Control.Whenever possible, we prefer to operate
our properties as it gives us more control over the nature and timing of capital
expenditures and overall operating expenses. We currently operate approximately 77% of our
wells, with our average working interest as of December 31, 2004, of approximately 72%.
    Concentrate on Core Areas.Our strategy of focusing drilling activities on
properties in relatively concentrated areas, both onshore and offshore, permits us to more
efficiently utilize our base of geological, engineering, exploration and production
experience and expertise in these regions. By concentrating our operations, we can manage a
large asset base with a relatively small number of employees and can integrate additional
properties at relatively low incremental costs. At December 31, 2004, approximately 95% of
our reserves were located in three core areas: South Texas, the Gulf of Mexico and the
Arkoma Basin. We expect to continue our efforts to develop our Rocky Mountain operations
into a core area and plan to cultivate one or more new core areas where we believe we can
sustain our future growth.
    Strive to Be a Low Cost Producer.We strive to minimize our operating costs by
concentrating our assets within geographic areas where we can consolidate a relatively high
degree of operating control and capture operating efficiencies. Although we expect our
costs will increase in 2005, we believe that our operating structure provides us a
significant competitive advantage because it maximizes our margins and cash flows. For
2004, our lease operating expense was $0.45 per Mcfe.
    Employ Conservative Financial Policies.We typically fund our exploitation and
exploration activities out of cash flows from operations. Historically, we have funded
acquisitions through our revolving bank credit facility, focusing on prompt repayment in
order to minimize our debt service obligations. While our debt levels have historically
increased periodically in connection with acquisitions, and are expected to increase from
time to time in the future as we continue to make acquisitions, we strive to maintain
conservative debt levels in order to allow ourselves flexibility to continually review and
adjust our capital budgets during the year based on operational developments, commodity
prices, service costs, acquisition opportunities and numerous other factors. In the future,
we may issue common stock in connection with acquisitions, either initially as an element of
the transaction consideration or subsequently as part of a financing plan. In addition, we
employ an active hedging program designed to reduce our exposure to adverse commodity price
fluctuations and provide more predictable cash flows that allow us to plan and fund our
capital expenditures. -5-




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Properties and Operating Areas The table below summarizes certain data for our core operating areas for the year ended December
31, 2004. Activity and Balances as of or for the Year Ended December 31, 2004 Average
    
    
    
    
    
    
    Total
    
    
    PercentageDaily
    
    
    Total
    
    
    Proved
    
    
    Total ProvedProduction
    
    
    Production
    
    
    Reserves
    
    
    ReservesWells DrilledArea
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    Successful(MMcfe/d)
    
    
    (MMcfe)
    
    
    (MMcfe)
    
    
    
    
    
    
    (Gross)
    
    
    (Gross)South Texas
    
    
    142
    
    
    
    51,930
    
    
    
    326,815
    
    
    
    41
    %
    
    
    76
    
    
    
    56Gulf of Mexico
    
    
    153
    
    
    
    56,088
    
    
    
    291,477
    
    
    
    37
    %
    
    
    19
    
    
    
    15Arkoma Basin
    
    
    38
    
    
    
    13,735
    
    
    
    131,262
    
    
    
    17
    %
    
    
    79
    
    
    
    73Rocky Mountains
    
    
    1
    
    
    
    272
    
    
    
    22,116
    
    
    
    3
    %
    
    
    31
    
    
    
    28Other
    
    
    5
    
    
    
    1,960
    
    
    
    21,454
    
    
    
    2
    %
    
    
    6
    
    
    
    5Total
    
    
    339
    
    
    
    123,985
    
    
    
    793,124
    
    
    
    100
    %
    
    
    211
    
    
    
    177
 South Texas.Our South Texas properties are concentrated in the Charco, Haynes and South Trevino
Fields of Zapata County; the Alexander, Hubbard and South Laredo Fields of Webb County; and the
Northeast Thompsonville Field in Jim Hogg County. As of December 31, 2004, our South Texas
properties cover approximately 67,900 net acres and we own interests in 640 producing wells, 534 or
83% of which we operate. Our average working interest is 83%. Average well depth is between 8,000
to 12,500 feet with production from the Wilcox formations. When we acquired the Charco Field in July 1996, it had approximately 150 producing wells and
average daily production was 38 MMcfe per day, net to our interest. We expanded our existing
production and reserve base with the acquisition of the Alexander, Hubbard and South Laredo Fields
in December 2001, and again, in May 2002, with the acquisition of the Northeast Thompsonville
Field. During 2004, we expanded our acreage position in Zapata County with the acquisition of
undeveloped acreage in the Cisco-Benavides Field for $2.7 million, and purchased incremental
working interests in several producing wells in the North East Thompsonville Field for $3.3
million. In total, our net South Texas production has more than tripled since July 1996, to an
average of 142 MMcfe per day during 2004, which compares to 140 MMcfe per day in 2003. Over the
course of eight and a half years, we have drilled 284 successful wells at an average success rate
of 80%, produced 293 Bcfe and added 507 Bcfe in reserves through drilling and acquisitions. As we
see our South Texas properties begin to mature and production growth to minimize, we plan to
maintain production at existing levels while improving drilling and operating efficiencies in an
effort to control finding and operating costs. Gulf of Mexico.Our offshore properties are located in the shallow waters of the Outer Continental
Shelf. Our key producing properties are located in the western and central Gulf of Mexico and
include the Mustang Island, High Island, East Cameron, Vermilion and West Cameron areas. In
October 2003, we added to our existing production base through the acquisition of 11 producing
fields in the central Gulf of Mexico. The properties were purchased for a net $147.5 million and
had estimated proved reserves of 88.5 Bcfe at October 15, 2003. During the second half of 2004, we
again added to our offshore shore production base through two producing property acquisitions. On
a combined basis, the properties were purchased for a net $139.8 million, had estimated proved
reserves of 76.9 Bcfe at acquisition, and covered 12 blocks in the Central Gulf of Mexico. As of
December 31, 2004, we hold interests in 142 blocks in federal and state waters, of which 78 are
developed. As of December 31, 2004, we operated 45 of our developed blocks, which accounted for
approximately 70% of our offshore production during 2004. We have a total of 92 producing
platforms and production caissons, of which we operate 60. During 2004, production from our Gulf
of Mexico properties averaged 153 MMcfe per day. During the last two years, our offshore operation has evolved from almost exclusively an
exploration focus to a blended enterprise with substantial elements of new project exploration and
exploitation activities aimed at maximizing production from older, previously produced fields
acquired from third parties. Going forward, we expect to continue to evaluate the profitability of
each of our core operating areas and shift our emphasis between exploration and exploitation in
response to operational developments and economic factors. Arkoma Basin.Our Arkoma Basin properties are located in two primary areas: the
Chismville/Massard Field located in Logan and Sebastian Counties of Arkansas and the Wilburton and
South Panola Fields located in Latimer County, Oklahoma. At December 31, 2004, we had
approximately 35,400 net acres under lease and we owned working interests in 349 producing natural
gas wells, 232 of which we operated. Wells average a depth of 5,500 feet and production is from
the Atoka formation. As a result of continued downspacing of in-field drilling by the Arkansas Oil
and Gas Commission, first in September 2002 from 680 acres to 160 acres per well and again in
September 2003 from 160 acres per well to 80 acres per well, we were able to increase the number of
wells drilled during 2004 to 79 wells from 51 wells drilled in 2003 and 24 -6-




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wells drilled in 2002. During 2004, average daily production increased by 65% from 23 MMcfe per
day during 2003 to 38 MMcfe per day during 2004. Acquisition values in the Arkoma Basin have
impeded the expansion of our operations beyond our existing acreage position and, as a result, our
current activities are focused on the substantial number of in-field drilling opportunities within
our existing acreage. The Arkansas Oil and Gas Commission has approved downspacing from 320 acres
per well in 2002 to approximately 40 acres per well as of December 2004, facilitating the expansion
of our in-field drilling opportunities. Rocky Mountains.During 2003, we began a lease acquisition initiative in the Rocky Mountain region,
initially leasing more than 200,000 net undeveloped acres encompassing portions of the Uinta Basin
of Northeastern Utah, the Williston Basin spanning North and South Dakota, the Crazy Mountain Basin
of Southwestern Montana, and the Green River Basin of Southwestern Wyoming. Our primary focus for
2004 was proving up and delineating portions of our Uinta Basin acreage, where we drilled a total
of 26 wells, of which 25, or 96%, were successful. At December 31, 2004, 19 of our Uinta wells
were shut-in and awaiting approvals for pipeline right-of-ways. In January 2005, 11 of the 19
Uinta wells came on-line with estimated initial production rates, on a combined basis, of
approximately 8 MMcfe per day, net to our interest. In August 2004, we acquired approximately 330,000 net acres in the DJ Basin of Eastern Colorado.
During the second half of 2004, we drilled four wells and successfully completed three or 75%.
Pipeline installation and hookup are expected for these DJ Basin wells during 2005. At December
31, 2004, we had estimated proved reserves in the Rocky Mountains of 22 Bcfe and our daily
production averaged 4 MMcfe per day, net to our interests. Other. As of December 31, 2004, other includes our East Texas properties and two fields located
in Central Mississippi. The East Texas properties are located in the Willow Springs Field in Gregg
County, Texas and include interests in 24 wells, all of which we operate. The Mississippi
properties were acquired in October 2004 as part of our acquisition of 10 offshore blocks in the
shallow waters of the Central Gulf of Mexico and consist of two fields containing three producing
wells, all of which are non-operated. The Wausau Field is located in Wayne County and the Oakvale
Dome Field is located in Jefferson Davis County. In addition to these properties, we have
interests or rights of an immaterial nature in other prospective properties or projects with
respect to which no reserves are currently associated, and may make future investments of
immaterial amounts in similar such projects from time to time in the future. 2004 Divestures In February 2004, we completed the sale of our South Louisiana properties for net proceeds of $13.1
million. The properties were located in the South Lake Arthur and Lake Pagie Fields located
primarily in Vermilion and Terrebonne Parishes. The properties represented 12.3 Bcfe proved
reserves as of December 31, 2003, and included interests in 33 gross (9.5 net) producing wells and
covered approximately 6,300 gross (2,300 net) acres. Production averaged 5 MMcfe/day during 2003. In June 2004, we divested of our Appalachian Basin assets as part of an asset exchange transaction
with KeySpan. The properties were located primarily in central West Virginia and included the
Belington, Clarksburg and Seneca Upshur Fields located in Barbour, Randolph, Upshur and Mingo
Counties of West Virginia. Included were the assets acquired on December 31, 2003 from EnerVest
East Limited Partnership that were located adjacent to our existing base in the Crawford and
Pennsboro Fields in Lewis, Harrison, Tyler and Ritchie Counties of West Virginia and the Waynesburg
and Yatesboro Fields in Greene and Armstrong Counties of southwestern Pennsylvania. Based on
internal estimates at June 1, 2004, the properties had 51.2 Bcfe of proved reserves with an agreed
upon fair value of $60 million. Our average daily production was approximately 8 MMcfe/day at May
21, 2004. We had approximately 207,000 gross (129,000 net) acres under lease and owned working
interests in approximately 1,414 gross (1,035 net) wells, of which we operated approximately 92% of
the wells. -7-




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Natural Gas and Oil Reserves The following table summarizes the estimates of historical net proved reserves as of December 31,
2004, 2003 and 2002, and the present values attributable to these reserves at these dates. The
reserve data and present values were fully engineered by Netherland, Sewell & Associates, Inc. or
Miller and Lents, Ltd., independent petroleum engineering consultants. As of December 31,Net Proved Reserves:
    
    2004
    
    
    2003
    
    
    2002(in thousands)Natural gas (MMcf)
    
    
    749,114
    
    
    
    709,883
    
    
    
    610,409Oil and natural gas liquids (MBbls)
    
    
    7,335
    
    
    
    7,481
    
    
    
    6,533Total (MMcfe)
    
    
    793,124
    
    
    
    754,769
    
    
    
    649,607Standardized
measure of discounted future net cash flows
(1)
    
    $
    1,440,055
    
    
    $
    1,504,406
    
    
    $
    1,058,064
   (1)
    
    The standardized measure of discounted future net cash flows has been
calculated in accordance with SFAS 69, Disclosures About Oil and Gas Producing
Activities (see Note 12  Supplemental Information on Natural Gas and Oil Exploration,
Development and Production Activities (Unaudited)) and, in accordance with current SEC
guidelines, does not include estimated future cash flows from our hedging program. In accordance with applicable requirements of the SEC, we estimate net proved reserves and future
net revenues using sales prices estimated to be in effect as of the date we make the reserve
estimates. Sales price estimates are held constant throughout the life of the properties, except to
the extent a contract specifically provides for escalation. Natural gas and oil prices have
fluctuated widely in recent years. Volatility is expected to continue and price fluctuations
directly affect estimated quantities of proved reserves and future net revenues. There are numerous
uncertainties inherent in estimating quantities of proved reserves and in projecting future rates
of production and timing of development expenditures, including many factors beyond our control. The reserve data contained in this Annual Report 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 prepared by one engineer may vary from those prepared by another. Estimates are subject
to revision based on numerous factors including reservoir performance, prices and economic
conditions. In addition, results of drilling, testing and actual production subsequent to the date
of estimate may justify revision of that estimate. Revisions to prior estimates may be material.
Reserve estimates are often different from the quantities of natural gas and oil that we are
ultimately able to recover and are highly dependent upon the accuracy of the underlying
assumptions. Our estimated proved reserves have not been filed with or included in reports to any
federal agency. -8-




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Drilling Activity We engage in numerous drilling activities on properties presently owned by us and intend to drill
or develop other properties we may acquire in the future. The following table sets forth the
results of our drilling activities for the years ended December 31, 2004, 2003 and 2002. Gross
wells are the sum of all wells in which we owned an interest. Net wells are the sum of our working
interests in the gross wells. Exploratory
    
    
    Development
    
    
    Total Wells DrilledSuccessful

    Dry
    
    
    Successful

    Dry
    
    
    Successful

    Dry

    TotalGross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net2004South Texas
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    1.0
    
    
    
    56
    
    
    
    54.6
    
    
    
    19
    
    
    
    18.0
    
    
    
    56
    
    
    
    54.6
    
    
    
    20
    
    
    
    19.0
    
    
    
    76
    
    
    
    73.6Gulf of Mexico
    
    
    3
    
    
    
    1.4
    
    
    
    4
    
    
    
    2.2
    
    
    
    12
    
    
    
    9.3
    
    
    
    
    
    
    
    
    
    
    
    15
    
    
    
    10.7
    
    
    
    4
    
    
    
    2.2
    
    
    
    19
    
    
    
    12.9Arkoma Basin
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    73
    
    
    
    45.8
    
    
    
    6
    
    
    
    3.0
    
    
    
    73
    
    
    
    45.8
    
    
    
    6
    
    
    
    3.0
    
    
    
    79
    
    
    
    48.8Rocky Mountains
    
    
    26
    
    
    
    25.4
    
    
    
    3
    
    
    
    2.3
    
    
    
    2
    
    
    
    2.0
    
    
    
    
    
    
    
    
    
    
    
    28
    
    
    
    27.4
    
    
    
    3
    
    
    
    2.3
    
    
    
    31
    
    
    
    29.7Other
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    0.5
    
    
    
    5
    
    
    
    5.0
    
    
    
    
    
    
    
    
    
    
    
    5
    
    
    
    5.0
    
    
    
    1
    
    
    
    0.5
    
    
    
    6
    
    
    
    5.5Total areas 2004
    
    
    29
    
    
    
    26.8
    
    
    
    9
    
    
    
    6.0
    
    
    
    148
    
    
    
    116.7
    
    
    
    25
    
    
    
    21.0
    
    
    
    177
    
    
    
    143.5
    
    
    
    34
    
    
    
    27.0
    
    
    
    211
    
    
    
    170.52003South Texas
    
    
    3
    
    
    
    3.0
    
    
    
    3
    
    
    
    3.0
    
    
    
    53
    
    
    
    51.3
    
    
    
    18
    
    
    
    17.5
    
    
    
    56
    
    
    
    54.3
    
    
    
    21
    
    
    
    20.5
    
    
    
    77
    
    
    
    74.8Gulf of Mexico
    
    
    6
    
    
    
    2.4
    
    
    
    8
    
    
    
    3.6
    
    
    
    3
    
    
    
    2.0
    
    
    
    
    
    
    
    
    
    
    
    9
    
    
    
    4.4
    
    
    
    8
    
    
    
    3.6
    
    
    
    17
    
    
    
    8.0Arkoma Basin
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    0.4
    
    
    
    46
    
    
    
    28.6
    
    
    
    4
    
    
    
    2.5
    
    
    
    46
    
    
    
    28.6
    
    
    
    5
    
    
    
    2.9
    
    
    
    51
    
    
    
    31.5Other
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    2.0
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    2.0
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    2.0Total areas 2003
    
    
    9
    
    
    
    5.4
    
    
    
    12
    
    
    
    7.0
    
    
    
    104
    
    
    
    83.9
    
    
    
    22
    
    
    
    20.0
    
    
    
    113
    
    
    
    89.3
    
    
    
    34
    
    
    
    27.0
    
    
    
    147
    
    
    
    116.32002South Texas
    
    
    2
    
    
    
    2.0
    
    
    
    1
    
    
    
    1.0
    
    
    
    52
    
    
    
    52.0
    
    
    
    8
    
    
    
    8.0
    
    
    
    54
    
    
    
    54.0
    
    
    
    9
    
    
    
    9.0
    
    
    
    63
    
    
    
    63.0Gulf of Mexico
    
    
    6
    
    
    
    2.0
    
    
    
    1
    
    
    
    0.4
    
    
    
    3
    
    
    
    1.1
    
    
    
    
    
    
    
    
    
    
    
    9
    
    
    
    3.1
    
    
    
    1
    
    
    
    0.4
    
    
    
    10
    
    
    
    3.5Arkoma Basin
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    0.8
    
    
    
    21
    
    
    
    12.0
    
    
    
    2
    
    
    
    1.4
    
    
    
    21
    
    
    
    12.0
    
    
    
    3
    
    
    
    2.2
    
    
    
    24
    
    
    
    14.2Total areas 2002
    
    
    8
    
    
    
    4.0
    
    
    
    3
    
    
    
    2.2
    
    
    
    76
    
    
    
    65.1
    
    
    
    10
    
    
    
    9.4
    
    
    
    84
    
    
    
    69.1
    
    
    
    13
    
    
    
    11.6
    
    
    
    97
    
    
    
    80.7
 As of December 31, 2004, we were drilling or participating in the drilling of 22 gross (18.2 net)
wells. Of these wells, through February 22, 2005, 17 gross (15.9 net) wells have been determined
to be successful and 2 gross (1.5 net) were unsuccessful, with the remaining 3 gross (0.8 net) wells
still in progress. Productive Wells The following table sets forth the number of productive wells in which we owned an interest as of
December 31, 2004. Productive wells consist of producing wells and wells capable of production,
including 28 wells, 22 of which were located in the Rocky Mountains, awaiting connections. Wells
that are completed in more than one producing horizon are counted as one well. The operator is
the designated party under the terms of an operating agreement that manages the day-to-day
operations of the well. As of December 31, 2004Natural Gas Wells
    
    
    Oil Wells
    
    
    Total WellsOperated
    
    
    Non-Operated
    
    
    Operated
    
    
    Non-OperatedGross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetSouth Texas
    
    
    534
    
    
    
    517.7
    
    
    
    106
    
    
    
    14.8
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    640
    
    
    
    532.5Gulf of Mexico
    
    
    101
    
    
    
    81.6
    
    
    
    48
    
    
    
    15.0
    
    
    
    16
    
    
    
    12.1
    
    
    
    6
    
    
    
    1.1
    
    
    
    171
    
    
    
    109.8Arkoma Basin
    
    
    232
    
    
    
    159.2
    
    
    
    117
    
    
    
    26.5
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    349
    
    
    
    185.7Rocky Mountains
    
    
    36
    
    
    
    34.1
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    36
    
    
    
    34.1Other
    
    
    24
    
    
    
    16.9
    
    
    
    3
    
    
    
    1.7
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    27
    
    
    
    18.6Total
    
    
    927
    
    
    
    809.5
    
    
    
    274
    
    
    
    58.0
    
    
    
    16
    
    
    
    12.1
    
    
    
    6
    
    
    
    1.1
    
    
    
    1,223
    
    
    
    880.7
 -9-




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##### Table of Contents



Acreage Data The following table sets forth the approximate developed and undeveloped acreage in which we held a
leasehold mineral or other interest as of December 31, 2004. 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 the acreage contains
proved reserves. Gulf of Mexico acreage includes leases in federal and state waters. As of December 31, 2004Undeveloped
    
    
    Developed
    
    
    Total AcreageGross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetSouth Texas
    
    
    17,467
    
    
    
    14,952
    
    
    
    67,670
    
    
    
    52,901
    
    
    
    85,137
    
    
    
    67,853Gulf of Mexico
    
    
    225,534
    
    
    
    161,455
    
    
    
    303,444
    
    
    
    182,814
    
    
    
    528,978
    
    
    
    344,269Arkoma Basin
    
    
    18,958
    
    
    
    7,088
    
    
    
    59,707
    
    
    
    28,322
    
    
    
    78,665
    
    
    
    35,410Rocky Mountains
    
    
    665,876
    
    
    
    505,001
    
    
    
    7,337
    
    
    
    7,337
    
    
    
    673,213
    
    
    
    512,338Other
    
    
    
    
    
    
    
    
    
    
    5,319
    
    
    
    3,351
    
    
    
    5,319
    
    
    
    3,351Total
    
    
    927,835
    
    
    
    688,496
    
    
    
    443,477
    
    
    
    274,725
    
    
    
    1,371,312
    
    
    
    963,221
 Undeveloped Acreage Expirations The table below summarizes by year and area our undeveloped acreage scheduled to expire in the next
five years. As of December 31, 20042005
    
    
    2006
    
    
    2007
    
    
    2008
    
    
    2009Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetSouth Texas
    
    
    5,588
    
    
    
    4,927
    
    
    
    5,313
    
    
    
    3,029
    
    
    
    4,783
    
    
    
    4,783
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Gulf of Mexico
    
    
    39,871
    
    
    
    36,538
    
    
    
    31,137
    
    
    
    23,909
    
    
    
    46,181
    
    
    
    37,921
    
    
    
    62,824
    
    
    
    35,215
    
    
    
    47,280
    
    
    
    28,324Arkoma Basin
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,816
    
    
    
    924
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Rocky Mountains
    
    
    1,601
    
    
    
    1,601
    
    
    
    208,113
    
    
    
    146,659
    
    
    
    112,841
    
    
    
    88,823
    
    
    
    148,332
    
    
    
    123,367
    
    
    
    27,318
    
    
    
    16,720Total
    
    
    47,060
    
    
    
    43,066
    
    
    
    244,563
    
    
    
    173,597
    
    
    
    166,621
    
    
    
    132,451
    
    
    
    211,156
    
    
    
    158,582
    
    
    
    74,598
    
    
    
    45,044
 Marketing and Customers We market the majority of the natural gas and oil production from properties we operate for both
our account and the account of the other working interest owners in these properties. We typically
sell a substantial portion of our production under short-term (usually one-month) fixed price
contracts tied to a local index. We do not have any material long-term, fixed price sales
contracts. The remaining portion of our production is sold on a daily basis into local spot
markets in order to accommodate fluctuations in daily production volumes. We normally sell
production to a relatively small number of customers, as is customary in the exploration,
development and production business. However, based on the current demand for natural gas and oil,
we believe that the loss of any one or all of our major purchasers would not have a material
adverse effect on our financial condition and results of operations. For a list of our purchasers
that accounted for 10% or more of our natural gas and oil revenues during the preceding last three
calendar years, see Notes to Consolidated Financial Statements  Note 8  Sales to Major
Customers. We enter into hedging transactions with unaffiliated third parties for portions of our natural gas
production to achieve more predictable cash flows and to reduce our exposure to short-term
fluctuations in gas prices. For a more detailed discussion, see Item 7. Managements Discussion
and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and
Qualitative Disclosures About Market Risk. We incur gathering and transportation expenses to move our natural gas from the wellhead to a
purchaser-specified delivery point. These expenses vary based on the volume and distance shipped,
and the fee charged by the third party transporter. We do not have any material transportation
agreements and we have not contracted for firm capacity for which we would pay monthly demand
charges. Our natural gas and oil are transported through third party gathering systems and
pipelines. Transportation space on these gathering systems and pipelines is occasionally limited
and at times unavailable because of repairs or improvements, or as a result of priority
transportation agreements with other gas shippers. While our ability to market our natural gas has
only been infrequently limited or delayed, if transportation space is restricted or is unavailable,
our cash flow from the affected properties could be adversely affected. See the section entitled
Risk Factors  Our business depends on oil and natural gas transportation facilities that are
owned by others. -10-




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##### Table of Contents



Title to Properties As is customary in the oil and gas industry, we initially conduct only a cursory review of the
title to undeveloped acreage in farm-out agreements and natural gas and oil leases. Prior to the
commencement of drilling operations, we conduct a thorough title examination and perform curative
work with respect to significant defects. To the extent title opinions or other investigations
reflect title defects, we, rather than the seller of the undeveloped property, are typically
responsible for curing any title defects at our expense. If we 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, we could suffer a loss of our entire investment in the property. Prior to completing an
acquisition of producing natural gas and oil leases, we perform title reviews on the most
significant leases and, depending on the materiality of properties, we may obtain a title opinion.
Our natural gas and oil properties are subject to customary royalty and other interests, liens for
current taxes and other burdens which we believe do not materially interfere with the use of or
affect our carrying value of the properties. Competition We encounter intense competition from other oil and gas companies in all areas of our operations,
including the acquisition of additional properties and acreage. This competition is intensifying
in response to rising natural gas price levels and the natural maturation of several of our key
fields. Our competitors include major integrated oil and gas companies and numerous independent
oil and gas companies, individuals and drilling and income programs. Many of our competitors are
large, well-established companies with substantially greater capital resources than our own and
which, in many instances, have been engaged in the oil and gas business for a much longer time than
we have. Our ability to acquire additional properties and to discover new reserves in the future
will be dependent upon our ability to evaluate and select suitable properties and to consummate
transactions in this highly competitive environment. Seasonal Nature of Business Generally, but not always, the demand for natural gas increases during the winter months as a
result of heating applications and decreases during the summer months. Seasonal anomalies such as
mild winters or hot summers sometimes lessen this fluctuation. In addition, as the industrial use
of natural gas has expanded in recent years, weather related demand and seasonal fluctuations are
diminishing. However, seasonal weather conditions, such as tropical weather in the Gulf of Mexico
and winter weather in the Rocky Mountain region can pose challenges for meeting our well drilling
and production objectives. Regulation The oil and gas industry is extensively regulated by numerous federal, state and local authorities,
including Native American tribes. 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, and Native American tribes 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 our cost of doing business and, consequently, affects
our profitability, generally, these burdens do not appear to affect us any differently or to any
greater or lesser extent than they affect other companies in the industry with similar types,
quantities and locations of production. Drilling and Production. Our operations are subject to various types of regulation at federal,
state and local levels. These types of regulation include requiring permits for the drilling of
wells, drilling bonds and reports concerning operations. Most states, and some counties,
municipalities and Native American tribes, in which we operate also regulate one or more of the
following:  
    the location of wells;
    the method of drilling and casing wells;
    the rates of production or allowables;
    the surface use and restoration of properties upon which wells are drilled; and
    the plugging and abandoning of wells. -11-




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##### Table of Contents



State laws regulate the size and shape of drilling and spacing units or proration units governing
the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to
facilitate exploration while other states rely on voluntary pooling of lands and leases. In some
instances, forced pooling or unitization may be implemented by third parties and may reduce our
interest in the unitized properties. In addition, state conservation laws establish maximum rates
of production from oil and gas wells, generally prohibit the venting or flaring of natural gas and
impose requirements regarding the ratability of production. These laws and regulations, may limit
the amount of oil and gas we can produce from our wells or limit the number of wells or the
locations at which we can drill. Our properties located in federal waters are regulated by the
Minerals Management Service and are not subject to regulation by state agencies. We conduct our operations in the Gulf of Mexico on oil and natural gas leases that are granted by
the U.S. federal government and are administered by the Minerals Management Service. The Minerals
Management Service issues leases through competitive bidding. The lease contracts contain
relatively standardized terms and require compliance with detailed regulations of the Minerals
Management Service. For offshore operations, lessees must obtain Minerals Management Service
approval for exploration plans and development and production plans prior to the commencement of
the 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 Minerals Management Service prior to the commencement of drilling. In certain instances,
substantial Certificates of Financial Responsibility or other acceptable assurances must be
provided and maintained under the federal Oil Pollution Act of 1990. The Minerals Management Service promulgates and enforces regulations that require offshore
production facilities located on the Outer Continental Shelf to meet stringent engineering,
construction, and safety specifications, that impose strong restrictions on the flaring or venting
of natural gas, that prohibit the burning of liquid hydrocarbons and oil without prior
authorization, and that govern the plugging and abandonment of offshore wells and removal of
offshore production facilities. To cover the various obligations of lessees on the Outer
Continental Shelf, the Minerals Management Service generally requires that lessees post and
maintain substantial bonds or other acceptable assurances that these obligations will be met. The
Outer Continental Shelf Lands Act may generally impose liabilities on us for our offshore
operations conducted on federal leases for clean-up costs and damages caused by pollution resulting
from our operations. Under circumstances such as conditions deemed to be a threat or harm to the
environment, the Minerals Management Service may suspend or terminate any of our operations in the
affected area. Environmental Matters and Regulation General. Our operations are subject to and must comply with the same federal, state and local laws
and regulations governing the discharge of materials into the environment or otherwise relating to
environmental protection as other companies in the oil and gas exploration and production industry.
These laws and regulations may:  
    require the acquisition of a permit before drilling commences;
    require the installation of expensive pollution control measures;
    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 lands lying within wilderness, wetlands
and other protected areas;
    require remedial measures to prevent pollution from former operations, such as
pit closure and plugging of abandoned wells; and
    impose substantial liabilities for pollution resulting from our operations. These laws, rules and regulations may also restrict the rate of oil and natural gas production
below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry
increases the cost of doing business in the industry and consequently affects profitability.
Additionally, Congress and the federal and state agencies frequently revise the environmental laws
and regulations. Any changes that result in more stringent and costly waste handling, disposal and
clean-up requirements could have a significant impact on the oil and gas industrys operating
costs, including ours. We believe that we substantially comply with all current applicable
environmental laws and regulations and that our continued compliance with existing requirements
will not have a material adverse impact on our financial condition and results of operations.
However, we cannot predict the passage of or quantify the potential impact of more stringent future
laws and regulations at this time. For the year ended December 31, 2004, we did not incur any
material capital expenditures for environmental control facilities. As of the date of our Annual
Report, we are not aware of any environmental issues or claims that will require material
expenditures during 2005 or that will have a material impact on our financial position or results
of operations. -12-




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##### Table of Contents



The most significant of these environmental laws and regulations include, among others, the: Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, or RCRA,
affects oil and gas production activities by imposing regulations on the generation,
transportation, treatment, storage, disposal and cleanup of hazardous wastes and on the disposal
of non-hazardous wastes. Under the auspices of the Environmental Protection Agency, or the EPA, the
individual states administer some or all of the provisions of the Resource Conservation and
Recovery Act, sometimes in conjunction with their own, more stringent requirements. Drilling
fluids, produced waters, and most of the other wastes associated with the exploration, development,
and production of crude oil, natural gas, or geothermal energy constitute solid wastes, which are
regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that
the EPA or the individual states will not adopt more stringent requirements for the handling of
non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation.
Indeed, legislation has been proposed from time to time in Congress to recategorize certain oil and
gas exploration and production wastes as hazardous wastes. We believe that we are currently in substantial compliance with the requirements of the Resource
Conservation and Recovery Act and related state and local laws and regulations and that we hold all
necessary and up-to-date permits, registrations and other authorizations to the extent that our
operations require them under the Resource Conservation and Recovery Act. Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive
Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund
law, imposes joint and several liability, without regard to fault or legality of conduct, on
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 site
where the release occurred and companies that disposed or arranged for the disposal of the
hazardous substance. CERCLA also authorizes the EPA and affected parties to respond to threats to
the public health or the environment and to seek recovery from responsible classes of persons for
the costs of the response actions. In the course of our operations, we generate wastes that may fall within CERCLAs definition of
hazardous substances. Therefore, governmental agencies or third parties may seek to hold us
responsible under CERCLA for all or part of the costs to clean up sites at which such hazardous
substances have been deposited. As of the date of our report, however, we have no knowledge of
having been named by the EPA or alleged by any third party as being responsible for costs and
liability associated with alleged releases of any hazardous substance at any superfund site. Oil Pollution Act. The Oil Pollution Act imposes on responsible parties strict, joint and several,
and potentially unlimited liability for removal costs and other damages caused by an oil spill
covered by the Oil Pollution Act and offers few defenses to such liability. The Oil Pollution Act
also requires the lessee of an offshore area or a permittee whose operations take place within a
covered offshore facility to establish and maintain financial responsibility of at least $35
million, which may be increased to $150 million for facilities with large worst-case spill
potentials and under other circumstances, to cover liabilities related to an oil spill for which
the lessee or permittee of the offshore area is statutorily responsible. Owners of multiple
facilities are required to maintain financial responsibility for only the facility with the largest
potential worst-case spill. We have received certification from the Minerals Management Service
that due to our financial status, we are able to cover a minimum of $35 million per occurrence and
because we do not have major oil producing facilities, the maximum certification of $150 million in
coverage is not currently required. As such, we currently believe we are in substantial compliance
with the financial responsibility provisions of the Oil Pollution Act. Federal Water Pollution Control Act/Clean Water Act. The Federal Water Pollution Control Act or
Clean Water Act and related state laws provide varying civil and criminal penalties and liabilities
for the unauthorized discharge of petroleum products and other pollutants to surface waters. The
federal discharge permitting program also prohibits the discharge of produced water, sand and other
substances related to the oil and gas industry to coastal waters. Regulations governing water
discharges also impose other requirements, such as the obligation to prepare spill response plans.
We currently believe that we are in substantial compliance with all pollutant, wastewater, and
stormwater discharge regulations and that we hold all necessary and valid permits, other required
authorizations, and spill response plans for the discharge of such materials from our operations. Federal Clean Air Act. The Federal Clean Air Act restricts the emission of air pollutants and
affects both onshore and offshore oil and gas operations. New facilities may be required to obtain
permits before work can begin, and existing facilities may be required to incur capital costs in
order to remain in compliance. In addition, EPA has developed and continues to develop more
stringent regulations governing emissions of toxic air pollutants. These regulations may increase
the costs of compliance for some facilities. We currently believe that we are in substantial
compliance with all air emissions regulations and that we hold all necessary and valid construction
and operating permits for our operations. -13-




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##### Table of Contents



In 1997, numerous countries participated in an international conference under the United Nations
Framework Convention on Climate Change and concluded an agreement, known as the Kyoto Protocol.
The Protocol became effective February 14, 2005, and will require reductions of certain emissions
that contribute to atmospheric levels of greenhouse gases. The United States has not ratified the
Protocol but may in the future. Presently, it is not possible to accurately estimate the costs we
could incur to comply with any laws or regulations developed to achieve such emissions reductions,
but such expenditures could be substantial. Legislation continues to be introduced in Congress and development of regulations continues in the
Department of Homeland Security and other agencies concerning the security of industrial
facilities, including oil and gas facilities. Our operations may be subject to such laws and
regulations. Presently, it is not possible to accurately estimate the costs we could incur to
comply with any such facility security laws or regulations, but such expenditures could be
substantial. Natural Gas Sales Transportation.Historically, federal legislation and regulatory controls have
affected the price of the natural gas we produce and the manner in which we market our production.
The Federal Energy Regulatory Commission, or 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 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been
enacted which have resulted in the complete removal of all price and non-price controls for sales
of domestic natural gas sold in first sales, which include all of our sales of our own
production. FERC also regulates interstate natural gas transportation rates and service conditions, which
affects the marketing of natural gas that we produce, as well as the revenues we receive for sales
of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule
makings that significantly fostered competition in the business of transporting and marketing gas.
Today, interstate pipeline companies are required to provide nondiscriminatory transportation
services to producers, marketers and other shippers, regardless of whether such shippers are
affiliated with an interstate pipeline company. 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. However, the
natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee
that the less stringent regulatory approach recently pursued by FERC and Congress will continue
indefinitely into the future nor can we determine what affect, if any, future regulatory changes
might have on our natural gas related activities. Under FERCs current regulatory regime, transmission services must be provided on an open-access,
non-discriminatory basis at cost-based rates or at market-based rates if the transportation market
at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional
transmission services, is regulated by the states onshore and in state waters. In offshore Federal
waters, gathering is regulated by FERC under the Outer Continental Shelf Lands Act. The Outer
Continental Shelf Lands Act requires open access and non-discriminatory rates, but does not provide
for cost-based rates. Although its policy is still in flux, FERC has recently reclassified certain
jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the
tendency to increase our costs of getting gas to point-of-sale locations. -14-




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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, our revenues are highly dependent on the price of,
and demand for, natural gas and oil. Even relatively modest changes in natural gas and oil 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 may fluctuate widely 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:  
    the domestic and foreign supply of natural gas and oil;
    weather conditions;
    the price of foreign imports;
    overall domestic and global economic conditions;
    terrorist attacks or military conflicts;
    political and economic conditions in oil producing countries;
    the ability of members of the Organization of Petroleum Exporting Countries to
agree to and maintain oil price and production controls;
    the level of consumer product demand;
    speculation in the commodity futures markets;
    technological advances affecting energy consumption;
    domestic and foreign governmental regulations, including regulations imposed by Native American tribes;
    approvals, proximity and capacity of natural gas and oil pipelines and other transportation facilities; and
    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, which may
result in a material decline in our revenues. We may be required to take additional writedowns if natural gas and oil prices decline. We may 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. We utilize the full cost method of accounting for natural gas and oil exploration and development
activities. Under full cost accounting, we are required by SEC regulations to perform a ceiling
test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or
ceiling, of the book value of our natural gas and oil properties that is equal to the expected
after tax present value (discounted at 10%) of the future net cash flows from proved reserves,
including the effect of cash flow hedges, calculated using prevailing prices on the last day of the
period. If the net book value of our natural gas and oil properties (reduced by any related net
deferred income tax liability and asset retirement obligation) exceeds our ceiling limitation, SEC
regulations require us to impair or writedown the book value of our natural gas and oil
properties. Depending on the magnitude of any future impairments, a ceiling test writedown could
significantly reduce our income, or produce a loss. As ceiling test computations involve the
prevailing price on the last day of the quarter, it is impossible to predict the timing and
magnitude of any future impairments. The book value of our proved natural gas and oil properties
increased in 2004 as a function of our higher acquisition, exploration and development costs for
the year and the increase in future development costs associated with reserves added during the
year. To the extent our finding and development costs continue to increase, we will become more
susceptible to ceiling test writedowns in low price environments. Lower natural gas and oil prices could negatively impact our ability to borrow. The amount of borrowings available to us under our revolving bank credit facility is
determined by reference to a borrowing base. The amount of our borrowing base is established by
our banks and is primarily a function of the quantity and value of our reserves. Our borrowing
base is re-determined at least twice a year to take into account changes in our reserve base and
prevailing commodity prices. Our current borrowing base is $400 million. Commodity prices can
affect both the value as well as the quantity of our reserves for borrowing base purposes as
certain reserves may not be economic -15-




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at lower price levels. Additionally, the indenture governing our 7% senior subordinated notes due
2013 conditions our ability to incur additional indebtedness on our satisfaction of tests relating
to earnings before interest, taxes and depreciation, depletion and amortization expense and
consolidated net tangible assets (as defined in the indenture), both of which are sensitive to
commodity prices. Consequently, the amount of borrowing available to us under our revolving bank
credit facility as well as our ability to incur additional indebtedness under our senior
subordinated notes could be adversely affected by extended periods of low commodity prices. The high-rate production characteristics of our properties subject us to high reserve replacement
needs and require significant capital expenditures to replace our reserves at a faster rate than
companies whose reserves have longer-life production profiles. Unless we conduct successful development, exploitation and exploration activities or acquire
properties containing proved reserves, our proved reserves will decline as they are produced.
Producing natural gas and oil reservoirs are generally characterized by declining production rates
that vary depending on reservoir characteristics and other factors. Virtually all of our onshore
production is located in prolific natural gas producing regions where completion techniques result
in hyperbolic production decline profiles characterized by high initial production rates, followed
by rapid intermediate production declines, and culminating in a long-term low production rate
subject to a shallow decline. Likewise, our offshore production is generally characterized by
small reservoirs with high porosity and permeablilty rocks that produce at very high rates but
typically deplete rapidly. Because of the high-rate production profiles of our properties,
replacing produced reserves is more difficult for us than for companies whose reserves have
longer-life production profiles. This imposes greater reinvestment risk for our company as we may
not be able to continue to replace our reserves or may not be able to do so at an acceptable
finding cost. Rising finding and development costs may impair our profitability. In order to continue to grow and maintain our profitability, we must annually add new reserves
exceeding our yearly production at a finding and development cost that yields an acceptable
operating margin and depreciation, depletion and amortization rate. Without cost effective
exploration, development or acquisition activities, our production, reserves and profitability will
decline over time. Given the relative maturity of most gas basins in North America the cost of
finding new reserves through exploration and development operations has been increasing. The
acquisition market for natural gas properties has become extremely competitive among producers for
additional production and expanded drilling opportunities in North America. Acquisition values
climbed toward historic highs during 2004 on a per unit basis, particularly in our focus areas of
South Texas and the Rocky Mountain regions, and we believe these values may continue to increase in
2005. For full cost companies such as ours, this increase in finding and development costs is
resulting in higher depreciation, depletion and amortization rates. If the upward trend in finding
and development costs continues, we and other full cost companies will be exposed to an increased
likelihood of a writedown in carrying value of our natural gas and oil properties in response to
falling prices, which would impair our profitability. The success of our business depends upon our ability to find, replace, develop and acquire natural
gas and oil reserves. Without successful exploration, development or acquisition activities, our oil and gas reserves and
our revenues will decline over time. In addition, we may not be able to maintain our current cost
structure while continuing to operate in mature producing basins. It is becoming more difficult to
find, replace and develop new reserves at historical costs. The continuing development of reserves
and acquisition activities require significant expenditures. Our cash flow from operations may not
be sufficient for this purpose, and we may not be able to obtain the necessary funds from other
sources. If we are not able to replace reserves at sufficient levels, the amount of credit
available to us may decrease since the amount of borrowing capacity available under our revolving
bank credit facility is based, in large part, on the estimated quantities of our proved reserves.
Without continued capital investment, our oil and gas reserves will decline. Estimates of proved reserves and future net revenue may change if the assumptions on which such
estimates are based prove to be inaccurate. Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any
material inaccuracies in these reserve estimates or underlying assumptions will materially affect
the quantities and present value of our reserves. 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 and natural gas. Natural gas and oil prices have fluctuated widely in recent years.
Volatility is expected to continue and price fluctuations directly affect estimated quantities of
proved reserves and future net revenues. 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 these variances may be significant. Also, we make certain assumptions
regarding future -16-




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natural gas and oil prices, production levels, and operating and development costs that may prove
incorrect. 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
and natural gas prices after the date of the estimate may result in revisions to our reserve
estimates. During 2004 and 2003, we incurred downward revisions of our proved reserves of 20 Bcfe
and 40 Bcfe, respectively, either from proved undeveloped reserves that were depleted or otherwise
not recoverable, or from production performance indicating less gas in place or smaller reservoir
size than initially estimated. The reserve data contained in this Annual Report 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 prepared by one engineer may vary from those prepared by another. Estimates are subject
to revision based on numerous factors including, reservoir performance, prices and economic
conditions. In addition, results of drilling, testing and actual production subsequent to the date
of estimate may justify revision of that estimate. Revisions to prior estimates may be material.
Reserve estimates are often different from the quantities of natural gas and oil that we are
ultimately able to recover and are highly dependent upon the accuracy of the underlying
assumptions. Our acquisition and investment activities may be unsuccessful and costly. The successful acquisition of producing properties requires assessment of reserves, future
commodity prices, operating costs and potential environmental and other liabilities. These
assessments may not be accurate. Our review of the properties we intend to acquire may not reveal
all existing or potential problems nor allow us to become sufficiently familiar with the properties
to fully assess their deficiencies and capabilities. We may not always perform inspections on every
property 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 may not be able to meet our substantial capital requirements. Our business is capital intensive. To maintain or increase our base of proved oil and gas reserves,
we must invest a significant amount of cash flow from operations in property acquisitions,
development and exploration activities. We are currently making and will continue to make
substantial capital expenditures to find, develop, acquire and produce natural gas and oil
reserves. If our revenues or borrowing base under our revolving 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. We
may not be able to obtain debt or equity financing, and cash generated by operations or available
under our revolving bank credit facility may not be sufficient to meet our capital requirements. Our business involves many operating risks that can cause substantial losses; insurance may not
protect us against all these risks. In our operations we may experience hazards and risks inherent in drilling for, producing and
transporting natural gas and oil. These hazards and risks may result in loss of hydrocarbons,
environmental pollution, personal injury claims, and other damage to our properties and third
parties and include:  
    fires;
    natural disasters, including adverse weather conditions;
    explosions;
    encountering formations with abnormal pressures;
    encountering unusual or unexpected geological formations;
    blowouts;
    cratering;
    unexpected operational events;
    equipment malfunctions; -17-




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
    pipeline ruptures;
    spills;
    compliance with environmental and government regulations; and
    title problems. We are insured against some, but not all, of the hazards associated with our business, although we
believe this is standard practice in our industry. Because of this practice, however, we may be
liable or sustain losses that could be substantial due to events that are not insured or are
underinsured. The occurrence of an event that is not covered or not fully covered by insurance
could have a material adverse impact on our financial condition and results of operations. Our reserves, production and cash flow are highly dependent upon operations that are concentrated
in three primary areas. During 2004, we generated approximately 98% of our production from three primary areas of
operation, with 42% from South Texas, 45% from offshore Gulf of Mexico and 11% from the Arkoma
Basin. The concentrated nature of our operations subjects us to the risk that a regional event
could cause a significant interruption in our production or otherwise have a material affect on our
profitability. This is particularly true of our offshore operations, which are susceptible to
weather disturbances, some of which can be severe enough to cause substantial damage to facilities
and production infrastructure. Drilling natural gas and oil wells is a high-risk activity and subjects us to a variety of factors
that we cannot control. Our drilling activities subject us to many risks, including the risk that we will not find
commercially productive reservoirs. Drilling for natural gas and oil can be unprofitable, not only
from dry wells, but also from productive wells that do not produce sufficient revenues to return a
profit. Also, title problems, weather conditions, governmental requirements and shortages or
delays in the delivery of equipment and services can delay our drilling operations or result in
their cancellation. The cost of drilling, completing and operating wells is often uncertain, and
new wells may not be productive. As a result, we may not recover all or any portion of our
investment. Our hedging activities could result in financial losses or reduce our income. To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the
prices of oil and natural gas, we currently and expect to in the future enter into hedging
arrangements for a significant portion of our natural gas and oil production. For both 2005 and
2006, we have entered into derivative instruments relating to approximately 70% of our planned
production utilizing a variety of instruments, including fixed price swaps and collars. We have
begun to establish hedging positions for 2007 and 2008. The derivative instruments that we employ
require us to make cash payments to the extent the NYMEX index exceeds a predetermined price,
thereby limiting our ability to realize the benefit of increases in natural gas prices. As we
typically index our derivative instruments to NYMEX prices as opposed to the local indices where we
sell our gas, our hedging strategy may not protect our cash flows if basis differentials increase
between the NYMEX and local prices. Under SFAS 133, our income could be negatively affected to the
extent our NYMEX-indexed derivative instruments are deemed ineffective in hedging price
fluctuations at our sales points. In addition, if we experience a sustained material interruption
in our production, we might be forced to satisfy all or a portion of our hedging obligations
without the benefit of the cash flow from our sale of the underlying physical commodity, resulting
in a substantial diminution of our liquidity. Another risk of hedging activities is that the
counterparty in any derivative transaction cannot or will not perform under the instrument and that
we will not realize the benefit of the hedge. It is also important to note that it is not
practical to hedge the cash flows relating to all of our production, and we therefore retain the
risk of a price decrease on our unhedged volumes. The availability and cost of rigs, equipment, and personnel could adversely affect our
profitability and level of operations. Driven by attractive commodity prices, domestic drilling activity measured as a function of rig
utilization has been at very high levels throughout 2003 and 2004. Given this extended strong
demand for drilling rigs and other oil field services necessary to our operation, we began
experiencing increased service and material costs in the second half of 2004, as well as longer
lead times and reduced service availability. We anticipate that this trend will continue in 2005.
If current utilization rates continue at fourth-quarter 2004 levels or increase, a general shortage
of drilling and completion rigs, field equipment and qualified personnel could develop, especially
in the areas where we operate. Should this transpire, the costs and delivery times of rigs,
equipment and personnel could be substantially greater than in previous years. If we do not have -18-




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access to necessary oil field services at a reasonable cost, we could be forced to curtail certain
operations and the profitability of those operations that we do conduct could be materially
impaired. Our business depends on oil and natural gas transportation facilities that are owned by others. The marketability of our natural gas and oil production depends in part on the availability,
proximity and capacity of pipeline systems owned by third parties. The unavailability of or lack of
available capacity on these systems and related facilities could result in the shut-in of producing
wells or the delay or discontinuation of development plans for properties. Although we have some
control over the transportation of our product, material changes in these business relationships
could materially affect our operations. Federal and state regulation of oil and natural gas
production and transportation, tax and energy policies, changes in supply and demand, pipeline
pressures, damage to or destruction of pipelines and general economic conditions could adversely
affect our ability to produce, gather and transport oil and natural gas. Our investments in the Rocky Mountains may not be successful. Our future growth plans rely in part on establishing significant production and reserves in the
Rocky Mountains, particularly the Uinta Basin in Utah and the DJ Basin in Colorado. To date, we
lack sufficient production history from these areas to accurately estimate the likelihood that our
endeavors will yield meaningful reserves and production with an acceptable rate of return. Certain
of our exploration objectives in the Rocky Mountain area involve geology types and mechanical
operations that differ substantially from our historic operations in South Texas and the Arkoma
Basin. In addition, operations in the Rocky Mountain region present unique operational challenges,
such as more acute transportation constraints, higher pricing differentials, and more extensive
regulatory oversight. For example, 22 of the 25 successful wells that we drilled during 2004 in
the Uinta Basin where shut in at year end awaiting right of way approval from the U.S. Bureau of
Land Management (the BLM). Increased drilling in the vicinity of our Rocky Mountain acreage has
also resulted in the EPA increasingly requiring the preparation of environmental assessments or
more comprehensive environmental impact statements, as a condition to conducting operations on
certain lands that the BLM administers. Any or all of these contingencies could delay or halt our
drilling activities or the construction of ancillary facilities necessary for production, which
would prevent us from developing our property interests in the Rocky Mountains as planned. This
could in turn impede our growth, as we intend to undertake significant activity in order to
increase our production and reserves in this area in the future. We may incur substantial costs to comply with costly and stringent environmental and other
governmental laws and regulations. Our exploration and production operations are regulated extensively at the federal, state, and
local levels. Environmental and other governmental laws and regulations have increased the costs
to plan, design, drill, install, operate and abandon oil and natural gas wells. Failure to comply
with these laws and regulations may result in the assessment of administrative, civil, and criminal
penalties, the imposition of investigating and remedial obligations, and the issuance of
injunctions limiting or prohibiting our operations. We have made and plan to continue making all
necessary expenditures, both financial and managerial, in our efforts to comply with the
requirements of environmental and governmental regulations. However, environmental laws and
regulations, including those that may at some time arise to address global climate change or
facility security concerns, are expected to continue to have an increasingly costly and stringent
impact on our operations resulting in substantial costs and liabilities in the future. We currently own, lease, and have in the past owned or leased, numerous properties that have been
used for the exploration and production of oil and gas for many years. Although we have used
operating and disposal practices that were standard in the industry at the time, petroleum
hydrocarbons or wastes may have been disposed or released on or under the properties owned or
leased by us or on or under other locations where such wastes have been taken for disposal. In
addition, petroleum hydrocarbons or wastes may have been disposed or released by prior operators of
properties that we are acquiring as well as by current third party operators of properties in which
we have an ownership interest. Properties impacted by any such disposal or releases could be
subject to costly and stringent investigatory or remedial requirements under environmental laws,
some of which impose strict, joint and several liability without regard to fault or the legality of
the original conduct, including the federal Comprehensive Environmental Response, Compensation, and
Liability Act, also known as CERCLA or the Superfund law, the federal Oil Pollution Act or
OPA, the federal Resource Conservation and Recovery Act or RCRA, and analogous state laws.
Under such laws and any implementing regulations, we could be required to remediate contaminated
properties and take actions to compensate for damages to natural resources. In addition, it is not
uncommon for neighboring landowners and other third parties to file claims for personal injury or
property damages allegedly caused by the release of petroleum hydrocarbons or wastes into the
environment. We currently do not expect any remedial obligations imposed under environmental laws
to have a significant effect on our operations. We face strong competition. -19-




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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. The inability of one or more of our customers to meet their obligations may adversely affect our
financial results. Substantially all of our accounts receivable result from natural gas and oil sales or joint
interest billings to third parties in the energy industry. This concentration of customers and
joint interest owners may impact our overall credit risk in that these entities may be similarly
affected by changes in economic and other conditions. Provisions in our Charter, Agreements, Stockholder Rights Plan and Delaware Law May Inhibit a
Takeover of Houston Exploration. Under our Restated Certificate of Incorporation, our Board of Directors is authorized to issue
shares of our common or preferred stock without approval of our stockholders. Issuance of these
shares could make it more difficult to acquire our company without the approval of our Board of
Directors as more shares would have to be acquired to gain control. We also have a stockholder
rights plan, commonly known as a poison pill, that entitles our stockholders to acquire
additional shares of our company, or a potential acquirer of our company, at a substantial discount
from market value in the event of an attempted takeover without the approval of our Board. The
indenture governing our 7% senior subordinated notes due 2013 also contains change of control
provisions that, among other things, allow the holders of the notes to require us to repurchase
them at 101% of their principal amount, and a change of control constitutes a default under our
revolving band credit facility. Finally, Delaware law imposes restrictions on mergers and other
business combinations between us and any holder of 15% or more of our outstanding common stock.
These provisions may deter hostile takeover attempts that could result in an acquisition of us that
would have been financially beneficial to our stockholders. Employees As of December 31, 2004, we had 155 full time employees, 121 of whom are located at our
headquarters in Houston, Texas and the remainder of whom are located in our South Texas, Arkansas,
Denver and East Texas field offices. None of our employees is represented by a labor union or
other collective bargaining arrangement. We employ the services of independent consultants and
contractors to perform various professional services, particularly in the areas of construction,
design and well-site surveillance, permitting and environmental assessment. At our direction,
independent contractors usually perform field and on-site production operation services, including
pumping, maintenance, dispatching, inspection and testing. Offices We currently lease approximately 91,600 square feet of office space in Houston, Texas, at 1100
Louisiana Street, where our principal offices are located. We lease approximately 2,250 square feet
of office space in Denver, Colorado, at 700 17th Street. In addition, we maintain field
operations offices in South Texas, Arkansas, and East Texas. Available Information Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and
amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange
Act are made available free of charge on our website at
http://www.houstonexploration.com as soon
as reasonably practicable after we electronically file such material with, or furnish it to, the
SEC. We have adopted a Code of Business Conduct to provide guidance to our directors, officers and
employees on matters of business conduct and ethics, including compliance standards and procedures.
We have also adopted a Code of Ethics for Senior Financial Officers that applies to our principal
executive officer, principal financial officer, principal accounting officer and controller. Our
Code of Business Conduct and Code of Ethics for Senior Financial Officers are available on the
Shareholder/Financial section of our web site at
www.houstonexploration.com under the heading
Corporate Governance. We intend to promptly disclose via a Current report on Form 8-K and on our
web site information about any waiver of these codes with respect to our executive officers and
directors. Our Corporate Governance Guidelines and the charters of our Audit Committee, Nominating
and Corporate Governance Committee, and Compensation Committee are also available on the
Shareholder/Financial section of our web site at
www.houstonexploration.com under the heading
Corporate Governance. In addition, a copy of our Code of Business Conduct, Code of Ethics for
Senior Financial Officers, Corporate Governance Guidelines and the charters of the Committees
referenced above are available in print at no cost to any stockholder who requests them by writing
or telephoning us at the following address or telephone number: -20-




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The Houston Exploration Company
1100 Louisiana Street, Suite 2000
Houston, TX 77002 - 5215
Attention: Corporate Secretary
Telephone: (713) 830-6800 Information contained on or connected to our web site is not incorporated by reference into this
Annual Report and should not be considered part of this report or any other filing that we make
with the SEC. Item 2. Properties (see Item 1. Business and Properties) 
 Item 3. Legal Proceedings We currently are not a party to any material pending legal or governmental proceedings, other than
ordinary routine litigation incidental to our business. While the ultimate outcome and impact of
any proceeding cannot be predicted with certainty, our management believes that the resolution of
any proceeding will not have a material adverse effect on our 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 our security holders during the last quarter of the fiscal
year ended December 31, 2004. 
 Part II. 
 Item 5. Market for the Registrants Common Equity Related Stockholder Matters and Issuer
Purchases of Equity Securities Our common stock is traded on the New York Stock Exchange under the symbol THX. The following
table sets forth the range of high and low sales prices for each calendar quarterly period from
January 1, 2003, through December 31, 2004 as reported on the New York Stock Exchange: Year Ended December 31, 2004
    
    High
    
    
    LowFirst Quarter
    
    $
    45.85
    
    
    $
    35.79Second Quarter
    
    
    52.47
    
    
    
    41.40Third Quarter
    
    
    59.79
    
    
    
    48.30Fourth Quarter
    
    
    61.80
    
    
    
    53.65
 Year Ended December 31, 2003
    
    High
    
    
    LowFirst Quarter
    
    $
    31.45
    
    
    $
    25.81Second Quarter
    
    
    35.20
    
    
    
    26.72Third Quarter
    
    
    36.28
    
    
    
    31.25Fourth Quarter
    
    
    37.70
    
    
    
    33.35
 As of February 22, 2005, 28,457,804 shares of common stock were outstanding, and we had
approximately 50 stockholders of record and approximately 14,800 beneficial owners. Dividends We have not declared or paid any cash dividends and do not anticipate declaring any dividends in
the foreseeable future. We plan to retain our cash for the operation and expansion of our business,
including exploration, development and acquisition activities. In addition, our revolving bank
credit facility and the indenture governing our 7% senior subordinated notes due June 15, 2013,
contain restrictions on the payment of dividends to holders of common stock. For more information,
see Item 7. Managements Discussion and Analysis of Financial Condition and Results of
Operations. -21-




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Item 6. Selected Financial Data The following table shows selected financial data derived from our consolidated financial
statements for each of the five years in the period ended December 31, 2004. You should read these
financial data in conjunction with Item 7. Managements Discussion and Analysis of Financial
Condition and Results of Operations and our Consolidated Financial Statements and the related
Notes. Years Ended December 31,2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(in thousands, except per share data)Income Statement Data:Revenues:Natural gas and oil revenues
    
    $
    649,087
    
    
    $
    491,440
    
    
    $
    344,295
    
    
    $
    387,156

    
    
    $
    277,487Other
    
    
    1,352
    
    
    
    1,312
    
    
    
    1,086
    
    
    
    1,353
    
    
    
    1,738Total revenues
    
    
    650,439
    
    
    
    492,752
    
    
    
    345,381
    
    
    
    388,509
    
    
    
    279,225Expenses:Lease operating expense
    
    
    55,925
    
    
    
    47,072
    
    
    
    33,976
    
    
    
    25,291
    
    
    
    23,553Severance tax
    
    
    11,933
    
    
    
    15,958
    
    
    
    9,487
    
    
    
    11,035
    
    
    
    9,757Transportation expense
    
    
    11,819
    
    
    
    10,387
    
    
    
    9,317
    
    
    
    7,652
    
    
    
    6,892Asset retirement accretion expense
    
    
    4,902
    
    
    
    3,668
    
    
    
    
    
    
    
    
    
    
    
    Depreciation, depletion and amortization
    
    
    265,148
    
    
    
    197,530
    
    
    
    171,610
    
    
    
    128,736
    
    
    
    89,239Writedown in carrying value
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    6,170
    
    
    
    General and administrative, net
    
    
    32,899
    
    
    
    19,542
    
    
    
    13,077
    
    
    
    17,110
    
    
    
    8,928Total operating expenses
    
    
    382,626
    
    
    
    294,157
    
    
    
    237,467
    
    
    
    195,994
    
    
    
    138,369Income from operations
    
    
    267,813
    
    
    
    198,595
    
    
    
    107,914
    
    
    
    192,515
    
    
    
    140,856Other (income) expense (1)
    
    
    (1,058
    )
    
    
    (15,746
    )
    
    
    (9,070
    )
    
    
    119
    
    
    
    1,752Interest expense, net
    
    
    9,455
    
    
    
    8,342
    
    
    
    7,398
    
    
    
    2,992
    
    
    
    11,361Income before income taxes
    
    
    259,416
    
    
    
    205,999
    
    
    
    109,586
    
    
    
    189,404
    
    
    
    127,743Income tax provision
    
    
    96,592
    
    
    
    72,187
    
    
    
    39,092
    
    
    
    66,803
    
    
    
    42,485Income before cumulative effect of change in
accounting principle
    
    $
    162,824
    
    
    $
    133,812
    
    
    $
    70,494
    
    
    $
    122,601
    
    
    $
    85,258Cumulative effect of change in accounting
principle (2)
    
    
    
    
    
    
    2,772
    
    
    
    
    
    
    
    
    
    
    
    Net income
    
    $
    162,824
    
    
    $
    131,040
    
    
    $
    70,494
    
    
    $
    122,601
    
    
    $
    85,258Earnings per share:Basic:Income per share before cumulative effect of
change in accounting principle change
    
    $
    5.50
    
    
    $
    4.30
    
    
    $
    2.31
    
    
    $
    4.06
    
    
    $
    3.06Cumulative effect of change in accounting
principle (2)
    
    
    
    
    
    
    (0.09
    )
    
    
    
    
    
    
    
    
    
    
    Net income per share  basic
    
    $
    5.50
    
    
    $
    4.21
    
    
    $
    2.31
    
    
    $
    4.06
    
    
    $
    3.06Diluted:Income per share before cumulative effect of
change in accounting principle
    
    $
    5.44
    
    
    $
    4.29
    
    
    $
    2.28
    
    
    $
    4.00
    
    
    $
    3.02Cumulative effect of change in accounting
principle (2)
    
    
    
    
    
    
    (0.09
    )
    
    
    
    
    
    
    
    
    
    
    Net income per share  diluted
    
    $
    5.44
    
    
    $
    4.20
    
    
    $
    2.28
    
    
    $
    4.00
    
    
    $
    3.02Weighted average shares  basic
    
    
    29,616
    
    
    
    31,097
    
    
    
    30,569
    
    
    
    30,228
    
    
    
    27,860Weighted average shares  diluted
    
    
    29,932
    
    
    
    31,213
    
    
    
    30,878
    
    
    
    30,645
    
    
    
    28,213Ratio of earnings to fixed charges(3)
    
    
    15.0
    x
    
    
    13.6
    x
    
    
    7.6
    x
    
    
    12.8
    x
    
    
    5.5
    x
 -22-




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Years Ended December 31,2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(in thousands)Cash Flow Data:Net cash provided by operating activities
    
    $
    522,436
    
    
    $
    390,832
    
    
    $
    243,869
    
    
    $
    358,032
    
    
    $
    200,791Net cash used in investing activities
    
    
    505,217
    
    
    
    461,822
    
    
    
    252,125
    
    
    
    368,277
    
    
    
    184,512Net cash (used in) provided by financing
activities
    
    
    (1,211
    )
    
    
    55,528
    
    
    
    17,668
    
    
    
    9,189
    
    
    
    (22,106
    )
 At December 31,2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(in thousands)Balance Sheet Data:Working capital (deficit)
    
    $
    (31,884
    )
    
    $
    (36
    )
    
    $
    10,550
    
    
    $
    34,314
    
    
    $
    19,746Property, plant and equipment, net
    
    
    1,548,256
    
    
    
    1,371,129
    
    
    
    1,022,414
    
    
    
    938,761
    
    
    
    705,390Total assets
    
    
    1,722,577
    
    
    
    1,509,065
    
    
    
    1,151,068
    
    
    
    1,059,092
    
    
    
    837,384Long-term debt and notes
    
    
    355,000
    
    
    
    302,000
    
    
    
    252,000
    
    
    
    244,000
    
    
    
    245,000Stockholders equity
    
    
    782,920
    
    
    
    735,534
    
    
    
    592,789
    
    
    
    565,881
    
    
    
    396,742
   (1)
    
    For 2004, 2003 and 2002, other income includes $1.2 million, $21.6 million
and $9.1 million, respectively, representing recoupments of prior period severance tax expense
that were recognized pursuant to the receipt of a high cost/tight sand designation for a
portion of our South Texas production in July 2002. See Note 9  Commitments and
Contingencies. Additionally, for 2004, other income includes $0.2 million in debt
extinguishment expenses incurred during the second quarter of 2004 pursuant to the reduction
of our borrowings base from $375 million to $340 million as a result of the disposition of our
Appalachian Basin assets. For 2003, other income includes $5.9 million in expenses incurred
pursuant to the early redemption of our $100 million 8 5/8% notes in June 2003. See Note 2 
Long-Term Debt and Notes. For 2001 and 2000, other expense of $0.2 million and $1.8 million,
respectively, represents nonrecurring expenses incurred in connection with a strategic review
of alternatives for Houston Exploration and KeySpans investment in our company, including the
possible sale of all or a portion of Houston Exploration. See Note 6  Related Party
Transactions.(2)
    
    On January 1, 2003, we adopted SFAS 143, Accounting for Asset Retirement
Obligations, which addresses accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset retirement costs. Pursuant
to our adoption of SFAS 143, we recognized a charge to income during the first quarter of 2003
of $2.8 million, net of tax, for the cumulative effect of the change in accounting principle.
See Note 1  Summary of Organization and Significant Accounting Policies  Asset Retirement
Obligations.(3)
    
    For purposes of determining the ratio of earnings to fixed charges,
earnings are defined as income (loss) before tax plus fixed charges, adjusted to exclude
capitalized interest. Fixed charges consist of interest expense, whether expensed or
capitalized, and an imputed or estimated interest component of rent expense. See Exhibit 12.1
for calculation. 
 Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations The following discussion is intended to assist you in understanding our business and the results of
operations together with our present financial conditions. This section should be read in
conjunction with our Consolidated Financial Statements and the accompanying notes included
elsewhere in this Annual Report on Form 10-K. Statements in our discussion may be forward-looking. These forward-looking statements involve
risks and uncertainties. We caution that a number of factors could cause future production,
revenues and expenses to differ materially from our expectations. See Forward-Looking Statements and Other Information at the beginning of this Annual Report and Risk Factors Affecting Our Business beginning on page 15
for additional discussion of some of these factors and risks. Overview of Our Business We are an independent natural gas and oil producer concentrating on growing reserves and production
through the exploration, development, exploitation and acquisition of natural gas and oil reserves
in North America. Our core areas of operations are South Texas, offshore in the shallow waters of
the Gulf of Mexico and the Arkoma Basin of Oklahoma and Arkansas. During 2003, we initiated
operations in the Rocky Mountain Region, with an initial focus in the Uinta Basin of northeastern
Utah, and during 2004, we expanded our focus to include the DJ Basin of Eastern Colorado. In
February 2004, we divested our South Louisiana assets and in June 2004, we divested our Appalachian
Basin assets in connection -23-




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with the KeySpan Exchange transaction described in Note 3  Stockholders Equity  KeySpan Exchange
and Offeringof Item 15 contained in this Form 10-K. We operate as one segment as each of our
operating areas has similar economic characteristics and each meets the criteria for aggregation as
defined in the Financial Accounting Standards Board (FASB) Statement of Financial Accounting
Standards (SFAS) 131, Disclosures about Segments of an Enterprise and Related Information. At December 31, 2004, net proved reserves were 793 billion cubic feet equivalent or Bcfe, with a
present value of future net cash flows before income taxes, discounted at 10% per annum, of $2.2
billion and standardized measure of future net cash flows including income taxes, discounted at 10%
per annum, of $1.4 billion. Our reserves are fully engineered on an annual basis by independent
petroleum engineers. Approximately 94% of our proved reserves at December 31, 2004, were natural
gas, approximately 63% of which were classified as proved developed. As of December 31, 2004, we
operated approximately 77% of our producing wells. Daily production averaged 339 million cubic
feet of natural gas equivalent or MMcfe in 2004. We were founded in December 1985 as a Delaware corporation and began exploring for natural gas and
oil on behalf of KeySpan Corporation. KeySpan, a member of the Standard & Poors 500 Index, is a
diversified energy provider whose principal natural gas distribution and electric generation
operations are located in the Northeastern United States. In September 1996 we completed our
initial public offering and sold approximately 31% of our shares to the public. Through three
separate transactions, the first in February 2003 and the last in November 2004, KeySpan completely
divested of its investment in the common stock of our company. As of December 31, 2004, KeySpan no
longer owned any common stock of our company. See Note 3  Stockholders Equity and Note 6 
Related Party Transactions for a complete description of these three transactions. Source of Our Revenues We derive our revenues from the sale of natural gas and oil that is produced from our natural gas
and oil properties. Revenues are a function of the volume produced and the prevailing market price
at the time of sale. The price of natural gas is the primary factor affecting our revenues. To
achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we
utilize derivative instruments to hedge future sales prices on a significant portion of our natural
gas production. During 2004 and 2003, the use of derivative instruments prevented us from
realizing the full benefit of upward price movements and may continue to do so in future periods. Principal Components of Our Cost Structure  
    Lease Operating Expenses.The day-to-day costs incurred to bring hydrocarbons
out of the ground and to the market together with the daily costs incurred to maintain our
producing properties. These costs include: lease operating expense, severance tax and
transportation expense, which costs are expected to increase.
    Depreciation, Depletion and Amortization. The systematic expensing of the
capital costs incurred to acquire, explore and develop natural gas and oil. As a full cost
company, we capitalize all costs associated with our acquisition, exploration and
development efforts, including interest and certain general and administrative costs, and
apportion these costs to each unit of production through depreciation, depletion and
amortization expense. Generally, if reserve quantities are revised up or down, the
depreciation, depletion and amortization rate per unit of production will change inversely.
    Asset Retirement Accretion Expense.The systematic, monthly accretion of the
future abandonment costs of tangible assets such as platforms, wells, service assets,
pipelines, and other facilities.
    General and Administrative Expense.Overhead, including payroll and benefits
for our corporate staff, costs of maintaining our headquarters, managing our production and
development operations and legal compliance are included in our general and administrative
expense. We capitalize general and administrative expense directly related to our
acquisition, exploration and development activities.
    Interest.We typically finance our working capital requirements and
acquisitions with borrowings under our revolving bank credit facility, and longer term, with
public traded debt instruments. As a result, we incur substantial interest expense that
correlates to both fluctuations in interest rates and our acquisition activity.
Acquisitions are a critical element of our growth strategy. We expect to continue to incur
significant interest expense as we continue to grow. We capitalize interest directly
related to our unevaluated properties that are not being amortized.
    Income Taxes.We are subject to state and federal income taxes and are
currently in a tax paying position. Prior to 2003, all of our taxes, both federal and
state, were deferred; however, during 2003, we utilized all of our net operating loss
carryforwards and as a result, we recognized current income tax expense and will continue to
recognize current tax expense as long as we are generating taxable income. -24-




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Industry Environment We currently operate in North America. After over 100 years of active natural gas and oil
exploration and production within the lower 48 states and Gulf of Mexico, the region is maturing
and production growth is slowing or possibly declining. Numerous technological advances during
this timeframe, including increasingly sophisticated geophysical tools that allow more accurate
identification of reservoirs, horizontal and other drilling technologies that facilitate and
enhance the extraction process, and advanced completion techniques have accelerated both production
and depletion rates. While new discoveries are still being made in North America, the frequency
and size of these discoveries is declining while the finding and development costs are increasing.
As a result, given our current technology, domestic natural gas and oil production as a whole may
be at or near its peak and can be expected to decline in the future, with the exception of regions
such as the Rocky Mountains. In this mature environment, companies will find it increasingly difficult to replace their reserves
through traditional exploration and development efforts, and companies will increasingly be forced
to rely on acquisitions to sustain their growth. Our future success in growing our reserve base at
an acceptable finding cost will depend in large part on our ability to acquire new proved reserves
and unevaluated acreage on which we can explore. We currently maintain a very active acquisition
program and expect to continue to devote significant resources to identifying and pursuing both
tactical acquisitions that augment our existing property base as well as substantial strategic
acquisitions. We anticipate that the continued decline of the North American gas basins will lead to higher cost
structures throughout our industry. We currently believe that the cost of finding, developing and
producing new natural gas and oil reserves through exploration and development operations will rise
as the industry makes fewer discoveries and such discoveries generally tend to decrease in reserve
size. In addition, we believe the acquisition market for natural gas properties has become
extremely competitive as producers vie for additional production and expanded drilling
opportunities in North America. Acquisition values climbed toward historic highs during 2004 on a
per unit basis, particularly in our focus areas of South Texas and the Rocky Mountains, and we
expect acquisition values to continue to climb in 2005. For full cost companies such as ours,
increases in both acquisition and finding and development costs, are expected to yield higher
depreciation, depletion and amortization rates and ultimately, could increase the likelihood of
a writedown in carrying value of our natural gas and oil properties if commodity prices fall
substantially below current levels. In addition, we expect drilling costs, especially in the Gulf
of Mexico, and lease operating expenses to continue to rise as producers are forced to make
operational enhancements to maintain aging fields. Like any commodity, the price that we receive for the gas we produce is largely a function of
supply and demand. Demand for natural gas is affected by general economic conditions, such as
growth in the space heating, industrial and power generation segments, and seasonal conditions.
Demand has also typically been impacted by seasonal fluctuations, with the peak demand during the
winter heating season and summer air conditioning season. As natural gas is difficult to import,
80% to 85% of the United States natural gas demand in recent years has been supplied by domestic
production. Imports from Canada have made up 10% to 15% of the United States natural gas needs
and imports from a variety of other countries now make up for 1% to 2% of total supply in the form
of liquefied natural gas, or LNG. Situations involving over or under supply of natural gas can result in substantial price
volatility. Continued concerns over the United States ability to meet its longer-term gas needs
from declining domestic supply have resulted in sustained prices above $5.00 throughout 2003, 2004
and continuing into 2005. As a direct result of the strong commodity prices during 2004, we were
able to increase our net income, generate substantial cash flows to fund acquisitions, our capital
budget and repay borrowings on our revolving bank credit facility. However, historically,
commodity prices have been very volatile, and we expect the volatility to continue in the future.
As a result, we cannot accurately predict future natural gas and oil prices, and, therefore, we
cannot determine what effect increases or decreases will have on our future revenues and cash
flows. A substantial or extended decline in natural gas and oil prices or poor drilling results
could have a material adverse effect on our financial position, results of operations, cash flows,
quantities of natural gas and oil reserves that may be economically produced and our ability to
access capital markets. Our continued growth and profitability depends on the strength of natural
gas prices and our ability to acquire, find and develop new reserves at economical costs. Critical Accounting Estimates The discussion and analysis of our financial condition and results of operations are based upon our
consolidated financial statements, which have been prepared in accordance with accounting
principles generally accepted in the United States. The preparation of our financial statements
requires us to make assumptions and prepare estimates that affect the reported amounts of assets
and liabilities, the disclosure of contingent assets and liabilities and revenues and expenses. We
base our estimates on historical experience and various other assumptions that we believe are
reasonable; however, actual results may differ. We evaluate our assumptions and estimates on a
regular basis and discuss the development and disclosure -25-




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process with our Audit
Committee. See Note 1 - Summary of Organization and Significant Accounting
Policies of Item 8 contained in this Form 10-K for a discussion of our significant accounting
policies. Proved Reserves. Our estimates of proved reserves are based on the quantities of natural gas and
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. However,
there are numerous uncertainties inherent in estimating quantities of proved reserves and in
projecting future revenues, rates of production and timing of development expenditures, including
many factors beyond our control. The estimation process relies on assumptions and interpretations
of available geologic, geophysical, engineering and production data and, the accuracy of reserve
estimates is a function of the quality and quantity of available data, engineering and geological
interpretation, and judgment. In addition, as a result of changing market conditions, commodity
prices and future development costs will change from year to year, causing estimates of proved
reserves to also change. For the years ended December 31, 2004 and 2003, we revised our proved
reserves downward from prior years reports by approximately 20 Bcfe and 40 Bcfe, respectively, due
to proved undeveloped reserves that were depleted or otherwise not recoverable, or from production
performance indicating less gas in place or smaller reservoir size than initially estimated.
Estimates of proved reserves are key components of our most significant financial estimates
involving our unevaluated properties, our rate for recording depreciation, depletion and
amortization and our full cost ceiling limitation. Our reserves are fully engineered on an annual
basis by independent petroleum engineers. Unevaluated Properties. The balance of unevaluated properties is comprised of capital costs
incurred for undeveloped acreage, seismic data, wells and production facilities in progress, wells
pending determination and related capitalized interest. These costs are initially excluded from
our amortization base until the outcome of the project has been determined, or generally, until it
is known whether proved reserves will or will not be assigned to the property. We assess all items
in our unevaluated property balance on a quarterly basis for possible impairment or reduction in
value. We believe that substantially all of the costs included in our unevaluated property balance
will be evaluated in the next four years. Asset Retirement Obligations.Asset retirement obligations represent the estimated future
abandonment costs of tangible long-lived assets such as platforms, wells, service assets,
pipelines, and other facilities. We estimate the fair value of an assets retirement obligation in
the period in which the liability is incurred, if a reasonable estimate can be made. We employ a
present value technique to estimate the fair value of an asset retirement obligation, which
reflects certain assumptions, including an inflation rate, our credit-adjusted, risk-free interest
rate, the estimated settlement date of the liability and the estimated current cost to settle the
liability which we compute from third party quotes. Changes in timing or to the original estimate
of cash flows will result in changes to the carrying amount of the liability. Derivative Instruments.Under SFAS 133, Accounting for Derivative Instruments and Hedging
Activities, as amended, we reflect the fair market value of our derivative instruments on our
balance sheet. Our estimates of fair value are determined by obtaining independent market quotes
from counterparties, as well as utilizing a Black-Scholes option valuation model that is based upon
underlying forward price curve data, a risk-free interest rate and estimated volatility factors. In addition to the critical estimates discussed above, estimates are used primarily in accounting
and computing depreciation, depletion and amortization, the full cost ceiling, taxes, accruals of
operating costs and production revenues, effectiveness of derivative instruments and fair value of
stock options and related compensation expense. New Accounting Pronouncements On September 28, 2004, the SEC released Staff Accounting Bulletin (SAB) 106 regarding the
application of SFAS 143, Accounting for Asset Retirement Obligations (AROs), by oil and gas
producing companies following the full cost accounting method. Pursuant to SAB 106, oil and gas
producing companies that have adopted SFAS 143 should exclude the future cash outflows associated
with settling AROs (ARO liabilities) from the computation of the present value of estimated future
net revenues for the purposes of the full cost ceiling calculation. In addition, estimated
dismantlement and abandonment costs, net of estimated salvage values, that have been capitalized
(ARO assets) should be included in the amortization base for computing depreciation, depletion and
amortization expense. Disclosures are required to include discussion of how a companys ceiling
test and depreciation, depletion and amortization calculations are impacted by the adoption of SFAS
143. SAB 106 is effective prospectively as of the beginning of the first fiscal quarter beginning
after October 4, 2004. Since our adoption of SFAS 143 on January 1, 2003, we have calculated the
ceiling test and our depreciation, depletion and amortization expense in accordance with the
interpretations set forth in SAB 106; therefore, the adoption of SAB 106 had no effect on our
financial statements. On December 16, 2004, the FASB revised Statement 123 (revised 2004), Share-Based Payment that
will require compensation costs related to share-based payment transactions (e.g., issuance of
stock options and restricted stock) to be -26-




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recognized in the financial statements. With limited exceptions, the amount of compensation cost
will be measured based on the grant-date fair value of the equity or liability instruments issued.
In addition, liability awards will be remeasured each reporting period. Compensation cost will be
recognized over the period that an employee provides service in exchange for the award. Statement
123(R) replaces SFAS 123, Accounting for Stock-Based Compensation, and supersedes Accounting
Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees. For us, SFAS
123(R) is effective for the first quarterly reporting period after June 15, 2005. Entities that
use the fair-value-based method for either recognition or disclosure under SFAS 123 are required to
apply SFAS 123(R) using a modified version of prospective application. Under this method, an
entity records compensation expense for all awards it grants after the date of adoption. In
addition, the entity is required to record compensation expense for the unvested portion of
previously granted awards that remain outstanding at the date of adoption. In addition, entities
may elect to adopt SFAS 123(R) using a modified retrospective method where by previously issued
financial statements are restated based on the expense previously calculated and reported in their
pro forma footnote disclosures. On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123 as amended
by SFAS 148, Accounting for Stock-Based Compensation  Transition and Disclosure using the
prospective method as defined by the SFAS 148. As a result, we have recognized compensation
expense for all stock options granted subsequent to January 1, 2003 with no expense recognized for
grants made prior to 2003. Adoption of SFAS 123(R) will require us to recognize compensation
expense over the remaining service period for the unvested portion of all options granted during
2000, 2001 and 2002. All options granted prior to 2000 are fully vested. We expect to adopt SFAS
123(R) on January 1, 2005, using the modified version of
prospective application and are currently evaluating the effect of
adopting SFAS 123(R). On December 16, 2004, the FASB issued Statement 153, Exchanges of Nonmonetary Assets, an
amendment of APB Opinion No. 29, to clarify the accounting for nonmonetrary exchanges of similar
productive assets. SFAS 153 eliminates the exception from the fair value measurement for
nonmonetary exchanges of similar productive assets and replaces it with a general exception for
exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has
commercial substance if the future cash flows of the entity are expected to change significantly as
a result of the exchange. The Statement will be applied prospectively and is effective for
nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. We do not
have any nonmonetary transactions for any period presented that this Statement would apply. We do
not expect the adoption of SFAS 153 to have a material impact on our financials statements. -27-




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Overview of 2004 Results The sustained strength of commodity prices throughout 2004 and production growth of 15% generated
from all core operating areas were the primary factors behind results for operations, earnings and
cash flows for 2004. The increase in our cash flows from operations allowed for increased capital
spending from prior year levels for drilling and acquisitions and the repurchase and retirement of
a portion of our common stock from KeySpan. During 2004:  
    We generated $162.8 million in net income, an increase of 24% from 2003;
    We produced a total of 124 Bcfe and increased our average daily production rate
by 15% to 339 MMcfe per day;
    We increased total net proved reserves by 5% to 793 Bcfe with a
standardized measure or after-tax discounted value of $1.4 billion;
    We added 225 Bcfe of net proved reserves with 164 Bcfe added through the drill
bit, 81 Bcfe added through acquisitions and incurred downward revisions due primarily to
reservoir performance of 20 Bcfe;
    We generated $522.4 million in net cash flows from operating activities and
invested $517.0 million in natural gas and oil properties, which included $149.6 million for
producing property acquisitions;
    We drilled a record 211 wells, of which 177, or 84%, were successful with 56
successful wells in South Texas, 15 offshore, 73 in Arkoma, 28 in the Rockies and 5 in other
areas;
    We successfully integrated the Gulf of Mexico producing properties acquired in
the fourth quarter of 2003 from Transworld Exploration and Production Inc., our largest
acquisition to date, and, through the drilling and completion of 10 development wells,
increased production from the acquired properties from an average of 30 MMcfe/day in
December 2003 to more than 57 MMcfe/day in December 2004;
    We divested our South Louisiana properties in February 2004, selling 12.3 Bcfe
of net proved reserves for a net $13.1 million;
    We divested our Appalachian Basin assets, in June 2004, as part of the KeySpan
Exchange (see Note 3  Shareholders Equity), receiving an exchange value of $60.0 million
for the properties that had estimated proved reserves of 51.2 Bcfe;
    We assisted KeySpan in completing the divesture of its investment in our common
stock, first with the KeySpan Exchange, in June 2004, whereby KeySpans investment in our
common stock was decreased from approximately 54% to 23% and finally, in November 2004, with
the sale of their remaining 23% or 6,580,392 shares through a secondary public offering (see
Note 3  Shareholders Equity  KeySpan Exchange and Offeringand KeySpan Secondary
Offering);
    We expanded our Rocky Mountain acreage position in August 2004, which previously
covered more than 200,000 net undeveloped acres throughout southwestern Montana, the Green
River Basin of southwestern Wyoming and in the Uinta Basin of northeastern Utah, to include
an additional 330,000 net acres in Colorados DJ Basin where we have identified locations to
drill approximately 100 wells during 2005;
    We acquired two offshore blocks located in the central Gulf of Mexico from BP
Exploration & Production Inc., in September 2004 for a net $30.0 million and added estimated
proved reserves of 16.2 Bcfe and future exploitation opportunities (see Note 10 
Acquisitions and Dispositions);
    We acquired another 10 offshore blocks in October 2004, located primarily in the
shallow waters of the central Gulf of Mexico, from Orca Energy, L.P and added an estimated
60.7 Bcfe of proved reserves and future exploitation opportunities for a net $113.6 million
(see Note 10  Acquisitions and Dispositions);
    We renegotiated our revolving bank credit facility in April 2004, and increased
the maximum capacity from $350 million to $450 million, extended the maturity from July 2005
to April 2008 and by the end of December 31, 2004, after giving effect to acquisitions and
dispositions, our borrowing base is $400 million;
    We increased our outstanding borrowings under our revolving bank credit facility
by a net $53 million, the majority of which was borrowed in the fourth quarter to fund our
two producing property acquisitions;
    We adopted a stockholder rights plan in October 2004, that is designed to assure
that our stockholders receive fair and equal treatment in the event of an unsolicited
takeover attempt and to protect against abusive or coercive takeover tactics that are not in
the best interest of our company or its stockholders ( see Note 3  Shareholders
Equity  Stockholders Rights Plan); and
    We announced our 2005 capital expenditure budget of $446 million, of which $445
million is expected to be spent for exploration and development activities. -28-




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##### Table of Contents



Operating and Financial Results for 2004 Compared to 2003 and Operating and Financial Results for
2003 Compared to 2002 Year Ended December 31,
    
    
    Year Ended December 31,Summary Operating Information:
    
    2004
    
    
    2003
    
    
    Variance
    
    
    2003
    
    
    2002
    
    
    Variance(in thousands)Operating revenues
    
    $
    650,439
    
    
    $
    492,752
    
    
    $
    157,687
    
    
    
    32
    %
    
    $
    492,752
    
    
    $
    345,381
    
    
    $
    147,371
    
    
    
    43
    %Operating expenses
    
    
    382,626
    
    
    
    294,157
    
    
    
    88,469
    
    
    
    30
    %
    
    
    294,157
    
    
    
    237,467
    
    
    
    56,690
    
    
    
    24
    %Income from operations
    
    
    267,813
    
    
    
    198,595
    
    
    
    69,218
    
    
    
    35
    %
    
    
    198,595
    
    
    
    107,914
    
    
    
    90,681
    
    
    
    84
    %Net income
    
    
    162,824
    
    
    
    131,040
    
    
    
    31,784
    
    
    
    24
    %
    
    
    131,040
    
    
    
    70,494
    
    
    
    60,546
    
    
    
    86
    %Production:Natural gas (MMcf)
    
    
    115,855
    
    
    
    99,965
    
    
    
    15,890
    
    
    
    16
    %
    
    
    99,965
    
    
    
    97,368
    
    
    
    2,597
    
    
    
    3
    %Oil (MBbls)
    
    
    1,355
    
    
    
    1,307
    
    
    
    48
    
    
    
    4
    %
    
    
    1,307
    
    
    
    859
    
    
    
    448
    
    
    
    52
    %Total (MMcfe) (1)
    
    
    123,985
    
    
    
    107,807
    
    
    
    16,178
    
    
    
    15
    %
    
    
    107,807
    
    
    
    102,522
    
    
    
    5,285
    
    
    
    5
    %Average daily production (MMcfe/d)
    
    
    339
    
    
    
    295
    
    
    
    44
    
    
    
    15
    %
    
    
    295
    
    
    
    281
    
    
    
    14
    
    
    
    5
    %Average Sales Prices:Natural Gas (per Mcf) realized (2)
    
    $
    5.17
    
    
    $
    4.55
    
    
    $
    0.62
    
    
    
    14
    %
    
    $
    4.55
    
    
    $
    3.32
    
    
    $
    1.23
    
    
    
    37
    %Natural Gas (per Mcf) unhedged
    
    
    5.78
    
    
    
    5.23
    
    
    
    0.55
    
    
    
    11
    %
    
    
    5.23
    
    
    
    3.16
    
    
    
    2.07
    
    
    
    66
    %Oil (per Bbl) realized (2)
    
    
    36.85
    
    
    
    28.15
    
    
    
    8.70
    
    
    
    31
    %
    
    
    28.15
    
    
    
    23.99
    
    
    
    4.16
    
    
    
    17
    %Oil (per Bbl) unhedged
    
    
    36.85
    
    
    
    28.46
    
    
    
    8.39
    
    
    
    29
    %
    
    
    28.46
    
    
    
    23.99
    
    
    
    4.47
    
    
    
    19
    %
   (1)
    
    Mcfe is defined as one million cubic feet equivalent of natural gas,
determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or
natural gas liquids.(2)
    
    Average realized prices include the effect of hedges. Income from Operations Production growth and higher realized natural gas prices were the primary factors contributing to
our 35% increase in operating income in 2004 over 2003. Increased revenues were offset in part by
a 30% increase in operating expenses. Higher natural gas prices were the primary factor contributing to our 86% increase in net income
and our 84% increase in operating income in 2003 over 2002. Adding to the effects of higher
commodity prices realized in 2003 was an increase of 5% in production volume from 2002 levels.
Increased revenues were offset in part by a 24% increase in operating expenses during 2003 due
primarily to the continued expansion of our operations combined with an increase in costs to
maintain our existing production base together with higher depreciation, depletion and amortization
rates. Production Volume 2004 vs. 2003 The 15% increase in production for 2004 is primarily a result of both production added from Gulf of
Mexico properties acquired during the fourth quarter of 2003 as well as newly developed production,
both onshore and offshore, from our existing property base. Onshore.Daily production rates increased 8% from an average of 173 MMcfe per day in 2003 to 186
MMcfe per day in 2004, despite our loss of approximately 8 MMcfe per day as a result of the
divesture of our South Louisiana and Appalachian Basin properties during the first half of 2004.
The Arkoma Basin was our onshore growth area during 2004. We experienced the full impact of the
accelerated drilling program initiated in 2003 that continued throughout 2004 as we added 15 MMcfe
per day in newly developed production. With three rigs drilling through the first 10 months of
2004, Arkoma production reached a record of 44 MMcfe per day during the fourth quarter compared to
25 MMcfe per day during the fourth quarter of 2003. For 2004, South Texas production increased to
an average of 142 MMcfe per day compared to 140 MMcfe per day 2003. Average daily production rates for Arkoma and South Texas were negatively impacted during the
quarter by our operational curtailment. As a result of rising rig rates and service costs during
the fourth quarter of 2004, we reduced our onshore rig activity to keep capital spending within
budgeted levels during the fourth quarter. In South Texas, we went -29-




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from six rigs to four and in Arkoma we went from three rigs to one. In addition, we deferred the
completion of seven wells in South Texas capable of producing an estimated 11 MMcfe per day, net,
and five wells in Arkoma capable of producing an estimated 2 MMcfe per day, net. By the end of
January 2005, we had resumed our six-rig program in South Texas and add a second rig in Arkoma. We
expect to be able to add a third rig in Arkoma by the end of the first quarter 2005. As our South
Texas properties begin to mature and production growth to minimize, our strategy will be to
maintain production at existing levels while improving drilling and operating efficiencies. In the Rockies, 2004 was an exploratory year and our activities were aimed at expanding our acreage
position and proving up reserves in several exploration projects on our Uinta Basin acreage
acquired in 2003. We drilled a total of 31 wells, 26 in the Uinta Basin, four in the DJ Basin and
one in Montana. Of the total drilled, 28 wells or 90% were successful. By December 2004, six of
our Uinta Basin wells were producing approximately 4 MMcfe per day, net to our interest. At
December 31, 2004, production from the remaining 19 of our 25 successful Uinta Basin wells remained
delayed, awaiting right-of-way approval for pipeline construction from the Bureau of Land
Management (BLM). Subsequent to December 31, 2004, we received approval from the BLM for
pipelines on 11 of the wells. We estimate initial production rates from these 11 wells, on a
combined basis, to be approximately 8 MMcfe per day, net to our interests. Offshore. We experienced record production growth as average daily rates increased 25% from 122
MMcfe per day during 2003 to an average of 153 MMcfe per day during 2004. We added approximately
41 MMcfe per day in newly developed production, of which an average of 22 MMcfe per day was
attributable to development drilling at High Island A283 and East Cameron 56/57 and 148. During
the year, we completed and brought on-line seven development wells at High Island A283, two at EC
56/57 and one at East Cameron 148. All of these fields were acquired in mid-October 2003, as part
of our acquisition of Gulf of Mexico properties. Production from these properties accounted for
approximately 71 MMcfe per day of our offshore production during 2004. Partially offsetting the
production from our newly acquired properties were declines from existing and maturing fields
totaling approximately 40 MMcfe per day, resulting in a net 31 MMcfe per day production increase
year-over-year. Because the majority of our fields are located in the Western and Central Gulf of
Mexico, Hurricane Ivan in September 2004, had minimal impact on our results for the year. We
estimate that during the third quarter, approximately 210,000 or 2 MMcfe per day was deferred. All
shut-in production was fully restored prior to the end of the third quarter of 2004. During the fourth quarter of 2004, we experienced production declines at three key fields. In
November 2004, the High Island 47 No. 1 well depleted. A third party operates this field and, our
working interest is 33%. Prior to depletion, the well produced an average of 5 MMcfe per day to
our interest, during 2004. In December 2004, our deep well at High Island 115, the No. 1, was
shut-in due to a mechanical problem. A third party operates the well, and, we have a 50% working
interest. During 2004, this well contributed an average of 9 MMcfe per day to our total daily
production. We expect production to be restored during the third quarter of 2005. In late
December 2004, our average daily production rate at High Island A283, dropped by an estimated 5
MMcfe/day from approximately 28 MMcfe/day as a result of the depletion on a pre-existing well and
natural decline of newly developed wells. Production Volume 2003 vs. 2002 The 5% increase in production for 2003 as compared to 2002, is primarily a result of newly
developed production combined with additions from acquisitions made in 2003 and 2002. Onshore. Daily production rates increased 12% from an average of 155 MMcfe/day during 2002 to 173
MMcfe/day during 2003. The increase in onshore production is primarily attributable to newly
developed production in South Texas and Arkoma. In South Texas we drilled 56 successful wells and
increased our average daily production rate to 140 MMcfe/day during 2003 from 123 MMcfe/day in
2002. In Arkoma, we more than doubled the number of wells drilled in 2002 by successfully drilling
46 wells during 2003. The impact of the newly developed production was seen in the fourth quarter
of 2003 as our average daily rate in Arkoma increased to 25 MMcfe/day. Offshore. Production decreased 3% from an average of 126 MMcfe/day during 2002 to an average of
122 MMcfe/day during 2003. For the first nine months of 2003, offshore production averaged 117
MMcfe/day as production declines due to maturing reservoirs from existing key fields, Mustang
Island A-31/32, High Island 39, West Cameron 587 and South Marsh Island 253, were greater than new
production added from wells and facilities brought on-line throughout 2003. Specifically, we had
disappointing results at South Timbalier 314/317 that was brought on-line in early 2003.
Contributing to the year-over-year production decline was the effect of shifting approximately $40
million of our 2002 offshore capital expenditure budget to our onshore region to fund the May 2002
acquisition of producing properties in South Texas from Burlington Resources. During the fourth
quarter of 2003, offshore production increased by approximately 16% to an average rate of 136
MMcfe/day as we began to absorb the properties acquired from Transworld in mid-October and
experienced production increases from newly developed fields, in particular, High Island 115 and
High Island 47. -30-




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##### Table of Contents



Commodity Prices and Effects of Hedging 2004 vs. 2003 Our average unhedged or sales price for natural gas increased by 11% from $5.23 per Mcf during 2003
to $5.78 per Mcf during 2004. Included in natural gas revenues for 2004 is a loss of $70.1 million
from natural gas hedging activities, which includes an unrealized loss of $1.9 million representing
the ineffective portion of our derivative instruments that are not eligible for deferral under SFAS
133. The ineffectiveness was a result of changes during the period in the price differentials
between the index price of the derivative contract, which uses a New York Mercantile Exchange
(NYMEX) index, and the index price for the point of sale for the cash flow that is being hedged,
the majority of which is the Houston Ship Channel index. As a result of the loss from hedging
activities, we realized an average natural gas price during 2004 of $5.17 per Mcf that was 89% of
or $0.61 lower than our average sales price. During 2003, we incurred a hedge loss from natural
gas derivatives of $67.9 million, which is included in natural gas revenues and includes an
unrealized loss of $1.9 million recognized for ineffectiveness, resulting in an average realized
price of $4.55 per Mcf that was 87% of, or $0.68 per Mcf lower than our sales price. Commodity Prices and Effects of Hedging 2003 vs. 2002 Our average wellhead price during 2003, before the effects of our hedging program, was $5.23 per
Mcfe, up 66% over 2002. The increase in our natural gas and oil revenues was substantially offset
by a $68.3 million loss from our hedging program, which lowered the price that we realized on our
natural gas production by $0.68 Mcf during the period. The largest portion of this loss resulted
from fixed price swaps for natural gas that we entered into during the fourth quarter of 2001 in
connection with our acquisition of producing properties in South Texas. As a result of these
swaps, we effectively fixed the price that we received on approximately 40 MMcf per day at $3.19,
resulting in a loss of $32 million, or 47% of our total hedging loss for 2003. For 2003, we realized an average natural gas price of $4.55 per Mcf, which was 87% of, or $0.68 per
Mcf lower than our average unhedged natural gas price or wellhead price of $5.23 per Mcf for the
period. Included in natural gas revenues is a loss of $67.9 million from natural gas hedging
activities, which includes an unrealized loss of $1.9 million representing the ineffective portion
of our derivative instruments that are not eligible for deferral under SFAS No. 133. For 2002, we
realized an average gas price of $3.32 per Mcf, which was 105% of the average unhedged natural gas
price of $3.16 per Mcf for the period. This resulted in natural gas revenues that were $16.4
million higher than the revenues we would have achieved if hedges had not been in place during the
period. For 2002, our natural gas revenues included a realized gain of $16.4 million from hedging
activities. For 2003, we realized an average oil price of $28.15 per Bbl, which was 99% of or $0.31 per Bbl
lower than the average unhedged price of $28.46 per Bbl for the period. As a result of oil hedging
activities, oil revenues for 2003 were $0.4 million lower than the revenues we would have achieved
if oil hedges had not been in place during the period. We had no oil hedges in place during 2002
and realized an average oil price of $23.99 per Bbl. Operating Expenses Year Ended December 31,
    
    
    Year Ended December 30,Operating Expenses per Mcfe
    
    2004
    
    
    2003
    
    
    Variance
    
    
    2003
    
    
    2002
    
    
    VarianceLease operating expense
    
    $
    0.45
    
    
    $
    0.44
    
    
    $
    0.01
    
    
    
    2
    %
    
    $
    0.44
    
    
    $
    0.33
    
    
    $
    0.11
    
    
    
    33
    %Severance tax
    
    
    0.10
    
    
    
    0.15
    
    
    
    (0.05
    )
    
    
    -33
    %
    
    
    0.15
    
    
    
    0.09
    
    
    
    0.06
    
    
    
    67
    %Transportation expense
    
    
    0.10
    
    
    
    0.10
    
    
    
    
    
    
    
    
    %
    
    
    0.10
    
    
    
    0.09
    
    
    
    0.01
    
    
    
    11
    %Asset retirement accretion expense
    
    
    0.04
    
    
    
    0.03
    
    
    
    0.01
    
    
    
    33
    %
    
    
    0.03
    
    
    
    
    
    
    
    0.03
    
    
    
    100
    %Depreciation, depletion and
amortization
    
    
    2.14
    
    
    
    1.83
    
    
    
    0.31
    
    
    
    17
    %
    
    
    1.83
    
    
    
    1.67
    
    
    
    0.16
    
    
    
    10
    %General and administrative, net
    
    
    0.27
    
    
    
    0.18
    
    
    
    0.09
    
    
    
    50
    %
    
    
    0.18
    
    
    
    0.13
    
    
    
    0.05
    
    
    
    38
    %Total operating expenses per
unit of production
    
    $
    3.10
    
    
    $
    2.73
    
    
    $
    0.37
    
    
    
    14
    %
    
    $
    2.73
    
    
    $
    2.31
    
    
    $
    0.42
    
    
    
    18
    %
 Total operating expenses in 2004 increased 30% over 2003 driven primarily by higher depreciation,
depletion and non-recurring general and administrative expenses. On a unit production basis,
operating expenses increased $0.37 per Mcfe produced, or 14%, over 2003. Depreciation, depletion
and amortization accounted for $0.31 of the increase and the additional general and administrative
expenses contributed $0.08 per Mcfe. Severance tax was $0.05 per Mcfe lower primarily as a result
of exemptions in South Texas due to our high-cost/tight-gas formation designation. -31-




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Lease Operating Expense. On an absolute dollar basis, lease operating expense increased by 19%
during 2004. This increase relates primarily to our integration of offshore Gulf of Mexico
properties that we acquired during the fourth quarter of 2003. These properties originally carried
a relatively high operating cost and we are working to bring the cost structure of these properties
more into line with our base offshore properties. Although lease operating expense was up in
absolute terms in 2004, on a per unit of production basis taking into account our 15% increase in
production, lease operating expense increased by only 2% or $0.01 in 2004. While we remain
committed to minimizing our operating cost structure, in light of increasing service costs and our
continued acquisition activities, we expect to experience upward pressure in our lease operating
expense during 2005 and beyond. During 2003, the increase in lease operating expenses as compared to 2002 is attributable to the
continued expansion of our operations both onshore and offshore. Our overall operating expenses
are increasing as we add new wells and production facilities and continue to maintain production
from existing, maturing properties. Specific increases for 2003 were incurred for production
enhancement and compression, insurance and contract services. In addition, we incurred $2.6
million in non-recurring expenses associated with workovers. The acquisition of the Transworld properties in October 2003 caused our lease operating expense on
a per unit basis to increase from an average of $0.42 per Mcfe for the first nine months of 2003 to
$0.47 per Mcfe during the fourth quarter of 2003. The majority of the Transworld fields were
originally developed by major oil and gas producers and due to their age and complexity, lease
operating expenses for these properties are expected to be significantly higher than that of our
existing offshore fields. Severance Tax. Severance tax is a function of volume and revenues generated from onshore
production. On an absolute dollar basis, severance tax decreased by 25% from 2003 to 2004. On an
Mcfe basis, severance tax decreased by $0.05 or 33% for the twelve-month period. Despite higher
wellhead prices during 2004, severance tax expense is lower primarily due to severance tax rebates
received late in 2004 on our South Texas properties as a result of their high-cost/tight-sand
designation. For 2003, the increase in severance tax expense and severance tax per Mcfe is due to a 66% increase
in average wellhead prices for natural gas during 2003 combined with a 12% increase in onshore
production as compared to 2002. Depreciation, Depletion and Amortization. The increase in our depreciation, depletion and
amortization expense for 2004 was primarily a result of a higher depletion rate combined with a 15%
increase in production for the year. Our depletion rate of $2.14 per Mcfe during 2004 was 17%
higher than the $1.83 per Mcfe during 2003. Higher average finding costs per unit were the primary
factor in the increase in our depletion rate. These higher finding costs are the result of the
naturally declining productivity of our mature onshore drilling operations compounded by increasing
service costs. Rising acquisition prices resulting from the continued strength of natural gas
prices were also a factor. In addition, our estimated future development costs at December 31,
2004 increased 48% from estimates at December 31, 2003, primarily as a result of the future
development costs relating to several offshore Gulf of Mexico properties acquired in October 2004.
For 2004, producing property dispositions resulted in reserve reductions of 63.3 Bcfe. Finally,
for 2004, we incurred downward revisions of 20 Bcfe, either due to proved undeveloped reserves that
were depleted or otherwise not recoverable, or from production performance indicating less gas in
place or smaller reservoir size than initially estimated. During 2003, the increase in our DD&A expense was primarily a result of a higher depletion rate
combined with a 5% increase in production volumes for 2003. Our depletion rate increased during
2003 as a result of downward reserve revisions related to reservoir performance of approximately 40
Bcfe; the addition of more costs to our depreciation base with fewer additions for reserves as our
average finding and development cost increased during 2003; and a 52% increase in our estimated
future development costs at year end, the majority of which was due to the proved undeveloped
classification of 68% of the reserves acquired from Transworld. Asset Retirement Accretion Expense.The increase in ARO accretion expense during 2004 as compared
to 2003, is primarily a result of additions to our ARO liability since the end of the third quarter
of 2003 as a result of producing property acquisitions, offset in part by the disposition of our
South Louisiana properties in February 2004 and our Appalachian Basin properties in June 2004. -32-




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##### Table of Contents



General and Administrative Expenses, Net of Overhead Reimbursements and Capitalized General and
Administrative Expenses Year Ended December 31,
    
    
    Year Ended December 31,General and Administrative per Mcfe
    
    2004
    
    
    2003
    
    
    Variance
    
    
    2003
    
    
    2002
    
    
    VarianceGross general and administrative expense
    
    $
    0.40
    
    
    $
    0.32
    
    
    $
    0.08
    
    
    
    25
    %
    
    $
    0.32
    
    
    $
    0.28
    
    
    $
    0.04
    
    
    
    14
    %Operating overhead reimbursements
    
    
    (0.01
    )
    
    
    (0.02
    )
    
    
    0.01
    
    
    
    -50
    %
    
    
    (0.02
    )
    
    
    (0.02
    )
    
    
    
    
    
    
    
    %Capitalized general and administrative
    
    
    (0.12
    )
    
    
    (0.12
    )
    
    
    
    
    
    
    
    %
    
    
    (0.12
    )
    
    
    (0.13
    )
    
    
    0.01
    
    
    
    -8
    %General and administrative expense, net
    
    $
    0.27
    
    
    $
    0.18
    
    
    $
    0.09
    
    
    
    50
    %
    
    $
    0.18
    
    
    $
    0.13
    
    
    $
    0.05
    
    
    
    38
    %
 2004 vs. 2003. For 2004, net general and administrative expenses were up by 69% on an absolute
dollar basis from $19.5 million in 2003 to $32.9 million in 2004. Of the $13.4 million increase,
$9.5 million related to severance expenses and special incentive payments. A substantial portion
of the remaining increase related to changes in accounting for stock-based compensation, as well as
continuing professional expenses related to corporate governance compliance. Specifically, $4.1
million of the increase related to special bonuses awarded by our Board to 12 key employees,
including our Chief Executive Officer who received $3.2 million, who assisted in structuring and
consummating the KeySpan Exchange and Offering completed in June 2004 (see Note 3  Stockholders
Equity  KeySpan Exchange and Offering). Approximately $0.3 million related to accelerated vesting
of restricted stock held by directors who resigned or retired from our Board in June following the
KeySpan Exchange. Lastly, approximately $5.1 million related to executive severance accrued with
respect to three senior executives with rights to receive severance, accelerated vesting of options
and restricted stock, and other benefits under their employment agreements as a result of an
organizational realignment of management responsibilities during the fourth quarter of 2004. One
executive resigned effective December 14, 2004 and two executives resigned effective March 1, 2005. For general and administrative expense on a per-unit of production basis, the additional
compensation expenses of $9.5 million resulted in an $0.08 per Mcfe increase for 2004. Absent
these additional compensation expenses, gross general and administrative expense for 2004 would
have been $0.32 per Mcfe, unchanged from $0.32 per Mcfe in 2003 and net general and administrative
expense would have been $0.19 per Mcfe for 2004, an increase of $0.01 or 6%, from 2003. While
general and administrative expenses have increased as our company has grown, per unit expense is
comparable year-over-year as a result of the increase in our production volume during 2004. 2003 vs. 2002. The increase in aggregate general and administrative expense during 2003 was due
primarily to the expansion of our workforce that corresponds to the continued expansion of our
operations. As our workforce expands, we have experienced an increase in salaries and related
employee benefit expenses that include increases in our incentive compensation expense together
with expense for stock compensation as we adopted the fair value expense provisions for stock
options under SFAS 123, as amended, in January 2003. Our rent expense increased as we expanded our
leased office space in downtown Houston to accommodate our growing workforce and opened an office
in Denver to coordinate our expansion into the Rocky Mountains. Our legal, audit and accounting
expenses increased as we implemented new corporate governance policies required by the
Sarbanes-Oxley Act of 2002 and engaged an outside firm to perform ongoing internal auditing
functions. The higher rate per Mcfe during 2003 reflects the increase in our aggregate general and
administrative expenses combined with a proportional reduction in the amount of general and
administrative expense capitalized during 2003. The mix of our capitalized expenses has changed as
we incurred more costs during 2003 that were not directly related to our natural gas and oil
exploration and development activities. We expect that as our company continues to grow and
expand, our general and administrative expenses will increase. Other Income and Expense, Interest and Taxes Other Income and Expense. For 2004, Other Income and Expense includes two items: (i) income of
$1.0 million related to refunds of prior years severance tax expense; and (ii) a $0.2 million
write-off of a portion of our debt issuance costs due to the June 2, 2004 reduction in the
borrowing base on our revolving bank credit facility due to the disposition of our Appalachian
Basin assets in June 2004. In July 2002, we applied for and received from the Railroad Commission
of Texas a high-cost/tight-gas formation designation for a portion of our South Texas production.
For qualifying wells, production is either exempt from tax or taxed at a reduced rate until
certain capital costs are recovered. For 2004, the recognition of other income as a result of the
recoupment of prior years expense is considerably less than in 2003 as we are nearing the end of
the recoupment process. For 2003, Other Income and Expense includes: (i) debt extinguishment
expenses totaling $5.9 million incurred pursuant to the call and early redemption of our $100
million 8 5/8% senior subordinated notes due 2008; and (ii) income of $21.6 million related to refunds
of prior years severance tax expense. In 2002, we recognized as other income, $9.1 million
related to the recoupment of prior years severance tax expense. -33-




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##### Table of Contents



Year Ended December 31,
    
    
    Year Ended December 31,Interest and Average Borrowings
    
    2004
    
    
    2003
    
    
    Variance
    
    
    2003
    
    
    2002
    
    
    Variance(in thousands)Gross interest
    
    $
    17,813
    
    
    $
    15,642
    
    
    $
    2,171
    
    
    
    14
    %
    
    $
    15,642
    
    
    $
    15,373
    
    
    $
    269
    
    
    
    2
    %Capitalized interest
    
    
    (8,358
    )
    
    
    (7,300
    )
    
    
    (1,058
    )
    
    
    14
    %
    
    
    (7,300
    )
    
    
    (7,975
    )
    
    
    675
    
    
    
    -8
    %Interest expense, net of
capitalized interest
    
    $
    9,455
    
    
    $
    8,342
    
    
    $
    1,113
    
    
    
    13
    %
    
    $
    8,342
    
    
    $
    7,398
    
    
    $
    944
    
    
    
    13
    %Average borrowings
    
    $
    289,410
    
    
    $
    240,000
    
    
    $
    49,410
    
    
    
    -21
    %
    
    $
    240,000
    
    
    $
    263,600
    
    
    $
    (23,600
    )
    
    
    -9
    %Average interest rate
    
    
    5.68
    %
    
    
    6.08
    %
    
    
    0.40
    %
    
    
    -7
    %
    
    
    6.08
    %
    
    
    5.38
    %
    
    
    0.70
    %
    
    
    13
    %
 Interest Expense, Net of Capitalized Interest. For 2004, the increase in gross interest expense is
due to an increase in both fixed debt and bank debt offset in part by a decrease in average
interest rates. Our fixed debt increased in June 2003 when we replaced our existing senior
subordinated notes of $100 million at 8 5/8% with new senior subordinated notes of $175 million at 7%.
Bank borrowings averaged $112 million at a rate if 3.74% during 2004 compared to an average of $90
million at 3.42% during 2003. Bank debt has increased as we utilized our revolving bank credit
facility to fund not only a portion of the KeySpan Exchange in June 2004 but also our two producing
property acquisitions in September and October 2004. Although the majority of our bank debt is at
LIBOR rates, we do expect to see an increase in rates during 2005 if, based on our belief, the
Federal Reserve continues its expected plan to slowly increase interest rates in an effort to curb
inflation. Rates were increased in February 2005, by one quarter of a percent. Capitalized
interest is a function of unevaluated properties and the increase for 2004 corresponds to the
increase in our average unevaluated property balance throughout 2004. During 2003, our average borrowings decreased and our average interest rate increased as we
replaced our existing fixed debt of $100 million at 8 5/8% with new fixed debt of $175 million at 7%
and used excess proceeds from the newly issued debt to repay outstanding borrowings under our
revolving bank credit facility which bears interest at lower rates that averaged 3.4% during both
2003 and 2002. Bank borrowings averaged $90 million at a rate if 3.42% during 2003 compared to an
average of $162.2 million at 3.42% during 2002. In addition, capitalized interest decreased during
2003. Our capitalized interest is a function of unevaluated properties and the decrease
corresponds to the decrease in our average unevaluated property balance throughout 2003 prior to
our October 2003 acquisition of producing properties from Transworld. Income Tax Provision.Our provision for taxes includes both state and federal taxes. For the
current year, our state tax obligations have increased as our onshore revenues have increased and
as we have expanded our operations into several Rocky Mountain states. The 34% increase in income
taxes for 2004 corresponds to the 26% increase in income before taxes. Our current provision
increased to $41.2 million as we utilized all of our net operating loss carryforwards during 2003
and moved to a tax paying status. Prior to the third quarter of 2003, the majority of our federal
income taxes were deferred. Our current provision for 2004 includes $1.4 million relating to
nondeductible excess executive compensation expense of which $1.0 million was incurred in the
second quarter as a result of the special bonus paid to our Chief Executive Officer in connection
with the KeySpan Exchange and $0.4 million incurred in the fourth quarter as a result of the
retirement of our former Senior Vice President and General Manager  Offshore Division. During 2003, our current provision increased to $12.5 million as we depleted our net operating loss
carryforwards and moved to a tax paying status where, as in prior years, all federal and state
income taxes were deferred. Liquidity Capital Requirements Our principal requirements for capital are to fund our capital investment program and to satisfy
our contractual obligations, primarily the repayment of long-term debt. Our capital investments
include the following:  
    Costs of acquiring and maintaining our lease acreage position and our seismic resources;
    Costs of drilling and completing new natural gas and oil wells;
    Costs of acquiring additional reserves;
    Costs of installing new production infrastructure;
    Costs of maintaining, repairing, and enhancing existing natural gas and oil wells;
    Costs related to plugging and abandoning unproductive or uneconomic wells; and -34-




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##### Table of Contents




    Indirect costs related to our exploration activities, including payroll and
other expense attributable to our exploration professional staff. Our capital expenditure budget for 2005 has been set at an initial level of $445 million. We are
the designated operator of approximately 77% of our wells. Operating allows us the ability to
exercise control over the magnitude and timing of our capital program and provides us significant
latitude to increase or decrease our spending in response to changes in price, operational
developments or acquisition opportunities. To maintain flexibility of our capital program, we do
not enter into material long-term obligations with any of our drilling contractors or service
providers with respect to our operated properties. We do not include property acquisition costs in
our capital budget because the size and timing of capital requirements for acquisitions are
inherently unpredictable. As the year progresses, we will continue to evaluate our capital
spending. Actual levels may vary due to a variety of factors, including drilling results, natural
gas prices, economic conditions and future acquisitions. Total company capital expenditures during 2004 were $518.5 million. We invested $517.0 million in
natural gas and oil properties, which included $149.6 million for the acquisition of producing
properties and, we spent $1.5 million for non-oil and gas property and equipment. Non-oil and gas
property and equipment includes expenditures to upgrade to our information technology systems and
office equipment and compares to $1.9 million spent in 2003. For 2004, we spent 53% offshore and
42% onshore with the balance of 5% on capitalized interest and general and administrative costs.
We completed the drilling of a record 211 gross wells (170.5 net) of which 84% or 177 (143.5 net)
were successful and 34 (27.0 net) were unsuccessful with an additional 25 wells (21.2 net) in
progress at the end to the year. The table below provides a five-year historical analysis of our
capital expenditures for natural gas and oil properties and total net proved reserve additions,
that is defined as the sum of reserve extensions and discoveries, revisions and acquisitions. See
Note 12  Supplemental Information On Natural Gas and Oil Exploration, Development and Production
Activities for a detail calculation of the changes in our reserve quantities during the period. Years Ended December 31,2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(in thousands)Natural gas and oil capital expendituresProducing property acquisitions
    
    $
    149,599
    
    
    $
    175,420
    
    
    $
    73,351
    
    
    $
    69,010
    
    
    $
    13,935Leasehold and lease acquisition costs (1)
    
    
    57,741
    
    
    
    56,076
    
    
    
    36,458
    
    
    
    48,068
    
    
    
    32,599Development
    
    
    245,971
    
    
    
    162,235
    
    
    
    122,036
    
    
    
    177,256
    
    
    
    103,335Exploration
    
    
    63,646
    
    
    
    66,259
    
    
    
    26,536
    
    
    
    72,056
    
    
    
    34,160Total natural gas and oil capital expenditures
    
    
    516,957
    
    
    
    459,990
    
    
    
    258,381
    
    
    
    366,390
    
    
    
    184,029Producing property dispositions
    
    
    (72,712
    )
    
    
    
    
    
    
    (5,309
    )
    
    
    
    
    
    
    Net natural gas and oil capital expenditures
    
    $
    444,245
    
    
    $
    459,990
    
    
    $
    253,072
    
    
    $
    366,390
    
    
    $
    184,029Proved reserve additions, net of revisions
(MMcfe)
    
    
    225,633
    
    
    
    212,969
    
    
    
    144,291
    
    
    
    136,231
    
    
    
    100,352
   (1)
    
    For 2004, 2003, 2002, 2001 and 2000, leasehold costs include capitalized
interest and general and administrative expenses of $23.2 million, $20.2 million, $21.1
million, $24.9 million and $23.3 million, respectively. Future Commitments In addition to our capital expenditure program, we are committed to making cash payments in the
future on two types of contracts: note agreements and operating leases. As of December 31, 2004,
we do not have any capital leases or have we entered into long-term contracts for drilling rigs or
equipment. As of December 31, 2004, we do not have off-balance sheet debt or other such unrecorded
obligations, and we have not guaranteed the debt of any other party. The table below provides
estimates of the timing of future payments that we were obligated to make based on agreements in
place at December 31, 2004. In addition to the contractual obligations listed on the table below,
our balance sheet at December 31, 2004, reflects accrued interest payable on our revolving bank
credit facility of approximately $92,000 which is payable over the next 90-day period. We expect
to make annual interest payments of $12.3 million per year on our $175 million of 7% senior
subordinated notes due June 2013. And, we anticipate making income tax payments of approximately
$50 million 2005. -35-




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##### Table of Contents



As of December 31, 2004Payments Due by PeriodReference
    
    
    Total
    
    
    1 year or less
    
    
    2  3 years
    
    
    4  5 years
    
    
    after 5 years(in thousands)Contractual Obligations:Revolving bank credit facility, due April 2008
    
    Note 2
    
    $
    180,000
    
    
    $
    
    
    
    $
    
    
    
    $
    180,000
    
    
    $
    7% senior subordinated notes, due June 2013
    
    Note 2
    
    
    175,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    175,000Derivative instruments
    
    Note 7
    
    
    75,149
    
    
    
    68,081
    
    
    
    5,551
    
    
    
    1,517
    
    
    
    Operating leases
    
    Note 9
    
    
    7,223
    
    
    
    1,550
    
    
    
    3,129
    
    
    
    2,544
    
    
    
    Lump sum payments employment contracts
    
    Note 6
    
    
    2,150
    
    
    
    2,150
    
    
    
    
    
    
    
    
    
    
    
    439,522
    
    
    
    71,781
    
    
    
    8,680
    
    
    
    184,061
    
    
    
    175,000Other Long-Term Obligations:Asset retirement obligations
    
    Note 1
    
    
    91,746
    
    
    
    662
    
    
    
    9,813
    
    
    
    6,771
    
    
    
    74,500Total contractual obligations and
commitments
    
    
    
    
    
    $
    531,268
    
    
    $
    72,443
    
    
    $
    18,493
    
    
    $
    190,832
    
    
    $
    249,500
 Capital Resources We intend to fund our capital expenditure program and contractual commitments through cash flows
from our operations and borrowings under our revolving bank credit facility. If a significant
acquisition opportunity arises, we may also access public markets for debt or to issue additional
equity securities. Our primary sources of cash during 2004 were from funds generated from
operations. Cash was used to fund acquisitions, exploration and development expenditures and to
reduce debt under our revolving bank credit facility. We made aggregate cash payments of $16.4
million and $41.8 million, respectively, for interest and taxes during 2004. The table below
summarizes the sources of cash during 2004 and 2003. Years Ended December 31,2004
    
    
    2003
    
    
    variance
    
    
    % change(in thousands)Net cash provided by operating activities
    
    $
    522,436
    
    
    $
    390,832
    
    
    $
    131,604
    
    
    
    34
    %Net cash used for investments in property and equipment
    
    
    505,217
    
    
    
    461,822
    
    
    
    43,395
    
    
    
    9
    %Net cash (used in) provided by financing activities
    
    
    (1,211
    )
    
    
    55,528
    
    
    
    (56,739
    )
    
    
    -102
    %Net (decrease) increase in cash
    
    $
    16,008
    
    
    $
    (15,462
    )
    
    $
    31,470
    
    
    
    -204
    %
 At December 31, 2004, we had a working capital deficit of $31.9 million, long-term debt of $355
million and $219.6 million of borrowing capacity available under our revolving bank credit
facility. The working capital deficit at December 31, 2004, was due to a current liability of
$68.1 million representing the fair value of our derivative instruments estimated to be payable
over the next 12 months. The fair value of our derivative instruments will fluctuate with
commodity prices, and as commodity prices increase, our liquidity exposure tends to increase as a
result of open derivative instruments. Consequently, we are more likely to have the largest
unfavorable mark-to-market position in a high commodity price environment. Our working capital
balance fluctuates as a result of the timing and amount of cash receipts and disbursements for
operating activities and borrowings or repayments under our revolving bank credit facility. As a
result, we often have a working capital deficit or a relatively small amount of positive working
capital, which is typical of companies of our size in the exploration and production industry. The 34% increase in net cash provided by operating activities during 2004 was primarily
attributable to the increase in net income as a result of a 14% increase in average realized
natural gas price, which included the effect of hedges, together with a 15% increase in production
volume, offset in part by a 30% increase in operating expenses. Fluctuations in operating assets
and liabilities are caused by the timing of cash receipts and disbursements. During 2004, total long-term debt increased by a net $53 million, as we borrowed to finance a
portion of the KeySpan Exchange and to fund the two producing property acquisitions made in
September and October of 2004. We used net proceeds of $282 million generated from the public
offering of 6,820,000 shares of our common stock plus bank borrowings of $107 million to fund the
$389 million cash portion of the KeySpan Exchange whereby we redeemed and cancelled 10,800,000 of
our shares held by KeySpan with cash value of $310.7 million. Access to Capital Markets. In March 2004, we filed a shelf registration statement with the SEC for
the offering, from time to time, of up to $600 million of our common stock, preferred stock,
depositary shares and debt securities, or a combination -36-




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##### Table of Contents



of any of these securities,
as well as for all the shares of our common stock owned at that time by
KeySpan. Subsequent to the June 2004 public offering of 6.8 million shares at $48.00 per share,
the proceeds of which were used to finance a portion of the KeySpan Exchange transaction, we have
approximately $272.5 million of capacity remaining under this shelf registration statement. On
October 27, 2004, we filed a second shelf registration statement with the SEC for the offering,
from time to time, of up to an additional $477.5 million of our equity or debt securities. The
combination of the two shelf registrations statements provides an aggregate of approximately $750
million for the offering of our common stock, preferred stock, depositary shares and debt
securities, or a combination of any of these securities. We believe that operating cash flow and our credit facility will be adequate to meet our capital
and operating requirements for 2005. We continuously monitor our working capital and debt position
as well as coordinate our capital expenditure program with expected cash flows and projected debt
repayment schedules. Although we have no specific budget for future property acquisitions, should
attractive opportunities arise, we believe we could finance the additional capital expenditures
with cash on hand, operating cash flow, additional borrowing under our revolving bank credit
facility, issuances of additional equity or debt securities or development with industry partners. Off-Balance Sheet Arrangements We do not currently utilize any off-balance sheet arrangements to enhance liquidity and capital
resource positions, or for any other purpose. Any future transactions involving off-balance sheet
arrangements would be scrutinized and disclosed. 
 Item 7A. Quantitative and Qualitative Disclosures About Market Risk Market Risk Our major market risk exposure continues to be the prices applicable to our natural gas and oil
production. Our sales price is primarily driven by the prevailing market price. Historically,
prices received for our natural gas and oil production have been volatile and unpredictable. Interest Rate Market Risk At December 31, 2004, total debt was $355 million, of which approximately 49% or $175 million is
fixed at an interest rate of 7%. The remaining 51% of our total debt balance at December 31, 2004,
or $180 million, represents our bank debt that is tied to floating or market interest rates.
Fluctuations in floating interest rates will cause our annual interest costs to fluctuate. During
the fourth quarter of 2004, the interest rate on our outstanding bank debt averaged 4.22%. If the
balance of our bank debt at December 31, 2004, were to remain constant, a 10% change in market
interest rates would impact our cash flow by an estimated $195,000 per quarter. Commodity Risk We utilize derivative commodity instruments to hedge future sales prices on a portion of our
natural gas and oil production to achieve a more predictable cash flow, as well as to reduce our
exposure to adverse price fluctuations of natural gas. Our derivatives are not held for trading
purposes. While the use of hedging arrangements limits the downside risk of adverse price
movements, it also limits increases in future revenues as a result of favorable price movements.
The use of hedging transactions also involves the risk that the counterparties are unable to meet
the financial terms of such transactions. Hedging instruments that we use are swaps, collars and
options, which we generally place with major investment grade financial institutions that we
believe are minimal credit risks. We believe that our credit risk related to our natural gas
futures and swap contracts is no greater than the risk associated with the primary contracts and
that the elimination of price risk reduces volatility in our reported results of operations,
financial position and cash flows from period to period and lowers our overall business risk;
however, as a result of our hedging activities we may be exposed to greater credit risk in the
future. Our hedges are cash flow hedges and qualify for hedge accounting under SFAS 133 and, accordingly,
we carry the fair market value of our derivative instruments on the balance sheet as either an
asset or liability and defer unrealized gains or losses, net of tax, in accumulated other
comprehensive income. Gains and losses are reclassified from accumulated other comprehensive income
to the income statement as a component of natural gas and oil revenues in the period the hedged
production occurs. If any ineffectiveness occurs, amounts are recorded directly to natural gas and
oil revenues. During both 2004 and 2003, we recognized $1.9 million in each year for
ineffectiveness. The ineffectiveness was primarily a result of changes at the end of the current
period in the price differentials between the index price of the derivative contract, which uses a
NYMEX index, and the index price for the point of sale for the cash flow that is being hedged, the
majority of which is the Houston Ship Channel index. -37-




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##### Table of Contents



Changes in Fair Value of Derivative Instruments The following table summarizes the change in the fair value of our derivative instruments for each
of the twelve-month periods from January 1 to December 31, 2004 and 2003 and provides the fair
value at the end of each period. Year Ended

    
    Year EndedDecember 31, 2004

    
    December 31, 2003Change in Fair Value of Derivatives Instruments:
    
    Before Tax

    
    Before Tax(in thousands)Fair value of contracts at January 1
    
    $
    (36,862
    )
    

    $
    (38,772
    )Realized loss on contracts settled
    
    
    68,195
    
    

    
    66,408Fair value of new contracts when entered into
    
    
    
    
    

    
    5,288(Decrease) in fair value of all open contracts
    
    
    (106,482
    )
    

    
    (69,786
    )Net (decrease) increase during period
    
    
    (38,287
    )
    

    
    1,910Fair value of contracts outstanding at December 31
    
    $
    (75,149
    )
    

    $
    (36,862
    )
 Derivatives in Place as of the Date of Our Report As of February 22, 2005, the following table summarizes, on an annual basis, our natural gas hedges
in place for 2005, 2006, 2007 and 2008. For 2005, we have hedged approximately 70% of our
estimated production or a total of 260,000 million British thermal units per day or MMBtu/day and,
our ceiling will average $6.086/MMBtu and our floor will average $4.978/MMBtu. For 2006, we have
hedged approximately 67% of our estimated production or a total of 250,000 MMBtu/day with an
average ceiling of $6.946/MMBtu and average floor of $5.788/MMBtu. Natural Gas Hedges
    
    Fixed Price Swaps
    
    
    CollarsDaily
    
    
    NYMEX
    
    
    Daily
    
    
    NYMEXVolume
    
    
    Contract
    
    
    Volume
    
    
    Contract Price(1)Period
    
    (MMBtu)
    
    
    Price
    
    
    (MMBtu)
    
    
    Floor
    
    
    CeilingJanuary  December 2005
    
    
    80,000
    
    
    $
    5.304
    
    
    
    180,000
    
    
    $
    4.833
    
    
    $
    6.434January  December 2006
    
    
    30,000
    
    
    
    5.893
    
    
    
    220,000
    
    
    
    5.788
    
    
    
    6.946January  December 2007
    
    
    
    
    
    
    
    
    
    
    30,000
    
    
    
    5.000
    
    
    
    6.597January  December 2008
    
    
    
    
    
    
    
    
    
    
    20,000
    
    
    
    5.000
    
    
    
    5.720
   (1)
    
    For collars, price represents a weighted average for outstanding
contracts. For natural gas, transactions are settled based upon the NYMEX price on the final trading day of
the month. In order to determine fair market value of our derivative instruments, we obtain
mark-to-market quotes from external counterparties. With respect to any particular swap transaction, the counterparty is required to make a payment to
us if the settlement price for any settlement period is less than the swap price for the
transaction, and we are required to make payment to the counterparty if the settlement price for
any settlement period is greater than the swap price for the transaction. For any particular collar
transaction, the counterparty is required to make a payment to us if the settlement price for any
settlement period is below the floor price for the transaction, and we are required to make payment
to the counterparty if the settlement price for any settlement period is above the ceiling price
for the transaction. We are 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, we
have 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. 
 Item 8.Financial Statements and Supplemental Data For financial statements required by Item 8, see Item 15 in Part IV of this Annual Report. 
 Item 9.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure None. -38-




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##### Table of Contents



Item 9A. Controls and
Procedures Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures Under the supervision and with the participation of our management, including our Chief Executive
Officer and our Chief Financial Officer, we conducted an evaluation of our disclosure controls and
procedures, as this term is defined under Rule 13a-15(e) promulgated under the Securities Exchange
Act of 1934, as amended (the Exchange Act). Based on this evaluation, our Chief Executive Officer
and our Chief Financial Officer concluded that our disclosure controls and procedures were
effective as of the end of the period covered by this Annual Report. Design and Evaluation of Internal Control Over Financial Reporting Pursuant to Section 404
of the Sarbanes-Oxley Act of 2002, we have included a report of managements
assessment of the design and effectiveness of its internal controls as part of this Annual Report
on Form 10-K for the fiscal year ended December 31, 2004. Deloitte and Touche LLP, our independent
public accountants, also attested to, and reported on, managements assessment of the effectiveness
of internal control over financial reporting. Managements report and the independent registered
public accounting firms attestation report are included in our 2004 Financial Statements in Item
15 under the captions entitled Managements Report on Internal Control Over Financial Reporting
and Report of Independent Registered Public Accounting Firm and are incorporated herein by
reference. Changes in Internal Control Over Financial Reporting No change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the
Securities Exchange Act of 1934) occurred during the fourth quarter of our fiscal year ended
December 31, 2004 that has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting. 
 Item 9B. Other Information. None. 
 Part III. 
 Item 10. Directors and Executive Officers of Houston Exploration The information required by Item 10 that relates to our directors and executive officers is
incorporated by reference from the information appearing under the captions Election of
Directors, Executive Officers, Board Committees  Audit Committee, Board Committees 
Nominating and Corporate Governance Committee and Compliance with Section 16(a) in our
definitive proxy statement that is to be filed with the SEC pursuant to the Exchange Act within 120
days of the end of our fiscal year on December 31, 2004. 
 Item 11. Executive Compensation The information required by Item 11 that relates to compensation of our principal executive
officers and our directors is incorporated by reference from the information appearing under the
captions Executive Compensation and Election of Directors  Directors Meetings and
Compensation in our definitive proxy statement that is to be filed with the SEC within 120 days of
the end of our fiscal year on December 31, 2004. In addition and in accordance with Item 402(a)(8)
of Regulation S-K, the information contained in our definitive 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 Annual Report. For
information concerning our code of ethics, see Item 1. and 2. Business and Properties  Available
Information. 
 Item 12. Security Ownership of Beneficial Owners and Management The information required by Item 12 that relates to the ownership of securities by management and
others is incorporated by reference from the information appearing under the caption Securities
Authorized for Issuance Under Equity Compensation Plans and Security Ownership of Certain
Beneficial Owners and Management in our definitive proxy statement that is to be filed with the
SEC within 120 days of the end of our fiscal year on December 31, 2004. 
 Item 13. Certain Relationships and Related Transactions The information required by Item 13 that relates to business relationships and transactions with
our management and other related parties is incorporated by reference from the information
appearing under the captions Certain Relationships and Related Party Transactions and
Compensation Committee Interlocks and Insider Participation in our definitive proxy statement
that is to be filed with the SEC within 120 days of the end of our fiscal year on December 31,
2004. -39-




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##### Table of Contents



Item 14. Principal Accounting Fees and Services The information required by Item 14 that relates to services provided by our Independent Public
Accountants and the fees incurred for services provided during 2004 and 2003 is incorporated by
reference from the information appearing under the captions Fees Billed by Independent Public
Accountants in our definitive proxy statement that is to be filed with the SEC within 120 days of
the end of our fiscal year on December 31, 2004. 
 Part IV. 
 Item 15.Exhibits, Financial Statement Schedules (a) Documents Filed as a Part of this Report 1. Financial Statements: PAGEIndex to Financial Statements
    
    
    F-1Managements Report on Internal Controls Over Financial Reporting
    
    
    F-2Report of Independent Registered Public Accounting Firm  Internal Control Over Financial Reporting
    
    
    F-3Report of Independent Registered Public Accounting Firm  Financial Statements
    
    
    F-4Consolidated Balance Sheets as of December 31, 2004 and 2003
    
    
    F-5Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002
    
    
    F-6Consolidated Statements of Stockholders Equity and Comprehensive Income for the Period
January 1, 2002 to December 31, 2004
    
    
    F-7Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002
    
    
    F-8Notes to Consolidated Financial Statements
    
    
    F-9Supplemental Information on Natural Gas and Oil Exploration, Development and
Production Activities (unaudited)
    
    
    F-32Quarterly Financial Information (Unaudited)
    
    
    F-37
 All other schedules are omitted because they are not applicable, not required, or because the
required information is included in the financial statements or related notes. 2. Exhibits: (a) See Index of Exhibits on page F-38 for a description of the exhibits filed as a part of this report. -40-




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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 COMPANYBy:
    /s/ William G. HargettWilliam G. HargettDate: February 22, 2005
    
    President and Chief Executive Officer -41-




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POWER OF ATTORNEY Each person whose signature appears below hereby constitutes and appoints John H. Karnes and James
F. Westmoreland, and each of them, his true and lawful attorney-in-fact and agent, with full powers
of substitution, for him and in his name, place and stead, in any and all capacities, to sign any
and all amendments to this Annual Report of Form 10-K, and to file the same, with all exhibits
thereto, and other documents in connection therewith, with the Securities and Exchange Commission
granting to said attorneys-in-fact, and each of them, full power and authority to perform any other
act on behalf of the undersigned required to be done in connection therewith. 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. Signature
    
    Title
    
    Date/s/ William G. Hargett

William G. Hargett
    
    Chairman of the Board of Directors,
President and Chief Executive Officer

(Principal Executive Officer)
    
    February 22, 2005/s/ John H. Karnes

John H. Karnes
    
    Senior Vice President and Chief Financial
Officer

(Principal Financial Officer)
    
    February 22, 2005/s/ James F. Westmoreland

James F. Westmoreland
    
    Vice President and Chief Accounting Officer

(Principal Accounting Officer)
    
    February 22, 2005/s/ Robert B. Catell

Robert B. Catell
    
    Director
    
    February 22, 2005/s/ John U. Clarke

John U. Clarke
    
    Director
    
    February 22, 2005/s/ David G. Elkins

David G. Elkins
    
    Director
    
    February 22, 2005/s/ Harold R. Logan, Jr.

Harold R. Logan, Jr.
    
    Director
    
    February 22, 2005/s/ Thomas A. McKeever

Thomas A. McKeever
    
    Director
    
    February 22, 2005/s/ Stephen W. McKessy

Stephen W. McKessy
    
    Director
    
    February 22, 2005/s/ Donald C. Vaughn

Donald C. Vaughn
    
    Director
    
    February 22, 2005
 -42-




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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 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 the 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 where the owner of a working interest in an natural gas and oil
lease assigns the working interest or a portion of the working interest 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. 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. G-1




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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 the 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. In addition, please
refer to the definitions of proved oil and gas reserves as provided in Rule 4-10(a)(2)(3)(4). The
rule is available at the SEC web site, http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas. Proved undeveloped location. A site on which a development well can be drilled consistent with
spacing rules for purposes of recovering proved undeveloped reserves. Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on
undrilled acreage or from existing wells where a relatively major expenditure is required from
recompletion. Recompletion.The completion for production of an existing well bore in another formation from that
in which the well has been previously completed. 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
natural gas or oil 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 the 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-2




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Index to Financial Statements PageManagements Report on Internal Controls Over Financial Reporting
    
    
    F-2Report of Independent Registered Public Accounting Firm  Internal Control Over Financial Reporting
    
    
    F-3Report of Independent Registered Public Accounting Firm  Financial Statements
    
    
    F-4Consolidated Balance Sheets as of December 31, 2004 and 2003
    
    
    F-5Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002
    
    
    F-6Consolidated Statements of Stockholders Equity and Comprehensive Income (Loss) for the Period
January 1, 2002 to December 31, 2004
    
    
    F-7Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002
    
    
    F-8Notes to Consolidated Financial Statements
    
    
    F-9Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities
(Unaudited)
    
    
    F-32Quarterly Financial Information (Unaudited)
    
    
    F-37
 F-1




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MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING To the Board of Directors and Stockholders of
The Houston Exploration Company The Houston Exploration Companys management is responsible for establishing and maintaining
adequate internal control over financial reporting, as such term is defined in Exchange Act Rules
13a-15(f). Under the supervision and with the participation of management, including Houston
Explorations principal executive officer and principal financial officer, Houston Exploration
conducted an evaluation of the effectiveness of internal control over financial reporting based on
the framework in Internal Control  Integrated Frameworkissued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on Houston Explorations evaluation under the framework in Internal Control  Integrated
Framework, our principal executive officer and principal financial officer concluded that internal
control over financial reporting was effective as of December 31, 2004. The conclusion of our
principal executive officer and principal financial officer is based on the recognition that there
are inherent limitations in all systems of internal control. Because of its inherent limitations,
internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance
with the polices or procedures may deteriorate. Managements assessment of the effectiveness of
internal control over financial reporting as of December 31, 2004 has been audited by Deloitte &
Touche LLP, an independent registered public accounting firm, as stated in their report which is
included herein. The Houston Exploration Company
Houston, Texas
February 22, 2005 /s/ William G. Hargett
    
    /s/ John H. KarnesWilliam G. Hargett
Chairman, President and Chief Executive Officer
    
    John H. Karnes
Senior Vice President and Chief Financial Officer
 F-2




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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of
The Houston Exploration Company
Houston, Texas We have audited managements assessment, included in the accompanying Managements Report on
Internal Control Over Financial Reporting, that The Houston Exploration Company (the Company)
maintained effective internal control over financial reporting as of December 31, 2004, based on
criteria established in Internal Control  Integrated Frameworkissued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). The Companys management is responsible for maintaining
effective internal control over financial reporting and for its assessment of the effectiveness of
internal control over financial reporting. Our responsibility is to express an opinion on
managements assessment and an opinion on the effectiveness of the Companys internal control over
financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating managements assessment, testing and evaluating the
design and operating effectiveness of internal control, and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis
for our opinions. A companys internal control over financial reporting is a process designed by, or under the
supervision of, the companys principal executive and principal financial officers, or persons
performing similar functions, and effected by the companys board of directors, management, and
other personnel to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A companys internal control over financial reporting includes
those policies and procedures that (1) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles,
and that receipts and expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and (3) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the financial statements. Because of the inherent limitations of internal control over financial reporting, including the
possibility of collusion or improper management override of controls, material misstatements due to
error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, managements assessment that the Company maintained effective internal control over
financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on
the criteria established in Internal ControlIntegrated Frameworkissued by the Committee of
Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained,
in all material respects, effective internal control over financial reporting as of December 31,
2004, based on the criteria established in Internal ControlIntegrated Frameworkissued by the
Committee of Sponsoring Organizations of the Treadway Commission. We have also audited, in
accordance with the Standards of the Public Company Accounting
Oversight Board (United States), the consolidated financial
statements as of and for the year ended December 31, 2004 of the
Company and our report dated February 22, 2005 which report
expresses an unqualified opinion and includes an explanatory
paragraph relating to the adoption of Statement of Financial
Accounting Standards (SFAS) No. 143, Accounting for
Asset Retirement Obligations, and SFAS No. 148,
Accounting for Stock-Based Compensation  Transition and
Disclosure, on January 1, 2003. DELOITTE & TOUCHE LLP Houston, Texas
February 22, 2005 F-3




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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of
The Houston Exploration Company
Houston, Texas We have audited the accompanying consolidated balance sheets of The Houston Exploration Company (a
Delaware corporation) and subsidiary (the Company) as of December 31, 2004 and 2003, and the
related consolidated statements of operations, stockholders equity and comprehensive income (loss)
and cash flows for each of three years in the period ended December 31, 2004. 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 the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects,
the financial position of the Company as of December 31, 2004 and 2003, and the results of its
operations and its cash flows for each of the three years in the period ended December 31, 2004, in
conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the effectiveness of the Companys internal control over financial reporting
as of December 31, 2004, based on the criteria established in Internal ControlIntegrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated
February 22, 2005 expressed an unqualified opinion on managements assessment of the effectiveness
of the Companys internal control over financial reporting and an unqualified opinion on the
effectiveness of the Companys internal control over financial reporting. As discussed in Note 1 to the consolidated financial statements, the Company adopted Statement of
Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, and
SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure, on January 1,
2003. DELOITTE & TOUCHE LLP Houston, Texas
February 22, 2005 F-4




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THE HOUSTON EXPLORATION COMPANY 
 CONSOLIDATED BALANCE SHEETS
 December 31,2004
    2003Assets:Cash and cash equivalents
    
    $
    18,577
    
    
    $
    2,569Accounts receivable
    
    
    103,069
    
    
    
    87,949Accounts receivable  Affiliate
    
    
    
    
    
    
    6,733Derivative financial instruments
    
    
    
    
    
    
    3,458Inventories
    
    
    976
    
    
    
    1,071Deferred tax asset
    
    
    24,101
    
    
    
    19,644Prepayments and other
    
    
    9,107
    
    
    
    5,818Total current assets
    
    
    155,830
    
    
    
    127,242Natural gas and oil properties, full cost methodUnevaluated properties
    
    
    122,691
    
    
    
    134,491Properties subject to amortization
    
    
    2,777,097
    
    
    
    2,324,011Other property and equipment
    
    
    11,740
    
    
    
    12,6172,911,528
    
    
    
    2,471,119Less: Accumulated depreciation, depletion and amortization
    
    
    1,363,272
    
    
    
    1,099,9901,548,256
    
    
    
    1,371,129Other non-current assets
    
    
    18,491
    
    
    
    10,694Total Assets
    
    $
    1,722,577
    
    
    $
    1,509,065Liabilities:Accounts payable and accrued expenses
    
    $
    118,971
    
    
    $
    83,983Derivative financial instruments
    
    
    68,081
    
    
    
    35,592Asset retirement obligation
    
    
    662
    
    
    
    7,703Total current liabilities
    
    
    187,714
    
    
    
    127,278Long-term debt and notes
    
    
    355,000
    
    
    
    302,000Derivative financial instruments
    
    
    7,068
    
    
    
    4,728Deferred federal income taxes
    
    
    288,069
    
    
    
    251,425Asset retirement obligation
    
    
    91,084
    
    
    
    84,654Other deferred liabilities
    
    
    10,722
    
    
    
    3,446Total Liabilities
    
    
    939,657
    
    
    
    773,531Commitments and Contingencies (see Note 9)Stockholders Equity:Preferred Stock, $0.01 par value, 5,000,000 shares authorized and no shares issued
    
    
    
    
    
    
    Common Stock, $.01 par value, 50,000,000 shares authorized and 28,380,207 and
31,437,581 shares issued and outstanding at December 31, 2004 and 2003,
respectively
    
    
    284
    
    
    
    315Additional paid-in capital
    
    
    273,002
    
    
    
    366,781Unearned compensation
    
    
    (2,537
    )
    
    
    (808
    )Retained earnings
    
    
    558,198
    
    
    
    395,374Accumulated other comprehensive income
    
    
    (46,027
    )
    
    
    (26,128
    )Total Stockholders Equity
    
    
    782,920
    
    
    
    735,534Total Liabilities and Stockholders Equity
    
    $
    1,722,577
    
    
    $
    1,509,065
 The accompanying notes are an integral part of these consolidated financial statements. F-5




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THE HOUSTON EXPLORATION COMPANY 
 CONSOLIDATED STATEMENTS OF OPERATIONS
 For the Years Ended December 31,2004
    
    
    2003
    
    

    2002Revenues:Natural gas and oil revenues
    
    $
    649,087
    
    
    $
    491,440
    
    
    $
    344,295Other
    
    
    1,352
    
    
    
    1,312
    
    
    
    1,086Total revenues
    
    
    650,439
    
    
    
    492,752
    
    
    
    345,381Operating expenses:Lease operating
    
    
    55,925
    
    
    
    47,072
    
    
    
    33,976Severance tax
    
    
    11,933
    
    
    
    15,958
    
    
    
    9,487Transportation expense
    
    
    11,819
    
    
    
    10,387
    
    
    
    9,317Asset retirement accretion expense
    
    
    4,902
    
    
    
    3,668
    
    
    
    Depreciation, depletion and amortization
    
    
    265,148
    
    
    
    197,530
    
    
    
    171,610General and administrative, net of amounts capitalized
    
    
    32,899
    
    
    
    19,542
    
    
    
    13,077Total operating expenses
    
    
    382,626
    
    
    
    294,157
    
    
    
    237,467Income from operations
    
    
    267,813
    
    
    
    198,595
    
    
    
    107,914Other (income) expense
    
    
    (1,058
    )
    
    
    (15,746
    )
    
    
    (9,070
    )Interest expense, net of amounts capitalized
    
    
    9,455
    
    
    
    8,342
    
    
    
    7,398Income before income taxes
    
    
    259,416
    
    
    
    205,999
    
    
    
    109,586Provision for taxes
    
    
    96,592
    
    
    
    72,187
    
    
    
    39,092Income before cumulative effect of change in accounting
principle
    
    $
    162,824
    
    
    $
    133,812
    
    
    $
    70,494Cumulative effect of change in accounting principle
    
    
    
    
    
    
    (2,772
    )
    
    
    Net income
    
    $
    162,824
    
    
    $
    131,040
    
    
    $
    70,494Earnings per share:Net income per share  basicIncome before cumulative effect of change in
accounting principle
    
    $
    5.50
    
    
    $
    4.30
    
    
    $
    2.31Cumulative effect of change in accounting principle
    
    
    
    
    
    
    (0.09
    )
    
    
    3⁄4Net income per share  basic
    
    $
    5.50
    
    
    $
    4.21
    
    
    $
    2.31Net income per share  dilutedIncome before cumulative effect of change in
accounting principle
    
    $
    5.44
    
    
    $
    4.29
    
    
    $
    2.28Cumulative effect of change in accounting principle
    
    
    
    
    
    
    (0.09
    )
    
    
    3⁄4Net income per share  diluted
    
    $
    5.44
    
    
    $
    4.20
    
    
    $
    2.28Weighted average shares outstanding  basic
    
    
    29,616
    
    
    
    31,097
    
    
    
    30,569Weighted average shares outstanding  diluted
    
    
    29,932
    
    
    
    31,213
    
    
    
    30,878
 The accompanying notes are an integral part of these consolidated financial statements. F-6




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THE HOUSTON EXPLORATION COMPANY 
 CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
AND COMPREHENSIVE INCOME (LOSS)
 AccumulatedAdditional
    
    
    
    
    
    
    
    
    
    
    Other
    
    
    TotalCommon Stock
    
    
    Paid-In
    
    
    Unearned
    
    
    Retained
    
    
    Comprehensive
    
    
    ShareholdersShares
    
    
    $ Value
    
    
    Capital
    
    
    Compensation
    
    
    Earnings
    
    
    Income (Loss)
    
    
    EquityBalance January 1, 2002
    
    
    30,463,230
    
    
    $
    305
    
    
    $
    336,977
    
    
    $
    (192
    )
    
    $
    193,840
    
    
    $
    34,951
    
    
    $
    565,881Common shares issued  stock options
    
    
    490,788
    
    
    
    5
    
    
    
    9,663
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9,668Contributed capital  KeySpan
property acquisition
    
    
    
    
    
    
    
    
    
    
    2,039
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,039Amortization restricted stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    85
    
    
    
    
    
    
    
    
    
    
    
    85Tax benefit exercise of
non-qualified stock options
    
    
    
    
    
    
    
    
    
    
    4,775
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4,775Comprehensive income:Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    70,494
    
    
    
    
    
    
    
    70,494Other comprehensive income:Derivative settlements
reclassified to income, net of
tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (10,633
    )
    
    
    (10,633
    )Unrealized loss change in fair
value of derivatives, net of
tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (49,520
    )
    
    
    (49,520
    )Total comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    10,341Balance December 31, 2002
    
    
    30,954,018
    
    
    $
    310
    
    
    $
    353,454
    
    
    $
    (107
    )
    
    
    264,334
    
    
    
    (25,202
    )
    
    $
    592,789Common shares issued  stock options
    
    
    461,563
    
    
    
    5
    
    
    
    10,218
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    10,223Common shares issued  restricted
stock
    
    
    22,000
    
    
    
    
    
    
    
    812
    
    
    
    (812
    )
    
    
    
    
    
    
    
    
    
    
    Common shares issued  public
offering
    
    
    3,000,000
    
    
    
    30
    
    
    
    79,170
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    79,200Common shares repurchased from
KeySpan
    
    
    (3,000,000
    )
    
    
    (30
    )
    
    
    (79,170
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (79,200
    )Amortization restricted stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    111
    
    
    
    
    
    
    
    
    
    
    
    111Stock compensation expense  stock
options
    
    
    
    
    
    
    
    
    
    
    903
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    903Tax benefit exercise of
non-qualified stock options
    
    
    
    
    
    
    
    
    
    
    1,394
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,394Comprehensive income:Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    131,040
    
    
    
    
    
    
    
    131,040Other comprehensive income:Derivative settlements
reclassified to income, net of
tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    43,165
    
    
    
    43,165Unrealized loss change in fair
value of derivatives, net of
tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (44,091
    )
    
    
    (44,091
    )Total comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    130,114Balance December 31, 2003
    
    
    31,437,581
    
    
    $
    315
    
    
    $
    366,781
    
    
    $
    (808
    )
    
    $
    395,374
    
    
    $
    (26,128
    )
    
    $
    735,534Common shares issued  stock options
    
    
    873,626
    
    
    
    9
    
    
    
    25,586
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    25,595Common shares issued  restricted
stock
    
    
    49,000
    
    
    
    
    
    
    
    2,855
    
    
    
    (2,855
    )
    
    
    
    
    
    
    
    
    
    
    Common shares issued  public
offering
    
    
    6,820,000
    
    
    
    68
    
    
    
    310,659
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    310,727Common shares repurchase from
KeySpan
    
    
    (10,800,000
    )
    
    
    (108
    )
    
    
    (441,471
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (441,579
    )Amortization restricted stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,126
    
    
    
    
    
    
    
    
    
    
    
    1,126Stock compensation expense  stock
options
    
    
    
    
    
    
    
    
    
    
    3,670
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3,670Tax benefit exercise of
non-qualified stock options
    
    
    
    
    
    
    
    
    
    
    4,922
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4,922Comprehensive income (loss):Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    162,824
    
    
    
    
    
    
    
    162,824Other comprehensive income (loss)Derivative settlements
reclassified to income, net of
tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    44,054
    
    
    
    44,054Unrealized loss change in fair
value of derivatives, net of
tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (63,953
    )
    
    
    (63,953
    )Total comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    142,925Balance December 31, 2004
    
    
    28,380,207
    
    
    $
    284
    
    
    $
    273,002
    
    
    $
    (2,537
    )
    
    $
    558,198
    
    
    $
    (46,027
    )
    
    $
    782,920
 The accompanying notes are an integral part of these consolidated financial statements. F-7




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
 Years Ended December 31,2004
    
    
    2003
    
    
    2002Operating Activities:Net income
    
    $
    162,824
    
    
    $
    131,040
    
    
    $
    70,494Adjustments to reconcile net income to net cash provided by
operating activities:Deferred income tax expense
    
    
    50,500
    
    
    
    58,274
    
    
    
    35,085Depreciation, depletion and amortization
    
    
    265,148
    
    
    
    197,530
    
    
    
    171,610Asset retirement accretion expense
    
    
    4,902
    
    
    
    3,668
    
    
    
    Stock compensation expense
    
    
    4,796
    
    
    
    1,014
    
    
    
    85Tax benefit non-qualified stock options
    
    
    4,922
    
    
    
    1,394
    
    
    
    4,775Unrealized loss due to ineffectiveness of derivative instruments
    
    
    1,950
    
    
    
    1,950
    
    
    
    Amortization of premiums paid on derivative contracts
    
    
    5,287
    
    
    
    
    
    
    
    Debt extinguishment expense
    
    
    211
    
    
    
    1,626
    
    
    
    Cumulative effect of change in accounting principle
    
    
    
    
    
    
    2,772
    
    
    
    Changes in operating assets and liabilities:(Increase) decrease in accounts receivable
    
    
    (8,387
    )
    
    
    (4,863
    )
    
    
    (45,337
    )(Increase) decrease in inventories
    
    
    95
    
    
    
    361
    
    
    
    (283
    )(Increase) decrease in prepayments and other
    
    
    (3,289
    )
    
    
    (3,622
    )
    
    
    763(Increase) decrease in other assets
    
    
    (6,218
    )
    
    
    (8,449
    )
    
    
    4,427Increase (decrease) in deferred liabilities
    
    
    7,276
    
    
    
    2,329
    
    
    
    741Increase (decrease) in accounts payable and accrued expenses
    
    
    34,988
    
    
    
    5,808
    
    
    
    1,509Decrease in ARO liability for assets abandoned
    
    
    (2,569
    )
    
    
    
    
    
    
    Net cash provided by operating activities
    
    
    522,436
    
    
    
    390,832
    
    
    
    243,869Investing Activities:Investment in property and equipment
    
    
    (518,500
    )
    
    
    (461,822
    )
    
    
    (257,436
    )Dispositions
    
    
    13,283
    
    
    
    
    
    
    
    5,311Net cash used in investing activities
    
    
    (505,217
    )
    
    
    (461,822
    )
    
    
    (252,125
    )Financing Activities:Proceeds from long-term borrowings
    
    
    420,000
    
    
    
    414,000
    
    
    
    79,000Repayments of long-term borrowings
    
    
    (367,000
    )
    
    
    (364,000
    )
    
    
    (71,000
    )Debt issuance costs
    
    
    (1,555
    )
    
    
    (4,695
    )
    
    
    Proceeds from issuance of common stock from exercise of stock
options
    
    
    25,596
    
    
    
    10,223
    
    
    
    9,668Proceeds from issuance of common stock
    
    
    310,727
    
    
    
    79,200
    
    
    
    Repurchase of common stock
    
    
    (388,979
    )
    
    
    (79,200
    )
    
    
    Net cash (used in) provided by financing activities
    
    
    (1,211
    )
    
    
    55,528
    
    
    
    17,668Decrease in cash and cash equivalents
    
    
    16,008
    
    
    
    (15,462
    )
    
    
    9,412Cash and cash equivalents, beginning of year
    
    
    2,569
    
    
    
    18,031
    
    
    
    8,619Cash and cash equivalents, end of year
    
    $
    18,577
    
    
    $
    2,569
    
    
    $
    18,031Supplemental Information:Non-cash transactions:Divesture and exchange of Appalachian Basin assets
    
    $
    60,000
    
    
    
    
    
    
    
    Deferred tax benefit exchange of Appalachian Basin assets
    
    
    7,400
    
    
    
    
    
    
    
    Cash paid (refunded) during period for:Interest
    
    $
    16,385
    
    
    $
    18,403
    
    
    $
    14,906Federal and state income taxes
    
    $
    41,854
    
    
    $
    14,800
    
    
    $
    (400
    )
 The accompanying notes are an integral part of these consolidated financial statements. F-8




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##### Table of Contents



THE HOUSTON EXPLORATION
COMPANY 
 NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
 NOTE 1  Summary of Organization and Significant Accounting Policies Our Business We are an independent natural gas and oil producer concentrating on growing reserves and production
through the exploration, development, exploitation and acquisition of natural gas and oil reserves
in North America. Our core areas of operations are South Texas, offshore in the shallow waters of
the Gulf of Mexico, the Arkoma Basin of Oklahoma and Arkansas and the Rocky Mountain region where,
during 2003, we began operations with an initial focus in the Uinta Basin of northeastern Utah and
during 2004, we expanded our focus to the DJ Basin in Eastern Colorado. In February 2004, we
divested our South Louisiana assets and in June 2004, we divested our Appalachian Basin assets in
connection with the KeySpan Exchange transaction described in Note 3  Stockholders Equity -
KeySpan Exchange and Offering. At December 31, 2004, our proved reserves were 793 billion cubic feet equivalent or Bcfe, with a
standardized measure of future net cash flows, discounted at 10% per annum, including
the effects of future income taxes of $1.4 billion. Our reserves are fully engineered on an
annual basis by independent petroleum engineers. Approximately 94% of our proved reserves at
December 31, 2004 were natural gas, approximately 63% of which were classified as proved developed.
At December 31, 2004, we operated approximately 77% of our producing wells. Daily production
averaged 339 million cubic feet of natural gas equivalent or MMcfe in 2004. We were founded in December 1985 as a Delaware corporation and began exploring for natural gas and
oil on behalf of KeySpan Corporation. KeySpan, a member of the Standard & Poors 500 Index, is a
diversified energy provider whose principal natural gas distribution and electric generation
operations are located in the Northeastern United States. In September 1996 we completed our
initial public offering and sold approximately 31% of our shares to the public. Through a series
of three separate transactions, the first in February 2003 and the last in November 2004, KeySpan
completely divested of its interest in the common stock of our company. As of December 31, 2004,
KeySpan no longer owned any common stock of our company. See Note 3  Stockholders Equity and
Note 6  Related Party Transactions for a description of these three transactions. Principles of Consolidation On June 2, 2004, all of the shares of our wholly-owned subsidiary, Seneca-Upshur Petroleum, Inc.,
were conveyed to KeySpan in connection with the KeySpan Exchange (as defined in Note 3 
Stockholders Equity). Subsequent to the transaction, Seneca-Upshur is no longer a subsidiary of
Houston Exploration but is a wholly-owned subsidiary of KeySpan, and as a result, our financial
statements reflect the consolidated results of Seneca-Upshur through May 31, 2004. Seneca-Upshur
was our only subsidiary, and prior to the KeySpan Exchange, our consolidated financial statements
included our accounts and the accounts of Seneca-Upshur. All significant inter-company balances
and transactions were eliminated. Seneca-Upshur is in the exploration and production business in West Virginia with interests in
Appalachian Basin assets. As of December 31, 2003, we had 50.5 Bcfe of estimated proved reserves
in the Appalachian Basin. Because we account for our natural gas and oil assets under the full
cost method of accounting, the disposition of our Appalachian Basin assets, which represented only
a portion of our full cost pool, is not considered discontinued operations under the Financial
Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) 144,
Accounting for the Impairment and Disposal of Long-lived Assets. Use of Estimates The preparation of the consolidated financial statements in conformity with accounting principals
generally accepted in the United States of America 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. Our most significant financial estimates are
based on remaining proved natural gas and oil reserves. Estimates of proved reserves are key
components of our depletion rate for natural gas and oil properties, our unevaluated properties and
our full cost ceiling test limitation. In addition, estimates are used in computing taxes,
preparing accruals of operating costs and production revenues, asset retirement obligations, fair
value and effectiveness of derivative instruments and fair value of stock options and the related
compensation expense. See Note 12  Supplemental Information on Natural Gas and Oil Exploration,
Development and Production Activities F-9




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) for more information relating to estimates of proved reserves. Because there are
numerous uncertainties inherent in the estimation process, actual results could differ materially
from these estimates. Business Segment Information The Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards
(SFAS) 131, Disclosures about Segments of an Enterprise and Related Information establishes
standards for reporting information about operating segments. Operating segments are defined as
components of an enterprise that engage in activities from which it may earn revenues and incur
expenses. Separate financial information is available and this information is regularly evaluated
by the chief decision maker for the purpose of allocating resources and assessing performance. Segment reporting is not applicable for us as each of our operating areas has similar economic
characteristics and each meets the criteria for aggregation as defined in SFAS 131. All of our
operations involve the exploration, development and production of natural gas and oil and all of
our operations are located in the United States. We have a single, company-wide management team
that administers all properties as a whole rather than as discrete operating segments. We track
only basic operational data by area. We do not maintain separate financial statement information
by area. We measure financial performance as a single enterprise and not on an area-by-area basis.
Throughout the year, we freely allocate capital resources on a project-by-project basis across our
entire asset base to maximize profitability without regard to individual areas or segments. Revenue Recognition and Gas Imbalances We use the entitlements method of accounting for the recognition of natural gas and oil revenues.
Under this method of accounting, income is recorded based on our net revenue interest in production
or nominated deliveries. We incur production gas volume imbalances in the ordinary course of
business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under
deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of
over-and-under deliveries or by cash settlement, as required by applicable contracts. Production
imbalances are marked-to-market at the end of each month at the lowest of (i) the price in effect
at the time of production; (ii) the current market price; or (iii) the contract price, if a
contract is in hand. At December 31, 2004, we had production imbalances representing assets of $3.3 million and
liabilities of $4.0 million. Our production imbalances represented a net asset of $1.8 million at
December 31, 2003, of which we had a right to offset the liability with the asset for a majority of
the balance. At December 31, 2004, the primary sources of our production imbalances related to
Gulf of Mexico properties acquired in October 2004 from Orca Energy, L.P. and in October 2003 from
Transworld Exploration and Production Inc. See Note 10  Acquisitions and Dispositions Orcaand
Transworld. Production imbalances are included in the line items other non-current assets and
other non-current liabilities on the balance sheet. F-10




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Net Income Per Share Basic earnings per share 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. Fully diluted earnings per share assumes the conversion of all potentially
dilutive securities and is calculated by dividing net income by the sum of the weighted average
number of shares of common stock outstanding plus all potentially dilutive securities. Years Ended December 31,2004
    
    
    2003
    
    
    2002(in thousands, except per share date)Numerator:Income before cumulative effect of change in accounting principle
    
    $
    162,824
    
    
    $
    133,812
    
    
    $
    70,494Cumulative effect of change in accounting principle
    
    
    
    
    
    
    (2,772
    )
    
    
    Net income
    
    $
    162,824
    
    
    $
    131,040
    
    
    $
    70,494Denominator:Weighted average shares outstanding
    
    
    29,616
    
    
    
    31,097
    
    
    
    30,569Add dilutive securities: Stock options
    
    
    316
    
    
    
    116
    
    
    
    309Total weighted average shares outstanding and dilutive securities
    
    
    29,932
    
    
    
    31,213
    
    
    
    30,878Earnings per share  basic:Income before cumulative effect of change in accounting principle
    
    $
    5.50
    
    
    $
    4.30
    
    
    $
    2.31Cumulative effect of change in accounting principle
    
    
    
    
    
    
    (0.09
    )
    
    
    Net income per share  basic
    
    $
    5.50
    
    
    $
    4.21
    
    
    $
    2.31Earnings per share  diluted:Income before cumulative effect of change in accounting principle
    
    $
    5.44
    
    
    $
    4.29
    
    
    $
    2.28Cumulative effect of change in accounting principle
    
    
    
    
    
    
    (0.09
    )
    
    
    Net income per share  diluted
    
    $
    5.44
    
    
    $
    4.20
    
    
    $
    2.28
 For the years ended December 31, 2004, 2003 and 2002, the calculation of shares outstanding for
diluted earnings per share does not include the effect of outstanding stock options to purchase
755,922, 1,865,313 and 1,880,029 shares respectively, because the exercise price of these shares
was greater than the average market price for the year, which would have an antidulitive effect on
earnings per share. Comprehensive Income Comprehensive income includes net income and certain items recorded directly to stockholders
equity and classified as other comprehensive income. The table below summarizes comprehensive
income and provides the components of the change in accumulated other comprehensive income for the
twelve-month periods ended December 31, 2004, 2003 and 2002, respectively. For the Year Ended December 31,2004
    
    
    2003
    
    
    2002(in thousands)Net income
    
    $
    162,824
    
    
    $
    131,040
    
    
    $
    70,494Other comprehensive income (loss)Derivative instruments settled and reclassified, net of tax
    
    
    44,054
    
    
    
    43,165
    
    
    
    (10,633
    )Change in unrealized loss fair value of open contracts, net of tax
    
    
    (63,953
    )
    
    
    (44,091
    )
    
    
    (49,520
    )Total other comprehensive (loss)
    
    
    (19,899
    )
    
    
    (926
    )
    
    
    (60,153
    )Comprehensive income
    
    $
    142,925
    
    
    $
    130,114
    
    
    $
    10,341
 F-11




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Natural Gas and Oil Properties Full Cost Accounting. We use the full cost method to account for our natural gas and oil
properties. Under full cost accounting, all costs incurred in the acquisition, exploration and
development of natural gas and oil reserves are capitalized into a full cost pool. Capitalized
costs include costs of all unproved properties, internal costs directly related to our natural gas
and oil activities and capitalized interest. We amortize these costs using a unit-of-production
method. We compute the provision for depreciation, depletion and amortization quarterly by
multiplying production for the quarter by a depletion rate. The depletion rate is determined by
dividing our total unamortized cost base by net equivalent proved reserves at the beginning of the
quarter. Our total unamortized cost base is the sum of our:  
    full cost pool (including assets associated with retirement obligations); plus,
    estimates for future development costs (excluding asset retirement obligations; less,
    unevaluated properties and their related costs; less,
    estimates for salvage. Costs associated with unevaluated properties are excluded from the amortization base until we have
made a determination as to the existence of proved reserves. We review our unevaluated properties
at the end of each quarter to determine whether the costs incurred should be reclassified to the
full cost pool and thereby subject to amortization. Sales of natural gas and oil properties are
accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the
adjustment would significantly alter the relationship between capitalized costs and proved
reserves. Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the
present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair
value of unproved properties less income tax effects (the ceiling limitation). We perform a
quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the
ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion and
amortization) less related deferred taxes are greater than the discounted future net revenues or
ceiling limitation, a writedown or impairment of the full cost pool is required. A writedown of the
carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts
stockholders equity in the period of occurrence and typically results in lower depreciation,
depletion and amortization expense in future periods. Once incurred, a writedown is not reversible
at a later date. The ceiling test is calculated using natural gas and oil prices in effect as of the balance sheet
date and adjusted for basis or location differential, held constant over the life of the
reserves. We use derivative financial instruments that qualify for cash flow hedge accounting under
SFAS 133 to hedge against the volatility of natural gas prices, and in accordance with SEC
guidelines, we include estimated future cash flows from our hedging program in our ceiling test
calculation. In addition, subsequent to the adoption of SFAS 143, Accounting for Asset Retirement
Obligations, the future cash outflows associated with settling asset retirement obligations are
not included in the computation of the discounted present value of future net revenues for the
purposes of the ceiling test calculation. In calculating our ceiling test at December 31, 2004, 2003 and 2002, we estimated, using a wellhead
price of $5.75 per Mcfe, $5.74 per Mcfe and $4.38 per Mcfe, respectively, that we had a full cost
ceiling cushion at each of the respective balance sheet dates, whereby the carrying value of our
full cost pool was less that the ceiling limitation by $399.3 million (after tax) for 2004, $440.7
million (after tax) for 2003 and by $279.4 million (after tax) for 2002. No writedown was
required. Unevaluated Properties. The costs associated with unevaluated properties and properties under
development are not initially included in the amortization base and relate to unproved leasehold
acreage, seismic data, wells and production facilities in progress and wells pending determination
together with interest costs capitalized for these projects. Unevaluated leasehold costs are
transferred to the amortization base with the costs of drilling the related well once determination
has been made or upon expiration of a lease. Costs of seismic data are allocated to various
unproved leaseholds and transferred to the amortization base with the associated leasehold costs on
a specific project basis. Costs associated with wells in progress and wells pending determination
are transferred to the amortization base once a determination is made whether or not proved
reserves can be assigned to the property. Costs of dry holes are transferred to the amortization
base immediately upon determination that the well is unsuccessful. All items included in our
unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction
in value. Of the $122.7 million of unevaluated property costs at December 31, 2004 that have been
excluded from the amortization base, $41.1 million were incurred during 2004, $48.2 million were
incurred in 2003, $16.5 million were incurred in 2002 and $16.9 million were incurred prior to
2001. Of the $134.5 million of unevaluated property costs at December 31, 2003 that have been
excluded F-12




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS from the amortization base, $78.9 million were incurred during 2003, $18.0 million were incurred in
2002, $21.4 million were incurred during 2001 and $16.2 were incurred prior to 2001. We estimate
these costs will be evaluated within a four-year period. Asset Retirement Obligations On January 1, 2003, we adopted SFAS 143, Accounting for Asset Retirement Obligations, which
addresses accounting and reporting for obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. For us, asset retirement obligations
(ARO) represent the systematic, monthly accretion and depreciation of future abandonment costs of
tangible assets such as platforms, wells, service assets, pipelines, and other facilities. SFAS
143 requires that the fair value of a liability for an assets retirement obligation be recorded in
the period in which it is incurred if a reasonable estimate of fair value can be made, and that the
corresponding cost is capitalized as part of the carrying amount of the related long-lived asset.
The liability is accreted to its then present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. If the liability is settled for an amount
other than the recorded amount, an adjustment is made to the full cost pool, with no gain or loss
recognized, unless the adjustment would significantly alter the relationship between capitalized
costs and proved reserves. Under our previous accounting method, we included estimated future
costs of abandonment and dismantlement in our full cost amortization base and amortized these costs
as a component of our depletion expense. Subsequent to our adoption of SFAS 143, the ARO assets,
which are carried on the balance sheet as part of the full cost pool, have been included in our
amortization base for the purposes of calculating depreciation, depletion and amortization expense.
For the purposes of calculating the ceiling test, the future cash outflows associated with
settling the ARO liability have been excluded from the computation of the discounted present value
of estimated future net revenues. Pursuant to the January 1, 2003 adoption of SFAS 143 we:  
    recognized a charge to income during the first quarter of 2003 of $2.8 million,
net of tax, for the cumulative effect of the change in accounting principle;
    increased our total liabilities by $57.2 million to record the asset retirement
obligations (ARO);
    increased our assets by $42.5 million to add the asset retirement costs to the
carrying amount of our natural gas and oil properties; and
    reduced our accumulated depreciation, depletion and amortization by $10.4
million for the amount of expense previously recognized. Adopting SFAS 143 had no impact on our reported cash flows. The following table describes
changes in our asset retirement liability during each of the years ended December 31, 2004 and
2003. The ARO liability in the table below includes amounts classified as both current and
long-term at December 31st. Years Ended December 31,2004
    
    
    2003(in thousands)ARO liability at January 1,
    
    $
    92,357
    
    
    $
    57,197Accretion expense
    
    
    4,902
    
    
    
    3,668Liabilities incurred from drilling
    
    
    4,487
    
    
    
    5,738Liabilities
incurred - assets acquired
    
    
    19,638
    
    
    
    29,243Liabilities
settled - assets sold
    
    
    (12,714
    )
    
    
    Liabilities
settled - assets abandoned
    
    
    (4,915
    )
    
    
    (160
    )Changes in estimates
    
    
    (12,009
    )
    
    
    (3,329
    )ARO liability at December 31,
    
    $
    91,746
    
    
    $
    92,357
 F-13




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following table describes the pro forma effect on net income and earnings per share for the
year ended December 31, 2002, if SFAS 143 had been adopted on January 1, 2001. Years Ended December 31,2004
    
    
    2003
    
    
    2002(in thousands, except per share amounts)Net income
    
    $
    162,824
    
    
    $
    131,040
    
    
    $
    68,774Earnings per share:Basic
    
    $
    5.50
    
    
    $
    4.21
    
    
    $
    2.25Diluted
    
    
    5.44
    
    
    
    4.20
    
    
    
    2.23
 Other Property and Equipment Other property and equipment includes the costs of various gathering facilities that 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 computer equipment and other office equipment which are recorded at cost and
depreciated using the straight-line method over estimated useful lives ranging between two to five
years. Cash and Cash Equivalents We consider all highly liquid short-term investments with original maturities of three months or
less to be cash and cash equivalents. Income Taxes We determine deferred taxes 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 as of the balance sheet dates. These differences relate primarily to  
    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,
    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 our operations and are stated at the lower
of the specific cost of each inventory item or market value. General and Administrative Costs and Expenses Under the full cost method of accounting, a portion of our general and administrative expenses that
are directly identified with our acquisition, exploration and development activities are
capitalized as part of our full cost pool. These capitalized costs include salaries, employee
benefits, costs of consulting services and other specifically identifiable costs and do not include
costs related to production operations, general corporate overhead or similar activities. We
capitalized general and administrative costs directly related to our acquisition, exploration and
development activities, during 2004, 2003 and 2002, of $14.8 million, $12.9 million and $13.2
million, respectively. We receive reimbursement for administrative and overhead expenses incurred on behalf of other
working interest owners on properties we operate. These reimbursements totaling $2.2 million, $1.6
million and $1.8 million for the years ended December 31, 2004, 2003 and 2002, respectively, were
allocated as reductions to general and administrative expenses incurred. Generally, we do not
receive any excess of reimbursements or fees over the costs incurred; however, if we did, we would
credit the excess to the full cost pool to be recognized through lower cost amortization as
production occurs. F-14




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Capitalization of Interest We capitalize interest related to our unevaluated natural gas and oil properties. For the years
ended December 31, 2004, 2003 and 2002, we capitalized interest costs of $8.4 million, $7.3 million
and $8.0 million, respectively. Financial Instruments The estimated fair value of financial instruments is the amount at which the instrument could be
exchanged currently between willing parties. On the balance sheet, we report cash and cash
equivalents, accounts receivable and accounts payable at cost or carrying value, which approximates
fair value due to the short maturity of these instruments. See Note 2  Long-term Debt and Notes
for fair value of our debt. Our derivative financial instruments are reported on the balance sheet
at fair market value. See Note 7  Derivative Financial Instruments. Concentration of Credit Risk Substantially all of our accounts receivable result from natural gas and oil sales or joint
interest billings to third parties in the oil and gas industry. This concentration of customers and
joint interest owners may impact our overall credit risk in that these entities may be similarly
affected by changes in economic and other conditions. Historically, we have not experienced credit
losses on these receivables. Based on the current demand for natural gas and oil, we do not expect
that termination of sales to any of our current purchasers would have a material adverse effect on
our ability to find replacement purchasers and to sell our production at favorable market prices. Further, our derivative instruments also expose us to credit risk in the event of nonperformance by
counterparties. Generally, these contracts are with major investment grade financial institutions
and other substantive counterparties. We believe that our credit risk related to the natural gas
futures and swap contracts is no greater than the risk associated with the primary contracts and
that the elimination of price risk reduces volatility in our reported results of operations,
financial position and cash flows from period to period and lowers our overall business risk; but,
as a result of our hedging activities we may be exposed to greater credit risk in the future. Derivative Instruments and Hedging Activities Our hedging policy does not permit us to hold derivative instruments for trading purposes. In our
hedging program, we utilize a variety of derivative instruments, including swaps, collars and
options. We generally place contracts with major financial institutions and other credit-worthy
counterparties. Although our hedging program protects a portion of our cash flows from downward
price movements, certain hedging strategies, specifically the use of swaps and collars, may also
limit our ability to realize the full benefit of future price increases. In addition, because our
derivative instruments are typically indexed to New York Mercantile Exchange (NYMEX) prices as
opposed to the index price where the gas is actually sold, our hedging strategy may not protect our
cash flows if the price differential increases between the NYMEX price and index price for the
point of sale. Our derivative instruments are designated cash flow hedges and qualify for hedge accounting under
SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended, and,
accordingly, we carry the fair market value of our derivative instruments on the balance sheet as
either an asset or liability and defer unrealized gains or losses in accumulated other
comprehensive income. Gains and losses are reclassified from accumulated other comprehensive income
to the income statement as a component of natural gas and oil revenues in the period the hedged
production occurs. If any ineffectiveness occurs, amounts are recorded directly to the income
statement. For each the years ended December 31, 2004 and 2003, our net income includes an
unrealized loss of $1.9 million ($1.3 million net of tax), which represents the ineffective portion
of our derivative instruments that was not eligible for deferral. The ineffectiveness was a result
of changes at the end of the current period in the price differentials between the index price of
the derivative contract, which uses a NYMEX index, and index price for the point of sale for the
cash flow that is being hedged, the majority of which is the Houston Ship Channel index. Based on market prices at December 31, 2004, we recorded an unrealized loss in accumulated other
comprehensive income of $46.0 million, net of tax, representing the fair value of our open
contracts. Any loss will be realized in future earnings at the time of the related sales of
natural gas production applicable to specific hedges. If prices in effect at December 31, 2004
were to remain unchanged, over the next 12-month period, we would expect to reclassify from
accumulated other comprehensive income to earnings a loss of $41.7 million, net of tax, relating to
our open derivative contracts. However, F-15




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS these amounts could vary materially as a result of changes in market conditions. See Note 7 
Derivative Instruments, for a detailed listing of our derivative contracts and the fair market
value of those contracts as of December 31, 2004 and 2003. Accounting for Stock Options On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123,
Accounting for Stock Based Compensation, as amended by SFAS 148, Accounting for StockBased
Compensation  Transition and Disclosure using the prospective method as defined by the SFAS
148. As a result, we now record as compensation expense the fair value of all stock options issued
subsequent to January 1, 2003. No expense for stock options has been recorded for grants made in
years prior to January 1, 2003. Prior to 2003, we accounted for stock-based compensation using the
intrinsic value method prescribed in Accounting Principles Board (APB) Opinion 25, Accounting
for Stock Issued to Employees, and related interpretations. Accordingly, compensation cost for
stock options was measured as the excess, if any, of the fair value of common stock at the date of
the grant over the amount the employee must pay to acquire the common stock. If the exercise price
of a stock option was equal to the fair market value at the time of grant, no compensation expense
was incurred. If we had accounted for all stock options using the fair value method as
recommended in SFAS 123, compensation expense would have had the following pro forma effect on our
net income and earnings per share for the years ended December 31, 2004, 2003 and 2002. Years Ended December 31,2004
    
    
    2003
    
    
    2002(in thousands, except per share data)Net income  as reported
    
    $
    162,824
    
    
    $
    131,040
    
    
    $
    70,494Add: Stock-based compensation expense included in
net income, net of tax
    
    
    2,581
    
    
    
    551
    
    
    
    55Less: Stock-based compensation expense determined
using fair value method, net of tax
    
    
    4,694
    
    
    
    4,427
    
    
    
    3,631Net income   pro forma
    
    $
    160,711
    
    
    $
    127,164
    
    
    $
    66,918Net income per share  basic  as reported
    
    $
    5.50
    
    
    $
    4.21
    
    
    $
    2.31Net income per share  diluted  as reported
    
    
    5.44
    
    
    
    4.20
    
    
    
    2.28Net income per share  basic  pro forma
    
    $
    5.43
    
    
    $
    4.09
    
    
    $
    2.19Net income
per share  diluted  pro forma
    
    
    5.37
    
    
    
    4.07
    
    
    
    2.17
 The effects of applying SFAS 123 in this pro forma disclosure may not be representative of future
amounts. See Note 4  Employee Benefit and Stock and Options Plans, for a summary of stock
compensation expenses incurred during the years ended December 31, 2004, 2003 and 2002. The
weighted average fair value of options at their grant date during 2004, 2003 and 2002 were 17.12.
$13.82 and $14.08, respectively. 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 2004, 2003 and 2002: Years Ended December 31,2004
    
    
    2003
    
    
    2002Risk-free interest rate.
    
    
    3.88
    %
    
    
    4.02
    %
    
    
    4.59
    %Expected years until exercise
    
    
    5
    
    
    
    5
    
    
    
    5Expected stock volatility
    
    
    40
    %
    
    
    43
    %
    
    
    46
    %Expected dividends
    
    
    
    
    
    
    
    
    
    
    
 New Accounting Pronouncements On September 28, 2004, the SEC released Staff Accounting Bulletin (SAB) 106 regarding the
application of SFAS 143, Accounting for Asset Retirement Obligations (AROs), by oil and gas
producing companies following the full cost accounting method. Pursuant to SAB 106, oil and gas
producing companies that have adopted SFAS 143 should exclude the future cash outflows associated
with settling AROs (ARO liabilities) from the computation of the present value of estimated future
net revenues for the purposes of the full cost ceiling calculation. In addition, estimated
dismantlement and abandonment costs, net of estimated salvage values, that have been capitalized
(ARO assets) should be included in the amortization base for computing depreciation, depletion and
amortization expense. Disclosures are required to include discussion of how a companys ceiling
test and depreciation, depletion and amortization calculations are impacted by the adoption of SFAS
143. SAB 106 is effective prospectively as of the beginning of the first fiscal quarter beginning
after F-16




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS October 4, 2004. Since our adoption of SFAS 143 on January 1, 2003, we have calculated the ceiling
test and our depreciation, depletion and amortization expense in accordance with the
interpretations set forth in SAB 106; therefore, the adoption of SAB 106 had no effect on our
financial statements. On December 16, 2004, the FASB revised Statement 123 (revised 2004), Share-Based Payment that
will require compensation costs related to share-based payment transactions (e.g., issuance of
stock options and restricted stock) to be recognized in the financial statements. With limited
exceptions, the amount of compensation cost will be measured based on the grant-date fair value of
the equity or liability instruments issued. In addition, liability awards will be measured each
reporting period. Compensation cost will be recognized over the period that an employee provides
service in exchange for the award. Statement 123(R) replaces SFAS 123, Accounting for Stock-Based
Compensation, and supersedes Accounting Principles Board (APB) Opinion No. 25, Accounting for
Stock Issued to Employees. For us, SFAS 123(R) is effective for the first quarterly reporting
period after June 15, 2005. Entities that use the fair-value-based method for either recognition
or disclosure under SFAS 123 are required to apply SFAS 123(R) using a modified version of
prospective application. Under this method, an entity records compensation expense for all awards
it grants after the date of adoption. In addition, the entity is required to record compensation
expense for the unvested portion of previously granted awards that remain outstanding at the date
of adoption. In addition, entities may elect to adopt SFAS 123(R) using a modified retrospective
method where by previously issued financial statements are restated based on the expense previously
calculated and reported in their pro forma footnote disclosures. On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123 as amended
by SFAS 148, Accounting for Stock-Based Compensation  Transition and Disclosure using the prospective method as defined
by the SFAS 148. As a result, we have recognized compensation expense for all stock options
granted subsequent to January 1, 2003 with no expense recognized for grants made prior to 2003.
Adoption of SFAS 123(R) will require us to recognize compensation expense over the remaining
service period for the unvested portion of all options granted during 2000, 2001 and 2002. All
options granted prior to 2000 are fully vested. We expect to adopt SFAS 123(R) on January 1, 2005
using the modified version of the prospective application and are currently evaluating the effect of adopting SFAS
123(R). On December 16, 2004, the FASB issued Statement 153, Exchanges of Nonmonetary Assets, an
amendment of APB Opinion No. 29, to clarify the accounting for nonmonetrary exchanges of similar
productive assets. SFAS 153 eliminates the exception from the fair value measurement for
nonmonetary exchanges of similar productive assets and replaces it with a general exception for
exchanges of nonmonetary assets that do not have commercial substance. The Statement will be
applied prospectively and is effective for nonmonetary asset exchanges occurring in fiscal periods
beginning after June 15, 2005. We do not have any nonmonetary transactions for any period
presented that this Statement would apply. We do not expect the adoption of SFAS 153 to have a
material impact on our financials statements. NOTE 2  Long-Term Debt and Notes Years Ended December 31,2004
    
    
    2003(in thousands)Senior Debt:Revolving bank credit facility, due April 1, 2008
    
    $
    180,000
    
    
    $
    127,000Subordinated Debt:7% senior subordinated notes, due June 15, 2013
    
    
    175,000
    
    
    
    175,000Total long-term debt and notes
    
    $
    355,000
    
    
    $
    302,000
 The carrying amount of borrowings outstanding under the revolving bank credit facility approximates
fair value as the interest rates are tied to current market rates. At December 31, 2004, the
quoted market value of our $175 million of 7% senior subordinated notes was 101% of the $175
million carrying value or $177 million. At December 31, 2003, the quoted market value of our $175
million of 7% senior subordinated notes was 103% of the $175 million carrying value or $180.3
million. At December 31, 2004, principle payments due over the next five-year period and
thereafter are as follows. F-17




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS After2005
    
    
    2006
    
    
    2007
    
    
    2008
    
    
    2009
    
    
    2010(in thousands)Revolving bank credit facility
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    180,000
    
    
    $
    
    
    
    $
    7% senior Subordinated Notes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    175,000Total maturities
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    180,000
    
    
    $
    
    
    
    $
    175,000
 Revolving Bank Credit Facility We maintain a revolving bank credit facility with a syndicate of lenders led by Wachovia Bank,
National Association, as issuing bank and administrative agent, The Bank of Nova Scotia and Fleet
National Bank as co-syndication agents and BNP Paribas and Comerica Bank as co-documentation
agents. The credit facility was amended and restated on April 1, 2004, primarily to increase the
size of the facility, and was amended again on June 2, 2004, in conjunction with the KeySpan
Exchange (as defined in Note 3). As amended, the facility provides us with a commitment of $400
million, which may be increased at our request and with prior approval from Wachovia to a maximum
of $450 million. Amounts available for borrowing under the credit facility are limited to a
borrowing base. On April 1, 2004, our borrowing base was increased from $300 million to $375
million, and on June 2, 2004, was reduced to $340 million as a result of the disposition of our
Appalachian Basin assets in the KeySpan Exchange. Pursuant to the reduction in our borrowing base,
we incurred $0.2 million debt extinguishment expenses during the second quarter of 2004 relating to
the write-off of a portion of our debt issuance costs. The $0.2 million is included in the line
item Other (income) expense on our Statement of Operations. Effective October 15, 2004, our
borrowing base was increased to $400 million, which is expected to remain in effect until the next
scheduled redetermination on April 1, 2005. Up to $40 million of the borrowing base is available
for the issuance of letters of credit. Outstanding borrowings are unsecured and rank senior in
right of payment to our $175 million 7% subordinated notes. The amended facility matures on April
1, 2008. At December 31, 2004, we had $180 million in outstanding borrowings under the credit
facility and $0.4 million in outstanding letter of credit obligations. Interest rates, margins and terms of payment remained unchanged from prior periods pursuant to the
April 1, 2004, amendment. Interest is payable on borrowings under our revolving bank credit
facility, as follows:  
    on base rate loans, at a fluctuating rate, or base rate, equal to the sum of (a)
the greater of the Federal funds rate plus 0.5% or Wachovias prime rate plus (b) a variable
margin between 0.00% and 0.50%, depending on the amount of borrowings outstanding under the
credit facility, or
    on fixed rate loans, a fixed rate equal to the sum of (a) a quoted LIBOR rate
divided by one minus the average maximum rate during the interest period set for certain
reserves of member banks of the Federal Reserve System in Dallas, Texas, plus (b) a variable
margin between 1.25% and 2.00%, depending on the amount of borrowings outstanding under the
credit facility. Interest is payable on base-rate loans on the last day of each calendar quarter. Interest on
fixed-rate loans is generally payable at maturity or at least every 90 days if the term of the loan
exceeds three months. In addition to interest, we must pay a quarterly commitment fee of between
0.30% and 0.50% per annum on the unused portion of the borrowing base. Our revolving bank credit facility contains customary negative covenants that place restrictions
and limits on, among other things, the incurrence of debt, guarantees, liens, leases and certain
investments. The credit facility also restricts and limits our ability to pay cash dividends, to
purchase or redeem our stock and to sell or encumber our assets. Financial covenants require us
to, among other things:  
    maintain a ratio of earnings before interest, taxes, depreciation, depletion and
amortization (EBITDA) to cash interest payments of at least 3.00 to 1.00;
    maintain a ratio of total debt to EBITDA of not more than 3.50 to 1.00; and
    not hedge more than 85% of our production during any calendar year. At December 31, 2004, and December 31, 2003, we were in compliance with all covenants. F-18




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Senior Subordinated Notes On June 10, 2003, we issued $175 million of 7% senior subordinated notes due June 15, 2013. The
notes bear interest at a rate of 7% per annum with interest payable semi-annually on June 15 and
December 15, beginning December 15, 2003. We may redeem the notes at our option, in whole or in
part, at any time on or after June 15, 2008, at a price equal to 100% of the principal amount plus
accrued and unpaid interest, if any, plus a specified premium that decreases yearly from 3.5% in
2008 to 0% in 2011 and thereafter. In addition, at any time prior to June 15, 2006, we may redeem
up to a maximum of 35% of the aggregate principal amount with the net proceeds of one or more
equity offerings at a price equal to 107% of the principal amount, plus accrued and unpaid interest
and liquidated damages, if any. The notes are general unsecured obligations and rank subordinate
in right of payment to all existing and future senior debt, including the revolving bank credit
facility, and will rank senior or equal in right of payment to all existing and future subordinated
indebtedness. The indenture governing the notes contains covenants that, among other things, restrict or limit:  
    incurrence of additional indebtedness and issuance of preferred stock;
    repayment of certain other indebtedness;
    payment of dividends or certain other distributions;
    investments and repurchases of equity;
    use of the proceeds of assets sales;
    transactions with affiliates;
    creation, incurrence or assumption of liens;
    merger or consolidation and sales or other dispositions of all or substantially all of our assets;
    entering into agreements that restrict the ability of our subsidiary to make certain distributions or payments; or
    guarantees by our subsidiary of certain indebtedness. In addition, upon the occurrence of a change of control, we will be required to offer to purchase
the notes at a purchase price equal to 101% of the aggregate principal amount, plus accrued and
unpaid interest and liquidated damages, if any. A change of control is:  
    the direct or indirect acquisition by any person, other than KeySpan or its
affiliates, of beneficial ownership of 35% or more of total voting power as long as KeySpan
and its affiliates own less than the acquiring person;
    the sale, lease, transfer, conveyance or other disposition, other than by way of
merger or consolidation, in one or a series of related transactions, of all or substantially
all of our assets to a third party other than KeySpan or its affiliates;
    the adoption of a plan relating to our liquidation or dissolution; or
    if, during any period of two consecutive years, individuals who at the beginning
of the period constituted our board of directors, including any new directors who were
approved by a majority vote of directors then in office who were either directors at the
beginning of the two-year period or who were previously so approved, cease for any reason to
constitute a majority of the members then in office. NOTE 3  Stockholders Equity KeySpan Secondary Offering On November 24, 2004, KeySpan completed a secondary public offering of its remaining 6,580,392
shares of our common stock at $56.25 per share. All shares were offered by KeySpan under our shelf
registration statement filed with the Securities and Exchange Commission on March 16, 2004. We did
not receive any proceeds from the sale of these shares in the offering. Subsequent to the
offering, KeySpan no longer held any common stock of our company. F-19




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS KeySpan Exchange and Offering On June 2, 2004, we completed an asset exchange transaction with KeySpan pursuant to which we
redeemed and cancelled 10,800,000 shares of our common stock owned by KeySpan in exchange for all
the stock of Seneca-Upshur Petroleum, Inc., our wholly-owned subsidiary, to which we contributed
all of our Appalachian Basin assets valued at $60 million and $389 million in cash, for a total
exchange value of $449 million. This transaction is referred to as the KeySpan Exchange. The
KeySpan Exchange is intended to qualify as a tax-free exchange under Section 355(a) of the Internal
Revenue Code. To fund the cash portion of the exchange, on June 2, 2004, we sold 6,200,000 shares of our common
stock in a registered public offering at $48.00 per share, (the Offering), and contributed to
Seneca-Upshur substantially all of the net proceeds from the Offering (approximately $282 million),
together with an additional $107 million of proceeds from bank borrowings. We then conveyed to
KeySpan all of the shares of Seneca-Upshur in exchange for 10,800,000 shares of our common stock
owned by KeySpan. On June 23, 2004, the underwriters of our Offering exercised a portion of their over-allotment
option and we sold an additional 620,000 shares of common stock at $48.00 per share for net
proceeds of $28.6 million. The proceeds from the over-allotment were used to reduce bank
borrowings. Our redemption and cancellation of the 10,800,000 shares received from KeySpan and our issuance of
6,820,000 new shares resulted in a net 3,980,000 decrease in the outstanding shares of our common
stock, and thereby reduced KeySpans ownership from approximately 54% to 24%. As a result of the
KeySpan Exchange and Offering, our bank borrowings increased by a net $79 million and we incurred
approximately $5.1 million in compensation and other expenses related to special bonuses awarded to
executives and key employees who assisted in structuring and consummating the transactions. As a
result of the reduction in ownership, KeySpan agreed to reduce its representation on our Board of
Directors from five to two directors. Our Chief Executive Officer, William G. Hargett, was elected
Chairman of the Board replacing Robert B. Catell, Chairman and Chief Executive Officer of KeySpan,
who remains on the Board. Stockholder Rights Plan On August 12, 2004, we adopted a stockholder rights plan designed to assure that our stockholders
receive fair and equal treatment in the event of an unsolicited attempt to takeover our company and
to protect against abusive or coercive takeover tactics that are not in the best interest of our
company or its stockholders. To implement the rights plan, the Board of Directors declared a
dividend of one preferred share purchase right for each outstanding share of our common stock to
stockholders of record as of the close of business on August 23, 2004, and directed the issuance of
one preferred share purchase right with respect to each share of our common stock that shall become
outstanding thereafter until the rights become exercisable or they expire as described below. Each
right initially represents a contingent right to purchase, under certain circumstances, one
one-thousandth of a share of our Series A Junior Participating Preferred Stock, par value $.01 per
share, at an initial exercise price of $275.00 per one one-thousandth of a share, subject to
adjustment under certain circumstances. The rights will become exercisable and trade independently
from our common stock upon the public announcement of the acquisition by a person or group of 10%
or more of our common stock, or ten days after commencement of a tender or exchange offer that
would result in the acquisition of 10% or more of our common stock. Each share purchased upon exercise of the rights will be entitled to a minimum quarterly
preferential dividend payment of the greater of (i) $10.00 per share and (ii) an amount equal to
1,000 times the dividend declared per share of common stock. Each share will be entitled to 1,000
votes, voting together with the common stock. In the event of our liquidation, each share of the
Series A Junior Participating Preferred Stock will be entitled to a minimum preferential payment of
the greater of (a) $10.00 per share (plus any accrued but unpaid dividends) and (b) an amount equal
to 1,000 times the payment made per share of common stock. If we are acquired in a merger or other business combination transaction after a person or group
has acquired 10% or more of our common stock, each right will entitle its holder to purchase, at
the rights exercise price, that number of the acquiring companys shares of common stock having a
market value of twice the rights exercise price. In addition, if a person or group acquires 10%
or more of our common stock, each right will entitle its holder (other than the acquiring person or
group) to purchase, at the rights exercise price, a number of fractional shares of the Series A
Junior Participating Preferred Stock or shares of our common stock having a market value of twice
the rights exercise price. F-20




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The rights expire on August 12, 2014, unless redeemed earlier by our Board of Directors. The Board
of Directors can redeem the rights at a price of $.01 per right at any time before the rights
become exercisable, and thereafter only in limited circumstances. Issuance of 3,000,000 Shares to the Public and Concurrent Repurchase of 3,000,000 Shares from
KeySpan In connection with our initial public offering in September 1996, we entered into a registration
rights agreement with KeySpan pursuant to which we were obligated, at KeySpans election, to
facilitate KeySpans sale of its shares of our stock by registering the shares under the Securities
Act of 1933 and assisting in KeySpans selling efforts. During February of 2003, KeySpan notified
us of its desire to sell 3,000,000 shares of their Houston Exploration stock. To accomplish the
transaction, we sold 3,000,000 newly issued shares of our stock in a public offering under our
shelf registration statement for net proceeds of $26.40 per share, or an aggregate $79.2 million,
and simultaneously bought a like number of KeySpans shares of our stock for the same price per
share. We cancelled the 3,000,000 shares acquired from KeySpan immediately following the
repurchase. KeySpan reimbursed us for all costs and expenses, and the transaction had no impact on
our capitalization. The transaction was evidenced in a stock purchase agreement, dated February
26, 2003. As a result of the transactions, KeySpans interest in our outstanding shares decreased
from 66% to 55%. NOTE 4 Employee Benefit and Stock and Option Plans 401(k) Plan We maintain a tax-qualified defined contribution plan under Section 401(k) of the Internal Revenue
Code for our employees. All employees are eligible to participate in the plan upon reaching 21
years of age and completing one month of service. Participants may elect to have us contribute on
their behalf up to 12.5% of their total compensation (subject to limitations imposed under the
current Internal Revenue Code) on a before tax basis. We make 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 Code. The amounts contributed under the 401(k) plan are held in a trust and invested at
the direction of each participant among various investment funds. An employees salary deferral
contributions to the 401(k) plan are 100% vested. Our matching contributions vest at the rate of
20% per year of service. Participants are entitled to distribution of their vested account balances
upon termination of employment. We made contributions to the 401(k) plan of $1.2 million, $1.3
million and $1.2 million, respectively, for the years ended December 31, 2004, 2003 and 2002. Deferred Compensation Plan We maintain a deferred compensation plan for the benefit of our employees. The plan is a
non-qualified plan and is intended to supplement our 401(k) plan by allowing highly compensated
employees to save on a tax deferred basis a portion of their eligible compensation subject to
limitations imposed by the plan. Under the terms of the plan, employees who have made the maximum
allowable contribution to their 401(k) accounts for any year ($13,000, $12,000 and $11,000 per
year, respectively, for 2004, 2003 and 2002, with an additional one-time contribution of $3,000 in
2004, $2,000 in 2003 and $1,000 in 2002 for employees 50 years of age or older) may elect to defer
an additional portion of their compensation into the deferred compensation plan. We match 100% of
each employees deferral up to an aggregate contribution of 12.5% under both the 401(k) plan and
the deferred compensation plan. During 2004, 2003 and 2002, we made matching contributions
totaling $0.7 million, $0.7 million and $0.5 million, respectively, to the deferred compensation
plan. Employer contributions vest 20% per year and become fully vested after a five-year period.
Notional accounts are maintained for each eligible employee to record salary deferrals, matching
contributions and earnings and losses. We make contributions to a grantor trust to fund plan
benefits, but the assets of the trust are subject to the claims of our general creditors. Assets
of the grantor trust are invested, at the direction of the employee, in various investment funds.
Income on trust assets is treated as our income. Participants are entitled to a benefit
attributable to their deferrals and the vested portion of our matching contributions at
predetermined future dates or upon termination of their employment. At December 31, 2004 and 2003,
the fair market value of the assets held in the trust of $6.7 million and $3.4 million,
respectively, are carried on our balance sheet as a non-current asset together with a corresponding
non-current liability for the same amount and are located in the line items Other Non-Current
Assets and Other Deferred Liabilities. F-21




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Supplemental Executive Retirement Plan We maintain an unfunded, non-qualified supplemental executive retirement plan. Currently, the only
beneficiary is our former President and Chief Executive Officer, James G. Floyd. Upon Mr. Floyds
retirement March 31, 2001, he became entitled to receive payment of $100,000 per year for life. If
Mr. Floyd predeceases his spouse, 50% of his retirement plan benefit will continue to be paid to
his surviving spouse for her life. We incurred expenses of approximately $105,000 during each of
the years ended December 31, 2004, 2003 and 2002 related to this retirement plan. Annual expense
incurred is greater than annual distribution due to the actuarial estimate of the future liability. Employee Annual Incentive Compensation Plan We maintain an Annual Incentive Compensation Plan that provides an annual incentive bonus to all
full-time employees if certain performance goals are met during the year. The plan is administered
by our Chief Executive Officer on behalf of our Board of Directors and the Compensation Committee.
Annual objectives and incentive opportunity levels are established and approved by the Compensation
Committee. Incentive awards are earned based on our actual performance in relation to
pre-established objectives and on an assessment of individual contribution during the year. We
incurred incentive compensation costs of approximately $6.2 million, $4.8 million and $3.7 million
in 2004, 2003 and 2002. Deferred Compensation Plan for Non-Employee Directors We maintain a deferred compensation plan for non-employee, non-affiliated directors, which was
adopted by our Board of Directors in October 1997 and under which participants may defer current
compensation in the form of phantom stock rights that are tied to the market price of the common
stock on the date services are performed. The term phantom stock rights refers to units of value
that track the performance of our companys common stock. These units are not convertible to stock
and do not possess any voting rights. Phantom stock rights are exchanged for a cash distribution
upon retirement. Stock and Option Plans We have four stock options plans, together our (Stock Plans): (i) 1996 Stock Option Plan which
was adopted at the completion of our initial public offering in September 1996, amended and
approved by the stockholders in 1997; (ii) 1999 Non-Qualified Stock Option Plan adopted by our
Board of Directors in October 1999; (iii) 2002 Long-Term Incentive Plan adopted in January 2002,
approved by the stockholders in May 2002 and amended by our Board in October 2003; and (iv) 2004
Long -Term Incentive Compensation Plan, approved by the stockholders in June 2004. All our
employees, directors, consultants and advisors are eligible to participate in our Stock Plans, with
the exception of executive officers that are not eligible to participate in the 1999 Plan. Options
granted under our Stock Plans 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
directors whose options vest immediately upon grant. All grants are made at the closing price of
our common stock as reported on the NYSE on the date of grant. The 1996, 2002 and 2004 Plans allow
for the grant of both incentive stock options and non-qualified stock options. Common stock issued through the exercise of non-qualified options will result in a tax deduction
for us which is equal to the taxable gain recognized by the optionee. Generally, we will not
receive an income tax deduction for incentive based options. For financial reporting purposes, the
tax effect of this deduction is accounted for as a credit to additional paid-in-capital rather than
as a reduction of income tax expense. The exercise of stock options during 2004, 2003 and 2002
resulted in a current tax benefit to us of approximately $4.9 million, $1.4 million and $4.8
million, respectively. In addition to stock options, the 2002 Plan and 2004 Plan allow for the grant of restricted stock.
Restricted stock carries voting and dividend rights; however, the sale or transfer of the shares is
restricted. During 2004 and 2003, restricted stock was granted and issued to certain executive
officers, non-employee directors and affiliated directors as a component of each recipients annual
compensation. Generally, restricted shares vest and become freely transferable at the end of five
years from the date of grant. Accelerated vesting will occur upon the occurrence of certain
events, including retirement from the company or Board of Directors or upon a change of control
(as defined by the Plan). On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123, as
amended by SFAS 148, Accounting for StockBased Compensation  Transition and Disclosure using
the Prospective Method as defined by the SFAS 148. As a result, we now record as compensation
expense the fair value of all stock options issued subsequent to January 1, 2003. No expense for
stock options was incurred prior to January 1, 2003. F-22




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The table below provides a detail of stock compensation expenses incurred during the years ended
December 31, 2004 and 2003. For 2004, we incurred additional expense of $1.6 million related to
the accelerated vesting of stock options and $0.8 million for the accelerated vesting of restricted
stock for retiring executive officers and members of our Board of Directors. Years Ended December 31,2004
    
    
    2003
    
    
    2002(in thousands)Options
    
    $
    3,670
    
    
    $
    903
    
    
    $
    Restricted stock(1)
    
    
    1,126
    
    
    
    111
    
    
    
    85Amounts capitalized
    
    
    (800
    )
    
    
    (166
    )
    
    
    Stock compensation expense, net of amounts capitalized
    
    $
    3,996
    
    
    $
    848
    
    
    $
    85
   (1)
    
    Includes $21,000, $85,000 and $85,000, respectively, during 2004, 2003 and 2002
for the amortization of 10,000 shares of restricted stock granted to our Chief Executive
Officer upon his employment with our company in April 2001.
These shares fully vested in
April 2004 and were not made pursuant to one of our Plan. The table below summarizes all of our Stock Plans as of December 31, 2004. Pursuant to shareholder
approval of the 2004 Plan received at our annual meeting in June 2004, all remaining options
available for grant under the 2002, 1999 and 1996 Plans were cancelled and 1,500,000 shares were
made available for grant under the 2004 Plan. 2004 Plan
    
    
    2002 Plan
    
    
    1999 Plan
    
    
    1996 Plan
    
    
    Total PlansOptions and restricted stock authorized
    
    
    1,500,000
    
    
    
    1,500,000
    
    
    
    800,000
    
    
    
    3,033,912
    
    
    
    6,833,912Options granted:Incentive stock options
    
    
    
    
    
    
    47,686
    
    
    
    
    
    
    
    1,032,302
    
    
    
    1,079,988Non-qualified stock options
    
    
    301,450
    
    
    
    1,193,989
    
    
    
    806,606
    
    
    
    2,009,910
    
    
    
    4,311,955Forfeitures
    
    
    (3,425
    )
    
    
    (39,110
    )
    
    
    (39,443
    )
    
    
    (11,877
    )
    
    
    (93,855
    )Cancellations
    
    
    
    
    
    
    (275,435
    )
    
    
    (32,837
    )
    
    
    (3,577
    )
    
    
    (311,849
    )Total options
    
    
    298,025
    
    
    
    1,478,000
    
    
    
    800,000
    
    
    
    3,033,912
    
    
    
    5,609,937Restricted stock granted (1)
    
    
    49,000
    
    
    
    22,000
    
    
    
    
    
    
    
    
    
    
    
    71,000Options and restricted stock available for grant
    
    
    1,152,975
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,152,975Total exercised and issued
    
    
    
    
    
    
    269,320
    
    
    
    421,734
    
    
    
    2,649,436
    
    
    
    3,340,490
   (1)
    
    Average grant price for restricted shares issued was $58.28 and $35.08,
respectively, during years ended December 31, 2004 and 2003. The table below summarizes the activity for stock options during the respective years for all of
our stock plans. Years Ended December 31,2004
    
    
    2003
    
    
    2002Shares
    
    
    Price(1)
    
    
    Shares
    
    
    Price(1)
    
    
    Shares
    
    
    Price(1)Options outstanding January 1
    
    
    2,535,159
    
    
    $
    30.23
    
    
    
    2,421,166
    
    
    $
    27.50
    
    
    
    2,164,448
    
    
    $
    24.81Granted
    
    
    342,950
    
    
    
    55.98
    
    
    
    606,725
    
    
    
    34.86
    
    
    
    753,559
    
    
    
    30.14Exercised
    
    
    (873,626
    )
    
    
    29.30
    
    
    
    (461,563
    )
    
    
    22.15
    
    
    
    (490,788
    )
    
    
    19.70Forfeited
    
    
    (46,885
    )
    
    
    34.49
    
    
    
    (31,169
    )
    
    
    27.73
    
    
    
    (6,053
    )
    
    
    27.77Options outstanding December 31
    
    
    1,957,598
    
    
    $
    35.05
    
    
    
    2,535,159
    
    
    $
    30.23
    
    
    
    2,421,166
    
    
    $
    27.50Options exercisable December 31
    
    
    555,546
    
    
    $
    29.80
    
    
    
    838,568
    
    
    $
    28.28
    
    
    
    848,103
    
    
    $
    25.12Options available for grant
December 31
    
    
    1,152,975
    
    
    
    
    
    
    
    309,889
    
    
    
    
    
    
    
    906,945
   (1)
    
    Weighted average price. For all grants, the grant price equal to closing market
price on the NYSE on date of grant. The table below sets forth a summary of options granted and outstanding, their remaining
contractual lives, a weighted average exercise price and the number vested and exercisable as of
December 31, 2004. F-23




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Options Outstanding
    
    
    Options Exercisable/Vested
    
    
    UnvestedShares
    
    
    
    
    
    
    Remaining
    
    
    Weighted
    
    
    Shares
    
    
    Weighted
    
    
    SharesRange of
    
    Underlying
    
    
    Year
    
    
    Contractual
    
    
    Average
    
    
    Underlying
    
    
    Average
    
    
    UnderlyingExercise Prices
    
    Options
    
    
    Granted
    
    
    Life
    
    
    Exercise Price
    
    
    Options
    
    
    Exercise Price
    
    
    Options$15.50 - $17.25
    
    
    15,000
    
    
    
    1996
    
    
    2 years
    
    $
    15.60
    
    
    
    15,000
    
    
    $
    15.60
    
    
    
    $13.13 - $25.00
    
    
    17,900
    
    
    
    1997
    
    
    3 years
    
    
    20.74
    
    
    
    17,900
    
    
    
    20.74
    
    
    
    $15.75 - $23.38
    
    
    6,920
    
    
    
    1998
    
    
    4 years
    
    
    18.86
    
    
    
    6,920
    
    
    
    18.86
    
    
    
    $16.94 - $21.00
    
    
    41,000
    
    
    
    1999
    
    
    5 years
    
    
    19.33
    
    
    
    41,000
    
    
    
    19.33
    
    
    
    $18.00 - $26.19
    
    
    46,700
    
    
    
    2000
    
    
    6 years
    
    
    23.49
    
    
    
    33,800
    
    
    
    24.07
    
    
    
    12,900$22.50 - $37.38
    
    
    494,808
    
    
    
    2001
    
    
    7 years
    
    
    29.41
    
    
    
    218,361
    
    
    
    29.85
    
    
    
    276,447$27.49 - $33.75
    
    
    483,540
    
    
    
    2002
    
    
    8 years
    
    
    30.15
    
    
    
    109,560
    
    
    
    30.05
    
    
    
    373,980$26.18 - $37.42
    
    
    512,705
    
    
    
    2003
    
    
    9 years
    
    
    34.87
    
    
    
    94,005
    
    
    
    35.36
    
    
    
    418,700$36.56 - $60.45
    
    
    339,025
    
    
    
    2004
    
    
    10 years
    
    
    55.98
    
    
    
    19,000
    
    
    
    56.89
    
    
    
    320,0251,957,598
    
    
    
    
    
    
    
    
    
    
    $
    35.05
    
    
    
    555,546
    
    
    $
    29.80
    
    
    
    1,402,052
 NOTE 5  Income Taxes The components of the federal income tax provision (benefit) are: Years Ended December 31,2004
    
    

    2003
    
    

    2002(in thousands)Current
    
    $
    46,092
    
    
    $
    13,913
    
    
    $
    4,007Deferred
    
    
    50,500
    
    
    
    58,274
    
    
    
    35,085Total
    
    $
    96,592
    
    
    $
    72,187
    
    
    $
    39,092
 For 2002, the current provision includes $0.8 million in Section 29 tax credits (see Note 6Related
Party Transactions  Section 29 Tax Credits). At December 31, 2004 and 2003, we had no net
operating loss carryforwards remaining for federal income tax purposes. At of December 31, 2002,
we had net operating loss carryforwards of approximately $47.5 million. Net operating loss
carryforwards may be used in future years to offset taxable income. The following is a reconciliation of statutory federal income tax expense (benefit) to our income
tax provision: Years Ended December 31,2004
    
    

    2003
    
    

    2002(in thousands)Income before income taxes
    
    $
    259,416
    
    
    $
    205,999
    
    
    $
    109,586Statutory rate
    
    
    35
    %
    
    
    35
    %
    
    
    35
    %Income tax expense computed at statutory rate
    
    
    90,796
    
    
    
    72,100
    
    
    
    38,355Reconciling items:State income taxes and other, net of federal
tax benefit
    
    
    4,358
    
    
    
    
    
    
    
    Section 29 tax credits and other tax credits (1)
    
    
    
    
    
    
    58
    
    
    
    (804
    )Permanent differences
    
    
    45
    
    
    
    29
    
    
    
    Non-deductible compensation expense
    
    
    1,393
    
    
    
    
    
    
    
    1,541Tax provision
    
    $
    96,592
    
    
    $
    72,187
    
    
    $
    39,092
   (1)
    
    For 2003, excess deductions taken in 2002. F-24




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Deferred Income Taxes Deferred income taxes primarily represent the net tax effect of temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes and the amounts used
for income tax purposes. The components of our deferred taxes are detailed in the table below. For 2004, the change in the balance of our deferred tax liability was comprised of deferred tax
expense of $50.5 million, a tax benefit of $11.1 million due to the change in the fair value of our
open derivative contracts that has been deferred in accumulated other comprehensive income and a
reduction of $7.4 million to our deferred tax liabilities related to oil and gas property and
equipment associated with the Appalachian Basin assets divested as part of the KeySpan Exchange in
June 2004. For 2003, the change in the balance of our deferred tax liability was comprised of deferred tax
expense of $59.7 million, a tax benefit of $1.5 million pursuant to the cumulative effect of the
change in accounting principle for the adoption of SFAS 143 and a tax benefit of $1.2 million due
to the change in the fair value of our open derivative contracts that has been deferred in
accumulated other comprehensive income. Years Ended December 31,2004
    
    
    2003(in thousands)Deferred tax assets:Derivative instruments
    
    $
    25,222
    
    
    $
    14,752Ineffectiveness derivative instruments
    
    
    1,381
    
    
    
    682Alternative minimum tax credit carryforwards
    
    
    
    
    
    
    7,187Deferred compensation
    
    
    4,327
    
    
    
    1,203Total deferred tax assets
    
    
    30,930
    
    
    
    23,824Deferred tax liabilities:Oil and gas property and equipment
    
    
    294,898
    
    
    
    255,605Total deferred tax liability
    
    $
    263,968
    
    
    $
    231,781
 NOTE 6  Related Party Transactions Transactions With KeySpan KeySpan Exchange To facilitate the KeySpan Exchange (see Note 3  KeySpan Exchange and Offering), we entered into a
Distribution Agreement with KeySpan that defines each companys rights and obligations with respect
to the exchange transaction. The Distribution Agreement contains, among other provisions,
customary representations and warranties concerning our Appalachian Basin properties, including
title, regulatory compliance and environmental matters, along with limited indemnification
obligations. Pursuant to the Distribution Agreement, the two companies also entered into a Tax
Matters Agreement, which generally provides that each party would be responsible for its own tax
consequences if the KeySpan Exchange fails to qualify as a tax-free transaction. In addition, we
entered into a Transition Services Agreement pursuant to which we will provide KeySpan with
transitional services with respect to the Appalachian Basin assets for a fee of $27,000 per month
until March 31, 2005. Issuance of 3,000,000 Shares to the Public and Concurrent Repurchase of 3,000,000 Shares from
KeySpan.See Note 3 Stockholders Equity. Sale of Section 29 Tax Credits In June 2003, we repurchased, for $2.6 million, certain interests in producing wells that were sold
in January 1997, to a subsidiary of KeySpan under an agreement designed to monetize tax credits
available under Section 29 of the Internal Revenue Code. 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. The wells
subject to the agreement are located in West Virginia, Oklahoma and East Texas and produce from
formations F-25




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS that qualify for Section 29 tax credits. Pursuant to the agreement, KeySpan acquired an economic
interest in wells that qualified for the tax credits and, in exchange, we:  
    retained a volumetric production payment and a net profits interest of 100% in the properties;
    received a cash down payment of $1.4 million; and
    receive a quarterly payment of $0.75 for every dollar of tax credit utilized. During the term of the agreement, we managed and administered the daily operations of the
properties in exchange for an annual management fee of $100,000. The agreement expired December 31,
2002, and as a result, we were required to repurchase the interests in the producing wells from
KeySpan. Subsequent to the repurchase, ownership of the tax credits reverted back to us. The
income statement effect, representing benefits received from Section 29 tax credits, was a benefit
of $0.8 million both during 2002 and 2001, with no benefit during 2003. Acquisition of KeySpan Joint Venture Assets In October 2002, we purchased from KeySpan a portion of the assets developed under the joint
exploration agreement with KeySpan Exploration & Production, LLC, a subsidiary of KeySpan (see
discussion of KeySpan Joint Venture below). The acquisition consisted of interests averaging
between 11.25% and 45% in 17 wells covering eight of the twelve blocks that were developed under
the joint exploration agreement from 1999 through 2002. KeySpan retained a 45% interest in four
blocks: South Timbalier 314 and 317 and Mustang Island 725 and 726, as these blocks were in
various stages of development at the time of the acquisition. KeySpan committed to continued
participation in the ongoing development of these blocks, which included the completion of the
platform and production facilities at South Timbalier 314/317, together with possible further
developmental drilling. Both Houston Exploration and KeySpan farmedout their interest in Mustang
Island 725/726 during 2003. At September 1, 2002, the effective date of the purchase, the
estimated proved reserves associated with the interests acquired were 13.5 Bcfe. The $26.5 million
purchase price was paid in cash and financed with borrowings under our revolving credit facility.
Subsequent purchase price adjustments reduced our acquisition price by $1.2 million. The purchase
price was adjusted for various closing items in the normal course of business, including revenues
received by and expenditures made by the seller related to the properties acquired for the period
between the effective date of the transaction (September 1, 2002) and the closing date (October 11,
2002). Our acquisition of the properties was accounted for as a transaction between entities under
common control. As a result, the excess book value of the properties acquired of $3.1 million
($2.0 million net of tax) was treated as a capital contribution from KeySpan and recorded as an
increase to additional paid-in capital during the fourth quarter of 2002. KeySpan Joint Venture Effective January 1, 1999, we entered into a joint exploration agreement with KeySpan Exploration &
Production, LLC, a subsidiary of KeySpan, to explore for natural gas and oil over an initial
two-year term expiring December 31, 2000. Under the terms of the joint venture, we contributed all
of our then undeveloped offshore acreage to the joint venture and we agreed that KeySpan would
receive 45% of our working interest in all prospects drilled under the program. KeySpan paid 100%
of actual intangible drilling costs for the joint venture up to a specified maximum. Further,
KeySpan paid 51.75% of all additional intangible drilling costs incurred and we paid 48.25%.
Revenues are shared 55% to Houston Exploration and 45% to KeySpan. Effective December 31, 2000, KeySpan and Houston Exploration agreed to end the primary or
exploratory term of the joint venture. As a result, KeySpan has not participated in any of our
offshore exploration prospects unless the project involved the development or further exploitation
of discoveries made during the initial term of the joint venture. During 2003, KeySpan spent
approximately $9.5 million for capital costs associated with its working interests in properties
developed under the joint venture. Costs incurred during 2003 were related to the installation of
production facilities at South Timbalier 314/317, the completion of the initial two exploratory
wells that were brought on-line during the first quarter of 2003 and participation in a third well,
a development well on the property during the second quarter of 2003. From the inception of the joint venture in January 1999 through December 31, 2003, we drilled a
total of 29 wells: 21 exploratory wells, of which 17 were successful, and eight development wells,
of which seven were successful. The joint venture had no drilling activity during 2004. KeySpan
spent a total of $127.8 million over the course of the joint venture, with less than $100,000 in
2004, and $9.5 million and $19.0 million, respectively being spent during 2003 and 2002. F-26




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Transactions With Our Executive Officers and Directors Employment Contracts We have entered into employment contracts with all of our executive officers. Contracts are
initially set for a three-year period and automatically extended one year on each anniversary
unless either party gives notice within a specified number of days prior to the anniversary of the
employment agreement. Executive officers receive annual salary and bonus payments pursuant to their
employment contracts and if we terminate an employment agreement without cause or if the employee
terminates an employment agreement with good reason, as defined in the employment agreements, we
are obligated to pay the employee a lump-sum severance payment of 2.99 times the employees then
current annual rate of total compensation, as defined in the agreement, in addition to the
continuation of certain insurance benefits for a specified time period. Subsequent to December 31,
2004, we entered into amended and restated employment agreements with certain executive officers.
See Note 11- Subsequent Events. Lump-Sum Payments to Executives Under Employment Contracts Pursuant to a management organizational change made within our company in November 2004 that
changed the reporting responsibilities of three executive officers, Charles W. Adcock, Senior Vice
President and General Manager  Offshore Division resigned, effective December 14, 2004, and
Timothy R. Lindsey, Senior Vice President of Exploration, and Tracy Price, Senior Vice President 
Land, resigned, effective March 1, 2005. Pursuant to their resignations and the termination of
their employment agreements with our company, we incurred approximately $5.1 million in general and
administrative expense of which $1.3 million, $1.1 million and $1.0 million, respectively, related
to lump-sum severance entitlements for Messrs. Adcock, Lindsey and Price and, $1.7 million related
to expense incurred as a result of the accelerated vesting of all their outstanding stock options
and restricted stock. Transactions Involving Companies with Common Directors John U. Clarke, a member of our Board of Directors and Chairman of the Audit Committee serves as a
Chairman and Chief Executive Officer of NATCO Group, a publicly traded oil field services and
equipment company. During 2004, 2003 and 2002 we purchased services and supplies from NATCO of
$0.9 million, $1.1 million and $1.1 million, respectively. Mr. Clarke meets all requirements of
the New York Stock Exchange to be considered an independent director of our company. NOTE 7  Derivative Instruments As of December 31, 2004, we had entered into commodity price hedging contracts with respect to our
production for 2005 through 2008 as listed in the tables below. The total estimated fair value of
our natural gas and oil derivative instruments at December 31, 2004 was a liability of $75.1
million ($48.5 million net of tax), of which we have deferred a net $46.0 million in accumulated
other comprehensive income and recognized $3.9 million ($2.5 net of tax) in earnings as a reduction
to natural gas and oil revenues as a result of the estimated ineffectiveness of our open contracts
as of the end of the period. From time to time, if the fair value of an open contract or contracts exceeds our available credit
limit with a particular counterparty, we could be required to post a letter of credit to further
guarantee our performance. As of December 31, 2004, we did not have any outstanding letters of
credit issued relating to derivative contracts. Natural Gas
    
    Fixed Price Swaps
    
    
    CollarsDaily
    
    
    NYMEX
    
    
    Daily
    
    
    NYMEXVolume
    
    
    Contract
    
    
    Volume
    
    
    Contract PricePeriod
    
    (MMBtu)
    
    

    Price
    
    
    (MMBtu)
    
    

    Floor
    
    

    Ceiling
    
    
    Fair Value(thousands)January  December 2005
    
    
    80,000
    
    
    $
    5.304
    
    
    
    180,000
    
    
    $
    4.833
    
    
    $
    6.434
    
    
    $
    (68,081
    )January  December 2006
    
    
    30,000
    
    
    
    5.893
    
    
    
    60,000
    
    
    
    5.500
    
    
    
    7.248
    
    
    
    (3,889
    )January  December 2007
    
    
    
    
    
    
    
    
    
    
    30,000
    
    
    
    5.000
    
    
    
    6.597
    
    
    
    (1,662
    )January  December 2008
    
    
    
    
    
    
    
    
    
    
    20,000
    
    
    
    5.000
    
    
    
    5.720
    
    
    
    (1,517
    )$
    (75,149
    )
 As of December 31, 2003, we had entered into commodity price hedging contracts with respect to our
production for 2004 and 2005 as listed in the tables below. The total estimated fair value of our
natural gas and oil derivative instruments at December 31, 2003 was a liability of $36.9 million
($27.4 million net of tax) of which we had deferred a net $26.1 million F-27




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS was in accumulated other comprehensive income and recognized $1.3 million in 2003 earnings as a
reduction to natural gas and oil revenues as a result of the estimated ineffectiveness of our open
contracts as of the end of the period. Natural Gas
    
    Options - Puts
    
    
    Fixed Price Swaps
    
    
    CollarsDaily
    
    
    NYMEX
    
    
    Daily
    
    
    NYMEX
    
    
    Daily
    
    
    NYMEXVolume
    
    
    Contract
    
    
    Volume
    
    
    Contract
    
    
    Volume
    
    
    Contract PricePeriod
    
    (MMBtu)
    
    

    Price
    
    

    (MMBtu)
    
    

    Price
    
    
    (MMBtu)
    
    

    Floor
    
    

    Ceiling
    
    
    Fair Value(thousands)January  March 2004
    
    
    100,000
    
    
    $
    5.000
    
    
    
    40,000
    
    
    $
    4.960
    
    
    
    100,000
    
    
    $
    3.750
    
    
    $
    5.045
    
    
    $
    (13,897
    )April  December 2004
    
    
    
    
    
    
    
    
    
    
    40,000
    
    
    
    4.960
    
    
    
    200,000
    
    
    
    4.125
    
    
    
    6.023
    
    
    
    (18,238
    )January  December 2005
    
    
    
    
    
    
    
    
    
    
    50,000
    
    
    
    4.766
    
    
    
    100,000
    
    
    
    4.500
    
    
    
    5.500
    
    
    
    (4,727
    )$
    (36,862
    )
 Fair market value is calculated for the respective months using prices derived from NYMEX futures
contract prices existing at December 31st and from market quotes received from
counterparties. For natural gas, transactions are settled based upon 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 us in the event that the settlement price for any
settlement period is less than the swap price for the transaction, and we are 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 the transaction. For any particular collar transaction the
counterparty is required to make a payment to us if the settlement price for any settlement period
is below the floor price for the transaction, and we are required to make payment to the
counterparty if the settlement price for any settlement period is above the ceiling price for the
transaction. We are 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. NOTE 8  Sales to Major Customers We sold natural gas and oil production representing 10% or more of our natural gas and oil revenues
for the years ended December 31, 2004, 2003 and 2002 as listed below. In 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, we believe that the loss of any of
our major purchasers would not have a material adverse effect on our operations. Amounts presented
in the below table that are less than 10% have been included for information and comparison
purposed only. For the Year Ended December 31,Major Purchaser
    
    
    2004
    
    
    
    2003
    
    
    
    2002ConocoPhillips
    
    
    11.9
    %
    
    
    18.4
    %
    
    
    14.9
    %KinderMorgan
    
    
    10.1
    %
    
    
    11.4
    %
    
    
    9.8
    %Anadarko Petroleum Corporation
    
    
    9.08
    %
    
    
    11.7
    %
    
    
    12.6
    %
 NOTE 9  Commitments and Contingencies Legal Proceedings We are involved from time to time in various claims and lawsuits incidental to our business. In the
opinion of management, the ultimate liability, if any, will not have a material adverse effect on
our financial position or results of operations. Severance Tax Refund During July 2002, we applied for and received from the Railroad Commission of Texas a
high-cost/tight-gas formation designation for a portion of our South Texas production. For
qualifying wells, production is either exempt from tax or taxed at a reduced rate until certain
capital costs are recovered. For the years ended December 31, 2004 and 2003, we recognized as
other income refunds of prior period severance tax payments of $1.2 million and $21.6 million,
respectively. For the year ended December 31, 2002, we recognized a total of $10.4 million, of
which $1.3 million related to refund of 2002 severance tax expense and $9.1 related to refunds of
prior period expense. At December 31, 2004, and 2003, our current receivables include $1.3 million
and $12.9 million, respectively, in gross refunds of which we estimate, approximately 70%, or $0.9
million and $9.0 million, respectively, relate to our net revenue interest. We expect to collect F-28




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS our current receivable prior to the end of the third quarter of 2005. Beginning September 1, 2003,
all refunds issued by the State of Texas are to be made in the form of a reduction to or credit
against our current severance tax liability rather than in the form of a cash reimbursement. Leases We have entered into non-cancelable operating lease agreements in the ordinary course of our
business activities. These leases include those for our office space at 1100 Louisiana in Houston,
Texas and at 700 17th Street in Denver, Colorado together with various types of office
equipment (telephones, copiers and faxes). The terms of these agreements have various expiration
dates from 2005 through 2009. Rental expense related to these leases was $1.6 million, $1.3 million
and $1.2 million, respectively, for the years ended December 31, 2004, 2003 and 2002. At December
31, 2004, our total commitment under these non-cancelable operating leases was $7.2 million.
Minimum rental commitments under the terms of our operating leases are as follows (in thousands): MinimumYears Ended December 31,
    
    Payments2005
    
    $
    1,5502006
    
    
    1,5362007
    
    
    1,5932008
    
    
    1,6112009
    
    
    933Thereafter
    
    
    Total
    
    $
    7,223
 NOTE 10  Acquisitions and Dispositions(Reserve quantities, wells, acreage and working interests
included below are unaudited.) Orca Acquisition On October 29, 2004, we completed the acquisition of certain producing properties from Orca Energy,
L.P. The $113.6 purchase price was paid in cash and financed by borrowings under our revolving bank
credit facility. The transaction was effective August 1, 2004. The Orca properties consist of 10
offshore blocks and two onshore fields. The onshore fields are non-operated and located in central
Mississippi: the Wausau Field, located in Wayne County and the Oakvale Dome Field, located in
Jefferson Davis County. The 10 offshore blocks are a mix of state and federal leases, located in
less than 50 feet of water, and include seven blocks in federal waters and three blocks in state
waters. Total acreage acquired covers 23,777 gross (17,973 net) acres. The properties include 15
platforms, five production caissons and 28 producing wells. Based on internal estimates, total
proved reserves acquired were approximately 60.7 Bcfe as of the closing date, October 29, 2004, of
which 81% were natural gas. Our average working interest in the properties acquired is 68% and we
will operate approximately 85% of the proved reserves acquired. BP Acquisition On September 30, 2004, we completed the purchase of two producing offshore fields from BP
Exploration & Production Inc. The net purchase price of $30.0 million was paid in cash and financed
by borrowings under our revolving bank credit facility. The $31.5 million purchase price was
reduced by $1.5 million for various customary closing items, including revenues received by and
expenditures made by the seller related to the properties acquired for the period between the
effective date of the transaction, August 1, 2004, and the closing date, September 30, 2004. The
properties acquired are located at Eugene Island 240 and Main Pass 264 and each block has one
producing platform. Based on internal estimates, total proved reserves associated with the
interests acquired were approximately 16.2 Bcfe as of September 30, 2004, of which 85% are natural
gas. Our average working interest is 85% and we will operate both blocks. Disposition and Exchange of Appalachian Basin Assets In connection with the KeySpan Exchange on June 2, 2004, (see Note 1  KeySpan Exchange and
Offering) we divested all of our Appalachian Basin assets with an agreed upon value of $60 million.
Pursuant to an Asset Contribution Agreement, we contributed to Seneca-Upshur all of the assets
relating solely to our Appalachian Basin assets that were not already owned by Seneca-Upshur, and
Seneca-Upshur assumed all of the liabilities relating to the Appalachian Basin assets for F-29




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS which it was not already liable. In the KeySpan Exchange, all of the stock of Seneca-Upshur was
then conveyed to KeySpan and effective June 1, 2004, Seneca-Upshur became an indirect wholly-owned
subsidiary of KeySpan. Our Appalachian property base was located primarily in central West Virginia and included the
Belington, Clarksburg and Seneca Upshur Fields located in Barbour, Randolph, Upshur and Mingo
Counties of West Virginia. Included in the assets exchanged were the assets acquired on December
31, 2003, from EnerVest East Limited Partnership located adjacent to our existing base in the
Crawford and Pennsboro Fields in Lewis, Harrison, Tyler and Ritchie Counties of West Virginia and
the Waynesburg and Yatesboro Fields in Greene and Armstrong Counties of southwestern Pennsylvania.
Based on internal estimates at June 1, 2004, our Appalachian Basin properties had 51.2 Bcfe of
estimated proved reserves, and our average daily production was approximately 8 MMcfe/day, which
represented approximately 3% of our total daily production. We had approximately 207,000 gross
(129,000 net) acres under lease and owned working interests in approximately 1,414 gross (1,035
net) wells, of which we operated approximately 92%. Our average working interest was 73%. Sale of Onshore South Louisiana Properties On February 4, 2004, we completed the sale of our onshore South Louisiana producing properties.
The sale was effective November 1, 2003, and the properties represented 12.3 Bcfe proved reserves
as of December 31, 2003, and included interests in 33 gross (9.5 net) producing wells and covered
approximately 6,300 gross (2,300 net) acres. The sale price of $15 million was reduced by $1.9
million for various customary closing items, including revenues received by and expenditures made
by us related to the properties sold for the period between the effective date of the transaction
and the closing date. The net proceeds of $13.1 million from the sale were used to repay
borrowings under our revolving bank credit facility. EnerVest Acquisition On December 31, 2003, we completed the purchase of certain producing natural gas and oil properties
and associated gathering pipelines and equipment located in the Appalachian Basin of West Virginia
and Pennsylvania from EnerVest East Limited Partnership. The properties acquired are adjacent to
our existing producing properties in West Virginia. The $28 million purchase price was reduced by
$0.2 million for various customary closing items, including revenues received by and expenditures
made by the seller related to the properties acquired for the period between the effective date of
the transaction, December 1, 2003, and the closing date, December 31, 2003. The net purchase price
of $27.9 million was paid in cash and financed by borrowings under our revolving bank credit
facility. The properties purchased cover approximately 146,000 gross (83,950 net) acres. The
properties acquired include working interests in approximately 774 producing wells Our average
working interest is 74% and we will we operate approximately 85% of the wells acquired. In
addition, the interests acquired include approximately 300 wells in which we will have an
overriding royalty interest. Total proved reserves associated with the interests acquired were
23.4 Bcfe, as of the December 31, 2003. Transworld Exploration and Production Inc. Acquisition On October 15, 2003, we completed the acquisition of Transworld Exploration and Production Inc.s
shallow-water Gulf of Mexico natural gas and oil producing properties and undeveloped acreage. At
closing, the $155 million purchase price was reduced by $7.5 million for various customary closing
items, including revenues received by and expenditures made by the seller related to the properties
acquired for the period between the effective date of the transaction, July 1, 2003, and the
closing date, October 15, 2003. The net purchase price of $147.5 million was paid in cash and
financed in part by cash on hand and in part by borrowings under our revolving bank credit
facility. The properties are located primarily in the central Gulf of Mexico in less than 320 feet
of water and include 21 blocks covering 86,237 gross (64,394 net) acres. As of the October 15,
2003 closing date, proved reserves are an estimated 88.5 Bcfe, of which 75% is natural gas.
Current production is from 11 fields and is estimated at approximately 35 MMcfe per day, net to our
interest. We operate properties representing 97% of the proved reserves with an average working
interest of 65%. Acquisition of KeySpan Joint Venture Assets (See Note 6  Related Party Transaction  Transactions
with KeySpan) Burlington Acquisition On May 30, 2002, we completed the purchase of natural gas and oil producing properties and
associated gathering pipelines, together with undeveloped acreage, from Burlington Resources Inc.
located in the Webb, Jim Hogg, Wharton and Calhoun counties of South Texas. The properties
purchased cover approximately 24,800 gross (10,800 net) acres located in F-30




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS the Northeast Thompsonville, South Laredo, McFarlan and Maude Traylor Fields. The properties
purchased represent interests in approximately 145 producing wells and total proved reserves of 42
Bcfe as of January 1, 2002, the effective date of the transaction. Our average working interest is
35% and we are the operator of approximately 23% of the producing wells acquired. The $44.5
million purchase price, which is net of a purchase price adjustment of $3.9 million, was financed
by borrowings under our revolving bank credit facility. The purchase price was reduced for various
closing items in the normal course of business, including revenues received by and expenditures
made by the seller related to the properties acquired for the period between the effective date of
the transaction (January 1, 2002) and the closing date (May 30, 2002). On July 16, 2002, we sold those interests acquired from Burlington in the McFarlan and Maude
Traylor Fields for approximately $5.0 million, which was net of a purchase price adjustment of $1.1
million. The effective date of this transaction was January 1, 2002. These two fields, located in
Wharton and Calhoun counties, respectively, are outside our current area of focus in South Texas.
The sale represented interests in 22 producing wells with reserves of approximately 5 Bcfe.
Proceeds from the sale were used to repay borrowings under our revolving bank credit facility. We retained the Northeast Thompsonville Field, located in Jim Hogg County, and the South Laredo
Field, located in Webb County. The Northeast Thompsonville Field has 10 wells producing from the
Wilcox formation, all of which we operate, and representing approximately 70% of the proved
reserves and 75% of the current production associated with the acquisition from Burlington. The
South Laredo Field, located in Webb County and in the Lobo Trend, contains 113 wells, all operated
by a third party. Conoco Acquisition We completed the purchase of certain natural gas and oil properties and associated gathering
pipelines and equipment, together with developed and undeveloped acreage, located in Webb and
Zapata counties of South Texas, from Conoco Inc on December 31, 2001. The $69 million purchase
price was paid in cash and financed by borrowings under our revolving bank credit facility. The
properties purchased cover approximately 25,274 gross (16,885 net) acres located in the Alexander,
Haynes, Hubbard and South Trevino Fields, which are in close proximity to our existing operations
in the Charco Field, and represent interests in approximately 159 producing wells. We operate
approximately 95% of the producing wells acquired and our average working interest is 87%. Total
proved reserves associated with the interests acquired were 85 Bcfe, as of the October 1, 2001, the
effective date of the transaction. NOTE 11  Subsequent Events Proposed Increase in Number of Shares Outstanding Our Board of Directors intends to seek shareholder approval at the next annual meeting in April
2005, to increase the number of shares we are authorized to issue to up to 105,000,000 shares of
stock, including up to 100,000,000 shares of common stock and up to 5,000,000 shares of preferred
stock. Amendments to Employment Agreements Effective February 8, 2005, we entered into amended and restated employment agreements with William
G. Hargett, our President and Chief Executive Officer, Steven L. Mueller, our Executive Vice
President and Chief Operating Officer, John H. Karnes, our Senior Vice President and Chief
Financial Officer, James F. Westmoreland, our Vice President and Chief Accounting Officer, and
Roger B. Rice, our Senior Vice President-Administration. We also entered into a new employment
agreement with Joanne C. Hresko, our Vice President and General Manager-Onshore Division. Each
agreement is for a term of three years, with automatic one-year extensions thereafter unless we or
the executive provide notice of termination at least 90 days prior to the end of the applicable
term. By entering into the amended and restated employment agreements and terminating their prior
employment agreements with us, Messrs. Hargett, Mueller, Karnes, Westmoreland and Rice are
foregoing certain rights, including the right to receive severance for a termination of employment
following a change of control of the Company absent the existence of good reason and the right to
guaranteed annual stock option grants and incentive compensation bonuses, which will now be subject
to the discretion of our Compensation and Management Development Committee. In addition to these
rights, Mr. Hargett also is foregoing the right to receive a transaction bonus upon the occurrence
of certain corporate transactions involving the Company, and all of the executives are agreeing to
somewhat broader non-competition provisions under the F-31




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS amended and restated agreements. In consideration of their entering into the amended and restated
agreements and foregoing such rights, we have agreed to pay to each of these executives cash and/or
restricted stock. The restricted stock will vest over a period of five years in accordance with
the terms of our 2004 Long-Term Incentive Compensation Plan. All of the new agreements provide that if we terminate an executives agreement without cause (as
defined in the employment agreement), or if the executive terminates his or her employment with us
for good reason (as defined in the agreement, which includes the occurrence of certain events
following a change in control of the Company), we are obligated to pay the executive a lump-sum
severance payment equal to 2.99 times his or her then current annual rate of total compensation,
and to continue certain welfare benefits. The agreements further provide that if any payments made
to the executives, whether or not under the agreement, would result in an excise tax being imposed
on the executives under Section 4999 of the Internal Revenue Code, we will make each of the
executives whole on a net after-tax basis. We may terminate any employment agreement for cause or upon the death or disability of the
executive without financial obligation (other than payment of any accrued obligations). Each
executive may terminate his or her employment agreement at any time for any reason upon at least 30
days prior written notice. In the event the executives employment is terminated by us without
cause or upon death or disability, or if the executive terminates his or her employment with us for
good reason, any unvested shares of restricted stock, unvested options or similar deferred
compensation automatically will vest and any other conditions to such awards shall be deemed
satisfied. During the first quarter of 2005, we expect to incur additional general and administrative expense
of approximately $5.1 million as a result of our terminating the prior employment agreements for
Messrs. Hargett, Mueller, Karnes, Westmoreland and Rice. Appointment of Thomas A. McKeever as Director Effective February 1, 2005, our Board of Directors appointed Thomas A. McKeever to serve as a
director. Mr. McKeever will stand for election at the Companys Annual Meeting to be held April 26,
2005. Mr. McKeever is not a party to any transaction described in Item 404(a) of Regulation S-K
involving the Houston Exploration. With the appointment of Mr. McKeever, Houston Explorations
Board was increased from seven to eight members. Mr. McKeever is expected to serve on our
Compensation and Management Development Committee, effective as of the date of our 2005 annual
meeting. Termination of Employment Agreements On February 17, 2005, Timothy R. Lindsey, Senior Vice President of Exploration, and Tracy Price,
Senior Vice President  Land, resigned from the company, effective March 1, 2005. Their
resignations were prompted by our management organizational change made in November 2004 in which
they were given new reporting responsibilities. Upon resignation, their employment agreements will
be terminated and each is entitled to receive a lump-sum severance payment in the amount of 2.99
times his total compensation, the continuation of certain health and medical benefits for a period
of at least 12 months and accelerated vesting of all outstanding stock options and restricted
stock. During the fourth quarter of 2004, we recognized additional general and administrative
expense of $3.1 million relating to the entitlements under these employment agreements. 
 NOTE 12  Supplemental Information On Natural Gas and Oil Exploration, Development and Production
Activities (Unaudited) The following information concerning our natural gas and oil operations has been provided pursuant
to Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing
Activities. Our 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. F-32




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Capitalized Costs of Natural Gas and Oil Properties As of December 31,2004
    
    

    2003
    
    

    2002(in thousands)Unevaluated properties, not subject to amortization
    
    $
    122,691
    
    
    $
    134,491
    
    
    $
    96,192Properties subject to amortization
    
    
    2,705,897
    
    
    
    2,252,852
    
    
    
    1,828,160Asset retirement obligations (1)
    
    
    71,200
    
    
    
    71,159
    
    
    
    Capitalized costs
    
    
    2,899,788
    
    
    
    2,458,502
    
    
    
    1,924,352Accumulated depreciation, depletion and amortization
    
    
    (1,355,857
    )
    
    
    (1,092,073
    )
    
    
    (906,089
    )Net capitalized costs
    
    $
    1,543,931
    
    
    $
    1,366,429
    
    
    $
    1,018,263
   (1)
    
    For 2002, our presentation does not include asset retirement obligations as we
adopted SFAS 143 Asset Retirement Obligations on January 1, 2003. Additions to Unevaluated Properties The following table provides a summary of unevaluated costs not being amortized as of December 31,
2004, by the year in which the costs were incurred. There are no individually significant
properties or significant development projects included in our unevaluated property balance. We
estimate that costs will be evaluated within four years. Costs incurred by Year as of December 31, 2004Total
    
    

    2004
    
    

    2003
    
    

    2002
    
    

    2001 and Prior(in thousands)Property acquisition costs
    
    $
    90,049
    
    
    $
    23,170
    
    
    $
    44,036
    
    
    $
    8,909
    
    
    $
    13,934Exploration and development
    
    
    22,128
    
    
    
    11,191
    
    
    
    397
    
    
    
    7,588
    
    
    
    2,952Capitalized interest
    
    
    10,514
    
    
    
    6,723
    
    
    
    3,791
    
    
    
    
    
    
    
    Total
    
    $
    122,691
    
    
    $
    41,084
    
    
    $
    48,224
    
    
    $
    16,497
    
    
    $
    16,886
 Capitalized Costs Incurred Costs incurred for natural gas and oil exploration, development and acquisition are summarized
below. Costs incurred during the years ended December 31, 2004, 2003 and 2002 include interest
expense and general and administrative costs related to acquisition, exploration and development of
natural gas and oil properties of $23.2 million, $20.2 million and $21.1 million, respectively.
During the years ended December 2004, 2003 and 2002, we spent $56.7 million, $46.0 million and
$11.0 million, respectively, to develop our proved undeveloped reserves. As of December 31,2004
    
    

    2003
    
    

    2002(in thousands)Property acquisition and leasehold costsUnevaluated
    
    $
    28,059
    
    
    $
    61,224
    
    
    $
    14,600Proved
    
    
    179,281
    
    
    
    170,272
    
    
    
    89,873Exploration costs
    
    
    63,646
    
    
    
    66,259
    
    
    
    26,563Development costs
    
    
    245,971
    
    
    
    162,235
    
    
    
    122,036516,957
    
    
    
    459,990
    
    
    
    253,072Asset retirement obligations costs  assumed (1)
    
    
    12,116
    
    
    
    31,652Asset retirement obligations costs  properties sold (1)
    
    
    (12,714
    )
    
    
    
    
    
    
    Asset retirement expenditures(1)
    
    
    (2,362
    )
    
    
    
    
    
    
    Total costs incurred
    
    $
    513,997
    
    
    $
    491,642
    
    
    $
    253,072
   (1)
    
    Asset retirement obligation costs reflect abandonment obligations assumed during
the year and revisions to prior estimates. As a result of the disposition of our South
Louisiana and Appalachian Basin assets during 2004, asset retirement obligations were reduced
by $12.7 million. Actual retirement expenditures reflect plugging and abandonment costs
during the year. For 2003, our presentation of asset retirement obligation costs incurred
does not include the cumulative effect of adopting SFAS 143 Asset Retirement Obligations on
January 1, 2003 of $42.5 million (see Note 1  Summary of Organization and Accounting
Policies - Asset Retirement Obligations). F-33




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil
Reserves The following summarizes the policies we used 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 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 the information in a manner comparable with industry peers. The information is based on estimates of proved reserves attributable to our interest in natural
gas and oil properties as of December 31 of the years presented. These estimates were 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 our proved reserves to the year-end quantities of those reserves.3.
    The future cash flows are reduced by estimated production costs, costs to develop and
produce the proved reserves and abandonment costs, all based on year-end economic
conditions.4.
    Future income tax expenses are based on year-end statutory tax rates giving effect to
the remaining tax basis in the natural gas and oil properties, other deductions, credits
and allowances relating to our proved natural gas and oil reserves.5.
    Future net cash flows are discounted to present value by applying a discount rate of
10%. The standardized measure of discounted future net cash flows does not purport, nor should it be
interpreted, to present the fair value of our 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 and does not include cash flows associated with hedges outstanding at each
of the respective reporting dates. As of December 31,2004
    
    

    2003
    
    

    2002(in thousands)Future cash inflows
    
    $
    4,558,560
    
    
    $
    4,335,669
    
    
    $
    2,845,768Future production costs
    
    
    (812,800
    )
    
    
    (764,373
    )
    
    
    (486,399
    )Future development costs
    
    
    (545,192
    )
    
    
    (369,121
    )
    
    
    (241,876
    )Future income taxes
    
    
    (976,611
    )
    
    
    (850,264
    )
    
    
    (542,782
    )Future net cash flows
    
    
    2,223,957
    
    
    
    2,351,911
    
    
    
    1,574,71110% annual discount for estimated timing of cash flows
    
    
    (783,902
    )
    
    
    (847,505
    )
    
    
    (516,647
    )Standardized measure of discounted future net cash flows
    
    $
    1,440,055
    
    
    $
    1,504,406
    
    
    $
    1,058,064
 At December 31, 2004, our Standardized Measure of Discounted Future Net Cash Flows includes
estimated future development costs for our proved undeveloped reserves for the next three years of
$229.7 million, $127.7 million, and $9.5 million, respectively, for 2005, 2006 and 2007. Present Value of Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves The present value of future
net cash flows attributable to estimated net proved reserves, discounted
at 10% per annum, (PV10) is a computation of the Standardized Measure of Discounted Future Net
Cash Flows on a pre-tax basis. The table below provides a reconciliation of PV10 to the
Standardized Measure of Discounted Future Net Cash Flows. PV10 may be considered a non-GAAP
financial measure as defined by the SECs Regulation G. We consider PV10 to be an important F-34




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS measure for evaluating the relative significance of our natural gas and oil properties. PV10 is
computed on the same basis as the Standardized Measure of Discounted Future Net Cash Flows but
without deducting income taxes. We believe investors and creditors may utilize our PV10 as a basis
for comparison of the relative size and value of our reserves to other companies. However, PV10 is
not a substitute for the standardized measure. Our PV10 measure and the Standardized Measure of
Discounted Future Net Cash Flows do not purport to present the fair value of our natural gas and
oil reserves. As of December 31,2004
    
    
    2003
    
    
    2002(in thousands)Net present value of future cash flows, before income taxes
    
    $
    2,071,976
    
    
    $
    2,056,414
    
    
    $
    1,364,921Future income taxes, discounted at 10%
    
    
    (631,921
    )
    
    
    (552,008
    )
    
    
    (306,857
    )Standardized measure of discounted future net cash flows
    
    $
    1,440,055
    
    
    $
    1,504,406
    
    
    $
    1,058,064
 The following table summarizes changes in the standardized measure of discounted future net cash
flows. As of December 31,2004
    
    
    2003
    
    
    2002(in thousands)Beginning of the year
    
    $
    1,504,406
    
    
    $
    1,058,064
    
    
    $
    551,525Revisions to previous estimates:Revisions in quantities
    
    
    (59,549
    )
    
    
    (123,954
    )
    
    
    (36,368
    )Changes in prices
    
    
    (34,170
    )
    
    
    459,373
    
    
    
    629,542Changes in future development costs
    
    
    (35,056
    )
    
    
    (13,029
    )
    
    
    (1,970
    )Development costs incurred during the period
    
    
    85,439
    
    
    
    72,717
    
    
    
    23,393Extensions and discoveries, net of related costs
    
    
    445,908
    
    
    
    434,311
    
    
    
    242,055Sales of natural gas and oil, net of production costs
    
    
    (639,555
    )
    
    
    (486,382
    )
    
    
    (275,157
    )Accretion of discount
    
    
    205,641
    
    
    
    136,492
    
    
    
    64,858Net change in income taxes
    
    
    (79,913
    )
    
    
    (245,151
    )
    
    
    (209,807
    )Purchase of reserves in place
    
    
    247,671
    
    
    
    254,030
    
    
    
    99,741Sale of reserves in place
    
    
    (110,877
    )
    
    
    
    
    
    
    (170
    )Production timing and other
    
    
    (89,890
    )
    
    
    (42,065
    )
    
    
    (29,578
    )End of year
    
    $
    1,440,055
    
    
    $
    1,504,406
    
    
    $
    1,058,064
 F-35




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Estimated Net Quantities of Natural Gas and Oil Reserves The following table sets forth our proved reserves, including changes, and proved developed
reserves (all within the United States) at the end of each of the three years in the period ended
December 31, 2004, 2003 and 2002. Natural Gas  (MMcf)
    
    Crude Oil, Liquids and Condensate (MBbls)2004
    
    
    2003
    
    
    2002
    
    
    2004
    
    
    2003
    
    
    2002Beginning of the year reserves
    
    
    709,883
    
    
    
    610,409
    
    
    
    568,208
    
    
    
    7,481
    
    
    
    6,533
    
    
    
    6,605Revisions of previous estimates
    
    
    (13,232
    )
    
    
    (30,573
    )
    
    
    (14,863
    )
    
    
    (1,110
    )
    
    
    (1,615
    )
    
    
    (26
    )Extensions and discoveries
    
    
    162,719
    
    
    
    140,632
    
    
    
    105,798
    
    
    
    255
    
    
    
    117
    
    
    
    342Production
    
    
    (115,855
    )
    
    
    (99,965
    )
    
    
    (97,368
    )
    
    
    (1,355
    )
    
    
    (1,307
    )
    
    
    (859
    )Purchase of reserves in place
    
    
    67,806
    
    
    
    89,380
    
    
    
    48,777
    
    
    
    2,245
    
    
    
    3,753
    
    
    
    483Sales of reserves in place
    
    
    (62,207
    )
    
    
    
    
    
    
    (143
    )
    
    
    (181
    )
    
    
    
    
    
    
    (12
    )End of year reserves
    
    
    749,114
    
    
    
    709,883
    
    
    
    610,409
    
    
    
    7,335
    
    
    
    7,481
    
    
    
    6,533Proved developed reserves:Beginning of year
    
    
    487,867
    
    
    
    435,629
    
    
    
    438,538
    
    
    
    4,073
    
    
    
    2,413
    
    
    
    2,123End of year
    
    
    475,080
    
    
    
    487,867
    
    
    
    435,629
    
    
    
    3,535
    
    
    
    4,073
    
    
    
    2,413
 Natural Gas Equivalents (MMcfe)2004
    
    
    2003
    
    
    2002Beginning of year reserves
    
    
    754,769
    
    
    
    649,607
    
    
    
    607,838Revisions of previous estimates
    
    
    (19,892
    )
    
    
    (40,263
    )
    
    
    (15,019
    )Extensions and discoveries
    
    
    164,249
    
    
    
    141,334
    
    
    
    107,850Production
    
    
    (123,985
    )
    
    
    (107,807
    )
    
    
    (102,522
    )Purchase of reserves in place
    
    
    81,276
    
    
    
    111,898
    
    
    
    51,675Sales of reserves in place
    
    
    (63,293
    )
    
    
    
    
    
    
    (215
    )End of year reserves
    
    
    793,124
    
    
    
    754,769
    
    
    
    649,607Proved developed reserves:Beginning of year
    
    
    512,305
    
    
    
    450,107
    
    
    
    451,276End of year
    
    
    496,290
    
    
    
    512,305
    
    
    
    450,107
 F-36




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
 NOTE 13 Quarterly Financial Information (Unaudited) The following represents our unaudited quarterly results for years ended December 31, 2004 and
2003. There quarterly results were prepared in accordance with GAAP and reflect all adjustments
that are, in the opinion of management, necessary for a fair statement of the results. These
adjustments are of a normal recurring nature. 1st Quarter
    
    
    2nd Quarter
    
    
    3rd Quarter
    
    
    4th Quarter2004Total revenues
    
    $
    151,882
    
    
    $
    172,776
    
    
    $
    162,760
    
    
    $
    163,021Total operating expenses (1)
    
    
    86,839
    
    
    
    97,702
    
    
    
    94,366
    
    
    
    103,719Income from operations
    
    
    65,043
    
    
    
    75,074
    
    
    
    68,394
    
    
    
    59,302Net income
    
    
    39,690
    
    
    
    45,350
    
    
    
    42,998
    
    
    
    34,786Net income per share  basic (2)
    
    $
    1.26
    
    
    $
    1.49
    
    
    $
    1.53
    
    
    $
    1.23Net income per share  diluted (2)
    
    $
    1.25
    
    
    $
    1.47
    
    
    $
    1.51
    
    
    $
    1.212003Total revenues
    
    $
    129,003
    
    
    $
    120,632
    
    
    $
    118,887
    
    
    $
    124,230Total operating expenses
    
    
    68,807
    
    
    
    70,341
    
    
    
    69,856
    
    
    
    85,153Income from operations
    
    
    60,196
    
    
    
    50,291
    
    
    
    49,031
    
    
    
    39,077Income before cumulative effect of change in accounting principle
    
    
    44,469
    
    
    
    28,923
    
    
    
    34,719
    
    
    
    25,701Cumulative effect of change in accounting principle
    
    
    (2,772
    )
    
    
    
    
    
    
    
    
    
    
    Net income
    
    
    41,697
    
    
    
    28,923
    
    
    
    34,719
    
    
    
    25,701Net income per share  basic:Income before cumulative effect of change in accounting principle
    
    $
    1.44
    
    
    $
    0.93
    
    
    $
    1.12
    
    
    $
    0.82Cumulative effect of change in accounting principle
    
    
    (0.09
    )
    
    
    
    
    
    
    
    
    
    
    Net income per share  basic (2)
    
    $
    1.35
    
    
    $
    0.93
    
    
    $
    1.12
    
    
    $
    0.82Net income per share  diluted:Income before cumulative effect of change in accounting principle
    
    $
    1.43
    
    
    $
    0.93
    
    
    $
    1.11
    
    
    $
    0.82Cumulative effect of change in accounting principle
    
    
    (0.09
    )
    
    
    
    
    
    
    
    
    
    
    Net income per share  diluted (2)
    
    $
    1.34
    
    
    $
    0.93
    
    
    $
    1.11
    
    
    $
    0.82
   (1)
    
    As a result of management organizational changes made within our company in November
2004, we recognized additional general and administrative expense of $5.1 million during the
fourth quarter of 2004. The additional compensation expenses were a result of lump-sum
severance payments and entitlements under executive employment agreements, including expenses
related to the accelerated vesting of stock options and restricted stock. See Note 11 
Subsequent Events  Termination of Employment Agreements.(2)
    
    Quarterly earnings per share is based on the weighted average number of shares
outstanding during the quarter. Because of changes in the number of shares outstanding during
the quarters due to the exercise of stock options and/or the issuance or repurchase of common
stock, the sum of quarterly earnings per share may not equal earnings per share for the year. F-37




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##### Table of Contents



INDEX TO EXHIBITS EXHIBITS
    
    
    
    DESCRIPTION3.1
    
    
    
    Restated Certificate of Incorporation (filed
as Exhibit 3.1 to our Quarterly Report on
Form 10-Q for the quarterly period ended June
30, 1997 (File No. 001-11899) and
incorporated by reference).3.2
    
    
    
    Restated Bylaws (filed as Exhibit 3.2 to our
Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 1997 (File
No. 001-11899) and incorporated by
reference).4.1
    
    
    
    Indenture, dated as of June 10, 2003, between
The Houston Exploration Company and the Bank
of New York, as Trustee, with respect to the
7% Senior Subordinated Notes due 2013 (filed
as Exhibit 4.2 to our Registration Statement
on Form S-4 (Registration No. 333-106836) and
incorporated by reference).10.1
    
    
    
    Rights Agreement, dated as of August 12,
2004, between The Houston Exploration Company
and The Bank of New York, as Rights Agent
(filed as Exhibit 4.1 to our Current Report
on Form 8-K dated August 13, 2004 (File No.
001-11899) and incorporated by reference).10.2
    
    
    
    Registration Rights Agreement dated as of
June 5, 2003, among The Houston Exploration
Company and Wachovia Securities, Inc., Lehman
Brothers Inc., BNP Paribas Securities Corp.,
Fleet Securities, Inc. and Scotia Capital
(USA) Inc., as Initial Purchasers (filed as
Exhibit 4.5 to our Registration Statement on
Form S-4 (Registration No. 333-106836) and
incorporated by reference).10.3
    
    
    
    Amended and Restated Registration Rights
Agreement dated as of June 2, 2004 between
The Houston Exploration Company and THEC
Holdings Corp. (filed as Exhibit 99.6 to our
Current Report on Form 8-K dated June 30,
2004 (File No. 001-11899) and incorporated by
reference).10.4
    
    
    
    Form of Certificate of Designation of Series
A Junior Participation Preferred Stock of The
Houston Exploration Company (filed as Exhibit
4.2 to our Current Report on Form 8-K dated
August 13, 2004 (File No. 001-11899) and
incorporated by reference).10.5
    
    
    
    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 our Quarterly
Report on Form 10-Q for the quarter ended
March 31, 1999 (File No. 001-11899) and
incorporated by reference).10.6
    
    
    
    First Amendment to the Exploration Agreement
between The Houston Exploration Company and
KeySpan Exploration and Production, L.L.C.
dated November 3, 1999 (filed as Exhibit
10.19 to our Annual Report on Form 10-K for
the year ended December 31, 1999 (File No.
001-11899) and incorporated by reference).10.7
    
    
    
    Restated Exploration Agreement dated June 30,
2000 between The Houston Exploration Company
and KeySpan Exploration and Production, L.L.C
(filed as Exhibit 10.1 to our Quarterly
Report on Form 10-Q for the quarter ended
September 30, 2000 (File No. 001-11899) and
incorporated by reference).10.8(2)
    
    
    
    Supplemental Executive Pension Plan (filed as
Exhibit 10.23 to our Registration Statement
on Form S-1 (Registration No. 333-4437) and
incorporated by reference).10.9(2)
    
    
    
    Deferred Compensation Plan for Non-Employee
Directors (filed as Exhibit 10.24 to our
Annual Report on Form 10-K for the year ended
December 31, 1997 (File No. 001-11899) and
incorporated by reference).10.10(2)
    
    
    
    Amended and Restated 1996 Stock Option Plan
(filed as Exhibit 10.1 to our Quarterly
Report on Form 10-Q for the quarter ended
June 30, 1998 (File No. 001-11899) and
incorporated by reference).10.11(2)
    
    
    
    1999 Non-Qualified Stock Option Plan dated
October 26, 1999 (filed as Exhibit 10.24 to
our Annual Report on Form 10-K for the year
ended December 31, 1999 (File No. 001-11899)
and incorporated by reference).




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##### Table of Contents



INDEX TO EXHIBITS EXHIBITS
    
    
    
    DESCRIPTION10.12(2)
    
    
    
    Executive Deferred Compensation Plan
dated January 1, 2002 (filed as Exhibit
10.28 to our Annual Report on Form 10-K
for the year ended December 31, 2002
(File No. 001-11899) and incorporated by
reference).10.13(2)
    
    
    
    Amended and Restated 2002 Long-Term
Incentive Plan effective May 17, 2002,
adopted October 26, 2003 (filed as
Exhibit 10.31 to our Annual Report on
Form 10-K for the year ended December
31, 2003 (file No. 001-11899) and
incorporated by reference).10.14(2)
    
    
    
    2004 Long Term Incentive Plan approved
by vote of stockholders on June 3, 2004
(filed as Appendix E to our Definitive
Proxy Statement on Schedule 14 A dated
June 3, 2004 (File No. 001-11899) and
incorporated by reference).10.16(2)
    
    
    
    Employment Agreement dated July 16, 2001
between The Houston Exploration Company
and Tracy Price (filed as Exhibit 10.1
to our Quarterly Report on Form 10-Q for
the quarter ended September 30, 2001
(File No. 001-11899) and incorporated by
reference).10.17(2)
    
    
    
    Employment Agreement dated September 29,
2003 between The Houston Exploration
Company and Timothy R. Lindsey (filed as
Exhibit 10.3 to our Quarterly Report on
Form 10-Q for the quarter ended
September 30, 2003 (File No. 001-11899)
and incorporated by reference).10.18(2)
    
    
    
    Amended and Restated Employment
Agreement dated February 8, 2005 between
The Houston Exploration Company and
William G. Hargett (filed as Exhibit
10.1 to our Current Report on Form 8-K
dated February 8, 2005 (File No.
001-11899) and incorporated by
reference).10.19(1)(2)
    
    
    
    Amended and Restated Employment
Agreement between The Houston
Exploration Company and Steven L.
Mueller dated February 8, 2005.10.20(1)(2)
    
    
    
    Amended and Restated Employment
Agreement between The Houston
Exploration Company and John H. Karnes
February 8, 2005.10.21(1)(2)
    
    
    
    Amended and Restated Employment
Agreement between The Houston
Exploration Company and James F.
Westmoreland dated February 8, 2005.10.22(1)(2)
    
    
    
    Amended and Restated Employment
Agreement between The Houston
Exploration Company and Roger B. Rice
dated February 8, 2005.10.23(2)
    
    
    
    Employment Agreement dated February 10,
2005 between The Houston Exploration
Company and Joanne C. Hresko (filed as
Exhibit 10.3 to our Current Report on
Form 8-K dated February 8, 2005 (File
No. 001-11899) and incorporated by
reference).10.24(2)
    
    
    
    Change of Control Plan dated October 26,
1999 (filed as Exhibit 10.25 to our
Annual Report on Form 10-K for the year
ended December 31, 1999 (File No.
001-11899) and incorporated by
reference).10.25
    
    
    
    Amended and Restated Credit Agreement
dated April 1, 2004 among The Houston
Exploration Company and Wachovia Bank,
National Association, as Issuing Bank
and Administrative Agent; The Bank of
Nova Scotia and Fleet National Bank as
Co-Syndication Agents; and BNP Paribas
and Comerica Bank as Co-Documentation
Agents (filed as Exhibit 10.1 to our
Quarterly Report on Form 10-Q for the
quarter ended March 31, 2004 (File No.
001-11899) and incorporated by
reference).10.26
    
    
    
    First Amendment dated May 26, 2004 to
the Amended and Restated Credit
Agreement dated April 1, 2004 among The
Houston Exploration Company and Wachovia
Bank, National Association, as Issuing
Bank and Administrative Agent; The Bank
of Nova Scotia and Fleet National Bank
as Co-Syndication Agents; and BNP
Paribas and Comerica Bank as
Co-Documentation Agents dated June 2,
2004 (filed as Exhibit 10.1 to our
Quarterly Report on Form 10-Q for the
quarter ended June 30, 2004 (File No.
001-11899) and incorporated by
reference).




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##### Table of Contents



INDEX TO EXHIBITS EXHIBITS
    
    
    
    DESCRIPTION10.27
    
    
    
    Purchase and Sale Agreement, dated September 3, 2003, by and among Transworld Exploration and
Production, Inc., as Seller, and The Houston Exploration Company, as Buyer (Exhibit 2.1 to
Current Report on Form 8-K dated October 15, 2003 (file No. 001-11899) and incorporated by
reference).10.28
    
    
    
    Purchase and Sale Agreement, dated September 17, 2004, between The Houston Exploration Company
and Orca Energy, L.P. (filed as Exhibit 2.1 to our Current Report on Form 8-K dated November 1,
2004 (File No. 001-11899) and incorporated by reference).10.29
    
    
    
    Distribution Agreement dated as of June 2, 2004 by and among The Houston Exploration Company,
Seneca-Upshur Petroleum, Inc., THEC Holdings Corp. and KeySpan Corporation (filed as Exhibit
99.2 to our Current Report on Form 8-K dated June 30, 2004 (File No. 001-11899) and
incorporated by reference).10.30
    
    
    
    Asset Contribution Agreement dated June 2, 2004 between The Houston Exploration Company and
Seneca-Upshur Petroleum, Inc. (filed as Exhibit 99.3 to our Current Report on Form 8-K dated
June 30, 2004 (File No. 001-11899) and incorporated by reference).10.31
    
    
    
    Tax Matters Agreement dated as of June 2, 2004 by and among The Houston Exploration Company,
Seneca-Upshur Petroleum, Inc., THEC Holdings Corp., and KeySpan Corporation (filed as Exhibit
99.4 to our Current Report on Form 8-K dated June 30, 2004 (File No. 001-11899) and
incorporated by reference).10.32
    
    
    
    Transition Service Agreement dated June 2, 2004 between The Houston Exploration Company and
Seneca-Upshur Petroleum, Inc. (filed as Exhibit 99.4 to our Current Report on Form 8-K dated
June 30, 2004 (File No. 001-11899) and incorporated by reference).10.33(2)
    
    
    
    Form of waiver to employment agreement between The Houston Exploration Company and its
executive officers allowing restricted stock awards in addition to stock option awards (filed
as Exhibit 10.4 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2004
(File No. 001-11899) and incorporated by reference).10.34(1)(2)
    
    
    
    Compensation table for Officers and Directors.12.1(1)
    
    
    
    Computation of ratio of earnings to fixed charges.23.1(1)
    
    
    
    Consent of Deloitte & Touche LLP.23.2(1)
    
    
    
    Consent of Netherland, Sewell & Associates.23.3(1)
    
    
    
    Consent of Miller and Lents.31.1(1)
    
    
    
    Certification of William G. Hargett, Chief Executive Officer, as required pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.31.2(1)
    
    
    
    Certification of John H. Karnes, Chief Financial Officer, as required pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.32.1(1)
    
    
    
    Certification of William G. Hargett, Chief Executive Officer, as required pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.32.2(1)
    
    
    
    Certification of John H. Karnes, Chief Financial Officer, as required pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
   (1)
    
    Filed herewith.(2)
    
    Management contract or compensation plan.