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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10-K

|  |  |                                                 
|- |  | ------------------------------------------------
|þ |  | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
|  |  | THE SECURITIES EXCHANGE ACT OF 1934             

For the fiscal year ended December 31, 2003

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                                 |  | 22-2674487         
|(State or other jurisdiction of          |  | (IRS Employer      
|Incorporation or organization)           |  | Identification No.)
|                                         |  |                    
|1100 Louisiana, Suite 2000               |  |                    
|Houston, Texas                           |  | 77002-5215         
|(Address of principal executive Offices) |  | (Zip code)         

(713) 830-6800
(Registrants telephone number, including area code)




Securities Registered Pursuant to Section 12(b) of the Act:

|                                      |  |                             
|------------------------------------- |  | ----------------------------
|                                      |  | Name of Each                
|Title of Each Class                   |  | Exchange on Which Registered
|                                      |  |                             
|Common Stock, $.01 par value          |  | New York Stock Exchange     
|7% 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 Regulations S-K is not contained herein, and will not be contained, to the
best of registrants knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. 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 $499,877,963, based on the closing sales price of
$34.70 per share of the registrants common stock as reported by on the New
York Stock Exchange as of June 30, 2003, 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 March 11, 2004, 31,786,097 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 June 3, 2004 are incorporated by reference into Part
III of this Form 10-K.



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TABLE OF CONTENTS



|                                                  |                                                                                               |  |  |  |  |  |  | 
|------------------------------------------------- | --------------------------------------------------------------------------------------------- |  |  |  |  |  |  | 
|Part I                                           
|                                                  | Items 1. and 2. Business and Properties                                                      
|                                                  | Item 2. Properties                                                                           
|                                                  | Item 3. Legal Proceedings                                                                    
|                                                  | Item 4. Submission of Matters to a Vote of Security Holders                                  
|                                                  | Item 5. Market for the Registrants Common Equity and Related Stockholder Matters            
|Part II.                                         
|                                                  | Item 6. Selected Financial Data                                                              
|                                                  | Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
|                                                  | Item 7A. Quantitative and Qualitative Disclosures About Market Risk                          
|                                                  | Item 8. Financial Statements                                                                 
|                                                  | Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 
|                                                  | Item 9A. Controls and Procedures                                                             
|Part III                                         
|                                                  | Item 10. Directors and Executive Officers of Houston Exploration                             
|                                                  | Item 11. Executive Compensation                                                              
|                                                  | Item 12. Security Ownership of Beneficial Owners and Management                              
|                                                  | Item 13. Certain Relationships and Related Transactions                                      
|                                                  | Item 14. Principal Accounting Fees and Services                                              
|Part IV                                          
|                                                  | Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K                     
|SIGNATURES                                       
|Glossary of Oil and Gas Terms                    
|Index to Financial Statements                    
|INDEPENDENT AUDITORS REPORT                     
|CONSOLIDATED BALANCE SHEETS                      
|CONSOLIDATED STATEMENTS OF OPERATIONS            
|CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY  
|CONSOLIDATED STATEMENTS OF CASH FLOWS            
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS       
|INDEX TO EXHIBITS                                
|Amended 2002 Long-Term Incentive Plan            
|Computation of Ratio of Earnings to Fixed Charges
|Subsidiary of Houston Exploration                
|Consent of Deloitte & Touche LLP                 
|Consent of Netherland, Sewell & Associates       
|Consent of Miller and Lents                      
|Certification of CEO Pursuant Section 302        
|Certification of CFO Pursuant Section 302        
|Certification of CEO Pursuant Section 906        
|Certification of CFO Pursuant Section 906        



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TABLE OF CONTENTS

|                                                                                              |  |  |     | 
|--------------------------------------------------------------------------------------------- |  |  | --- | 
|Part I                                                                                        |  |  | 2   | 
|Items 1. and 2. Business and Properties                                                       |  |  | 2   | 
|Item 3. Legal Proceedings                                                                     |  |  | 17  | 
|Item 4. Submission of Matters to a Vote of Security Holders                                   |  |  | 17  | 
|Part II                                                                                       |  |  | 18  | 
|Item 5. Market for the Registrants Common Equity and Related Stockholder Matters             |  |  | 18  | 
|Item 6. Selected Financial Data                                                               |  |  | 19  | 
|Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations |  |  | 21  | 
|Item 7A. Quantitative and Qualitative Disclosures About Market Risk                           |  |  | 36  | 
|Item 8. Financial Statements                                                                  |  |  | 38  | 
|Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure  |  |  | 38  | 
|Item 9A. Controls and Procedures                                                              |  |  | 38  | 
|Part III                                                                                      |  |  | 38  | 
|Item 10. Directors and Executive Officers of the Registrant                                   |  |  | 38  | 
|Item 11. Executive Compensation                                                               |  |  | 38  | 
|Item 12. Security Ownership of Beneficial Owners and Management                               |  |  | 38  | 
|Item 13. Certain Relationships and Related Transactions                                       |  |  | 38  | 
|Item 14. Principal Accounting Fees and Services                                               |  |  | 39  | 
|Part IV                                                                                       |  |  | 39  | 
|Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K                      |  |  | 39  | 
|Signatures                                                                                    |  |  | 40  | 
|Glossary of Natural Gas and Oil Terms                                                         |  |  | G-1 | 
|Index to Financial Statements                                                                 |  |  | F-1 | 

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Forward-Looking Statements

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 and
Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). In some cases,
these forward-looking statements generally can be identified by words such as
anticipate, believe, continue, expect, estimate, intend, may,
plan, potential, predict, project, should, target, goal,
objective or similar expressions. All statements under the caption Item 7.
Managements Discussion and Analysis of Financial Condition and Results of
Operations relating to our anticipated capital expenditures, future production
and reserves, schedules, plans, timing of development, future cash flows and
borrowings, pursuit of potential future acquisition opportunities and sources
of funding for exploration and development are forward-looking statements.
Although we believe that these forward-looking statements are based on
reasonable estimates and assumptions, our expectations may not occur and we
cannot guarantee that the anticipated future results will be realized. 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 write downs if natural gas and oil prices
decline, our ability to meet our substantial capital requirements, our
substantial outstanding indebtedness, the uncertainty of estimates of natural
gas and oil reserves and production rates, our ability to replace reserves, and
our hedging activities. 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 its
sole subsidiary on a consolidated basis.

If you are not familiar with the natural gas and oil terms used in this 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.




Part I.

Items 1. and 2. Business and Properties




Overview of Our Business

We are an independent natural gas and oil company engaged in the exploration,
development, exploitation and acquisition of natural gas and oil reserves in
North America. Natural gas is our primary focus. 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 Appalachian Basin of West
Virginia. During 2003, we began operations in the Rocky Mountain Region with
an initial focus in the Uinta Basin of northeastern Utah.

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.
As of December 31, 2003, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 55% of the outstanding shares of our
common stock.

In February 2003, KeySpan divested three million shares of our common stock.
KeySpan has publicly announced it does not consider its investment in Houston
Exploration a part of its core asset group and that it may sell or dispose of
all or a portion of its non-core assets, including its investment in our
company. Because market conditions are unpredictable, KeySpan is unable to
determine if or when any additional dispositions of all or a portion of its
remaining ownership interest in our company will take place.

Our corporate offices are located at 1100 Louisiana Street, Suite 2000,
Houston, Texas 77002. Our telephone number is (713) 830-6800.

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Investment Strategy

We strive to maximize shareholder value while maintaining our financial
flexibility by pursuing an investment strategy involving elements of each of
the following activities:



| |  | Exploitation. Exploitation, both onshore and offshore, is one of our
core competencies and the cornerstone of our investment strategy. We
invest in exploitation and development properties intended to generate
stable and growing cash flows from which we can fund future expansion
of our business and reserve base.                                 
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| 
| |  | Exploration. Founded as an exploration company, we continue to invest
in exploratory prospects to supplement the reserves added through our
exploitation activities. We generate the majority of our exploration
prospects through our in-house geo-science personnel and currently
have assembled a three-year inventory of offshore drilling prospects.
| 
| |  | Acquisitions. We augment our exploration and exploitation activities
with acquisitions of new properties that we believe conform to our
operating philosophy and offer unexploited reserve potential.                                                                                                                                                    

We typically fund exploitation and exploration activities out of cash flows
from operations. We typically fund acquisitions through our revolving bank
credit facility. When we incur debt in connection with an acquisition, we
focus on prompt repayment in order to minimize our debt service obligations.
Our current debt levels provide 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.

Operating Philosophy



| |  | Natural Gas Emphasis. Our production and reserve base is heavily
weighted toward natural gas. We have focused our growth and operations in
the United States. There is intense competition for the acquisition and
development of domestic reserves. Since natural gas can only be
transported from overseas in liquefied form and is thus more difficult to
import than crude oil, we believe natural gas is better insulated from the
price volatility associated with global geopolitical instability. The
lease operating expense associated with natural gas properties is also
typically less than oil properties, which allows us to maintain our low
per-unit cost structure.                                     
|- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| 
| |  | Operating Control. Whenever possible, we prefer to operate our
properties because this allows us more control over the nature and timing of
capital expenditures and overall operating expenses. As operator, we
supervise production, maintain production records, employ or contract for
field personnel, distribute revenues and perform other functions. As
operator, we receive reimbursement for direct expenses incurred, as well
as monthly per-well producing and drilling overhead reimbursements at
rates customarily charged in the area by unaffiliated third parties. We
currently operate approximately 85% of our wells.                                                                                  
| 
| |  | Geographic Focus. By concentrating our operations within geographically
focused areas, we can manage a large asset base with a relatively small
number of employees and can integrate additional properties at relatively
low incremental costs. Our strategy of focusing drilling activities on
properties in relatively concentrated offshore and onshore areas permits
us to more efficiently utilize our base of geological, engineering,
exploration and production experience in these regions. At December 31,
2003, 90% of our reserves were located in our three core areas: South
Texas, the Gulf of Mexico and the Arkoma Basin. Future growth
opportunities may likely require the addition of new core areas.
| 
| |  | Operating Environment. We focus our operations in areas that are
conducive to low cost operations, avoiding areas where fractionalized
ownership issues, local regulation or lack of a qualified workforce would
drive up operational, legal and other costs.                                                                                                                                                                                                                                                                                                                                                                                                                                                             
| 
| |  | Cash Flow Hedging. We maintain an active hedging program designed to
reduce the impact of commodity price fluctuations and provide more
predictable cash flows that allow us to better plan our capital
expenditures. We utilize a variety of hedging strategies, including fixed
price swaps, options and collars under which we are assured a minimum
floor price for our production and the benefit of price increases up to a
predetermined ceiling price. Depending on the outlook for future prices
and the state of the derivatives markets, we may hedge up to 80% of our
production for 2004 and up to 70% for 2005.                                                                                             

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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, 2003.

|                                                                    |  |            |     |            |  |          |         |              |  |            |         |               |  |         |     |   |  |       |     |  |  |  |     | 
|------------------------------------------------------------------- |  | ---------- | --- | ---------- |  | -------- | ------- | ------------ |  | ---------- | ------- | ------------- |  | ------- | --- | - |  | ----- | --- |  |  |  | --- | 
|Activity and Balances as of or for the Year Ended December 31, 2003
|                                                                   
|                                                                    |  |            |     |            |  |          |         |              |  |            |         |               |  |         |     |   |  | Total
|                                                                    |  | Average    |     |            |  |          |         | Total        |  | Percentage |         | Wells Drilled
|                                                                    |  | Daily      |     | Total      |  | Proved   |         | Total Proved |  |           
|Area                                                                |  | Production |     | Production |  | Reserves |         | Reserves     |  | Total      |         | Successful   
|                                                                    |  |            |     |            |  |          |         |              |  |            |         |              
|                                                                    |  | (MMcfe/d)  |     | (MMcfe)    |  | (MMcfe)  |         |              |  |            |         | (Gross)       |  | (Gross)
|South Texas                                                         |  |            | 140 |            |  |          | 51,137  |              |  |            | 315,437 |               |  |         | 42  | % |  |       | 77  |  |  |  | 56  | 
|Gulf of Mexico                                                      |  |            | 122 |            |  |          | 44,607  |              |  |            | 246,650 |               |  |         | 33  | % |  |       | 17  |  |  |  | 9   | 
|Arkoma Basin                                                        |  |            | 23  |            |  |          | 8,385   |              |  |            | 111,316 |               |  |         | 15  | % |  |       | 51  |  |  |  | 46  | 
|West Virginia                                                       |  |            | 3   |            |  |          | 1,194   |              |  |            | 50,455  |               |  |         | 7   | % |  |       | 2   |  |  |  | 2   | 
|Other onshore                                                       |  |            | 7   |            |  |          | 2,484   |              |  |            | 30,911  |               |  |         | 3   | % |  |       |    |  |  |  |    | 
|                                                                    |  |            |     |            |  |          |         |              |  |            |         |               |  |         |     |   |  |       |     |  |  |  |     | 
|Total                                                               |  |            | 295 |            |  |          | 107,807 |              |  |            | 754,769 |               |  |         | 100 | % |  |       | 147 |  |  |  | 113 | 
|                                                                    |  |            |     |            |  |          |         |              |  |            |         |               |  |         |     |   |  |       |     |  |  |  |     | 

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. In total, our South Texas properties cover approximately 65,000 net
acres and we own interests in 581 producing wells, 476 of which we operate.
Our average working interest is 82%. 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. In December 2001, we expanded our existing production and reserve
base with the acquisition of the Alexander, Hubbard and South Laredo Fields,
and again, in May 2002, with the acquisition of the Northeast Thompsonville
Field. In total, our net South Texas production has more than tripled since
July 1996, to an average of 143 MMcfe per day during December 2003. Over the
course of seven and a half years, we have drilled 228 successful wells at an
average success rate of 82%, produced 241 Bcfe and added 444 Bcfe in reserves
through drilling and acquisitions.

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 South Timbalier 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. Of the proved reserves
acquired, 75% were classified as natural gas and 68% were proved undeveloped.
Taking into account the recent acquisition and as of December 31, 2003, we hold
interests in 127 blocks in federal and state waters, of which 69 are developed.
We operate 32 of our developed blocks, which accounts for approximately 65%
of our offshore production. We have a total of 80 producing
platforms and production caissons of which we operate 49.

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. We have approximately 36,000 net acres under lease and we own
working interests in 275 producing natural gas wells, 170 of which we operate.
Wells average a depth of 5,500 feet and production is from the Atoka formation.
As a result of the downspacing from 640 acres to 160 acres per well approved
by the Arkansas Oil and Gas Commission in September 2002, we were able to more
than double the number of wells drilled during 2003 from 24 wells in 2002 to 51
wells in 2003. By December 2003, our average daily production had increased by
35% from an average of 20 MMcfe per day in 2002 to 27 MMcfe per day, net to our
interest. In September 2003, the Arkansas Oil and Gas Commission approved
further downspacing to 80 acres per well, allowing for continued expansion of
our drilling opportunities.

Appalachian Basin.Our property base is located in central West Virginia and
includes the Belington, Clarksburg and Seneca Upshur Fields located in Barbour,
Randolph, Upshur and Mingo Counties of West Virginia. On December 31,

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2003, we extended our existing reserve base through an acquisition of
additional producing properties. The properties acquired are adjacent to our
existing production base and include 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. We purchased net proved reserves of 23.4 Bcfe for $27.9 million.
Average daily production is estimated at approximately 4 MMcfe per day, net to
our interest. The properties purchased cover approximately 146,000 gross
(83,950 net) acres and include approximately 774 producing wells. In addition,
the interests acquired include approximately 300 wells in which we will have an
overriding royalty interest. Giving effect to the acquisition and as of
December 31, 2003, we have approximately 129,000 net acres under lease and own
working interests in 1,411 wells of which we operate 1,304 or 92%. Our average
working interest is 73%.

Other Onshore.During 2003, we also owned properties in East Texas and South
Louisiana. East Texas properties are located in the Willow Springs Field in
Gregg County, Texas and include interests in 24 wells of which we operate 23.
The South Louisiana properties are located in the South Lake Arthur and Lake
Pagie Fields located primarily in Vermillion and Terrebonne Parishes. On
February 4, 2004 we completed the sale of our 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 net proceeds from the sale of $12.8 million were
used to repay borrowings under our revolving bank credit facility.

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Natural Gas and Oil Reserves

The following table summarizes the estimates of our historical net proved
reserves as of December 31, 2003, 2002 and 2001, 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. and
Miller and Lents, Ltd., independent petroleum engineering consultants.

|                                                            |  |                    |           |      |  |                |           |  |  |   |         | 
|----------------------------------------------------------- |  | ------------------ | --------- | ---- |  | -------------- | --------- |  |  | - | ------- | 
|                                                            |  | As of December 31,
|                                                            |  |                   
|Net Proved Reserves:                                        |  | 2003               |           | 2002 |  | 2001          
|                                                            |  |                    |           |      |  |               
|                                                            |  |                    |           |      |  | (in thousands) |           |  |  |  
|Natural gas (MMcf)                                          |  |                    | 709,883   |      |  |                | 610,409   |  |  |   | 568,208 | 
|Oil and natural gas liquids (MBbls)                         |  |                    | 7,481     |      |  |                | 6,533     |  |  |   | 6,605   | 
|Total (MMcfe)                                               |  |                    | 754,769   |      |  |                | 649,607   |  |  |   | 607,838 | 
|Present value of future net revenues before income taxes(1) |  | $                  | 1,955,197 |      |  | $              | 1,326,314 |  |  | $ | 714,416 | 
|Standardized measure of discounted future net cash flows(2) |  | $                  | 1,504,406 |      |  | $              | 1,058,064 |  |  | $ | 551,525 | 



| | (1) |  | The present value of future net revenues attributable to our reserves
was prepared using prices in effect at the end of the respective periods
presented, discounted at 10% per annum (PV10) on a pre-tax basis. In
accordance with current Securities and Exchange Commission (SEC)
guidelines, the PV10 includes the fair value of our natural gas and oil
hedges in place at December 31, 2003, 2002 and 2001 of a negative $101.2
million, a negative $38.6 million and a positive $65.8 million,
respectively. Year-end prices per Mcf of natural gas used in making the
present value determinations as of December 31, 2003, 2002 and 2001 were
$ 5.79, $4.35 and $2.38, respectively. Year-end prices per Bbl of oil
used in making the present value determinations as of December 31, 2003,
2002 and 2001 were $30.27, $28.74 and $17.78, respectively.
| | --- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| | (2) |  | The standardized measure of discounted future net cash flows
represents the PV10 after income tax and 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 inflows from our hedging program.                                                                                                                                                                                                                                                                                                                                                                                                   

In accordance with applicable requirements of the SEC, we estimate our net
proved reserves and future net revenues using sales prices estimated to be in
effect as of the date we make the reserve estimates. We hold the estimates
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 on Form 10-K represent only
estimates. Reservoir engineering is a subjective process of estimating
underground accumulations of natural gas and oil that cannot be measured in an
exact manner. The accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and
judgment. As a result, estimates 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.

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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
during the year ended December 31, 2003. 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.

|                    |                   |  |                                      |     |                    |  |               |      |     |  |       |    |     |  |      |      |  |  |     |     |  |  |       |       | 
|------------------- | ----------------- |  | ------------------------------------ | --- | ------------------ |  | ------------- | ---- | --- |  | ----- | -- | --- |  | ---- | ---- |  |  | --- | --- |  |  | ----- | ----- | 
|                    |                   |  | For the Year Ended December 31, 2003
|                    |                   |  |                                     
|                    |                   |  | Successful - Productive              |     | Unsuccessful - Dry |  | Total Drilled
|                    |                   |  |                                      |     |                    |  |              
|                    |                   |  | Gross                                |     | Net                |  | Gross         |      | Net |  | Gross |    | Net
|                    |                   |  |                                      |     |                    |  |               |      |     |  |       |    |    
|Exploratory:        |                   |  |                                      |     |                    |  |               |      |     |  |       |    |     |  |      |      |  |  |     |     |  |  |       |      
|South Texas         |                   |  | 3                                    |     |                    |  | 3.0           |      |     |  | 3     |    |     |  | 3.0  |      |  |  | 6   |     |  |  | 6.0   |      
|Gulf of Mexico      |                   |  | 6                                    |     |                    |  | 2.4           |      |     |  | 8     |    |     |  | 3.6  |      |  |  | 14  |     |  |  | 6.0   |      
|Arkoma              |                   |  |                                     |     |                    |  |              |      |     |  | 1     |    |     |  | 0.4  |      |  |  | 1   |     |  |  | 0.4   |      
|                    |                   |  |                                      |     |                    |  |               |      |     |  |       |    |     |  |      |      |  |  |     |     |  |  |       |      
|                    | Total exploratory |  |                                      | 9   |                    |  |               | 5.4  |     |  |       | 12 |     |  |      | 7.0  |  |  |     | 21  |  |  |       | 12.4  | 
|                    |                   |  |                                      |     |                    |  |               |      |     |  |       |    |     |  |      |      |  |  |     |     |  |  |       |       | 
|Development:        |                   |  |                                      |     |                    |  |               |      |     |  |       |    |     |  |      |      |  |  |     |     |  |  |       |      
|South Texas         |                   |  | 53                                   |     |                    |  | 51.3          |      |     |  | 18    |    |     |  | 17.5 |      |  |  | 71  |     |  |  | 68.8  |      
|Gulf of Mexico      |                   |  | 3                                    |     |                    |  | 2.0           |      |     |  |      |    |     |  |     |      |  |  | 3   |     |  |  | 2.0   |      
|Arkoma              |                   |  | 46                                   |     |                    |  | 28.6          |      |     |  | 4     |    |     |  | 2.5  |      |  |  | 50  |     |  |  | 31.1  |      
|West Virginia       |                   |  | 2                                    |     |                    |  | 2.0           |      |     |  |      |    |     |  |     |      |  |  | 2   |     |  |  | 2.0   |      
|Other onshore       |                   |  |                                     |     |                    |  |              |      |     |  |      |    |     |  |     |      |  |  |    |     |  |  |      |      
|                    |                   |  |                                      |     |                    |  |               |      |     |  |       |    |     |  |      |      |  |  |     |     |  |  |       |      
|                    | Total development |  |                                      | 104 |                    |  |               | 83.9 |     |  |       | 22 |     |  |      | 20.0 |  |  |     | 126 |  |  |       | 103.9 | 
|                    |                   |  |                                      |     |                    |  |               |      |     |  |       |    |     |  |      |      |  |  |     |     |  |  |       |       | 
|Total wells drilled |                   |  | 113                                  |     |                    |  | 89.3          |      |     |  | 34    |    |     |  | 27.0 |      |  |  | 147 |     |  |  | 116.3 |      
|                    |                   |  |                                      |     |                    |  |               |      |     |  |       |    |     |  |      |      |  |  |     |     |  |  |       |      

As of December 31, 2003, we were drilling or participating in the drilling of
16 gross (12.2 net) wells. Of these wells, through March 12, 2004, 12 gross
(9.7 net) wells have been determined to be successful and 3 gross (23 net) were
unsuccessful with the remaining 1 gross (0.2 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, 2003. Productive wells consist of producing
wells and wells capable of production, including wells awaiting connections.
Wells that are completed in more than one producing horizon are counted as one
well. The day-to-day operations of natural gas properties are the
responsibility of an operator designated under an operating agreement.

|               |  |                   |       |              |  |             |         |              |  |       |     |     |  |       |       |     |  |       |    |     |  |  |      |  |  |  |    |  |  |  |     |  |  |  |       |  |  |  |         | 
|-------------- |  | ----------------- | ----- | ------------ |  | ----------- | ------- | ------------ |  | ----- | --- | --- |  | ----- | ----- | --- |  | ----- | -- | --- |  |  | ---- |  |  |  | -- |  |  |  | --- |  |  |  | ----- |  |  |  | ------- | 
|               |  | Natural Gas Wells |       | Oil Wells    |  | Total Wells
|               |  |                   |       |              |  |            
|               |  | Operated          |       | Non-Operated |  | Operated    |         | Non-Operated |  |       |     |     |  |       |       |    
|               |  |                   |       |              |  |             |         |              |  |       |     |     |  |       |       |    
|               |  | Gross             |       | Net          |  | Gross       |         | Net          |  | Gross |     | Net |  | Gross |       | Net |  | Gross |    | Net
|               |  |                   |       |              |  |             |         |              |  |       |     |     |  |       |       |     |  |       |    |    
|South Texas    |  |                   | 476   |              |  |             | 461.4   |              |  |       | 105 |     |  |       | 14.3  |     |  |       |   |     |  |  |     |  |  |  |   |  |  |  |    |  |  |  | 581   |  |  |  | 475.7   | 
|Gulf of Mexico |  |                   | 72    |              |  |             | 58.5    |              |  |       | 43  |     |  |       | 16    |     |  |       | 16 |     |  |  | 12.3 |  |  |  | 10 |  |  |  | 1.4 |  |  |  | 141   |  |  |  | 88.2    | 
|Arkoma Basin   |  |                   | 170   |              |  |             | 116.4   |              |  |       | 105 |     |  |       | 24.8  |     |  |       |   |     |  |  |     |  |  |  |   |  |  |  |    |  |  |  | 275   |  |  |  | 141.2   | 
|West Virginia  |  |                   | 1,304 |              |  |             | 985.1   |              |  |       | 107 |     |  |       | 47.3  |     |  |       |   |     |  |  |     |  |  |  |   |  |  |  |    |  |  |  | 1,411 |  |  |  | 1,032.4 | 
|Other onshore  |  |                   | 28    |              |  |             | 17.7    |              |  |       | 24  |     |  |       | 6.0   |     |  |       |   |     |  |  |     |  |  |  | 5  |  |  |  | 1.2 |  |  |  | 57    |  |  |  | 24.9    | 
|               |  |                   |       |              |  |             |         |              |  |       |     |     |  |       |       |     |  |       |    |     |  |  |      |  |  |  |    |  |  |  |     |  |  |  |       |  |  |  |         | 
|Total          |  |                   | 2,050 |              |  |             | 1,639.1 |              |  |       | 384 |     |  |       | 108.4 |     |  |       | 16 |     |  |  | 12.3 |  |  |  | 15 |  |  |  | 2.6 |  |  |  | 2,465 |  |  |  | 1,762.4 | 
|               |  |                   |       |              |  |             |         |              |  |       |     |     |  |       |       |     |  |       |    |     |  |  |      |  |  |  |    |  |  |  |     |  |  |  |       |  |  |  |         | 

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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, 2003. 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, 2003
|               |  |                        
|               |  | Undeveloped             |         | Developed |  | Total Acreage
|               |  |                         |         |           |  |              
|               |  | Gross                   |         | Net       |  | Gross         |         | Net |  | Gross |         | Net
|               |  |                         |         |           |  |               |         |     |  |       |         |    
|South Texas    |  |                         | 20,296  |           |  |               | 15,564  |     |  |       | 65,478  |     |  |  | 49,213  |  |  |  | 85,774    |  |  |  | 64,777  | 
|Gulf of Mexico |  |                         | 223,965 |           |  |               | 180,479 |     |  |       | 299,333 |     |  |  | 183,448 |  |  |  | 523,298   |  |  |  | 363,927 | 
|Arkoma Basin   |  |                         | 18,958  |           |  |               | 7,088   |     |  |       | 59,707  |     |  |  | 28,322  |  |  |  | 78,665    |  |  |  | 35,410  | 
|West Virginia  |  |                         | 2,755   |           |  |               | 2,755   |     |  |       | 204,518 |     |  |  | 125,707 |  |  |  | 207,273   |  |  |  | 128,462 | 
|Rocky Mountain |  |                         | 198,458 |           |  |               | 182,905 |     |  |       |        |     |  |  |        |  |  |  | 198,458   |  |  |  | 182,905 | 
|Other onshore  |  |                         | 442     |           |  |               | 39      |     |  |       | 9,389   |     |  |  | 5,002   |  |  |  | 9,831     |  |  |  | 5,041   | 
|               |  |                         |         |           |  |               |         |     |  |       |         |     |  |  |         |  |  |  |           |  |  |  |         | 
|Total          |  |                         | 464,874 |           |  |               | 388,830 |     |  |       | 638,425 |     |  |  | 391,692 |  |  |  | 1,103,299 |  |  |  | 780,522 | 
|               |  |                         |         |           |  |               |         |     |  |       |         |     |  |  |         |  |  |  |           |  |  |  |         | 

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, 2003
|               |  |                        
|               |  | 2004                    |        | 2005 |  | 2006  |        | 2007 |  | 2008 
|               |  |                         |        |      |  |       |        |      |  |      
|               |  | Gross                   |        | Net  |  | Gross |        | Net  |  | Gross |        | Net |  | Gross |        | Net |  | Gross |        | Net
|               |  |                         |        |      |  |       |        |      |  |       |        |     |  |       |        |     |  |       |        |    
|South Texas    |  |                         | 6,532  |      |  |       | 4,920  |      |  |       | 6,979  |     |  |       | 5,499  |     |  |       | 1,081  |     |  |  | 594    |  |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       | 
|Gulf of Mexico |  |                         | 50,502 |      |  |       | 44,742 |      |  |       | 43,511 |     |  |       | 42,071 |     |  |       | 26,499 |     |  |  | 22,017 |  |  |  | 46,181 |  |  |  | 37,921 |  |  |  | 57,274 |  |  |  | 33,727 | 
|Arkoma Basin   |  |                         |       |      |  |       |       |      |  |       |       |     |  |       |       |     |  |       |       |     |  |  |       |  |  |  | 2,750  |  |  |  | 898    |  |  |  |       |  |  |  |       | 
|West Virginia  |  |                         |       |      |  |       |       |      |  |       |       |     |  |       |       |     |  |       |       |     |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       | 
|Rocky Mountain |  |                         | 3,270  |      |  |       | 3,265  |      |  |       | 31,410 |     |  |       | 31,218 |     |  |       | 2,560  |     |  |  | 2,016  |  |  |  | 22,474 |  |  |  | 22,410 |  |  |  | 2,774  |  |  |  | 2,774  | 
|Other onshore  |  |                         | 383    |      |  |       | 8      |      |  |       | 56     |     |  |       | 30     |     |  |       | 2      |     |  |  | 1      |  |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       | 
|               |  |                         |        |      |  |       |        |      |  |       |        |     |  |       |        |     |  |       |        |     |  |  |        |  |  |  |        |  |  |  |        |  |  |  |        |  |  |  |        | 
|Total          |  |                         | 60,687 |      |  |       | 52,935 |      |  |       | 81,956 |     |  |       | 78,818 |     |  |       | 30,142 |     |  |  | 24,628 |  |  |  | 71,405 |  |  |  | 61,229 |  |  |  | 60,048 |  |  |  | 36,501 | 
|               |  |                         |        |      |  |       |        |      |  |       |        |     |  |       |        |     |  |       |        |     |  |  |        |  |  |  |        |  |  |  |        |  |  |  |        |  |  |  |        | 

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 sell substantially all of our production to a
variety of purchasers under short-term (usually one month) contracts or spot
gas purchase contracts ranging anywhere from one to 30 days, all at market
prices. 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 more a
detailed discussion, see Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations  General and Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.

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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 read the section entitled Risk Factors  Operating Hazards
and Uninsured Risks.

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

The demand for natural gas often decreases during the
summer months and increases during the winter months. Seasonal anomalies such
as mild winters or hot summers sometimes lessen this fluctuation. In addition,
pipelines, utilities, local distribution companies and industrial users utilize
natural gas storage facilities and purchase some of their anticipated winter
requirements during the summer. This can also lessen seasonal demand
fluctuations.

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Regulation

The oil and gas industry is extensively regulated by numerous federal, state
and local authorities. Legislation affecting the oil and gas industry is under
constant review for amendment or expansion, frequently increasing the
regulatory burden. Also, numerous departments and agencies, both federal and
state, are authorized by statute to issue rules and regulations binding on the
oil and gas industry and its individual members, some of which carry
substantial penalties for failure to comply. Although the regulatory burden on
the oil and gas industry increases 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 in which we operate also regulate:



| |  |  | 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.                                          

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
which 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;

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| |  |  | 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, 2003, we did not incur any material capital
expenditures for environmental control facilities. As of the date of our
report, we are not aware of any environmental issues or claims that will
require material capital expenditures during 2004 or that will have a material
impact on our financial position or results of operations.

The most significant of these environmental laws and regulations include, among
others, the:

Resource Conservation and Recovery Act. The Resource Conservation and
Recovery Act 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. At this time, 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 believe we are in substantial compliance

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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 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
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.

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. If the Protocol enters into force, it
would 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 issues 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.

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Risk Factors Affecting Our Business

A Decline in Natural Gas and Oil Prices May Adversely Affect Our Financial
Results.

As an independent natural gas and oil producer, the revenues we generate from
our operations are highly dependent on the price of, and demand for, natural
gas and oil. Even relatively modest changes in natural gas and oil 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;                                                                                
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | the price of foreign imports;                                                                                                          
|
| |  |  | overall domestic and global economic conditions;                                                                                       
|
| |  |  | terrorist attacks or military conflicts;                                                                                               
|
| |  |  | political and economic conditions in oil producing countries, including the Middle East and South America;                             
|
| |  |  | 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;                                                                                                  
|
| |  |  | weather conditions;                                                                                                                    
|
| |  |  | domestic and foreign governmental regulations; and                                                                                     
|
| |  |  | the price and availability of alternative fuels.                                                                                       

If natural gas and oil prices decline, the amount of natural gas and oil we can
economically produce will be reduced, which may result in a material decline in
our revenues.

We May Be Required to Take Writedowns of the Carrying Value of Our Natural Gas
and Oil Properties.

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 Regulation S-X Rule 4-10 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 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 the 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 2003 as a function of our higher finding and
development cost 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.

The Success of Our Business Depends Upon Our Ability to Find, Develop and
Acquire Oil and Gas 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 increasingly more difficult to find
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 maximum amount of borrowing capacity available under our
revolving credit facility is based, at least in part, on the estimated
quantities of our proved reserves.

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Our Acquisition and Investment Activities May Not Be Successful.

The successful acquisition of producing properties requires assessment of
reserves, future commodity prices, operating costs, potential environmental and
other liabilities. 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 credit facility decrease as a
result of lower natural gas and oil prices, operating difficulties or declines
in reserves, we may not be able to expend the capital necessary to undertake or
complete future drilling programs or acquisition opportunities unless we raise
additional funds through debt or equity financings. Without continued
employment of capital, our oil and gas reserves will decline. We may not be
able to obtain debt or equity financing, and cash generated by operations or
available under our revolving credit facility may not be sufficient to meet our
capital requirements.

The Amount of Our Outstanding Indebtedness May Restrict Our Financial
Flexibility.

Our level of indebtedness affects our operations in a number of ways. Our
revolving credit facility and the indenture governing our senior subordinated
notes contain covenants that require a substantial portion of our cash flow
from operations to be dedicated to the payment of interest on our indebtedness.
Funds dedicated to debt service payment will not be available for other
purposes. Further, other covenants in these agreements require us to meet the
financial tests specified in these agreements and establish other restrictions
that limit our ability to borrow additional funds or dispose of assets. They
may also affect our flexibility in planning for, and reacting to, changes in
business conditions. Future acquisition and development activities may require
us to significantly alter our capitalization structure, which may alter our
indebtedness. Our ability to meet our debt service obligations and reduce our
total indebtedness will depend upon our future performance.

Estimates of Proved Reserves and Future Net Revenue May Change.

The estimates of proved reserves of natural gas and oil included in this
document are based on various assumptions. The accuracy of any reserve estimate
is a function of the quality of available data, engineering, geological
interpretation and judgment and the assumptions used regarding quantities of
recoverable natural gas and oil reserves and prices for crude oil and natural
gas. Actual prices, production, development expenditures, operating expenses
and quantities of recoverable oil and natural gas reserves will vary from those
assumed in our estimates, and these variances may be significant. Any
significant variance from the assumptions used could result in the actual
quantity of our reserves and future net cash flow being materially different
from the estimates in our reserve reports. In addition, results of drilling,
testing and production and changes in crude oil and natural gas prices after
the date of the estimate may result in downward revisions.

The Oil and Gas 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 of 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;                              
|
| |  |  | explosions;                                     
|
| |  |  | encountering formations with abnormal pressures;
|
| |  |  | blowouts;                                       
|
| |  |  | cratering;                                      
|
| |  |  | unexpected operational events;                  

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| |  |  | pipeline ruptures; and
| | - |  | ----------------------
|
| |  |  | spills.               

We are insured against some, but not all, of the hazards associated with our
business. As a result, we may be liable or sustain losses that could be
substantial due to events that are not insured.

Our Reserves, Production and Cash Flow are Highly Dependent upon Operations
that are Concentrated in Three Primary Areas.

During 2003, approximately 96% of our production was generated from three
primary areas of operations with 46% from our South Texas, 41% from offshore
Gulf of Mexico and 8% 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 tropical weather disturbances, some of which can be
severe enough to cause substantial damage to facilities and production
infrastructure. We are not insured against all potential losses. Losses could
occur for uninsurable or uninsured risks or in amounts in excess of existing
insurance coverage. The occurrence of an event that is not fully covered by
insurance could have a material adverse impact on our financial condition and
results of operations.

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 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 Could Reduce Our
Income.

To achieve a more predictable cash flow and to reduce our exposure to adverse
fluctuations in the prices of oil and natural gas, we currently and may in the
future enter into hedging arrangements for a significant portion of our natural
gas and oil production. For 2004 we have entered into derivative instruments
relating to about 70% of our planned production utilizing a variety of
instruments, including fixed price swaps, collars and options. Many 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. 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. Lastly, an attendant risk exists in hedging activities 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 un-hedged volumes.

We May Incur Substantial Costs to Comply With Environmental and Other
Governmental Regulations.

Our exploration and production operations are regulated extensively at the
federal and state levels. Environmental and other governmental regulations
have increased the costs to plan, design, drill, install, operate and abandon
oil and natural gas wells. We have made and will continue to make 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 increasing impact on our operations. Accordingly,
increasingly strict environmental laws, regulations and enforcement policies
and claims for damages to property, employees, other persons and the
environment resulting from our operations, could result in substantial costs
and liabilities in the future.

Competitive Industry Conditions May Adversely Affect Our Results of Operations.

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

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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. In addition, our natural gas futures and swap
contracts also expose us to credit risk in the event of nonperformance by
counterparties.

Potential Conflicts of Interest With Our Majority Stockholder.

A variety of conflicts of interest between KeySpan and our public stockholders
may arise as a result of KeySpans controlling interest in our company. As of
the date of this report, KeySpan owns approximately 55% of our common stock,
and we are one of their indirect subsidiaries. KeySpan is in a position to
control:



| |  |  | the election of the entire Board of Directors;                                              
| | - |  | --------------------------------------------------------------------------------------------
|
| |  |  | the outcome of the vote on all matters requiring the vote of our stockholders;              
|
| |  |  | all matters relating to our management;                                                     
|
| |  |  | the acquisition or disposition of our assets, including the sale of our business as a whole;
|
| |  |  | payment of dividends on our common stock;                                                   
|
| |  |  | the future issuance of our common stock or other securities; and                            
|
| |  |  | hedging, drilling, operating and acquisition expenditure plans.                             

The Chairman of our Board of Directors, Robert B. Catell, is also the Chairman
of the Board of Directors and Chief Executive Officer of KeySpan. In addition
to Mr. Catell, six of our eleven other directors are currently or previously
affiliated with KeySpan: Gerald Luterman is Executive Vice President and Chief
Financial Officer of KeySpan; H. Neil Nichols is Senior Vice President of
Corporate Development and Asset Management of KeySpan; Robert J. Fani is
President of KeySpan Energy Services and Supply; Stephen W. McKessy is a member
of KeySpans Board and serves on the Audit Committee and James Q. Riordan,
former Chairman of our Audit Committee, retired from KeySpans Board in May
2002.

Our Majority Stockholder has Indicated its Desire to Divest.

In February 2003, KeySpan divested three million shares of our common stock.
KeySpan has publicly announced it does not consider its investment in Houston
Exploration a part of its core asset group and that it may sell or dispose of
all or a portion of its non-core assets, including its investment in our
company. Because market conditions are unpredictable, KeySpan is unable to
determine if or when any additional dispositions of all or a portion of its
remaining ownership interest in our company will take place.

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Employees

As of December 31, 2003, we had 170 full time employees, 117 of whom are
located at our headquarters in Houston, Texas and the remainder of whom are
located in our South Texas, Arkansas, West Virginia, Denver and East Texas
field offices. None of our employees are 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 69,000 square feet of office space in Houston,
Texas at 1100 Louisiana Street, where our principal offices are located. We
maintain 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, West Virginia 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 internet 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
website at www.houstonexploration.com under the heading Corporate Governance.
We intend to promptly disclose on our website 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 website 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:

|                                 
|---------------------------------
|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 website 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 are not a party to any material pending legal or governmental proceedings,
other than ordinary routine litigation incidental to our business. Where 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, 2003.

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Part II.

Item 5. Market for the Registrants Common Equity and Related Stockholder Matters

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, 2002 through December 31,
2003 as reported on the New York Stock Exchange:

|                             |  |      |       |     |  |   |       | 
|---------------------------- |  | ---- | ----- | --- |  | - | ----- | 
|Year Ended December 31, 2003 |  | High |       | Low
|                             |  |      |       |    
|First Quarter                |  | $    | 31.45 |     |  | $ | 25.81 | 
|Second Quarter               |  |      | 35.20 |     |  |   | 26.72 | 
|Third Quarter                |  |      | 36.28 |     |  |   | 31.25 | 
|Fourth Quarter               |  |      | 37.70 |     |  |   | 33.35 | 

|                             |  |      |       |     |  |   |       | 
|---------------------------- |  | ---- | ----- | --- |  | - | ----- | 
|Year Ended December 31, 2002 |  | High |       | Low
|                             |  |      |       |    
|First Quarter                |  | $    | 33.65 |     |  | $ | 27.32 | 
|Second Quarter               |  |      | 31.85 |     |  |   | 28.40 | 
|Third Quarter                |  |      | 31.45 |     |  |   | 23.80 | 
|Fourth Quarter               |  |      | 34.00 |     |  |   | 28.21 | 

As of March 11, 2004, 31,786,097 shares of common stock were outstanding, and we
had approximately 40 stockholders of record and approximately 4,500 beneficial
owners.

Dividends

We have never 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 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.

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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, 2003. 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,             
|                                                                                   |                                          |                          |         | 2003                                  |         | 2002 |         | 2001    |         | 2000 |         | 1999   
|                                                                                   |                                          |                          |         |                                       |         |      |         |         |         |      |         |        
|                                                                                   |                                          |                          |         | (in thousands, except per share data)
|Income Statement Data:                                                             |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |        
|Revenues:                                                                          |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |        
|                                                                                   | Natural gas and oil revenues(1)          |                          | $       | 491,440                               |         |      | $       | 344,295 |         |      | $       | 387,156 |         |   | $       | 277,487 |         |   | $      | 157,137 |        
|                                                                                   | Other                                    |                          |         | 1,312                                 |         |      |         | 1,086   |         |      |         | 1,353   |         |   |         | 1,738   |         |   |        | 1,147   |        
|                                                                                   |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |         |        
|                                                                                   |                                          | Total revenues(1)        |         |                                       | 492,752 |      |         |         | 345,381 |      |         |         | 388,509 |   |         |         | 279,225 |   |        |         | 158,284 | 
|Expenses:                                                                          |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |        
|                                                                                   | Lease operating expense                  |                          |         | 47,072                                |         |      |         | 33,976  |         |      |         | 25,291  |         |   |         | 23,553  |         |   |        | 18,406  |        
|                                                                                   | Severance tax                            |                          |         | 15,958                                |         |      |         | 9,487   |         |      |         | 11,035  |         |   |         | 9,757   |         |   |        | 5,444   |        
|                                                                                   | Transportation expense (1)               |                          |         | 10,387                                |         |      |         | 9,317   |         |      |         | 7,652   |         |   |         | 6,892   |         |   |        | 6,557   |        
|                                                                                   | Asset retirement accretion expense       |                          |         | 3,668                                 |         |      |         |        |         |      |         |        |         |   |         |        |         |   |        |        |        
|                                                                                   | Depreciation, depletion and amortization |                          |         | 197,530                               |         |      |         | 171,610 |         |      |         | 128,736 |         |   |         | 89,239  |         |   |        | 74,051  |        
|                                                                                   | Writedown in carrying value              |                          |         |                                      |         |      |         |        |         |      |         | 6,170   |         |   |         |        |         |   |        |        |        
|                                                                                   | General and administrative, net          |                          |         | 19,542                                |         |      |         | 13,077  |         |      |         | 17,110  |         |   |         | 8,928   |         |   |        | 4,150   |        
|                                                                                   |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |         |        
|                                                                                   |                                          | Total operating expenses |         |                                       | 294,157 |      |         |         | 237,467 |      |         |         | 195,994 |   |         |         | 138,369 |   |        |         | 108,608 | 
|Income from operations                                                             |                                          |                          | 198,595 |                                       |         |      | 107,914 |         |         |      | 192,515 |         |         |   | 140,856 |         |         |   | 49,676 |        
|Other (income) expense (2)                                                         |                                          |                          | (15,746 | )                                     |         |      | (9,070  | )       |         |      | 119     |         |         |   | 1,752   |         |         |   |       |        
|Interest expense, net                                                              |                                          |                          | 8,342   |                                       |         |      | 7,398   |         |         |      | 2,992   |         |         |   | 11,361  |         |         |   | 13,307 |        
|                                                                                   |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |         |        
|Income before income taxes                                                         |                                          |                          | 205,999 |                                       |         |      | 109,586 |         |         |      | 189,404 |         |         |   | 127,743 |         |         |   | 36,369 |        
|Income tax provision                                                               |                                          |                          | 72,187  |                                       |         |      | 39,092  |         |         |      | 66,803  |         |         |   | 42,485  |         |         |   | 11,748 |        
|                                                                                   |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |         |        
|Income before cumulative effect of change in
accounting principle                  |                                          | $                        | 133,812 |                                       |         | $    | 70,494  |         |         | $    | 122,601 |         |         | $ | 85,258  |         |         | $ | 24,621 |        
|Cumulative effect of change in accounting
principle (3)                            |                                          |                          | 2,772   |                                       |         |      |        |         |         |      |        |         |         |   |        |         |         |   |       |        
|                                                                                   |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |         |        
|Net income                                                                         |                                          | $                        | 131,040 |                                       |         | $    | 70,494  |         |         | $    | 122,601 |         |         | $ | 85,258  |         |         | $ | 24,621 |        
|                                                                                   |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |         |        
|Earnings per share:                                                                |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |        
|Basic:                                                                             |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |        
|Income per share before cumulative effect of
change in accounting principle change |                                          | $                        | 4.30    |                                       |         | $    | 2.31    |         |         | $    | 4.06    |         |         | $ | 3.06    |         |         | $ | 1.03   |        
|Cumulative effect of change in accounting
principle (3)                            |                                          |                          | 0.09    |                                       |         |      |        |         |         |      |        |         |         |   |        |         |         |   |       |        
|                                                                                   |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |         |        
|Net income per share  basic                                                       |                                          | $                        | 4.21    |                                       |         | $    | 2.31    |         |         | $    | 4.06    |         |         | $ | 3.06    |         |         | $ | 1.03   |        
|                                                                                   |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |         |        
|Fully Diluted:                                                                     |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |        
|Income per share before cumulative effect of
change in accounting principle        |                                          | $                        | 4.29    |                                       |         | $    | 2.28    |         |         | $    | 4.00    |         |         | $ | 3.02    |         |         | $ | 0.95   |        
|                                                                                   |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |         |        
|Cumulative effect of change in accounting
principle (3)                            |                                          |                          | (0.09   | )                                     |         |      |        |         |         |      |        |         |         |   |        |         |         |   |       |        
|                                                                                   |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |         |        
|Net income per share  fully diluted                                               |                                          | $                        | 4.20    |                                       |         | $    | 2.28    |         |         | $    | 4.00    |         |         | $ | 3.02    |         |         | $ | 0.95   |        
|                                                                                   |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |         |        
|Weighted average shares                                                            |                                          |                          | 31,097  |                                       |         |      | 30,569  |         |         |      | 30,228  |         |         |   | 27,860  |         |         |   | 23,906 |        
|Weighted average shares  diluted                                                  |                                          |                          | 31,213  |                                       |         |      | 30,878  |         |         |      | 30,645  |         |         |   | 28,213  |         |         |   | 28,310 |        
|                                                                                   |                                          |                          |         |                                       |         |      |         |         |         |      |         |         |         |   |         |         |         |   |        |         |         | 
|Ratio of earnings to fixed charges(4)                                              |                                          |                          | 13.6x   |                                       |         |      | 7.6x    |         |         |      | 12.8x   |         |         |   | 5.5x    |         |         |   | 2.0x   |        

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|                                                    |  |                          |         |      |  |      |         |      |  |      |         |  |  |   |         |   |  |   |         | 
|--------------------------------------------------- |  | ------------------------ | ------- | ---- |  | ---- | ------- | ---- |  | ---- | ------- |  |  | - | ------- | - |  | - | ------- | 
|                                                    |  | Years Ended December 31,
|                                                    |  | 2003                     |         | 2002 |  | 2001 |         | 2000 |  | 1999
|                                                    |  |                          |         |      |  |      |         |      |  |     
|                                                    |  | (in thousands)          
|Cash Flow Data:                                     |  |                          |         |      |  |      |         |      |  |      |         |  |  |   |         |   |  |   |         | 
|Net cash provided by operating activities           |  | $                        | 390,832 |      |  | $    | 243,869 |      |  | $    | 358,032 |  |  | $ | 200,791 |   |  | $ | 110,072 | 
|Net cash used in investing activities               |  |                          | 461,822 |      |  |      | 252,125 |      |  |      | 368,277 |  |  |   | 184,512 |   |  |   | 147,654 | 
|Net cash provided by (used) in financing activities |  |                          | 55,528  |      |  |      | 17,668  |      |  |      | 9,189   |  |  |   | (22,106 | ) |  |   | 48,439  | 

|                                   |  |                 |           |      |  |      |           |      |  |      |           |  |  |   |         |  |  |   |         |  
|---------------------------------- |  | --------------- | --------- | ---- |  | ---- | --------- | ---- |  | ---- | --------- |  |  | - | ------- |  |  | - | ------- | -
|                                   |  | At December 31,
|                                   |  | 2003            |           | 2002 |  | 2001 |           | 2000 |  | 1999
|                                   |  |                 |           |      |  |      |           |      |  |     
|Balance Sheet Data:                |  |                 |           |      |  |      |           |      |  |      |           |  |  |   |         |  |  |   |         |  
|Working capital (deficit)          |  | $               | (36       | )    |  | $    | 10,550    |      |  | $    | 34,314    |  |  | $ | 19,746  |  |  | $ | (71,219 | )
|Property, plant and equipment, net |  |                 | 1,371,129 |      |  |      | 1,151,068 |      |  |      | 938,761   |  |  |   | 705,390 |  |  |   | 610,116 |  
|Total assets                       |  |                 | 1,509,065 |      |  |      | 1,138,816 |      |  |      | 1,059,092 |  |  |   | 837,384 |  |  |   | 678,483 |  
|Long-term debt and notes           |  |                 | 302,000   |      |  |      | 252,000   |      |  |      | 244,000   |  |  |   | 245,000 |  |  |   | 281,000 |  
|Stockholders equity               |  |                 | 735,534   |      |  |      | 592,789   |      |  |      | 565,881   |  |  |   | 396,742 |  |  |   | 217,590 |  



---

|(1) |  | For all periods presented, we applied Emerging Issues Task Force (EITF)
No. 00-10 Accounting for Shipping and Handling Fees and Costs. For the
years ended December 31, 2001, 2000 and 1999, transportation expenses
previously reflected as a reduction to natural gas and oil revenues were
added back to revenues and reflected as a separate component of operating
expense.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|--- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | For 2003 and 2002, other income includes $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. Additionally, 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. Please 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.
|   
|(3) |  | 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.                                                                                                                                                                                                                                                                                                              
|   
|(4) |  | 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     

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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 statements. 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 at the beginning of this
Annual Report and Risk Factors Affecting Our Business found on page 13 for additional discussion of some of these factors and risks.

Overview of Our Business

We are an independent natural gas and oil company engaged in the exploration,
development, exploitation and acquisition of natural gas and oil reserves in
North America. Natural gas is our primary focus. 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 Appalachian Basin of West
Virginia. During 2003, we commenced operations in the Rocky Mountain Region,
with an initial focus in the Uinta Basin of northeastern Utah. We operate in one segment as each of our operating areas has similar economic characteristics and each
meets the criteria for aggregation as defined in SFAS 131.

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. The use of certain types
derivative instruments may prevent us from realizing the benefit of upward
price movements. At December 31, 2003, KeySpan held 55% of our common stock. KeySpan has indicated a desire
to divest of its shares held in our company. In February 2003, KeySpan divested three million shares of our common stock.
KeySpan has publicly announced it does not consider its investment in Houston Exploration a part of its core asset group and that it may sell
or dispose of all or a portion of its non-core assets, including its investment in our company. Because market conditions are unpredictable, KeySpan is unable to determine
if or when any additional dispositions of all or a portion of its remaining ownership interest in our company will take place.

Principal Components of Our Cost Structure



| |  | Lifting Costs.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.                                                                                                                                                                                                                                                                                                                                                                                        
|- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| 
| |  | Depreciation, Depletion and Amortization (DD&A). 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 direct 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 sold through DD&A expense. Generally, if reserve
quantities are revised up or down, the DD&A rate per unit of
production will change inversely. When the depreciable base increases
or decreases, the DD&A rate will move in the same direction.
| 
| |  | Asset Retirement Accretion Expense (ARO). The systematic, monthly accretion of future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities.                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| 
| |  | General and Administrative (G&A).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 (G&A). We capitalize G&A directly related to our
acquisition, exploration and development activities.                                                                                                                                                                                                                                                                                
| 
| |  | Interest.We typically finance 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 and certain properties under
development, which are not being amortized.                                                                 
| 
| |  | Income Taxes.We are generally subject to a 35% federal income tax
rate. For income tax purposes, we are allowed deductions for
accelerated depreciation, depletion and intangible drilling costs that
reduce our current tax liability. 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
recognized current tax expense as long as we are generating taxable
income.                                                                                                          

Industry Environment

We currently operate exclusively 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 has matured and production of natural gas and oil has declined.
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 production rates and hastened depletion. While new discoveries are
still being made in North America, the frequency and size of these discoveries
is declining. As a result,

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domestic natural gas and oil production as a whole may have peaked and is
expected to decline in the future, with the exception of regions such as the
Rocky Mountains, which we believe, continues to hold the prospect for
production growth.

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 growing our reserve base at an acceptable
finding cost will depend in large part on our ability to acquire new proven
reserves and unevaluated acreage on which we can explore for new discoveries.
We maintain a very active acquisition program and will 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 basin will
lead to higher cost structures throughout our industry. We believe that the
cost of finding, developing and producing new natural gas and oil reserves will
rise as the industry makes fewer discoveries of smaller reserve size. For full
cost companies such as ours, this will result in higher finding and development
costs and higher DD&A rates and ultimately the increased likelihood of a
writedown in carrying value of our natural gas and oil properties. In addition, we think lease
operating expenses will 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. For example, concerns over the adequacy of
natural gas in storage during the first quarter of 2003 resulted in prices
exceeding $9.00 during the quarter and emerging 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 and into
2004. As a direct result, 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 comodity prices our
ability to acquire, find and develop new reserves at economical costs.

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Critical Accounting Estimates

Proved Reserves. Our most significant financial estimates are based on
estimates of proved natural gas and oil reserves. Estimates of proved reserves
are key components of our unevaluated properties, our rate for recording
depreciation, depletion and amortization, and our full cost ceiling limitation.
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 highly dependent on the quality and quantity of available
data. Our reserves are fully engineered on an annual basis by independent
petroleum engineers.

Asset Retirement Obligation.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,
the 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 third parties, 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.

Recent Accounting Developments

SFAS 141, Business Combinations and SFAS 142, Goodwill and Intangible
Assets, became effective on July 1, 2001 and January 1, 2002, respectively.
These new standards emphasize a more precise evaluation of assets and their
balance sheet classification as either tangible or intangible assets. We
understand that the issue is under evaluation as to whether provisions of SFAS
141 and SFAS 142 may call for mineral rights held under lease or other
contractual arrangements together with cash costs for the acquisition of
natural gas and oil leasehold interests to be classified in the balance sheet
as intangible assets. If these types of leasehold costs (both proved and
unevaluated) are determined to be intangible assets, they would be classified
separately from natural gas and oil properties as intangible assets on our
balance sheets. This issue relates only to balance sheet classification and
presentation and we do not believe it will have an effect on cash flows or
results of operations. At December 31, 2003, if we applied the interpretation
currently under discussion, undeveloped leasehold costs of $117.1 million and
developed leasehold costs of $221.3 million, net of accumulated amortization,
would be reclassified from tangibles to intangibles, representing costs
incurred since June 30, 2001, the effective date of SFAS 141. At December 31,
2002, we had undeveloped leasehold costs of $49.5 million and developed
leasehold costs of $111.5 million, net of accumulated amortization that would
be reclassified from tangibles to intangibles. Consistent with current
industry practice, we will continue to classify our natural gas and oil
leasehold costs as tangible natural gas and oil properties until the Emerging
Issues Task Force issues further guidance.

New Accounting Pronouncements

In November 2002, FASB issued Financial Interpretation No. (FIN) 45,
Guarantors Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others. FIN 45 requires certain
guarantees to be recorded at fair value, which is different from the previous
practice of recording a liability only when a loss is probable and reasonably
estimable, as those terms are defined in SFAS 5, Accounting for
Contingencies. FIN 45 has a dual effective date. The initial recognition and
measurement provisions are applicable on a prospective basis to guarantees
issued or modified after December 31, 2002. The disclosure requirements in the
interpretation are effective for financial statements for interim or annual
periods ending after December 15, 2002. As of our December 31, 2003, and
December 31, 2002, balance sheet dates, we did not have any guarantees of
indebtedness of others and as a result, our adoption of FIN 45 did not have an
effect on our financial statements.

In January 2003, the FASB issued FIN 46, Consolidation of Variable Interest
Entities  An Interpretation of Accounting Research Bulletin 51. FIN 46
addresses consolidation by business enterprises of variable interest entities
(VIEs) and the primary objective is to provide guidance on the identification
of, and financial reporting for, entities over which control is achieved
through means other than voting rights; such entities are known as VIEs. FIN
46 requires an entity to consolidate a VIE if the entity has a variable
interest (or combination of variable interests) that will absorb a majority of
the entitys expected losses if they occur, receive a majority of the entitys
expected residual returns if they occur or both. This guidance applies
immediately to VIEs created after January 31, 2003, and to VIEs in which an
enterprise obtains an interest after that date. However, on October 8, 2003,
the FASB decided to grant a broader deferral of the implementation of FIN 46.
Pursuant to this deferral, public companies must complete their evaluations of
VIEs that existed prior to February 1, 2003, and the consolidation of those for
which they are the primary beneficiary for financial statements issued for the
first period ending after December 15, 2003. For calendar year companies,
consolidation of previously existing VIEs will be required in their December
31, 2003, financial statements. We have completed our evaluation of FIN 46 and
because we do not believe that we have any VIEs there is no impact to our
consolidated financial statements.

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Overview of 2003 Results

Strong energy commodity prices were the primary force behind a record year for
operations, earnings and cash flows. The increase in our cash flows allowed
for increased capital spending for drilling, acquisitions, and the repayment of
debt, all of which improved our balance sheet. During 2003:



| |  | We generated, $131.0 million in net income, an 86% increase from 2002,
which was primarily attributable to a 37% increase in average realized
natural gas prices;                                                                                                                                                                                                                  
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| 
| |  | We produced a total of 108 Bcfe, and increased our average daily
production rate by 5% to 295 MMcfe, per day, and we closed out 2003
with a record production rate of 319 MMcfe per day during December;                                                                                                                                                                           
| 
| |  | We increased our total net proved reserves by 16% to 755 Bcfe with a
pre-tax net present value, discounted at 10%, of future net cash flows of $2.0 billion;                                                                                                                                                                                                                       
| 
| |  | We replaced 198% of our production by adding 213 Bcfe of net proved
reserves through a combination of drilling and acquisitions;                                                                                                                                                                                                                                                   
| 
| |  | We drilled a record 147 wells, 130 onshore and 17 offshore, of which
113 were successful reflecting a success rate of 77%;                                                                                                                                                                                                                                                         
| 
| |  | We participated in and brought on-line our first deep shelf discovery
at High Island 115 and had a 40% success rate on deep shelf tests for
the year;                                                                                                                                                                                                                              
| 
| |  | We completed our largest acquisition of producing properties to date
in October, by purchasing 88.5 Bcfe of net proved reserves in the Gulf
of Mexico from Transworld Exploration and Production Inc. for a net
$147.5 million;                                                                                                                                                    
| 
| |  | We added to our West Virginia production base in December by acquiring
producing properties adjacent to our existing fields and acquired 23.4
Bcfe of net proved reserves for a net $27.9 million. In conjunction
with this acquisition and in an effort to improve our onshore asset
portfolio;                                                                                   
| 
| |  | We agreed to divest of our South Louisiana properties, effective

November 1, 2003,and sold 12.3 Bcfe of net proved reserves for a net
$12.8 million in February 2004;                                                                                                                                                                                                             
| 
| |  | We established a new operating area in the Rocky Mountain Region by
leasing 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 and successfully drilled
our first exploratory well in the Uinta Basin during December, with an
estimated 30 wells planned for 2004;
| 
| |  | We recouped and recognized as other income $21.6 million ($14.0
million net of tax) of prior years severance tax expense pursuant to
the high-cost/tight-gas formation designation received during the
second half of 2002 for a portion of our South Texas production;                                                                                                         
| 
| |  | We generated $390.8 million in net cash flows from operating
activities and invested a net $460.0 million in natural gas and oil
properties, which included $175.4 million for producing property
acquisitions;                                                                                                                                                                    
| 
| |  | We added 141 Bcfe in total proved reserves through the drill bit, 112
Bcfe through acquisitions and incurred downward revisions of 40 Bcfe
bringing our all-in finding and development cost to $2.16 per Mcfe
for 2003 and $1.93 per Mcfe for a five-year average;                                                                                                               
| 
| |  | We assisted KeySpan in divesting three million shares of our common
stock which reduced their ownership interest to 55%;                                                                                                                                                                                                                                                           
| 
| |  | We took advantage of favorable long-term interest rates by redeeming
our $100 million of 8-5/8% senior subordinate notes due 2008 and
issuing $175 million of 7% senior subordinated notes due 2013; and,                                                                                                                                                                          
| 
| |  | We announced our 2004 capital expenditure budget of $315 million.                                                                                                                                                                                                                                                                                                                  

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##### Table of Contents



Operating and Financial Results for 2003 Compared to 2002

|                                     |  |                                  |         |      |  |          |         |          |  |   |         |  |  |  |    |  
|------------------------------------ |  | -------------------------------- | ------- | ---- |  | -------- | ------- | -------- |  | - | ------- |  |  |  | -- | -
|                                     |  | For the Years Ended December 31,
|                                     |  |                                 
|                                     |  | 2003                             |         | 2002 |  | Variance |         | % change
|                                     |  |                                  |         |      |  |          |         |         
|Summary operating information:       |  |                                  |         |      |  |          |         |          |  |   |         |  |  |  |    |  
|Operating revenues                   |  | $                                | 492,752 |      |  | $        | 345,381 |          |  | $ | 147,371 |  |  |  | 43 | %
|Operating expenses                   |  |                                  | 294,157 |      |  |          | 237,467 |          |  |   | 56,690  |  |  |  | 24 | %
|Income from operations               |  |                                  | 198,595 |      |  |          | 107,914 |          |  |   | 90,681  |  |  |  | 84 | %
|Net income                           |  | $                                | 131,040 |      |  | $        | 70,494  |          |  | $ | 60,546  |  |  |  | 86 | %
|Production:                          |  |                                  |         |      |  |          |         |          |  |   |         |  |  |  |    |  
|Natural gas (MMcf)                   |  |                                  | 99,965  |      |  |          | 97,368  |          |  |   | 2,597   |  |  |  | 3  | %
|Oil (MBbls)                          |  |                                  | 1,307   |      |  |          | 859     |          |  |   | 448     |  |  |  | 52 | %
|Total (MMcfe) (2)                    |  |                                  | 107,807 |      |  |          | 102,522 |          |  |   | 5,285   |  |  |  | 5  | %
|Average daily production (MMcfe/day) |  |                                  | 295     |      |  |          | 281     |          |  |   | 14      |  |  |  | 5  | %
|Average Sales Prices:                |  |                                  |         |      |  |          |         |          |  |   |         |  |  |  |    |  
|Natural Gas (per Mcf) realized (1)   |  | $                                | 4.55    |      |  | $        | 3.32    |          |  | $ | 1.23    |  |  |  | 37 | %
|Natural Gas (per Mcf) unhedged       |  |                                  | 5.23    |      |  |          | 3.16    |          |  |   | 2.07    |  |  |  | 66 | %
|Oil (per Bbl) realized (1)           |  |                                  | 28.15   |      |  |          | 23.99   |          |  |   | 4.16    |  |  |  | 17 | %
|Oil (per Bbl) unhedged               |  |                                  | 28.46   |      |  |          | 23.99   |          |  |   | 4.47    |  |  |  | 19 | %



---

|(1) |  | Average realized prices include the effect of hedges.                                                                                                                             
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Mcfe is defined 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.

Operating Income

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 was an increase of 5%
in production volume. Increased revenues were offset in part by a 24% increase
in operating costs due primarily to the continued expansion of our operations
combined with an increase in costs to maintain our existing production base
together with higher DD&A rates for 2003.

Commodity Prices

Our average wellhead price during 2003, before the effects of our hedging
program, was $5.23 per Mcfe up 66% over 2002. This increase in natural gas
prices during 2003 accounted for $207 million, or approximately 89% of our $232
million increase, in revenues before the effects of our hedging program.

Our increase in 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.

Production Volume

The 5% increase in production for the current year is a result of newly
developed production combined with additions from acquisitions made in 2003 and
2002.

Onshore, our 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. For 2004, we expect our
onshore daily production rate to grow by an estimated 5% or to average between
180 and 184 MMcfe/day.

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##### Table of Contents



Offshore, our 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. For 2004, we expect offshore production to increase by 25% to
approximately 155 MMcfe/day, which will include an estimated 35 MMcfe per day
from the Transworld properties.

Effects of Hedging

For 2003, we realized an average natural gas price of $4.55 per Mcf, which was
87% or $0.68 per Mcf lower than our average unhedged natural gas price or
wellhead price of $5.23 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.
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. 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 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% 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

|                                                |  |                          |      |      |  |          |      |         |  |   |      |  |  |  |     |  
|----------------------------------------------- |  | ------------------------ | ---- | ---- |  | -------- | ---- | ------- |  | - | ---- |  |  |  | --- | -
|                                                |  | Years Ended December 31,
|Operating Expenses (per Mcfe):                  |  | 2003                     |      | 2002 |  | Variance |      | %change
|                                                |  |                          |      |      |  |          |      |        
|Lease operating expense                         |  | $                        | 0.44 |      |  | $        | 0.33 |         |  | $ | 0.11 |  |  |  | 33  | %
|Severance tax                                   |  |                          | 0.15 |      |  |          | 0.09 |         |  |   | 0.06 |  |  |  | 67  | %
|Transportation expense                          |  |                          | 0.10 |      |  |          | 0.09 |         |  |   | 0.01 |  |  |  | 11  | %
|Asset retirement accretion expense              |  |                          | 0.03 |      |  |          |     |         |  |   | 0.03 |  |  |  | 100 | %
|Depreciation, depletion and amortization        |  |                          | 1.83 |      |  |          | 1.67 |         |  |   | 0.16 |  |  |  | 10  | %
|General and administrative, net                 |  |                          | 0.18 |      |  |          | 0.13 |         |  |   | 0.05 |  |  |  | 38  | %
|                                                |  |                          |      |      |  |          |      |         |  |   |      |  |  |  |     |  
|Total operating expenses per unit of production |  | $                        | 2.73 |      |  | $        | 2.31 |         |  | $ | 0.42 |  |  |  | 18  | %
|                                                |  |                          |      |      |  |          |      |         |  |   |      |  |  |  |     |  

Lease Operating Expense. The increase in lease operating expenses for 2003 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. Our plan for 2004 is to
reduce operating expenses per unit of production for these properties through
integration and exploitation. We estimate that our lease operating expenses
will average $0.54 per Mcfe during the first quarter of 2004.

Severance Tax. Severance tax is a function of volume and revenues generated
from onshore production. The increase in severance tax expense and severance
tax per Mcfe for 2003 is due to a 66% increase in average wellhead prices for
natural gas during 2003 combined with a 12% increase in onshore production
during 2003.

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##### Table of Contents



Depreciation, Depletion and Amortization. The increase in our DD&A expense for
2003 was primarily a result of a higher depletion rate combined with a 5%
increase in production volumes for 2003. Our depletion rate increased as a
result of:



| |  |  | downward reserve revisions related to reservior 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 from $1.75 per Mcfe during 2002 to $2.16 per Mcfe 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.                 

For 2004, based on our current reserve
base, we
expect our depreciation, depletion and amortization rate to average $2.00 per
Mcfe.

General and Administrative Expenses, Net of Overhead Reimbursements and
Capitalized General and Administrative.

|                                               |  |                          |       |      |  |          |       |         |  |   |      |  |  |  |    |  
|---------------------------------------------- |  | ------------------------ | ----- | ---- |  | -------- | ----- | ------- |  | - | ---- |  |  |  | -- | -
|                                               |  | Years Ended December 31,
|General and Administrative per Mcfe:           |  | 2003                     |       | 2002 |  | Variance |       | %change
|                                               |  |                          |       |      |  |          |       |        
|Gross general and administrative expense       |  | $                        | 0.32  |      |  | $        | 0.28  |         |  | $ | 0.04 |  |  |  | 14 | %
|Operating overhead reimbursements              |  |                          | (0.02 | )    |  |          | (0.02 | )       |  |   |     |  |  |  |   |  
|Capitalized general and administrative expense |  |                          | (0.12 | )    |  |          | (0.13 | )       |  |   | 0.01 |  |  |  | -8 | %
|                                               |  |                          |       |      |  |          |       |         |  |   |      |  |  |  |    |  
|General and administrative expense, net        |  | $                        | 0.18  |      |  | $        | 0.13  |         |  | $ | 0.05 |  |  |  | 38 | %
|                                               |  |                          |       |      |  |          |       |         |  |   |      |  |  |  |    |  

The increase in aggregate general and administrative expense is 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 No.
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. For 2004, we
estimate that net general and administrative expenses will average between
$0.19 and $0.20 per Mcfe.

Other Income and Expense, Interest and Taxes

Other Income and Expense. For 2003, Other Income and Expense includes two
components: debt extinguishment expenses totaling $5.9 million ($3.9 million
net of tax); and income of $21.6 million ($14.0 million net of tax) related to
the recoupment of prior years severance tax expense. 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. In 2002, we recognized as
other income, $9.1 million ($5.9 million net of tax) related to the recoupment
of prior years severance tax expense. For future periods, we do not expect to
recognize additional refunds in excess of $1 million. The debt extinguishment
expenses were incurred in June pursuant to the call and early redemption of our
$100 million 8-5/8% notes and the issuance of $175 million of 7% senior
subordinated notes. We paid a premium for early redemption of $4.3 million and
incurred a non-cash charge of $1.6 million to write-off the balance of the
unamortized costs associated with issuing the $100 million 8-5/8% senior
subordinated notes.

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##### Table of Contents



Interest Expense, Net of Capitalized Interest.

|                                             |  |                          |         |      |  |          |         |         |  |   |        |   |  |  |    |  
|-------------------------------------------- |  | ------------------------ | ------- | ---- |  | -------- | ------- | ------- |  | - | ------ | - |  |  | -- | -
|                                             |  | Years Ended December 31,
|                                             |  |                         
|Interest Expense and Average Borrowings      |  | 2003                     |         | 2002 |  | Variance |         | %change
|                                             |  |                          |         |      |  |          |         |        
|Gross interest                               |  | $                        | 15,642  |      |  | $        | 15,373  |         |  | $ | 269    |   |  |  | 2  | %
|Capitalized interest                         |  |                          | (7,300  | )    |  |          | (7,975  | )       |  |   | 675    |   |  |  | -8 | %
|                                             |  |                          |         |      |  |          |         |         |  |   |        |   |  |  |    |  
|Interest expense, net of amounts capitalized |  |                          | 8,342   |      |  |          | 7,398   |         |  |   | 944    |   |  |  | 13 | %
|                                             |  |                          |         |      |  |          |         |         |  |   |        |   |  |  |    |  
|Average borrowings                           |  | $                        | 240,000 |      |  | $        | 263,600 |         |  |   | 23,600 |   |  |  | 9  | %
|Average interest rate                        |  |                          | 6.08    | %    |  |          | 5.38    | %       |  |   | 0.70   | % |  |  | 13 | %

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. 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.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.

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##### Table of Contents



Operating and Financial Results for 2002 Compared to 2001

|                                     |  |                                  |         |      |  |          |         |          |  |   |         |   |  |  |     |  
|------------------------------------ |  | -------------------------------- | ------- | ---- |  | -------- | ------- | -------- |  | - | ------- | - |  |  | --- | -
|                                     |  | For the Years Ended December 31,
|                                     |  |                                 
|                                     |  | 2002                             |         | 2001 |  | Variance |         | % change
|                                     |  |                                  |         |      |  |          |         |         
|Summary operating information:       |  |                                  |         |      |  |          |         |          |  |   |         |   |  |  |     |  
|Operating revenues                   |  | $                                | 345,381 |      |  | $        | 388,509 |          |  | $ | (43,128 | ) |  |  | -11 | %
|Operating expenses                   |  |                                  | 237,467 |      |  |          | 195,994 |          |  |   | 41,473  |   |  |  | 21  | %
|Income from operations               |  |                                  | 107,914 |      |  |          | 192,515 |          |  |   | (84,601 | ) |  |  | -44 | %
|Net income                           |  | $                                | 70,494  |      |  | $        | 122,601 |          |  | $ | (52,107 | ) |  |  | -43 | %
|Production:                          |  |                                  |         |      |  |          |         |          |  |   |         |   |  |  |     |  
|Natural gas (MMcf)                   |  |                                  | 97,368  |      |  |          | 87,095  |          |  |   | 10,273  |   |  |  | 12  | %
|Oil (MBbls)                          |  |                                  | 859     |      |  |          | 459     |          |  |   | 400     |   |  |  | 87  | %
|Total (MMcfe)                        |  |                                  | 102,522 |      |  |          | 89,849  |          |  |   | 12,673  |   |  |  | 14  | %
|Average daily production (MMcfe/day) |  |                                  | 281     |      |  |          | 246     |          |  |   | 35      |   |  |  | 14  | %
|Average Sales Prices:                |  |                                  |         |      |  |          |         |          |  |   |         |   |  |  |     |  
|Natural Gas (per Mcf) realized (1)   |  | $                                | 3.32    |      |  | $        | 4.32    |          |  | $ | (1.00   | ) |  |  | -23 | %
|Natural Gas (per Mcf) unhedged       |  |                                  | 3.16    |      |  |          | 4.18    |          |  |   | (1.02   | ) |  |  | -24 | %
|Oil (per Bbl) realized (1)           |  |                                  | 23.99   |      |  |          | 22.83   |          |  |   | 1.16    |   |  |  | 5   | %



---

|(1) |  | Average realized prices include the effect of hedges.
|--- |  | -----------------------------------------------------

Operating Income

Significantly lower natural gas prices were the primary factor contributing to
our 43% decrease in net income and our 44% decrease operating income in 2002
from 2001. Operating expenses increased by 21% due to a combination of the
continued expansion of our operations, an increase in costs to maintain our
existing production base and higher DD&A rates. Offsetting the effects of
lower natural gas prices and higher operating expenses was an increase of 14%
in production volume.

Commodity Prices

Our average wellhead price during 2002 was $3.16 per MMcfe, before the effects
of our hedging program, down 24% over 2001. Natural gas and oil revenues,
before effects of hedging, decreased by $46.3 million during 2002. The effect
of the decrease in natural gas prices from 2001 levels accounted for $99.3
million of the decrease which was offset in part by an increase of $52 million
attributable to the 14% increase in production volume and $1.0 million related
to the increase in oil prices during 2002. For 2002, our natural gas and oil
revenues were increased by a $16.4 million gain from our hedging program, which
increased our average realized price for natural gas production by $0.32 Mcf
during the period.

Production Volume

During 2002, our production increased 14%. The increase was primarily
attributable to production added from properties acquired in South Texas since
December 31, 2001 together with newly developed production generated from our
subsequent development and workover programs initiated on these acquired
properties during 2002. During 2002, we successfully drilled and completed a
total of 84 new wells, consisting of 75 onshore wells and 9 offshore wells. Of
the 75 wells drilled onshore, 54 were drilled in South Texas, of which 27 were
drilled on our newly acquired acreage with the balance being drilled in our
Charco Field.

Onshore, our daily production rates increased 32% from an average of 117
MMcfe/day during 2001 to an average of 155 MMcfe/day during 2002. Properties
acquired from Conoco Inc. on December 31, 2001 accounted for 33 MMcfe/day of
the increase for 2002 and properties acquired from Burlington Resources on May
30, 2002 accounted for 7 MMcfe/day of the increase for 2002. Production from
our Charco Field in South Texas averaged 83 MMcfe/day during the current year
and remained unchanged from 2001 rates. Production from all other onshore

areas (Arkoma, East Texas, West Virginia and South Louisiana) decreased 2
MMcfe/day or approximately 6% from an average of 34 MMcfe/day during 2001 to 32
MMcfe/day during 2002 primarily a result of a decrease in production in South
Louisiana due principally to natural reservoir decline.

Offshore, our production decreased 2% from an average of 129 MMcfe/day during
2001 to an average of 126 MMcfe/day during 2002. During January 2002, we
initiated production from our newly completed facilities at Vermilion 408. We

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##### Table of Contents



added new facilities and a series of new wells throughout 2002 at East Cameron
81, 82 and 83. During September and October 2002 we evacuated and shut-in
offshore platforms and facilities due to Tropical Storms Faye and Isidore and
Hurricane Lili. We estimate that we shut-in approximately 750 MMcfe or 2
MMcfe/day on an annualized basis. In October 2002, we acquired from KeySpan
incremental working interests in 17 offshore wells that were initially
developed under a joint exploration agreement with KeySpan (see Note 6 -
Related Party Transactions  KeySpan Joint Venture) from 1999 through 2002.
Overall, for the year 2002, increments in production growth resulting from our
acquisition and our new exploration and development projects was offset by
natural production declines in existing properties. Effects of Hedging As a result of hedging activities, we realized an average gas price of $3.32
per Mcf for 2002, which was $0.16 per Mcf or 105% greater than the average
unhedged natural gas price of $3.16 that we otherwise would have received if
hedges had not been in place during the year. For 2002, our hedging activities
resulted in a gain of $16.4 million that is included in natural gas and oil
revenues. For 2001, we realized an average gas price of $4.32 per Mcf, which
was $0.14 per Mcf or 103% higher than the average unhedged natural gas price of
$4.18. As a result, natural gas and oil revenues for 2001 include a realized
gain of $12.9 million from hedging activities. Operating Expenses Years Ended December 31,2002
    
    2001
    
    Variance
    
    % changeOperating expenses (per Mcfe):Lease operating expense
    
    $
    0.33
    
    
    $
    0.28
    
    
    $
    0.05
    
    
    
    18
    %Severance tax
    
    
    0.09
    
    
    
    0.12
    
    
    
    (0.03
    )
    
    
    -25
    %Transportation expense
    
    
    0.09
    
    
    
    0.09
    
    
    
    
    
    
    
    Depreciation, depletion and amortization
    
    
    1.67
    
    
    
    1.43
    
    
    
    0.24
    
    
    
    17
    %Writedown in carrying value of properties
    
    
    
    
    
    
    0.07
    
    
    
    (0.07
    )
    
    
    100
    %General and administrative, net
    
    
    0.13
    
    
    
    0.19
    
    
    
    (0.06
    )
    
    
    -32
    %Total operating expenses per unit of production
    
    $
    2.31
    
    
    $
    2.18
    
    
    $
    0.13
    
    
    
    6
    %
 Lease Operating Expense. The increase in both lease operating expenses and
lease operating expenses per unit is attributable to the continued expansion of
our operations combined with an increase in expenses incurred during 2002.
Onshore operations expanded with the acquisition of approximately 304 new
producing wells in South Texas from the December 31, 2001 acquisition from
Conoco Inc. and the May 30, 2002 acquisition from Burlington Resources.
Excluding the incremental expenses relating to newly acquired properties, the
increase in our onshore lease operating expenses is due primarily to increased
ad valorem taxes and increased compression expenses. Ad valorem taxes
increased as a result of the high natural gas prices experienced in 2001.
Compression expenses increased during the second half of 2002 as we implemented
a project in the Charco Field to boost production by adding compressors to
streamline and lower gathering system pressure. Offshore, our lease operating
expenses increased due to the addition of production facilities at Vermilion
408 and East Cameron 81, new processing fees attributable to oil production at
Vermilion 408 where we have chosen to have a third party process our oil rather
than constructing our own oil facilities, the implementation of compression
projects to enhance production capabilities at several of our existing
facilities and finally, an increase in well control insurance premiums during
the current year. Severance Tax. The decrease in severance tax expense is primarily due to $1.3
million recorded during the fourth quarter of 2002 related to refunds of
expense incurred during the current year. 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 (see Note 9
- Commitments and Contingencies  Severance Tax Refund). In addition to the
$1.3 million recorded as a reduction to current year severance tax expense, we
recognized as other non-operating income $9.1 million for refunds relating to
prior periods. Excluding the effect for the $1.3 million, severance tax would
have been $10.8 million and $0.11 per Mcfe during 2002 compared to $11.0
million and $0.12 per Mcfe for 2001. Expense is comparable because wellhead
prices were 25% lower during 2002 as compared to wellhead prices received
during 2001; however, our onshore production increased by 32% during 2002 which
accounts for the decrease in the adjusted severance tax on a per unit basis. Depreciation, Depletion and Amortization. The increase in depreciation,
depletion and amortization expense was a result of higher production volumes
combined with a higher depletion rate. Our depletion rate increased in 2002 as
we completed the evaluation of several properties that were classified as
unproved at December 31, 2001. As evaluation is completed, the costs
associated with these properties were reclassified into our amortization base.
The higher depletion rate is a result of a combination of adding costs to the
full cost pool with fewer new reserves being added from exploration and
developmental drilling together with an overall increase in our finding and
development costs. We believe that higher finding costs are -30-




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being experienced across the industry, particularly for companies our size
whose primary area of exploration is the Outer Continental Shelf or the shallow
waters of the Gulf of Mexico. General and Administrative Expenses, Net of Overhead Reimbursements and
Capitalized General and Administrative Expenses Years Ended December 31,General and Administrative per Mcfe:
    
    2002
    
    2001
    
    Variance
    
    %changeGross general and administrative expense
    
    $
    0.28
    
    
    $
    0.34
    
    
    $
    (0.06
    )
    
    
    -18
    %Less effects of 2001 on-time charge
    
    
    
    
    
    
    (0.06
    )
    
    
    (0.06
    )
    
    
    100
    %Gross general and administrative expense, adjusted
    
    
    0.28
    
    
    
    0.28
    
    
    
    
    
    
    
    Operating overhead reimbursements
    
    
    (0.02
    )
    
    
    (0.01
    )
    
    
    (0.01
    )
    
    
    100
    %Capitalized general and administrative expense
    
    
    (0.13
    )
    
    
    (0.14
    )
    
    
    0.01
    
    
    
    -7
    %General and administrative expense, net
    
    $
    0.13
    
    
    $
    0.13
    
    
    $
    
    
    
    
    
 Included in aggregate and net administrative expenses during 2001 were payments
totaling $5.2 million, $0.06 per Mcfe in 2001, made in connection with the
termination of former executive officers employment contracts. Excluding the
one-time charges during 2001, both aggregate and net general and administrative
expenses for 2002 are comparable to 2001. Per unit expense were unchanged as
aggregate dollars increased by 8% year over year (excluding the effect of the
one-time charge in 2001) as a result of the 14% increase in production for
2002. Aggregate expenses incurred increased as a result of the overall
expansion of our business, our workforce and our office space. Payroll and
employee benefits, rent and utilities and legal, accounting and consulting
expenses all increased during 2002. Overhead reimbursements increased due to
an increase in the number of producing properties operated that have third
party working interests. On a percentage basis, we capitalized approximately
the same percentage of general and administrative expenses during both 2002 and
2001. Other Income and Expense, Interest and Taxes Other Income and Expense.For 2002, we recorded other income of $9.1 million
relating to refund of severance tax paid in prior periods and recorded pursuant
to our receipt of a high-cost/tight sand designation for a portion of our
South Texas production (see Note 9  Commitments and Contingencies  Severance
Tax Refund). For 2001, we incurred an additional $0.1 million in expenses
relating to a strategic review initiated in the fourth quarter of 1999 and
completed in the first quarter of 2000. In September 1999, together with
KeySpan, our majority stockholder, we had announced our intention to review
strategic alternatives for our company and KeySpans investment in our company.
Consideration was given to a full range of strategic transactions including
the possible sale of all or a portion of our assets. On February 25, 2000, we
announced, together with KeySpan, that the review of strategic alternatives for
Houston Exploration had been completed. Interest Expense, Net of Capitalized Interest. Years Ended December 31,Interest Expense and Average Borrowings
    
    2002
    
    2001
    
    Variance
    
    %changeGross interest expense
    
    $
    15,373
    
    
    $
    15,034
    
    
    $
    339
    
    
    
    2
    %Capitalized interest
    
    
    (7,975
    )
    
    
    (12,042
    )
    
    
    4,067
    
    
    
    -34
    %Interest expense, net of amounts capitalized
    
    $
    7,398
    
    
    $

    2,992
    
    
    $
    4,406
    
    
    
    147
    %Average borrowings
    
    $
    263,600
    
    
    $
    190,900
    
    
    $
    72,700
    
    
    
    38
    %Average interest rate
    
    
    5.38
    %
    
    
    7.43
    %
    
    $
    0.05
    
    
    
    -28
    %
 During 2002, aggregate interest increased slightly by 2% as our average
outstanding borrowing increased and our average interest rate decreased. Net
interest expense increased substantially during 2002 as we capitalized 34% less
interest as a result of a decrease in exploratory drilling during 2002. Our
capitalized interest is a function of exploratory drilling and unevaluated
properties, both of which were at lower levels during 2002. Income Tax Provision. The provision for income taxes decreased due to the 42%
decrease in pre-tax income during 2002 as a result of the combination of a
decrease in natural gas revenues and increases in both operating expenses and
net interest expense. -31-




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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 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
    
    Indirect costs related to our exploration activities, including payroll
and other expense attributable to our exploration professional staff. Our capital expenditure budget for 2004 has been set at an initial level of
$315 million. We are the designated operator of approximately 85% 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. During 2003, we invested $459.9 million in natural gas and oil properties,
which includes $175.4 million for the acquisition of producing properties, and
$1.9 million for other property and equipment. Investments in non-natural gas
and oil properties includes the expansion of our Houston office space together
with upgrades to our information technology systems and equipment and compares
to $2.4 million spent in 2002. For 2003, we spent 59% offshore and 36% onshore
with the balance of 5% on capitalized interest and general and administrative
costs. We completed the drilling of a record 147 gross wells (116.3 net) of
which 77% or 113 (89.3 net) were successful and 38 (27.0 net) were unsuccessful
with an additional 16 wells (12.2 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, total net proved reserve
additions and our average all-in finding and development costs. Years Ended December 31,(in thousands, except per unit amounts)2003
    
    2002
    
    2001
    
    2000
    
    1999Natural gas and oil capital expendituresProducing property acquisitions (1)
    
    $
    175,420
    
    
    $
    68,042
    
    
    $
    69,010
    
    
    $
    13,935
    
    
    $
    21,746Leasehold and lease acquisition costs(2)
    
    
    56,076
    
    
    
    36,458
    
    
    
    48,068
    
    
    
    32,599
    
    
    
    25,696Development
    
    
    162,235
    
    
    
    122,036
    
    
    
    177,256
    
    
    
    103,335
    
    
    
    87,965Exploration
    
    
    66,259
    
    
    
    26,536
    
    
    
    72,056
    
    
    
    34,160
    
    
    
    12,257Total natural gas and oil capital expenditures
    
    $
    459,990
    
    
    $
    253,072
    
    
    $
    366,390
    
    
    $
    184,029
    
    
    $
    147,664Proved reserve additions, net of revisions (MMcfe)
    
    
    212,969
    
    
    
    144,291
    
    
    
    136,231
    
    
    
    100,352
    
    
    
    135,791Finding and development cost per Mcfe
    
    $
    2.16
    
    
    $
    1.75
    
    
    $
    2.69
    
    
    $
    1.83
    
    
    $
    1.09
   (1)
    
    For 2002, producing property acquisitions is net of dispositions of $5.3
million.(2)
    
    For 2003, 2002, 2001, 2000 and 1999, leasehold costs include capitalized
interest and general and administrative expenses of $20.2 million, $21.1
million, $24.9 million, $23.3 million and $17.4 million, respectively. -32-




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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. 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, 2003. In
addition to the contractual obligations listed on the table below, our balance
sheet at December 31, 2003, reflects accrued interest payable on our revolving
bank credit facility of $12,200 which is payable over the next 90-day period.
We expect to make annual interest payments of $12.5 million per year on our
$175 million of 7% senior subordinated notes due June 2013. And, we anticipate
making income tax payments of approximately $30 million to $40 million in 2004. At December 31, 2003Payments Due by PeriodTotal
    
    1 year or less
    
    2 - 3 years
    
    4 - 5 years
    
    after 5 years(in thousands)Contractual Obligations:Revolving bank credit facility, due July 2005
    
    $
    127,000
    
    
    $
    
    
    
    $
    127,000
    
    
    $
    
    
    
    $
    7% senior subordinated notes, due June 2013
    
    
    175,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    175,000Operating leases
    
    
    8,343
    
    
    
    1,470
    
    
    
    4,374
    
    
    
    2,500
    
    
    
    310,343
    
    
    
    1,470
    
    
    
    131,374
    
    
    
    2,500
    
    
    
    175,000Other Long-Term Obligations:Asset retirement obligations
    
    
    92,357
    
    
    
    7,543
    
    
    
    13,555
    
    
    
    6,825
    
    
    
    64,435Total contractual obligations and commitments
    
    $
    402,700
    
    
    $
    9,013
    
    
    $
    144,929
    
    
    $
    9,325
    
    
    $
    239,435
 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. To the extent we make a significant acquisition, we may also
access public markets for debt. Our primary sources of cash during 2003 were
from funds generated from operations and net proceeds received from the
concurrent early redemption of our $100 million 8-5/8% senior subordinated
notes and the issuance of $175 million 7% senior subordinated notes in June.
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 $18.4 million and $14.8 million, respectively, for interest
and taxes. The table below summarizes the sources of cash during 2003 and 2002. Years Ended December 31,2003
    
    2002
    
    variance
    
    % changeNet income
    
    $
    131,040
    
    
    $
    70,494
    
    
    $
    60,546
    
    
    
    86
    %Non-cash charges
    
    
    268,228
    
    
    
    211,555
    
    
    
    56,673
    
    
    
    27
    %Cash from operations before changes in operating
assets and liabilities
    
    
    399,268
    
    
    
    282,049
    
    
    
    117,219
    
    
    
    42
    %Change (increase) in operating assets and liabilities
    
    
    (8,436
    )
    
    
    (38,180
    )
    
    
    29,744
    
    
    
    78
    %Net cash provided by operating activities
    
    
    390,832
    
    
    
    243,869
    
    
    
    146,963
    
    
    
    60
    %Net cash used for investments in property and equipment
    
    
    461,822
    
    
    
    252,125
    
    
    
    209,697
    
    
    
    83
    %Net cash provided by financing activities
    
    
    55,528
    
    
    
    17,668
    
    
    
    37,860
    
    
    
    214
    %Net (decrease) increase in cash
    
    $
    (15,462
    )
    
    $
    9,412
    
    
    $
    (24,874
    )
    
    -
    264
    %
 At December 31, 2003, we had a working capital deficit of $36,000, long-term
debt of $302 million and $172.6 million of borrowing capacity available under
our revolving bank credit facility. The working capital deficit was due to a
current liability of $36.5 million representing the fair value of our
derivative instruments. 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- -33-




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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. The 60% increase in net cash provided by operating activities during 2003 was
primarily attributable to the increase in net income as a result of a 37%
increase in average realized natural gas price, which includes the
effects of hedging, together with a 5% increase in
production volume, offset in part by a 24% increase in operating expenses. The
increase in non-cash charges for 2003 was primarily a result of the increase in
depreciation, depletion and amortization and deferred tax expense combined with
current year charges for debt extinguishment, ineffectiveness of our derivative
instruments and the cumulative effect of adopting SFAS 143 for asset retirement
obligations. The increase in cash from operations was reduced in part by a net
increase in operating assets and liabilities. Fluctuations in operating assets
and liabilities are caused by the timing of cash receipts and disbursements. During 2003, we took advantage of lower long-term interest rates to increase
our available borrowing capacity under our revolving bank credit facility. In
June, we called and redeemed our $100 million 8-5/8% notes due 2008 and issued
$175 million 7% senior subordinated notes. The net proceeds from the $175
million notes were used to repay the outstanding principal and interest on the
$100 million notes together with a premium of $4.3 million for early
redemption. We used the remaining net proceeds to repay outstanding borrowings
under our revolving bank credit facility and by the end of the third quarter of
2003, we had reduced our bank borrowings from $157 million at December 31, 2002
to zero at September 30, 2003. In the fourth quarter of 2003, we increased our
bank borrowings to $127 million of which $115 million was used in October to
finance a portion of the Transworld net purchase price of $147.5 million with
the balance borrowed in December to fund a portion of the $27.9 million net
purchase price for the EnerVest properties. For 2003, total long-term debt
increased by a net $50 million as we increased fixed debt by $75 million and
reduced our bank debt by $25 million compared to an increase of $8 million in
total long-term borrowings during 2002. We received cash proceeds of $10.2
million for the issuance of common stock from the exercise of stock options
compared to $9.7 million received in 2002. And, during the first quarter of
2003, we sold 3 million newly issued shares of our common stock in a public
offering for net proceeds of $79.2 million, and simultaneously repurchased the
same number of shares from KeySpan for $79.2 million. 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 as documentation agent.
The credit facility provides us with a commitment of $300 million which may be
increased at our request and with prior approval from Wachovia to a maximum of
$350 million by adding one or more lenders or by allowing one or more lenders
to increase their commitments. The credit facility is subject to borrowing
base limitations. Our current borrowing base is $300 million and is
redetermined semi-annually, with the next redetermination scheduled for April
1, 2004. Up to $25 million of the borrowing base is available for the issuance
of letters of credit. The credit facility matures July 15, 2005, is unsecured
and with the exception of trade payables, ranks senior to our 7% senior
subordinated notes. At December 31, 2003, we were in compliance with all
covenants. See Note 2  Long-term Debt and Notes for a summary of material
covenants. At December 31, 2003, we had borrowings under our revolving bank credit
facility of $127 million and $0.4 million in outstanding letter of credit
obligations. Subsequent to December 31, 2003, we repaid a net $37 million in
outstanding borrowing under the facility, the primary source of these funds was
proceeds received from the sale of our South Louisiana properties in early
February 2004. At March 12, 2004, the date of this report, outstanding
borrowings and letter of credit obligations under our revolving bank credit
facility total $90.4 million. In an effort to increase our borrowing capacity for property acquisitions, we
are in the process of amending our current revolving bank credit facility to
increase the borrowing capacity from $300 million to $400 million. The lenders
and the primary terms and conditions of the new facility are expected to be
consistent with the existing facility. The commitment is expected to increase
to $400 million with the capability to increase the commitment to $450 million
and we expect to have $40 million of the borrowing base available for letters
of credit. The new facility is expected to become effective on April 1, 2004.
Our initial borrowing base is expected to be $375 million and is scheduled for
redetermination October 1, 2004. Outstanding borrowings are expected to
continue to be unsecured and with the exception of trade payables, the new
facility is expected to rank senior to our $175 million 7% subordinated notes.
The new facility is expected to mature on April 1, 2008. Senior Subordinated Notes.On June 10, 2003, we issued $175 million 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 which 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 -34-




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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 $175 million 7% senior subordinated notes were issued in conjunction with
the call and early redemption of our $100 million 8-5/8% senior subordinated
notes due January 1, 2008. The redemption and payment of the call premium on
the $100 million notes was funded with a portion of the proceeds received from
the issuance of the $175 million 7% senior subordinated notes. Pursuant to the
early redemption of the $100 million notes, we incurred debt extinguishment
expenses totaling $5.9 million ($3.9 million net of tax) consisting of the call
premium of $4.3 million together with a non-cash charge of $1.6 million for the
write-off of the balance of the unamortized issue costs of the 8-5/8% notes.
The debt extinguishment expenses of $5.9 million are included in the line item
Other (Income) Expense on the Statement of Operations for the year ended
December 31, 2003. Access to Capital Markets. We currently have on file with the SEC a shelf
registration statement covering the sale, from time to time, of our common
stock, preferred stock, depositary shares and debt securities, or a combination
of any of these securities. The shelf was filed in May 1999 and provided for
an initial aggregate public offering price of up to $250 million. In February
2003, we sold 3,000,000 shares of our common stock to the public under the
shelf registration statement and used the proceeds to concurrently repurchase
three million shares of our common stock from KeySpan. Following that
offering, we had approximately $169.8 million of capacity remaining under the
shelf. In March 2004, we plan to terminate our existing shelf registration
statement and replace it with a new shelf registration statement to be filed
with the SEC covering 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 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 2004. 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 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. -35-




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Item 7A.Quantitative and Qualitative Disclosures About Market Risk Natural Gas and Oil Hedging 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
No.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 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 other income or expense. In 2003, we recognized $1.9
million of ineffectiveness. 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 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. Ineffectiveness was not material prior to 2003. 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,
2003 and 2002 and provides the fair value at the end of each period. 2003
    
    2002Before Tax
    
    After Tax
    
    Before Tax
    
    After TaxChange in Fair Value of Derivatives InstrumentsFair value of contracts at January 1
    
    $
    (38,772
    )
    
    $
    (25,202
    )
    
    $
    53,771
    
    
    $
    34,951(Gain) loss on contracts settled and realized
    
    
    66,408
    
    
    
    43,165
    
    
    
    (16,358
    )
    
    
    (10,633
    )Fair value of new contracts when entered into
during period
    
    
    5,288
    
    
    
    
    
    
    
    
    
    
    
    (Decrease) in fair value of all open contracts
    
    
    (69,786
    )
    
    
    (44,091
    )
    
    
    (76,185
    )
    
    
    (49,520
    )Fair value of contracts outstanding at December 31
    
    $
    (36,862
    )
    
    $
    (26,128
    )
    
    $
    (38,772
    )
    
    $
    (25,202
    )
 Derivatives in Place as of the Date of Our Report As of March 12, 2004, the date of this report, the following table summarizes,
on a monthly basis, our natural gas hedges in place for 2004 and 2005. For
each month of 2004, we have hedged approximately 70% of our estimated
production or a total of 240,000 million British thermal units per day or
MMBtu/day. For the three months January through March 2004, our floor price
will average $4.472/MMBtu on 240,000 MMBtu/day and our ceiling price will
average $5.021/MMBtu on 140,000 MMBtu/day, with no ceiling price on the
remaining 100,000 MMBtu/day. For the remaining nine months of 2004, our floor
price will average $4.264/MMBtu on 240,000 MMBtu/day and our ceiling price will
average $5.845/MMBtu on 240,000 MMBtu/day. For each calendar month of 2005, we
have 150,000 MMBtu/day hedged with an effective floor price of $4.589 and an
effective ceiling price of $5.255. All amounts in the table below are in
thousands, except for prices. -36-




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##### Table of Contents



Natural Gas Hedges
    
    Options - Puts
    
    Fixed Price Swaps
    
    CollarsVolume
    
    NYMEX
    
    Volume
    
    NYMEX
    
    Volume
    
    NYMEXPeriod
    
    (MMbtu)
    
    Contract Price
    
    (MMbtu)
    
    Contract Price
    
    (MMbtu)
    
    Contract PriceAvg Floor
    
    Avg CeilingJanuary 2004
    
    
    3,100
    
    
    $
    5.000
    
    
    
    1,240
    
    
    $
    4.960
    
    
    
    3,100
    
    
    $
    3.750
    
    
    $
    5.045February 2004
    
    
    2,900
    
    
    
    5.000
    
    
    
    1,160
    
    
    
    4.960
    
    
    
    2,900
    
    
    
    3.750
    
    
    
    5.045March 2004
    
    
    3,100
    
    
    
    5.000
    
    
    
    1,240
    
    
    
    4.960
    
    
    
    3,100
    
    
    
    3.750
    
    
    
    5.045April 2004
    
    
    
    
    
    
    
    
    
    
    1,200
    
    
    
    4.960
    
    
    
    6,000
    
    
    
    4.125
    
    
    
    6.023May 2004
    
    
    
    
    
    
    
    
    
    
    1,240
    
    
    
    4.960
    
    
    
    6,200
    
    
    
    4.125
    
    
    
    6.023June 2004
    
    
    
    
    
    
    
    
    
    
    1,200
    
    
    
    4.960
    
    
    
    6,000
    
    
    
    4.125
    
    
    
    6.023July 2004
    
    
    
    
    
    
    
    
    
    
    1,240
    
    
    
    4.960
    
    
    
    6,200
    
    
    
    4.125
    
    
    
    6.023August 2004
    
    
    
    
    
    
    
    
    
    
    1,240
    
    
    
    4.960
    
    
    
    6,200
    
    
    
    4.125
    
    
    
    6.023September 2004
    
    
    
    
    
    
    
    
    
    
    1,200
    
    
    
    4.960
    
    
    
    6,000
    
    
    
    4.125
    
    
    
    6.023October 2004
    
    
    
    
    
    
    
    
    
    
    1,240
    
    
    
    4.960
    
    
    
    6,200
    
    
    
    4.125
    
    
    
    6.023November 2004
    
    
    
    
    
    
    
    
    
    
    1,200
    
    
    
    4.960
    
    
    
    6,000
    
    
    
    4.125
    
    
    
    6.023December 2004
    
    
    
    
    
    
    
    
    
    
    1,240
    
    
    
    4.960
    
    
    
    6,200
    
    
    
    4.125
    
    
    
    6.023January 2005
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    4.766
    
    
    
    3,100
    
    
    
    4.500
    
    
    
    5.500February 2005
    
    
    
    
    
    
    
    
    
    
    1,450
    
    
    
    4.766
    
    
    
    2,800
    
    
    
    4.500
    
    
    
    5.500March 2005
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    4.766
    
    
    
    3,100
    
    
    
    4.500
    
    
    
    5.500April 2005
    
    
    
    
    
    
    
    
    
    
    1,500
    
    
    
    4.766
    
    
    
    3,000
    
    
    
    4.500
    
    
    
    5.500May 2005
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    4.766
    
    
    
    3,100
    
    
    
    4.500
    
    
    
    5.500June 2005
    
    
    
    
    
    
    
    
    
    
    1,500
    
    
    
    4.766
    
    
    
    3,000
    
    
    
    4.500
    
    
    
    5.500July 2005
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    4.766
    
    
    
    3,100
    
    
    
    4.500
    
    
    
    5.500August 2005
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    4.766
    
    
    
    3,100
    
    
    
    4.500
    
    
    
    5.500September 2005
    
    
    
    
    
    
    
    
    
    
    1,500
    
    
    
    4.766
    
    
    
    3,000
    
    
    
    4.500
    
    
    
    5.500October 2005
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    4.766
    
    
    
    3,100
    
    
    
    4.500
    
    
    
    5.500November 2005
    
    
    
    
    
    
    
    
    
    
    1,500
    
    
    
    4.766
    
    
    
    3,000
    
    
    
    4.500
    
    
    
    5.500December 2005
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    4.766
    
    
    
    3,100
    
    
    
    4.500
    
    
    
    5.500
 For natural gas, transactions are settled based upon the New York Mercantile
Exchange or NYMEX price on the final trading day of the month. For oil, our
swaps are settled against the average NYMEX price of oil for the calendar month
rather than the last 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. -37-




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Item 8.Financial Statements 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. 
 Item 9A.Controls and Procedures We maintain disclosure controls and procedures that are designed to ensure that
information required to be disclosed by us in the reports we file under the
Securities Exchange Act of 1934, as amended (Exchange Act) is communicated,
processed, summarized and reported within the time periods specified in the
SECs rules and forms. We carried out an evaluation under the supervision and
with the participation of our management, including our principal executive
officer and principal financial officer, of the effectiveness of our disclosure
controls and procedures (as defined in Rule 13a-14 of the Exchange Act), as of
the end of the period covered by this report. Based on that evaluation, our
principal executive officer and principal financial officer concluded that, as
of December 31, 2003, our disclosure controls and procedures are functioning
effectively as designed. There have been no changes in our internal control
over financial reporting that occurred during the most recent fiscal quarter
prior to the end of the period covered by this report that have materially
affected, or are reasonable likely to materially affect, our internal controls
over financial reporting. 
 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, 2003. 
 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, 2003. 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, 2003. 
 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, 2003. -38-




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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 2003 and 2002 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, 2003. 
 Part IV. 
 Item 15.Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) Documents Filed as a Part of this Report 1. Financial Statements: PAGEIndex to Financial Statements
    
    
    F-1Independent Auditors Report
    
    
    F-2Consolidated Balance Sheets As of December 31, 2003 and 2002
    
    
    F-3Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001
    
    
    F-4Consolidated Statements of Stockholders Equity and Comprehensive Income for the Period
January 1, 2001 to December 31, 2003
    
    
    F-5Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001
    
    
    F-7Notes to Consolidated Financial Statements
    
    
    F-8Supplemental Information on Natural Gas and Oil Exploration, Development andProduction Activities (Unaudited)
    
    
    F-32Quarterly Financial Information (Unaudited)
    
    
    F-35
 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-37 for a description of the exhibits
filed as a part of this report.(b)
    
    Reports on Form 8-K.Current Report on Form 8-K filed on October 29, 2003 to report under Item 2.  Acquisition or Disposition of Assets our completion of
the acquisition of the natural gas and oil properties from Transworld
Exploration and Production Inc. on October 15, 2003.Current Report on Form 8-K filed on November 6, 2003 to furnish under Item 12 -
Results of Operations and Financial Conditions our earnings release for the
third quarter of 2003 and the nine-month period ended September 30, 2003.Current Report on Form 8-K filed on November 10,2003 to report under Item 11 -
Temporary Suspension of Trading Under Registrants Employee Benefit Plans our
notice sent to our directors and executive officers subject to Section 16 of
the Securities and Exchange Act of 1934, informing them of a blackout period
under our 401(k) Plan and Trust.Current Report on Form 8-K/A filed on December 4, 2003 that amended our Form
8-K filed on June 3, 2003 to report under Item 5  Other
Events and Regulation FD Disclosure selected historical financial data and a
reconciliation of non-GAAP financial measures to GAAP measures.Current Report on Form 8-K filed on February 5, 2004 to furnish under Item 12 -
Results of Operations and Financial Conditions our earnings release for the
fourth quarter of 2003 and the twelve-month period ended December 31, 2003. -39-




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##### Table of Contents



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: March 12, 2004
    
    
    
    President and Chief Executive Officer
 -40-




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##### Table of Contents



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
    
    President, Chief Executive Officer and Director
(Principal Executive Officer)
    
    March 12, 2004/s/ John H. Karnes
    John
H. Karnes
    
    Senior Vice President and Chief
Financial Officer
(Principal Financial Officer)
    
    March 12, 2004/s/ James F. Westmoreland
    James
F. Westmoreland
    
    Vice President and Chief Accounting Officer
(Principal Accounting Officer)
    
    March 12, 2004/s/ Robert B. Catell
    Robert
B. Catell
    
    Chairman of the Board of Directors
    
    March 12, 2004/s/ Gordon F. Ahalt
    Gordon
F. Ahalt
    
    Director
    
    March 12, 2004/s/ John U. Clarke
    John
U. Clarke
    
    Director
    
    March 12, 2004/s/ David G. Elkins
    David
G. Elkins
    
    Director
    
    March 12, 2004/s/ Robert J. Fani
    Robert
J. Fani
    
    Director
    
    March 12, 2004/s/ Harold R. Logan, Jr.
    Harold
R. Logan, Jr.
    
    Director
    
    March 12, 2004/s/ Gerald Luterman
    Gerald
Luterman
    
    Director
    
    March 12, 2004/s/ Stephen W. McKessy
    Stephen
W. McKessy
    
    Director
    
    March 12, 2004/s/ H. Neil Nichols
    H.
Neil Nichols
    
    Director
    
    March 12, 2004/s/ James Q. Riordan
    James
Q. Riordan
    
    Director
    
    March 12, 2004/s/ Donald C. Vaughn
    Donald
C. Vaughn
    
    Director
    
    March 12, 2004
 -41-




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##### Table of Contents



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. MMBbls. One million barrels of crude oil or other liquid hydrocarbons. MMbtu. One million Btus. MMMbtu. One billion Btus. G-1




---



##### Table of Contents



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 website,
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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##### Table of Contents



Index to Financial Statements PageIndependent Auditors Report
    
    
    F-2Consolidated Balance Sheets As of December 31, 2003 and 2002
    
    
    F-3Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001
    
    
    F-4Consolidated Statements of Stockholders Equity and Comprehensive Income (Loss) for the Period
January 1, 2001 to December 31, 2003
    
    
    F-5Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001
    
    
    F-7Notes to Consolidated Financial Statements
    
    
    F-8Supplemental Information on Natural Gas and Oil Exploration, Development and
Production Activities (Unaudited)
    
    
    F-32Quarterly Financial Information (Unaudited)
    
    
    F-35
 F-1




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INDEPENDENT AUDITORS REPORT To the Board of Directors and Stockholders of
The Houston Exploration Company We have audited the accompanying consolidated balance sheets of The Houston
Exploration Company (a Delaware corporation and an indirect 55% owned
subsidiary of KeySpan Corporation) and subsidiary (the Company) as of
December 31, 2003 and 2002, 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, 2003. These financial
statements are the responsibility of the Companys management. Our
responsibility is to express an opinion on the financial statements based on
our audits. We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidences 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,
2003 and 2002, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2003 in conformity with
accounting principles generally accepted in the United States of America. 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 17, 2004 F-2




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THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data) December 31,2003
    
    2002Assets:Cash and cash equivalents
    
    $
    2,569
    
    
    $
    18,031Accounts receivable
    
    
    87,949
    
    
    
    86,713Accounts receivable  Affiliate
    
    
    6,733
    
    
    
    3,106Derivative financial instruments
    
    
    3,458
    
    
    
    Inventories
    
    
    1,071
    
    
    
    1,432Deferred tax asset
    
    
    19,644
    
    
    
    12,252Prepayments and other
    
    
    5,818
    
    
    
    2,196Total current assets
    
    
    127,242
    
    
    
    123,730Natural gas and oil properties, full cost method
Unevaluated properties
    
    
    134,491
    
    
    
    96,192Properties subject to amortization
    
    
    2,324,011
    
    
    
    1,828,160Other property and equipment
    
    
    12,617
    
    
    
    10,6992,471,119
    
    
    
    1,935,051Less: Accumulated depreciation, depletion and amortization
    
    
    1,099,990
    
    
    
    912,6371,371,129
    
    
    
    1,022,414Other non-current assets
    
    
    10,694
    
    
    
    4,924Total Assets
    
    $
    1,509,065
    
    
    $
    1,151,068Liabilities:Accounts payable and accrued expenses
    
    $
    83,983
    
    
    $
    78,175Derivative financial instruments
    
    
    35,592
    
    
    
    35,005Asset retirement obligation
    
    
    7,703
    
    
    
    Total current liabilities
    
    
    127,278
    
    
    
    113,180Long-term debt and notes
    
    
    302,000
    
    
    
    252,000Derivative financial instruments
    
    
    4,728
    
    
    
    3,767Deferred federal income taxes
    
    
    251,425
    
    
    
    188,215Asset retirement obligation
    
    
    84,654
    
    
    
    Other deferred liabilities
    
    
    3,446
    
    
    
    1,117Total Liabilities
    
    
    773,531
    
    
    
    558,279Commitments and Contingencies (see Note 9)Stockholders Equity:Common Stock, $.01 par value, 50,000,000 shares authorized and
31,437,581 and 30,954,018 shares issued and outstanding at
December 31, 2003 and 2002, respectively
    
    
    315
    
    
    
    310Additional paid-in capital
    
    
    366,781
    
    
    
    353,454Unearned compensation
    
    
    (808
    )
    
    
    (107
    )Retained earnings
    
    
    395,374
    
    
    
    264,334Accumulated other comprehensive income
    
    
    (26,128
    )
    
    
    (25,202
    )Total Stockholders Equity
    
    
    735,534
    
    
    
    592,789Total Liabilities and Stockholders Equity
    
    $
    1,509,065
    
    
    $
    1,151,068
 The accompanying notes are an integral part of these consolidated financial statements. F-3




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data) For the Years Ended December 31,2003
    
    2002
    
    2001Revenues:Natural gas and oil revenues
    
    $
    491,440
    
    
    $
    344,295
    
    
    $
    387,156Other
    
    
    1,312
    
    
    
    1,086
    
    
    
    1,353Total revenues
    
    
    492,752
    
    
    
    345,381
    
    
    
    388,509Operating expenses:Lease operating
    
    
    47,072
    
    
    
    33,976
    
    
    
    25,291Severance tax
    
    
    15,958
    
    
    
    9,487
    
    
    
    11,035Transportation expense
    
    
    10,387
    
    
    
    9,317
    
    
    
    7,652Asset retirement accretion expense
    
    
    3,668
    
    
    
    
    
    
    
    Depreciation, depletion and amortization
    
    
    197,530
    
    
    
    171,610
    
    
    
    128,736Writedown in carrying value of natural gas and oil properties
    
    
    
    
    
    
    
    
    
    
    6,170General and administrative, net of amounts capitalized
    
    
    19,542
    
    
    
    13,077
    
    
    
    17,110Total operating expenses
    
    
    294,157
    
    
    
    237,467
    
    
    
    195,994Income from operations
    
    
    198,595
    
    
    
    107,914
    
    
    
    192,515Other (income) expense
    
    
    (15,746
    )
    
    
    (9,070
    )
    
    
    119Interest expense, net of amounts capitalized
    
    
    8,342
    
    
    
    7,398
    
    
    
    2,992Income before income taxes
    
    
    205,999
    
    
    
    109,586
    
    
    
    189,404Provision for taxes
    
    
    72,187
    
    
    
    39,092
    
    
    
    66,803Income before cumulative effect of change in
accounting principle
    
    $
    133,812
    
    
    $
    70,494
    
    
    $
    122,601Cumulative effect of change in accounting principle
    
    
    (2,772
    )
    
    
    
    
    
    
    Net income
    
    $
    131,040
    
    
    $
    70,494
    
    
    $
    122,601Earnings per share:Net income per share  basicIncome before cumulative effect of change in
accounting principle
    
    $
    4.30
    
    
    $
    2.31
    
    
    $
    4.06Cumulative effect of change in accounting principle
    
    
    (0.09
    )
    
    
    
    
    
    
    Net income per share  basic
    
    $
    4.21
    
    
    $
    2.31
    
    
    $
    4.06Net income per share  fully dilutedIncome before cumulative effect of change in
accounting principle
    
    $
    4.29
    
    
    $
    2.28
    
    
    $
    4.00Cumulative effect of change in accounting principle
    
    
    (0.09
    )
    
    
    
    
    
    
    Net income per share  fully diluted
    
    $
    4.20
    
    
    $
    2.28
    
    
    $
    4.00Weighted average shares outstanding  basic
    
    
    31,097
    
    
    
    30,569
    
    
    
    30,228Weighted average shares outstanding  fully diluted
    
    
    31,213
    
    
    
    30,878
    
    
    
    30,645
 The accompanying notes are an integral part of these consolidated financial statements. F-4




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
AND COMPREHENSIVE INCOME
(in thousands, except share data) AccumulatedCommon Stock
    
    Additional
    
    
    
    
    
    Retained
    
    Other
    
    TotalPaid-In
    
    Unearned
    
    Earnings
    
    Comprehensive
    
    StockholdersShares
    
    $ Value
    
    Capital
    
    Compensation
    
    (Deficit)
    
    Income (Loss)
    
    EquityBalance January 1, 2001
    
    
    29,829,050
    
    
    $
    298
    
    
    $
    325,205
    
    
    $
    
    
    
    $
    71,239
    
    
    $
    
    
    
    $
    396,742Issuance of
common stock, par value $0.01(1)
    
    
    624,180
    
    
    
    6
    
    
    
    10,183
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    10,189Issuance of restricted common stock,
par value $0.01(2)
    
    
    10,000
    
    
    
    1
    
    
    
    255
    
    
    
    (256
    )Stock
compensation expense  amortization
restricted stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    64
    
    
    
    
    
    
    
    
    
    
    
    64Tax benefit from exercise of non-qualified
stock options
    
    
    
    
    
    
    
    
    
    
    1,334
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,334Comprehensive income:Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    122,601
    
    
    
    
    
    
    
    122,601Other comprehensive income (as restated):Cumulative effect of accounting change
for derivative instruments, net of tax
benefit of $26,274
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (48,795
    )
    
    
    (48,795
    )Derivative settlements reclassified to
income, net of tax benefit of $4,524
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (8,402
    )
    
    
    (8,402
    )Unrealized gain due to change in fair
value
of derivative instruments, net of
tax expense of $49,618
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    92,148
    
    
    
    92,148Total comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    157,552Balance December 31, 2001
    
    
    30,463,230
    
    
    $
    305
    
    
    $
    336,977
    
    
    $
    (192
    )
    
    $
    193,840
    
    
    $
    34,951
    
    
    $
    565,881Issuance of common stock, value $0.01(1)
    
    
    490,788
    
    
    
    5
    
    
    
    9,663
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9,668Contributed capital from KeySpan (3)
    
    
    
    
    
    
    
    
    
    
    2,039
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,039Stock
compensation expense  amortization
of restricted stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    85
    
    
    
    
    
    
    
    
    
    
    
    85Tax benefit from 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 benefit of $5,725
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (10,633
    )
    
    
    (10,633
    )Unrealized loss due to change in fair
value of derivative instruments, net of
tax benefit of $26,665
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (49,520
    )
    
    
    (49,520
    )Total comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    10,341Balance December 31, 2002
    
    
    30,954,018
    
    
    $
    310
    
    
    $
    353,454
    
    
    $
    (107
    )
    
    $
    264,334
    
    
    $
    (25,202
    )
    
    $
    592,789
 (continued on next page) F-5




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
AND COMPREHENSIVE INCOME
(continued) AccumulatedCommon Stock
    
    Additional
    
    
    
    
    
    Retained
    
    Other
    
    TotalPaid-In
    
    Unearned
    
    Earnings
    
    Comprehensive
    
    StockholdersShares
    
    $ Value
    
    Capital
    
    Compensation
    
    (Deficit)
    
    Income (Loss)
    
    EquityBalance December 31, 2002
    
    
    30,954,018
    
    
    $
    310
    
    
    $
    353,454
    
    
    $
    (107
    )
    
    $
    264,334
    
    
    $
    (25,202
    )
    
    $
    592,789Issuance of common stock, par value $0.01(1)
    
    
    461,563
    
    
    
    5
    
    
    
    10,218
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    10,223Issuance of restricted stock, par value $0.01(4)
    
    
    22,000
    
    
    
    
    
    
    
    812
    
    
    
    (812
    )
    
    
    
    
    
    
    
    
    
    
    Issuance of common stock, par value $0.01(5)
    
    
    3,000,000
    
    
    
    30
    
    
    
    79,170
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    79,200Repurchase of common stock, par value $0.01(5)
    
    
    (3,000,000
    )
    
    
    (30
    )
    
    
    (79,170
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (79,200
    )Stock
compensation expense  amortization
of restricted stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    111
    
    
    
    
    
    
    
    
    
    
    
    111Stock
compensation expense  stock options
    
    
    
    
    
    
    
    
    
    
    903
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    903Tax benefit from 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 benefit of $23,243
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    43,165
    
    
    
    43,165Unrealized loss due to change in fair
value of derivative instruments, net of
tax benefit of $23,745
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (44,091
    )
    
    
    (44,091
    )Total comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    130,114Balance December 31, 2003
    
    
    31,437,581
    
    
    $
    315
    
    
    $
    366,781
    
    
    $
    (808
    )
    
    $
    395,374
    
    
    $
    (26,128
    )
    
    $
    735,534
   (1)
    
    Common stock issued through the exercise of stock
options. See Note 4 
Stock Option Plans.(2)
    
    Restricted stock issued to our President and Chief Executive Officer in
April 2001 at $25.58 per share.
See Note 6  Related Party Transactions  Transactions with our Executives.(3)
    
    Excess fair market value of oil and gas properties purchased from KeySpan
in October 2002.
See Note 6  Related Party Transactions  Acquisition of KeySpan Joint
Venture Assets(4)
    
    Restricted stock issued pursuant to our Amended and Restated 2002
Long-Term Incentive Plan to non-employee directors and directors
affiliated with KeySpan. We issued 20,000 shares (2,000 shares to each)
on November 7, 2003 at $37.15 per share and 2,000 shares on December 3,
2003 at $34.79 per share. Restricted stock issued to directors vests at
the earlier of retirement from our Board or at the ended of five years
from date of grant. See Note 4  Stock Option Plans.(5)
    
    Issuance of three million of our common shares to the public and
concurrent repurchase of three million shares from KeySpan. See Note
3 
Stockholders Equity. The accompanying notes are an integral part of these consolidated financial statements. F-6




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands) Years Ended December 31,2003
    
    2002
    
    2001Operating Activities:Net income
    
    $
    131,040
    
    
    $
    70,494
    
    
    $
    122,601Adjustments to reconcile net income to net cash provided by
operating activities:Deferred income tax expense
    
    
    59,668
    
    
    
    39,860
    
    
    
    67,643Depreciation, depletion and amortization
    
    
    197,530
    
    
    
    171,610
    
    
    
    128,736Asset retirement accretion expense
    
    
    3,668
    
    
    
    
    
    
    
    Writedown in carrying value of natural gas and oil properties
    
    
    
    
    
    
    
    
    
    
    6,170Stock compensation expense
    
    
    1,014
    
    
    
    85
    
    
    
    64Unrealized loss due to ineffectiveness of derivative instruments
    
    
    1,950
    
    
    
    
    
    
    
    Debt extinguishment expense
    
    
    1,626
    
    
    
    
    
    
    
    Cumulative effect of change in accounting principle
    
    
    2,772
    
    
    
    
    
    
    
    Changes in operating assets and liabilities:(Increase) decrease in accounts receivable
    
    
    (4,863
    )
    
    
    (45,337
    )
    
    
    70,119(Increase) decrease in inventories
    
    
    361
    
    
    
    (283
    )
    
    
    774(Increase) decrease in prepayments and other
    
    
    (3,622
    )
    
    
    763
    
    
    
    (1,046
    )(Increase) decrease in other assets
    
    
    (8,449
    )
    
    
    4,427
    
    
    
    (5,469
    )Increase (decrease) in deferred liabilities
    
    
    2,329
    
    
    
    741
    
    
    
    140Increase (decrease) in accounts payable and accrued expenses
    
    
    5,808
    
    
    
    1,509
    
    
    
    (31,700
    )Net cash provided by operating activities
    
    
    390,832
    
    
    
    243,869
    
    
    
    358,032Investing Activities:Investment in property and equipment
    
    
    (461,822
    )
    
    
    (257,436
    )
    
    
    (368,277
    )Dispositions and other
    
    
    
    
    
    
    5,311
    
    
    
    Net cash used in investing activities
    
    
    (461,822
    )
    
    
    (252,125
    )
    
    
    (368,277
    )Financing Activities:Proceeds from long-term borrowings
    
    
    414,000
    
    
    
    79,000
    
    
    
    172,000Repayments of long-term borrowings
    
    
    (364,000
    )
    
    
    (71,000
    )
    
    
    (173,000
    )Debt issuance costs for $175 million of 7% senior subordinated notes.
    
    
    (4,695
    )
    
    
    
    
    
    
    Proceeds from issuance of common stock from exercise of stock options
    
    
    10,223
    
    
    
    9,668
    
    
    
    10,189Proceeds from issuance of common stock
    
    
    79,200
    
    
    
    
    
    
    
    Repurchase of common stock
    
    
    (79,200
    )
    
    
    
    
    
    
    Net cash provided by financing activities
    
    
    55,528
    
    
    
    17,668
    
    
    
    9,189Decrease in cash and cash equivalents
    
    
    (15,462
    )
    
    
    9,412
    
    
    
    (1,056
    )Cash and cash equivalents, beginning of year
    
    
    18,031
    
    
    
    8,619
    
    
    
    9,675Cash and cash equivalents, end of year
    
    $
    2,569
    
    
    $
    18,031
    
    
    $
    8,619Supplemental Information:Cash paid for interest
    
    $
    18,403
    
    
    $
    14,906
    
    
    $
    14,777Cash payment (refund) of federal and state income taxes
    
    $
    14,800
    
    
    $
    (400
    )
    
    $
    475
 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 Summary of Organization and Significant Accounting Policies Our Business We are an independent natural gas and oil company engaged in the exploration,
development, exploitation and acquisition of natural gas and oil reserves in
North America. Natural gas is our primary focus. 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 Appalachian Basin of West
Virginia. During 2003, we began operations in the Rocky Mountain Region, with
an initial focus in the Uinta Basin of northeastern Utah. At December 31, 2003, our net proved reserves were 755 billion cubic feet
equivalent or Bcfe, with a present value, discounted at 10% per annum, of cash
flows before income taxes of $1.9 billion. Our reserves are fully engineered on
an annual basis by independent petroleum engineers. Approximately 94% of our
net proved reserves at December 31, 2003 were natural gas, approximately 68% of
which were classified as proved developed. We operate approximately 85% of our
producing wells. 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.
As of December 31, 2003, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 55% of the outstanding shares of our
common stock. Principles of Consolidation The consolidated financial statements include our accounts and the accounts of
our wholly owned subsidiary, Seneca Upshur Petroleum Company, which is in the
exploration and production business in West Virginia. All significant
inter-company balances and transactions have been eliminated. 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 and our full cost ceiling test limitation. See
Note 12  Supplemental Information on Natural Gas and Oil Exploration,
Development and Production Activities (Unaudited). Because there are numerous
uncertainties inherent in the estimation process, actual results could differ
materially from these estimates. Reclassifications Certain reclassifications have been made to prior years reported amounts in
order to conform with current year presentations. 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 F-8




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 using market prices as of the end of the period. Our
production imbalances represented a net asset of $1.8 million and $33,000 at
December 31, 2003 and 2002, respectively. The increase in our imbalance
position at December 31, 2003 was due primarily to imbalances associated with
Gulf of Mexico properties acquired in October 2003 from Transworld Exploration
and Production Inc. See Note 10  Acquisitions  Transworld. 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 31,2003
    
    2002
    
    2001Numerator:Income before cumulative effect of change in accounting principle
    
    $
    133,812
    
    
    $
    70,494
    
    
    $
    122,601Cumulative effect of change in accounting principle
    
    
    (2,772
    )
    
    
    
    
    
    
    Net income
    
    $
    131,040
    
    
    $
    70,494
    
    
    $
    122,601Denominator:Weighted average shares outstanding
    
    
    31,097
    
    
    
    30,569
    
    
    
    30,228Add dilutive securities: Stock options
    
    
    116
    
    
    
    309
    
    
    
    417Total weighted average shares outstanding and dilutive securities
    
    
    31,213
    
    
    
    30,878
    
    
    
    30,645Earnings per share  basic:Income before cumulative effect of change in accounting principle
    
    $
    4.30
    
    
    $
    2.31
    
    
    $
    4.06Cumulative effect of change in accounting principle
    
    
    (0.09
    )
    
    
    
    
    
    
    Net income per share  basic
    
    $
    4.21
    
    
    $
    2.31
    
    
    $
    4.06Earnings per share  fully diluted:Income before cumulative effect of change in accounting principle
    
    $
    4.29
    
    
    $
    2.28
    
    
    $
    4.00Cumulative effect of change in accounting principle
    
    
    (0.09
    )
    
    
    
    
    
    
    Net income per share  fully diluted
    
    $
    4.20
    
    
    $
    2.28
    
    
    $
    4.00
 For the years ended December 31, 2003, 2002 and 2001, the calculation of shares
outstanding for fully diluted earnings per share does not include the effect of
outstanding stock options to purchase 1,865,313, 1,880,029 and 1,182,843 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. F-9




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Comprehensive Income The table below summarizes our Comprehensive Income for the years ended
December 31, 2003, 2002 and 2001, respectively. Amounts are in thousands. Years Ended December 31,2003
    
    2002
    
    2001Net income
    
    $
    131,040
    
    
    $
    70,494
    
    
    $
    122,601Other comprehensive income, net of taxes:Net unrealized (loss) gain on fair
value of derivative instruments
    
    
    (926
    )
    
    
    (60,153
    )
    
    
    34,951Comprehensive income
    
    $
    130,114
    
    
    $
    10,341
    
    
    $
    157,552
 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; plus,
    
    estimates for future development costs; 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 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 Securities and
Exchange Commission guidelines, we include estimated future cash flows from our
hedging program in our ceiling test calculation. In calculating our ceiling test at December 31, 2003 and 2002, we estimated,
using a wellhead price of $5.79 per Mcf and $4.35 per Mcf, 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 $440.7 million (after tax) for 2003 and by $279.4 million
(after tax) for 2002. No writedown was required. In calculating the ceiling test at December 31, 2001, we estimated, using a
wellhead price of $2.38 per Mcf, that our capitalized costs exceeded the
ceiling limitation by $6.2 million ($4.0 million after tax). As a result, we
reduced or wrote down the carrying value of our full cost pool and incurred a
charge to earnings of $6.2 million ($4.0 million, after tax). F-10




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Natural gas prices continue to be volatile and the risk that we will be
required to writedown our full cost pool increases when natural gas prices are
depressed or if we have significant downward revisions in our estimated proved
reserves. 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 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
successful 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 $134.5 million of unevaluated property costs at December 31, 2003 that
have been excluded 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. Of the $96.2 million of
unevaluated property costs at December 31, 2002 that have been excluded from
the amortization base, $38.8 million were incurred during 2002, $28.2 million
were incurred in 2001, $6.9 million were incurred in 2000 and $22.3 million
were incurred prior to 2000. We estimate these costs will be evaluated within
a four-year period. Classification of Intangible Leasehold Costs SFAS 141, Business Combinations and SFAS 142, Goodwill and Intangible
Assets, became effective on July 1, 2001 and January 1, 2002, respectively.
These new standards emphasize a more precise evaluation of assets and their
balance sheet classification as either tangible or intangible assets. We
understand that the issue is under evaluation as to whether provisions of SFAS
141 and SFAS 142 may call for mineral rights held under lease or other
contractual arrangements together with cash costs for the acquisition of
natural gas and oil leasehold interests to be classified in the balance sheet
as intangible assets. If these types of leasehold costs (both proved and
unevaluated) are determined to be intangible assets, they would be classified
separately from natural gas and oil properties as intangible assets on our
balance sheets. This issue relates only to balance sheet classification and
presentation and we do not believe it will not have an effect on cash flows or
results of operations. At December 31, 2003, if we applied the interpretation
currently under discussion, undeveloped leasehold costs of $117.1 million and
developed leasehold costs of $221.3 million, net of accumulated amortization,
would be reclassified from tangibles to intangibles, representing costs
incurred since June 30, 2001, the effective date of SFAS 141. At December 31,
2002, we had undeveloped leasehold costs of $49.5 million and developed
leasehold costs of $111.5 million, net of accumulated amortization that would
be reclassified from tangibles to intangibles. Consistent with current
industry practice, we will continue to classify our natural gas and oil
leasehold costs as tangible natural gas and oil properties until the Emerging
Issues Task Force issues further guidance. 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 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, a gain
or loss is recognized and an adjustment is made to the full cost pool. 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. F-11




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 on a pro forma basis our asset retirement liability as if SFAS
143 had been adopted on January 1, 2002. The ARO liability in the table below
includes amounts classified as both current and long-term at
December 31st. Years Ended December 31,2003
    
    2002ARO liability at January 1,
    
    $
    57,197
    
    
    $
    45,759Additions from drilling
    
    
    5,738
    
    
    
    8,507Additions from purchases
    
    
    29,243
    
    
    
    286Deletions from abandonment
    
    
    (160
    )
    
    
    Changes resulting from timing
    
    
    (3,329
    )
    
    
    ARO accretion expense
    
    
    3,668
    
    
    
    2,645ARO liability at December 31,
    
    $
    92,357
    
    
    $
    57,197
 The following table describes the pro forma effect on net income and earnings
per share for the years ended December 31, 2002 and 2001 as if SFAS 143 had
been adopted on January 1, 2001. Years Ended December 31,2003
    
    2002
    
    2001Net income
    
    $
    131,040
    
    
    $
    68,774
    
    
    $
    121,009Earnings per share:Basic
    
    $
    4.21
    
    
    $
    2.25
    
    
    $
    4.00Fully diluted
    
    
    4.20
    
    
    
    2.23
    
    
    
    3.95
 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 90 days or less to be 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 F-12




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  
    
    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, we capitalize a portion of our
general and administrative expenses that are directly identified with our
acquisition, exploration and development activities. 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 2003, 2002 and 2001, of $12.9
million, $13.2 million and $12.8 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 $1.6 million, $1.8 million and $1.2 million for the years ended
December 31, 2002, 2001 and 2000, 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. Capitalization of Interest We capitalize interest related to our unevaluated natural gas and oil
properties and certain properties under development that are not currently
being amortized. For the years ended December 31, 2003, 2002 and 2001, we
capitalized interest costs of $7.3 million, $8.0 million and $12.0 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. Pursuant to our adoption of SFAS 133 on
January 1, 2001, our derivative financial instruments are reported on the
balance sheet at fair market value. Derivative Instruments and Hedging Activities To reduce our exposure to adverse price fluctuations, we generally hedge
between 70 and 80 percent of our estimated future production volume. 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 benefit
of future price increases. Our hedges are designated cash flow hedges and qualify for hedge accounting
under SFAS 133, as amended, Accounting for Derivative Instruments and Hedging
Activities 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 2003, our earnings include an
unrealized loss of $1.9 million ($1.3 million net of tax) representing the
ineffective portion of our derivative instruments that were not eligible for
deferral. 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 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. 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, 2003 and 2002. F-13




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. 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 has been or will be recorded for
grants made in previous years. For the year ended December 31, 2003, we
incurred $0.9 million in compensation expense related to stock options issued
during the year. 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 is equal to the fair market value at the
time of grant, no compensation expense is incurred. As a result, we incurred
no compensation expense during 2002 and 2001 relating to stock options. See
Note 4  Employee Benefit and Stock Plans  Fair Value of Employee
Stock-Based Compensationfor a pro-forma disclosure of net income had stock
options been accounted for based upon the fair value provisions of the SFAS
123. New Accounting Pronouncements In November 2002, FASB issued Financial Interpretation (FIN) No. 45,
Guarantors Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others. FIN 45 requires certain
guarantees to be recorded at fair value, which is different from the previous
practice of recording a liability only when a loss is probable and reasonably
estimable, as those terms are defined in SFAS 5, Accounting for
Contingencies. FIN 45 has a dual effective date. The initial recognition and
measurement provisions are applicable on a prospective basis to guarantees
issued or modified after December 31, 2002. The disclosure requirements in the
interpretation are effective for financial statements for interim or annual
periods ending after December 15, 2002. As of our December 31, 2003 and
December 31, 2002 balance sheet dates, we did not have any guarantees of
indebtedness of others and as a result, our adoption of FIN 45 did not have an
effect on our financial statements. In January 2003, the FASB issued FIN No. 46, Consolidation of Variable
Interest Entities  An Interpretation of Accounting Research Bulletin 51.
FIN 46 addresses consolidation by business enterprises of variable interest
entities (VIEs) and the primary objective is to provide guidance on the
identification of, and financial reporting for, entities over which control is
achieved through means other than voting rights; such entities are known as
VIEs. FIN 46 requires an entity to consolidate a VIE if the entity has a
variable interest (or combination of variable interests) that will absorb a
majority of the entitys expected losses if they occur, receive a majority of
the entitys expected residual returns if they occur or both. This guidance
applies immediately to VIEs created after January 31, 2003, and to VIEs in
which an enterprise obtains an interest after that date. However, on October
8, 2003, the FASB decided to grant a broader deferral of the implementation of
FIN 46. Pursuant to this deferral, public companies must complete their
evaluations of VIEs that existed prior to February 1, 2003, and the
consolidation of those for which they are the primary beneficiary for financial
statements issued for the first period ending after December 15, 2003. For
calendar year companies, consolidation of previously existing VIEs will be
required in their December 31, 2003 financial statements. We have completed
our F-14




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS evaluation of FIN 46 and because we do not believe that we have any VIEs there
is no impact to our consolidated financial statements. NOTE 2  Long-Term Debt and Notes Years Ended December 31,2003
    
    2002(in thousands)Senior Debt:Revolving bank credit facility, due July 15, 2005
    
    $
    127,000
    
    
    $
    152,000Subordinated Debt:8-5/8% senior subordinated notes, due January 1, 2008
    
    
    
    
    
    
    100,0007% senior subordinated notes, due June 15, 2013
    
    
    175,000
    
    
    
    Total long-term debt and notes
    
    $
    302,000
    
    
    $
    252,000
 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, 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, 2002, the quoted market value of our
$100 million of 8-5/8% senior subordinated notes was 103.8% of the $100 million
carrying value or $103.8 million. At December 31, 2003, principle payments due
over the next five-year period and thereafter are as follows. 2004
    
    2005
    
    2006
    
    2007
    
    2008
    
    2009Revolving bank credit facility
    
    $
    
    
    
    $
    127,000
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    7% senior Subordinated Notes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    175,000Total maturities
    
    $
    
    
    
    $
    127,000
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    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 as documentation agent. The credit facility provides us with a
commitment of $300 million which may be increased at our request and with prior
approval from Wachovia to a maximum of $350 million by adding one or more
lenders or by allowing one or more lenders to increase their commitments. The
credit facility is subject to borrowing base limitations. Our current
borrowing base is $300 million and is redetermined semi-annually, with the next
redetermination scheduled for April 1, 2004. Up to $25 million of the
borrowing base is available for the issuance of letters of credit. The credit
facility matures July 15, 2005, is unsecured and with the exception of trade
payables, ranks senior to our 7% senior subordinated notes. At December 31,
2003, we had $127 million in outstanding borrowings under the credit facility
and $0.4 million in outstanding letter of credit obligations. 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% 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. F-15




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Our revolving bank credit facility contains customary negative covenants that
place restrictions and limits on, among other things, the incurrence of debt,
guaranties, 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 80% of our natural gas production during any 12-month
period beginning July 15, 2002 through and including December 31, 2004, and not
more than 70% of our natural gas production during any 12-month period,
thereafter. At December 31, 2003 and 2002, we were in compliance with all covenants. Senior Subordinated Notes 7% Senior Subordinated Notes due June 15, 2013.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 which 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. We received $170.3 million in net proceeds from the issuance of the $175
million of 7% senior subordinated notes. A portion of the net proceeds was
used to repay the aggregate principal of $100 million on the 8-5/8% senior
subordinated notes F-16




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS together with a premium of $4.3 million for early redemption. The remaining
portion of the net proceeds was used to repay $60 million in outstanding
borrowings on our revolving bank credit facility with the balance of
approximately $6.1 million being applied to working capital, a portion of which
was utilized in July 2003 to fund the payment of $4.6 million in accrued
interest due on the $100 million 8 5/8% notes. 8 5/8% Senior Subordinated Notes due January 1, 2008. On July 11, 2003, we
redeemed our $100 million 8 5/8% senior subordinated notes due January 1, 2008.
The $100 million 8 5/8% senior subordinated notes were issued on March 2, 1998.
The notes bore interest at a rate of 8 5/8% per annum with interest payable
semi-annually on January 1 and July 1. The $100 million 8 5/8% notes were
redeemable, at our option, in whole or in part, at any time on or after January
1, 2003 at a price equal to 100% of the principal amount plus accrued and
unpaid interest, if any, plus a specified premium of 4.313%. The redemption
and payment of the call premium were funded with a portion of the proceeds
received from our June 10, 2003 issuance of the $175 million 7% senior
subordinated notes due June 15, 2013. Upon closing of the $175 million 7%
senior subordinated notes on June 10, 2003, the $100 million 8 5/8% notes were
called. During the second quarter of 2003 and pursuant to the early redemption
of the $100 million notes, we incurred debt extinguishment expenses totaling
$5.9 million ($3.9 million net of tax) consisting of the call premium of $4.3
million together with a non-cash charge of $1.6 million for the write-off of
the balance of the unamortized issue costs of the 8 5/8% notes. The debt
extinguishment expenses of $5.9 million are included in the line item Other
(Income) Expense on the Statement of Operations for the year ended December
31, 2003. NOTE 3  Stockholders Equity 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 are
obligated, at KeySpans election, to facilitate KeySpans sale of its shares of
Houston Exploration 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. For the mutual convenience of the parties, we elected to
complete KeySpans sale through our pre-existing shelf registration statement rather
than filing a separate, new registration statement for KeySpan. To accomplish
the transaction, we simultaneously sold 3,000,000 newly issued shares of
Houston Exploration stock in a public offering for net proceeds of $26.40 per
share, or an aggregate $79.2 million, and bought a like number of KeySpans
shares of Houston Exploration 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. Our Board of Directors
approved the transaction in principle and delegated to a special, independent
committee of the Board plenary authority to negotiate the terms of, and finally
approve or veto the transaction. In finally approving the terms of the stock
purchase agreement, the independent committee determined that the agreement was
consistent with our pre-existing obligations under our registration rights
agreement and that issuing the shares under our existing shelf registration
statement was in the best interests of our public stockholders to facilitate
the prompt and orderly disposition of the shares. 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, including the
common stock of our company. 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 $1.3 million, $1.2 million and $0.7 million,
respectively, for the years ended December 31, 2003, 2002 and 2001. F-17




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Deferred Compensation Plan In November 2002, we implemented 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 ($12,000 and $11,000 per year, respectively, for 2003 and 2002, with an
additional $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 2003 and 2002, we made matching contributions
totaling $ 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, including our common stock. 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, 2003 and 2002, the fair market value of the assets
held in the trust of $3.4 million and $1.0 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. 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, $105,000, and $113,000, respectively, during the years
ended December 31, 2003, 2002 and 2001 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 $4.8 million, $3.7 million and $6.8 million in 2003,
2002 and 2001. Incentive Compensation Plan for Non-Employee Directors We maintain an incentive 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 three 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; and (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. All our employees, directors, consultants and advisors are eligible to
participate in our Stock Plans, with the exception of executive officers who
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 F-18




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS price of our common stock as reported on the NYSE on the date of grant. The
1996 and 2002 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 2003, 2002 and 2001 resulted in a current tax benefit to us of
approximately $1.4 million, $4.8 million and $1.3 million, respectively. In addition to stock options, the 2002 Plan allows for the grant of up to
300,000 shares of restricted stock. Restricted stock carries voting and
dividend rights; however, the sale or transfer of the shares is restricted.
During 2003, we granted and issued 22,000 shares of restricted stock to
non-employee directors and affiliated directors at an average grant price of
$35.08 per share. The shares were issued as part of each directors annual
compensation. The shares vest and become freely transferable at the earlier of
retirement from our Board of Directors or at the end of five years from the
date of grant. For 2003, we incurred $0.8 million to shareholders equity for
the unearned compensation expense, the cost of which will be amortized, on a
straight-line basis and recognized in earnings as compensation expense over the
stocks five-year vesting period. During 2003, we recognized stock
compensation expense of $26,000 related to these grants of restricted stock
made pursuant to the 2002 Plan. In addition, during 2003, 2002 and 2001, we
incurred stock compensation expense of $85,000, $85,000 and $64,000 for the
amortization of restricted stock granted to our Chief Executive Officer upon
his employment with our company in April 2001. See Note 6  Related Party
Transaction  Transactions with Executives. The table below summarizes all of our Stock Plans as of December 31, 2003. 2002 Plan
    
    1999 Plan
    
    1996 Plan
    
    Total PlansOptions and restricted stock authorized
    
    
    1,500,000
    
    
    
    800,000
    
    
    
    3,033,912
    
    
    
    5,333,912Options granted:Incentive stock options
    
    
    47,686
    
    
    
    
    
    
    
    1,032,302
    
    
    
    1,079,988Non-qualified stock options
    
    
    1,152,489
    
    
    
    806,606
    
    
    
    2,009,910
    
    
    
    3,969,005Forfeitures
    
    
    (10,750
    )
    
    
    (24,343
    )
    
    
    (11,877
    )
    
    
    (46,970
    )Total options
    
    
    1,189,425
    
    
    
    782,263
    
    
    
    3,030,335
    
    
    
    5,002,023Restricted stock granted
    
    
    22,000
    
    
    
    
    
    
    
    
    
    
    
    22,000Options and restricted stock available for grant
    
    
    288,575
    
    
    
    17,737
    
    
    
    3,577
    
    
    
    309,889Total exercised and issued
    
    
    39,250
    
    
    
    230,740
    
    
    
    2,196,874
    
    
    
    2,466,864
 F-19




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The table below sets forth a summary of activity for stock options during the
respective years for all of our stock plans. Years Ended December 31,2003
    
    2002
    
    2001Shares
    
    Price(1)
    
    Shares
    
    Price(1)
    
    Shares
    
    Price(1)Options outstanding January 1
    
    
    2,421,166
    
    
    $
    27.50
    
    
    
    2,164,448
    
    
    $
    24.81
    
    
    
    1,660,745
    
    
    $
    17.99Granted
    
    
    606,725
    
    
    
    34.86
    
    
    
    753,559
    
    
    
    30.14
    
    
    
    1,129,871
    
    
    
    30.15Exercised
    
    
    (461,563
    )
    
    
    22.15
    
    
    
    (490,788
    )
    
    
    19.70
    
    
    
    (624,180
    )
    
    
    16.32Forfeited
    
    
    (31,169
    )
    
    
    27.73
    
    
    
    (6,053
    )
    
    
    27.77
    
    
    
    (1,988
    )
    
    
    29.02Options outstanding December 31
    
    
    2,535,159
    
    
    $
    30.23
    
    
    
    2,421,166
    
    
    $
    27.50
    
    
    
    2,164,448
    
    
    $
    24.81Options exercisable December 31
    
    
    838,568
    
    
    $
    28.28
    
    
    
    848,103
    
    
    $
    25.12
    
    
    
    940,929
    
    
    $
    21.83Options available for grant December 31
    
    
    309,889
    
    
    
    
    
    
    
    906,945
    
    
    
    
    
    
    
    155,451
   (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, 2003. 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
    
    
    31,200
    
    
    
    1996
    
    
    3 years
    
    $
    15.60
    
    
    
    31,200
    
    
    $
    15.60
    
    
    
    $13.13 - $25.00
    
    
    56,900
    
    
    
    1997
    
    
    4 years
    
    
    20.32
    
    
    
    56,900
    
    
    
    20.32
    
    
    
    $15.75 - $23.38
    
    
    54,364
    
    
    
    1998
    
    
    5 years
    
    
    18.63
    
    
    
    54,364
    
    
    
    18.63
    
    
    
    $16.94 - $21.00
    
    
    126,900
    
    
    
    1999
    
    
    6 years
    
    
    18.96
    
    
    
    97,320
    
    
    
    19.02
    
    
    
    29,580$18.00 - $26.19
    
    
    61,800
    
    
    
    2000
    
    
    7 years
    
    
    23.30
    
    
    
    36,000
    
    
    
    24.26
    
    
    
    25,800$22.50 - $37.38
    
    
    911,620
    
    
    
    2001
    
    
    8 years
    
    
    31.08
    
    
    
    415,554
    
    
    
    33.21
    
    
    
    496,066$27.49 - $33.75
    
    
    686,150
    
    
    
    2002
    
    
    9 years
    
    
    30.14
    
    
    
    124,230
    
    
    
    30.03
    
    
    
    561,920$26.18 - $37.42
    
    
    606,225
    
    
    
    2003
    
    
    10 years
    
    
    34.86
    
    
    
    23,000
    
    
    
    35.06
    
    
    
    583,2252,535,159
    
    
    
    
    
    
    
    
    
    
    $
    30.23
    
    
    
    838,568
    
    
    $
    28.28
    
    
    
    1,696,591 F-20




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Fair Value of Employee Stock-Based Compensation 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 has been or
will be recorded for grants made in previous years. For the year ended
December 31, 2003, we incurred $0.9 million in gross compensation expense
related to stock options issued during the year of which $0.2 million was
capitalized. 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 is equal to the fair market value at the time of grant, no
compensation expense is incurred. As a result, we incurred no compensation
expense during 2002 and 2001 relating to stock options. Had stock options been
accounted for 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, 2003, 2002 and
2001. Years Ended December 31,2003
    
    2002
    
    2001(in thousands, except per share data)Net income  as reported
    
    $
    131,040
    
    
    $
    70,494
    
    
    $
    122,601Add: Stock-based compensation expense included in
Net income, net of tax
    
    
    551
    
    
    
    55
    
    
    
    42Less: Stock-based compensation expense determined
using fair value method, net of tax
    
    
    4,427
    
    
    
    3,631
    
    
    
    3,894Net income   pro forma
    
    $
    127,164
    
    
    $
    66,918
    
    
    $
    118,749Net income per share  as reported
    
    $
    4.21
    
    
    $
    2.31
    
    
    $
    4.06Net income per share  fully diluted  as reported
    
    
    4.20
    
    
    
    2.28
    
    
    
    4.00Net income per share  pro forma
    
    
    4.09
    
    
    $
    2.19
    
    
    $
    3.93Net income per share  fully diluted  pro forma
    
    
    4.07
    
    
    $
    2.17
    
    
    $
    3.87
 The effects of applying SFAS 123 in this pro forma disclosure may not be
representative of future amounts. The weighted average fair values of options
at their grant date during 2003, 2002 and 2001, where the exercise price
equaled the market price on the grant date were $13.82, $14.08 and $13.45,
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 2003, 2002 and 2001: Years Ended December 31,2003
    
    2002
    
    2001Risk-free interest rate
    
    
    4.02
    %
    
    
    4.59
    %
    
    
    5.80
    %Expected years until exercise
    
    
    5
    
    
    
    5
    
    
    
    5Expected stock volatility
    
    
    43
    %
    
    
    46
    %
    
    
    41
    %Expected dividends
    
    
    
    
    
    
    
    
    
    
    
 F-21




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 5  Income Taxes The components of the federal income tax provision (benefit) are: Years Ended December 31,2003
    
    2002
    
    2001(in thousands)Current.
    
    $
    12,519
    
    
    $
    (768
    )
    
    $
    (840
    )Deferred
    
    
    59,668
    
    
    
    39,860
    
    
    
    67,643Total
    
    $
    72,187
    
    
    $
    39,092
    
    
    $
    66,803
 For 2002 and 2001, the credit in the current provision primarily represents
Section 29 tax credits (see Note 6Related Party Transactions  Section 29 Tax
Credits). At December 31, 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 31,2003
    
    2002
    
    2001(in thousands)Income before income taxes
    
    $
    205,999
    
    
    $
    109,586
    
    
    $
    189,404Statutory rate
    
    
    35
    %
    
    
    35
    %
    
    
    35
    %Income tax expense computed at statutory rate
    
    
    72,100
    
    
    
    38,355
    
    
    
    66,291Reconciling items:Section 29 tax credits and other tax credits(1)
    
    
    58
    
    
    
    (804
    )
    
    
    512Permanent differences
    
    
    29
    
    
    
    
    
    
    
    Non-deductible compensation expense from 2001
    
    
    
    
    
    
    1,541
    
    
    
    Tax provision
    
    $
    72,187
    
    
    $
    39,092
    
    
    $
    66,803
   (1)
    
    For 2003, excess deductions taken in 2002. For 2001, Section
29 tax credit amount includes an adjustment for an under-accrual of
tax expense in 2000. F-22




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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. The change
in the balance of our deferred income taxes for the current year 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, a tax benefit of $1.4 million from the exercise of non-qualified
employee stock options and a tax benefit of $1.2 million due to the change in
the fair value of our derivative instruments that are deferred in accumulated
other comprehensive income. Years Ended December 31,2003
    
    2002(in thousands)Deferred tax assets:Derivative instruments
    
    $
    14,112
    
    
    $
    13,570Alternative minimum tax credit carryforwards
    
    
    7,187
    
    
    
    462Net operating loss carryforwards
    
    
    
    
    
    
    16,656Total deferred tax assets
    
    
    21,299
    
    
    
    30,688Deferred tax liabilities:Oil and gas property and equipment
    
    
    252,440
    
    
    
    206,651Other comprehensive income  derivative instruments
    
    
    640
    
    
    
    Total deferred tax liabilities
    
    
    253,080
    
    
    
    206,651Total deferred tax liability
    
    $
    231,781
    
    
    $
    175,963
 NOTE 6  Related Party Transactions Transactions With KeySpan Issuance of 3,000,000 Shares to the Public and Concurrent Repurchase of
3,000,000 Shares from KeySpan(See Note 3 Stockholders Equity.) KeySpans Investment in Our Company KeySpan has publicly announced that it considers its investment in Houston
Exploration a non-core asset and that it continues to review strategic
alternatives for its investment in our company including the sale of all or a
portion of its investment in our common stock. At December 31, 2003, KeySpan
held approximately 55% of the common shares outstanding or 17.4 million shares
with a value of approximately $635 million. 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 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. F-23




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 below discussion of KeySpan Joint Venture).
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
fair 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. KeySpan
spent a total of $127.8 million, with $9.5 million, $19.0 million and $17.2
million, respectively being spent during 2003, 2002 and 2001. Transactions With Our Executive Officers and Directors Restricted Stock Grant to President and Chief Executive On April 4, 2001, our Board of Directors appointed William G. Hargett to serve
as our President and Chief Executive Officer and to serve on its Board of
Directors. Pursuant to an employment agreement entered into on April 4, 2001
between us and Mr. Hargett, Mr. Hargett received a grant of 10,000 restricted
shares of Houston Exploration common stock with a fair market value of
approximately $256,000 at the time of grant. Until vested, the stock is
restricted from transfer and F-24




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS subject to forfeiture in the event Mr. Hargetts employment is terminated. The
shares vest, become nonforfeitable and freely transferable in equal one-third
increments on each anniversary of the grant date. The cost of the restricted
stock will be recognized in earnings as compensation expense over the stocks
three-year vesting period. During 2003, 2002 and 2001 we recognized stock
compensation expense of $85,000, $85,000 and $64,000, respectively related to
this restricted stock grant. Employment Contracts We have entered into employment contracts with all nine 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. Termination of Employment Agreements for Former Executives During 2001, we recognized $5.2 million in general and administrative expenses
pursuant to lump-sum payments made for the termination of employment contracts
of our former President and Chief Executive Officer and Director, James G.
Floyd, our Senior Vice President of Exploration and Production, Randall J.
Fleming and our Chief Financial Officer, Thomas W. Powers. Each received lump
sums of $2.3 million, $1.4 million and $1.5 million, respectively. 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 director of NATCO Group, a publicly traded oil field
services and equipment company. During 2003, 2002 and 2001 we purchased
services and supplies from NATCO of $1.1 million, $1.1 million and $0.9
million, respectively. Gordon F. Ahalt, also a member of our Board and Audit
Committee serves as a director of Cal Dive International, a publicly traded
offshore oil field service company that provides subsea construction,
inspection, maintenance, repair and salvage services. During 2003 and 2002, we
purchased services totaling $1.9 million and $0.3 million, respectively, from
Cal Dive, with no purchases for 2001. F-25




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 7  Derivative Instruments 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.
Volumes and fair values are stated in thousands. The total estimated fair
value of our natural gas and oil derivative instruments at December 31, 2003
was a negative $36.9 million ($27.4 million net of taxes of which $26.1 million
was deferred in accumulated other comprehensive income and $1.3 million was
recognized in current earnings as a reduction to natural gas and oil revenues.) Natural Gas Hedges
    
    Options - Puts
    
    Fixed Price Swaps
    
    Collars
    
    Fair ValueNYMEX
    
    
    
    
    
    NYMEXVolume
    
    Contract
    
    Volume
    
    Contract
    
    Volume
    
    NYMEXPeriod
    
    (MMbtu)
    
    Price
    
    (MMbtu)
    
    Price
    
    (MMbtu)
    
    Contract PriceAvg Floor
    
    Avg CeilingJanuary 2004
    
    
    3,100
    
    
    $
    5.000
    
    
    
    1,240
    
    
    $
    4.960
    
    
    
    3,100
    
    
    $
    3.750
    
    
    $
    5.045
    
    
    $
    (4,901
    )February 2004
    
    
    2,900
    
    
    
    5.000
    
    
    
    1,160
    
    
    
    4.960
    
    
    
    2,900
    
    
    
    3.750
    
    
    
    5.045
    
    
    
    (4,786
    )March 2004
    
    
    3,100
    
    
    
    5.000
    
    
    
    1,240
    
    
    
    4.960
    
    
    
    3,100
    
    
    
    3.750
    
    
    
    5.045
    
    
    
    (4,210
    )April 2004
    
    
    
    
    
    
    
    
    
    
    1,200
    
    
    
    4.960
    
    
    
    6,000
    
    
    
    4.125
    
    
    
    6.023
    
    
    
    (1,879
    )May 2004
    
    
    
    
    
    
    
    
    
    
    1,240
    
    
    
    4.960
    
    
    
    6,200
    
    
    
    4.125
    
    
    
    6.023
    
    
    
    (1,277
    )June 2004
    
    
    
    
    
    
    
    
    
    
    1,200
    
    
    
    4.960
    
    
    
    6,000
    
    
    
    4.125
    
    
    
    6.023
    
    
    
    (1,400
    )July 2004
    
    
    
    
    
    
    
    
    
    
    1,240
    
    
    
    4.960
    
    
    
    6,200
    
    
    
    4.125
    
    
    
    6.023
    
    
    
    (1,631
    )August 2004
    
    
    
    
    
    
    
    
    
    
    1,240
    
    
    
    4.960
    
    
    
    6,200
    
    
    
    4.125
    
    
    
    6.023
    
    
    
    (1,807
    )September 2004
    
    
    
    
    
    
    
    
    
    
    1,200
    
    
    
    4.960
    
    
    
    6,000
    
    
    
    4.125
    
    
    
    6.023
    
    
    
    (1,699
    )October 2004
    
    
    
    
    
    
    
    
    
    
    1,240
    
    
    
    4.960
    
    
    
    6,200
    
    
    
    4.125
    
    
    
    6.023
    
    
    
    (1,899
    )November 2004
    
    
    
    
    
    
    
    
    
    
    1,200
    
    
    
    4.960
    
    
    
    6,000
    
    
    
    4.125
    
    
    
    6.023
    
    
    
    (2,794
    )December 2004
    
    
    
    
    
    
    
    
    
    
    1,240
    
    
    
    4.960
    
    
    
    6,200
    
    
    
    4.125
    
    
    
    6.023
    
    
    
    (3,852
    )January 2005
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    4.766
    
    
    
    3,100
    
    
    
    4.500
    
    
    
    5.500
    
    
    
    (3,074
    )February 2005
    
    
    
    
    
    
    
    
    
    
    1,450
    
    
    
    4.766
    
    
    
    2,800
    
    
    
    4.500
    
    
    
    5.500
    
    
    
    (2,612
    )March 2005
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    4.766
    
    
    
    3.100
    
    
    
    4.500
    
    
    
    5.500
    
    
    
    (2,064
    )April 2005
    
    
    
    
    
    
    
    
    
    
    1,500
    
    
    
    4.766
    
    
    
    3,000
    
    
    
    4.500
    
    
    
    5.500
    
    
    
    343May 2005
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    4.766
    
    
    
    3,100
    
    
    
    4.500
    
    
    
    5.500
    
    
    
    803June 2005
    
    
    
    
    
    
    
    
    
    
    1,500
    
    
    
    4.766
    
    
    
    3,000
    
    
    
    4.500
    
    
    
    5.500
    
    
    
    754July 2005
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    4.766
    
    
    
    3,100
    
    
    
    4.500
    
    
    
    5.500
    
    
    
    672August 2005
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    4.766
    
    
    
    3,100
    
    
    
    4.500
    
    
    
    5.500
    
    
    
    605September 2005
    
    
    
    
    
    
    
    
    
    
    1,500
    
    
    
    4.766
    
    
    
    3,000
    
    
    
    4.500
    
    
    
    5.500
    
    
    
    630October 2005
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    4.766
    
    
    
    3,100
    
    
    
    4.500
    
    
    
    5.500
    
    
    
    500November 2005
    
    
    
    
    
    
    
    
    
    
    1,500
    
    
    
    4.766
    
    
    
    3,000
    
    
    
    4.500
    
    
    
    5.500
    
    
    
    (254
    )December 2005
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    4.766
    
    
    
    3,100
    
    
    
    4.500
    
    
    
    5.500
    
    
    
    (1,030
    )$
    (36,862
    )
 F-26




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS As of December 31, 2002, we had entered into commodity price hedging contracts
with respect to our production for 2003 and 2004 as listed in the tables below.
Volumes and fair values are stated in thousands. The total estimated fair
value of our natural gas and oil derivative instruments at December 31, 2002
was a deferred loss of $38.8 million ($25.2 million net of taxes). Natural Gas Hedges
    
    Fixed Price Swaps
    
    Collars
    
    Fair ValueNYMEX
    
    
    
    
    
    NYMEXVolume
    
    Contract
    
    Volume
    
    Contract PricePeriod
    
    (MMbtu)
    
    Price
    
    (MMbtu)
    
    Avg Floor
    
    Avg Ceiling
    
    $ in thousandsJanuary 2003
    
    
    1,240
    
    
    $
    3.194
    
    
    
    4,495
    
    
    $
    3.493
    
    
    $
    4.954
    
    
    $
    (2,917
    )February 2003
    
    
    1,120
    
    
    
    3.194
    
    
    
    4,060
    
    
    
    3.493
    
    
    
    4.954
    
    
    
    (2,908
    )March 2003
    
    
    1,240
    
    
    
    3.194
    
    
    
    4,495
    
    
    
    3.493
    
    
    
    4.954
    
    
    
    (3,187
    )April 2003
    
    
    1,200
    
    
    
    3.194
    
    
    
    4,500
    
    
    
    3.476
    
    
    
    4.909
    
    
    
    (2,542
    )May 2003
    
    
    1,240
    
    
    
    3.194
    
    
    
    4,650
    
    
    
    3.476
    
    
    
    4.909
    
    
    
    (2,440
    )June 2003
    
    
    1,200
    
    
    
    3.194
    
    
    
    4,500
    
    
    
    3.476
    
    
    
    4.909
    
    
    
    (2,446
    )July 2003
    
    
    1,240
    
    
    
    3.194
    
    
    
    4,650
    
    
    
    3.476
    
    
    
    4.909
    
    
    
    (2,665
    )August 2003
    
    
    1,240
    
    
    
    3.194
    
    
    
    4,650
    
    
    
    3.476
    
    
    
    4.909
    
    
    
    (2,754
    )September 2003
    
    
    1,200
    
    
    
    3.194
    
    
    
    4,500
    
    
    
    3.476
    
    
    
    4.909
    
    
    
    (2,634
    )October 2003
    
    
    1,240
    
    
    
    3.194
    
    
    
    4,650
    
    
    
    3.476
    
    
    
    4.909
    
    
    
    (2,782
    )November 2003
    
    
    1,200
    
    
    
    3.194
    
    
    
    4,500
    
    
    
    3.476
    
    
    
    4.909
    
    
    
    (3,377
    )December 2003
    
    
    1,200
    
    
    $
    3.194
    
    
    
    4,650
    
    
    
    3.476
    
    
    
    4.909
    
    
    
    (4,209
    )January 2004
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    3.500
    
    
    
    4.750
    
    
    
    (916
    )February 2004
    
    
    
    
    
    
    
    
    
    
    1,400
    
    
    
    3.500
    
    
    
    4.750
    
    
    
    (759
    )March 2004
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    3.500
    
    
    
    4.750
    
    
    
    (597
    )April 2004
    
    
    
    
    
    
    
    
    
    
    1,500
    
    
    
    3.500
    
    
    
    4.750
    
    
    
    (217
    )May 2004
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    3.500
    
    
    
    4.750
    
    
    
    (103
    )June 2004
    
    
    
    
    
    
    
    
    
    
    1,500
    
    
    
    3.500
    
    
    
    4.750
    
    
    
    (71
    )July 2004
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    3.500
    
    
    
    4.750
    
    
    
    (83
    )August 2004
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    3.500
    
    
    
    4.750
    
    
    
    (94
    )September 2004
    
    
    
    
    
    
    
    
    
    
    1,500
    
    
    
    3.500
    
    
    
    4.750
    
    
    
    (72
    )October 2004
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    3.500
    
    
    
    4.750
    
    
    
    (97
    )November 2004
    
    
    
    
    
    
    
    
    
    
    1,500
    
    
    
    3.500
    
    
    
    4.750
    
    
    
    (277
    )December 2004
    
    
    
    
    
    
    
    
    
    
    1,550
    
    
    
    3.493
    
    
    
    4.750
    
    
    
    (480
    )$
    (38,627
    )
 Oil Hedges
    
    Fixed Price Swaps
    
    Collars
    
    Fair ValueNYMEX
    
    
    
    
    
    NYMEXVolume
    
    Contract
    
    Volume
    
    Contract PricePeriod
    
    (MBbl)
    
    Price
    
    (MBbl)
    
    Avg Floor
    
    Avg Ceiling
    
    $ in thousandsJanuary 2003
    
    
    31
    
    
    $
    28.50
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    (77
    )February 2003
    
    
    28
    
    
    
    28.50
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (48
    )March 2003
    
    
    31
    
    
    
    28.50
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (20
    )$
    (145
    )
 F-27




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For natural gas, transactions are settled based upon the NYMEX price on the
final trading day of the month. For oil, our swaps are settled against the
average NYMEX price of oil for the calendar month rather than the last day of
the month. 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. These hedging transactions are settled based upon the average of the reported
settlement prices on the NYMEX for the last three trading days of a particular
contract month or the NYMEX price on the final trading day of the month (the
settlement price). With respect to any particular swap transaction, the
counterparty is required to make a payment to 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, 2003, 2002 and 2001 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. For the Year Ended December 31,Major Purchaser
    
    2003
    
    2002
    
    2001Anadarko Petroleum Corporation
    
    
    11.7
    %
    
    
    12.6
    %
    
    
    7.3
    %ConocoPhillips
    
    
    18.4
    %
    
    
    14.9
    %
    
    
    4.0
    %KinderMorgan
    
    
    11.4
    %
    
    
    9.8
    %
    
    
    5.0
    %Dynegy, Inc.
    
    
    
    
    
    
    5.5
    %
    
    
    16.4
    %Adams Resources and Energy, Inc.
    
    
    4.5
    %
    
    
    8.2
    %
    
    
    12.5
    %El Paso Corporation
    
    
    0.8
    %
    
    
    4.8
    %
    
    
    9.5
    %
   Note:
    
    Amounts disclosed that are less than 10% are presented
for information and comparison purposes only. 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
year ended December 31, 2003, we recognized as other income refunds of prior
period severance tax payments of $21.6 million ($14.0 million net of tax). For
the year ended December 31, 2002, we recognized a total of $10.4 million ($6.8
million net of tax), 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, 2003 and 2002, our current receivables include $12.9 million and $14.8
million, respectively, in gross refunds of which we estimate, approximately
70%, or $9.0 million and $10.4 million, respectively, relate to our net revenue
interest. We expect to collect our current receivable prior to the end of the
third quarter of 2004. 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. For future periods, we do not expect to recognize as income
future refunds of prior F-28




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS years severance tax in excess of $1 million. 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
2004 through 2009. Rental expense related to these leases was $1.3 million,
$1.2 million and $0.6 million, respectively, for the years ended December 31,
2003, 2002 and 2001. At December 31, 2003, our total commitment under these
non-cancelable operating leases was $8.3 million. Minimum rental commitments
under the terms of our operating leases are as follows (in thousands): MinimumYear Ended December 31,
    
    Payments2004
    
    $
    1,4702005
    
    
    1,3712006
    
    
    1,4782007
    
    
    1,5252008
    
    
    1,5792009 and thereafter
    
    
    920Total
    
    $
    8,343
 NOTE 10  Acquisitions 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%. F-29




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 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 On December 31, 2001, 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. 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 Event Sale of Onshore South Louisiana Properties On February 4, 2003, 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 $2.2 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, January 1, 2004, and the
closing date, February 4, 2003. The net proceeds from the sale of $12.8
million were used to repay borrowings under our revolving bank credit facility. F-30




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 13 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. Our natural
gas and oil reserves were estimated by independent reserve engineers. Capitalized Costs of Natural Gas and Oil Properties As of December 31,2003
    
    2002
    
    2001(in thousands)Unevaluated properties, not subject to amortization
    
    $
    134,491
    
    
    $
    96,192
    
    
    $
    177,987Properties subject to amortization
    
    
    2,324,011
    
    
    
    1,828,160
    
    
    
    1,493,293Capitalized costs
    
    
    2,458,502
    
    
    
    1,924,352
    
    
    
    1,671,280Accumulated depreciation, depletion and amortization
    
    
    (1,092,073
    )
    
    
    (906,089
    )
    
    
    (735,257
    )Net capitalized costs
    
    $
    1,366,429
    
    
    $
    1,018,263
    
    
    $
    936,023
 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, 2003,
2002 and 2001 include interest expense and general and administrative costs
related to acquisition, exploration and development of natural gas and oil
properties of $20.2 million, $21.1 million and $24.9 million, respectively. As of December 31,2003
    
    2002
    
    2001(in thousands)Property
acquisition and leasehold costsUnevaluated(1)
    
    $
    61,224
    
    
    $
    14,600
    
    
    $
    31,711Proved
    
    
    170,272
    
    
    
    89,873
    
    
    
    85,367Exploration costs
    
    
    66,259
    
    
    
    26,563
    
    
    
    72,056Development costs
    
    
    162,235
    
    
    
    122,036
    
    
    
    177,256459,990
    
    
    
    253,072
    
    
    
    366,390Asset retirement obligation(2)
    
    
    31,652
    
    
    
    
    
    
    
    Total costs incurred
    
    $
    491,642
    
    
    $
    253,072
    
    
    $
    366,390
   (1)
    
    Unevaluated amounts represent costs we incurred during the year and
excluded from the amortization base until proved reserves are
established or impairment is determined. We estimate that these costs
will be evaluated within four years.(2)
    
    Asset retirement obligation costs incurred during 2003 exclude the
cumulative effect of the change for prior years of $42.5 million
pursuant to our adoption of SFAS 143 on January 1, 2003. During the years ended December 2003, 2002 and 2001, we spent $46.0 million,
$11.0 million and $19.9 million, respectively, to develop our proved
undeveloped reserves. At December 31, 2003, 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 $96.3 million,
$126.4 million, and $10.5 million, respectively, for 2004, 2005 and 2006. F-31




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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 (unaudited) 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. F-32




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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
and is unaudited. As of December 31,2003
    
    2002
    
    2001(in thousands)Future cash inflows
    
    $
    4,335,669
    
    
    $
    2,845,768
    
    
    $
    1,471,557Future production costs
    
    
    (764,373
    )
    
    
    (486,399
    )
    
    
    (302,145
    )Future development costs
    
    
    (369,121
    )
    
    
    (241,876
    )
    
    
    (189,480
    )Future income taxes
    
    
    (850,264
    )
    
    
    (542,782
    )
    
    
    (211,191
    )Future net cash flows
    
    
    2,351,911
    
    
    
    1,574,711
    
    
    
    768,74110% annual discount for estimated timing of cash flows
    
    
    (847,505
    )
    
    
    (516,647
    )
    
    
    (217,216
    )Standardized measure of discounted future net cash flows
    
    $
    1,504,406
    
    
    $
    1,058,064
    
    
    $
    551,525
 The following table summarizes changes in the standardized measure of
discounted future net cash flows and is unaudited. As of December 31,2003
    
    2002
    
    2001(in thousands)Beginning of the year
    
    $
    1,058,064
    
    
    $
    551,525
    
    
    $
    2,064,027Revisions to previous estimates:Changes in prices
    
    
    459,373
    
    
    
    629,542
    
    
    
    (2,088,576
    )Changes in quantities
    
    
    (123,954
    )
    
    
    (36,368
    )
    
    
    (52,928
    )Changes in future development costs
    
    
    (13,029
    )
    
    
    (1,970
    )
    
    
    (18,001
    )Development costs incurred during the period
    
    
    72,717
    
    
    
    23,393
    
    
    
    65,940Extensions and discoveries, net of related costs
    
    
    434,311
    
    
    
    242,055
    
    
    
    116,710Sales of natural gas and oil, net of production costs
    
    
    (486,382
    )
    
    
    (275,157
    )
    
    
    (343,181
    )Accretion of discount
    
    
    136,492
    
    
    
    64,858
    
    
    
    279,648Net change in income taxes
    
    
    (245,151
    )
    
    
    (209,807
    )
    
    
    635,400Purchase of reserves in place
    
    
    254,030
    
    
    
    99,741
    
    
    
    51,674Sale of reserves in place
    
    
    
    
    
    
    (170
    )
    
    
    (133
    )Production timing and other
    
    
    (42,065
    )
    
    
    (29,578
    )
    
    
    (159,055
    )End of year
    
    $
    1,504,406
    
    
    $
    1,058,064
    
    
    $
    551,525
 F-33




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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 net 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, 2003, 2002 and 2001. All
amounts are unaudited. Natural Gas
    
    Crude Oil, Liquids and Condensate(MMcf)
    
    (MBbls)2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Beginning of the year reserves
    
    
    610,409
    
    
    
    568,208
    
    
    
    529,518
    
    
    
    6,533
    
    
    
    6,605
    
    
    
    5,352Revisions of previous estimates
    
    
    (30,573
    )
    
    
    (14,863
    )
    
    
    (41,914
    )
    
    
    (1,615
    )
    
    
    (26
    )
    
    
    (174
    )Extensions and discoveries
    
    
    140,632
    
    
    
    105,798
    
    
    
    83,551
    
    
    
    117
    
    
    
    342
    
    
    
    1,800Production
    
    
    (99,965
    )
    
    
    (97,368
    )
    
    
    (87,095
    )
    
    
    (1,307
    )
    
    
    (859
    )
    
    
    (459
    )Purchase of reserves in place
    
    
    89,380
    
    
    
    48,777
    
    
    
    84,148
    
    
    
    3,753
    
    
    
    483
    
    
    
    115Sales of reserves in place
    
    
    
    
    
    
    (143
    )
    
    
    
    
    
    
    
    
    
    
    (12
    )
    
    
    (29
    )End of year reserves
    
    
    709,883
    
    
    
    610,409
    
    
    
    568,208
    
    
    
    7,481
    
    
    
    6,533
    
    
    
    6,605Proved developed reserves:Beginning of year
    
    
    435,629
    
    
    
    438,538
    
    
    
    420,733
    
    
    
    2,413
    
    
    
    2,123
    
    
    
    1,810End of year
    
    
    487,867
    
    
    
    435,629
    
    
    
    438,538
    
    
    
    4,073
    
    
    
    2,413
    
    
    
    2,123
 Natural Gas Equivalents(MMcfe)2003
    
    2002
    
    2001Beginning of year reserves
    
    
    649,607
    
    
    
    607,838
    
    
    
    561,630Revisions of previous estimates
    
    
    (40,263
    )
    
    
    (15,019
    )
    
    
    (42,958
    )Extensions and discoveries
    
    
    141,334
    
    
    
    107,850
    
    
    
    94,351Production
    
    
    (107,807
    )
    
    
    (102,522
    )
    
    
    (89,849
    )Purchase of reserves in place
    
    
    111,898
    
    
    
    51,675
    
    
    
    84,838Sales of reserves in place
    
    
    
    
    
    
    (215
    )
    
    
    (174
    )End of year reserves
    
    
    754,769
    
    
    
    649,607
    
    
    
    607,838Proved developed reserves:Beginning of year
    
    
    450,107
    
    
    
    451,276
    
    
    
    431,593End of year
    
    
    512,305
    
    
    
    450,107
    
    
    
    451,276
 F-34




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##### Table of Contents



THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 13 Quarterly Financial Information (Unaudited) 1st
    
    2nd
    
    3rd
    
    4thQuarter
    
    Quarter
    
    Quarter
    
    Quarter(in thousands, except per share data)2003Total 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 (1)
    
    $
    1.35
    
    
    $
    0.93
    
    
    $
    1.12
    
    
    $
    0.82Net income per share  fully 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  fully diluted (1)
    
    $
    1.34
    
    
    $
    0.93
    
    
    $
    1.11
    
    
    $
    0.822002Total revenues
    
    $
    74,816
    
    
    $
    85,955
    
    
    $
    84,205
    
    
    $
    100,405Total operating expenses
    
    
    54,425
    
    
    
    57,436
    
    
    
    58,745
    
    
    
    66,861Income from operations
    
    
    20,391
    
    
    
    28,519
    
    
    
    25,460
    
    
    
    33,544Net income
    
    
    12,534
    
    
    
    17,654
    
    
    
    15,272
    
    
    
    25,034Net income per share  basic (1)
    
    $
    0.41
    
    
    $
    0.58
    
    
    $
    0.50
    
    
    $
    0.81Net income per share  fully diluted (1)
    
    $
    0.41
    
    
    $
    0.57
    
    
    $
    0.50
    
    
    $
    0.81
   (1)
    
    Quarterly earnings per share is based on the weighted average number
of shares outstanding during the quarter. Because of the increase in the
number of shares outstanding during the quarters due to the exercise of
stock options, the sum of quarterly earnings per share may not equal
earnings per share for the year. F-35




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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. (Exhibit 4.2 to our Registration
Statement on Form S-4 (Registration No. 333-106836) and incorporated by
reference).10.1
    
    
    
    Registration Rights Agreement dated as of July 2, 1996 between The
Houston Exploration Company and THEC Holdings Corp. (filed as Exhibit
10.13 to our Registration Statement on Form S-1 (Registration No.
333-4437) 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. (Exhibit 4.5 to our Registration
Statement on Form S-4 (Registration No. 333-106836) and incorporated by
reference).10.3
    
    
    
    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).10.4
    
    
    
    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).10.5
    
    
    
    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 on Form 10-Q for the quarter ended
September 30, 2000 File No. 001-11899) and incorporated
by reference).10.6(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).10.7(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).10.8(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).10.9(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).10.10(2)
    
    
    
    Executive Deferred Compensation Plan dated January 1, 2002
(incorporated by reference from Exhibit 10.28 to the original filing on
February 20, 2003 of our Annual Report on Form 10-K for the year ended
December 30, 2002 File No. 001-11899).10.11(2)
    
    
    
    2002 Long-Term Incentive Plan effective May 17, 2002 (filed as Exhibit
1 to our Definitive Proxy Statement on Schedule 14A (File No. 001-11899)
and incorporated by reference).10.12(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).10.13(2)
    
    
    
    Employment Agreement dated July 2, 1996 between The
Houston Exploration Company and James F. Westmoreland
(filed as Exhibit 10.11 to our Registration Statement on
Form S-1 (Registration No. 333-4437) and incorporated by
reference).10.14(2)
    
    
    
    First Amendment to Employment Agreement dated April 26,
2001 between The Houston Exploration Company and James
F. Westmoreland (filed as Exhibit 10.5 to our Quarterly
Report on Form 10-Q for the quarter ended March 31, 2001
File No. 001-11899).
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##### Table of Contents



INDEX TO EXHIBITS EXHIBITS
    
    
    
    DESCRIPTION10.15(2)
    
    
    
    Second Amendment to Employment Agreement dated January 10, 2003
between The Houston Exploration Company and James F. Westmoreland
(incorporated by reference from Exhibit 10.27 to the original filing on
February 20, 2003 of our Annual Report on Form 10-K for the year ended
December 30, 2002 File No. 001-11899).10.16(2)
    
    
    
    Employment Agreement dated May 1, 1998 between The
Houston Exploration Company and Thomas E. Schwartz
(filed as Exhibit 10.2 to our Quarterly Report on Form
10-Q for the quarter ended March 31, 1998 (File No.
001-11899) and incorporated by reference).10.17(2)
    
    
    
    First Amendment to Employment Agreement dated April 26,
2001 between The Houston Exploration Company and Thomas
W. Schwartz (filed as Exhibit 10.4 to our Quarterly
Report on Form 10-Q for the quarter ended March 31, 2001
File No. 001-11899)10.18(2)
    
    
    
    Employment Agreement, dated September 19, 1996, between
The Houston Exploration Company and Charles W. Adcock
(filed as Exhibit 10.26 to our Annual Report on Form
10-K for the year ended December 31, 1996 (File No. 001-11899) and incorporated by reference).10.19(2)
    
    
    
    First Amendment to Employment Agreement dated April 26,
2001 between The Houston Exploration Company and Charles
W. Adcock (filed as Exhibit 10.3 to our Quarterly Report
on Form 10-Q for the quarter ended March 31, 2001 File
No. 001-11899).10.20(2)
    
    
    
    Employment Agreement dated April 4, 2001 between The
Houston Exploration Company and William G. Hargett
(filed as Exhibit 10.2 to our Quarterly Report on Form
10-Q for the quarter ended March 31, 2001 File No.
001-11899).10.21(2)
    
    
    
    First Amendment to Employment Agreement between The Houston
Exploration Company and William G. Hargett dated May 17, 2002 (filed as
Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended
June 30, 2002 File No. 001-11899).10.22(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).10.23(2)
    
    
    
    Employment Agreement dated October 22, 2001 between The Houston
Exploration Company and Steven L. Mueller (filed as Exhibit 10.32 to our
Annual Report on Form 10-K for the year ended December 31, 2001 File No.
001-11899).10.24(2)
    
    
    
    Employment Agreement dated March 1, 2002 between The Houston
Exploration Company and Roger B. Rice (filed as Exhibit 10.33 to our
Annual Report on Form 10-K for the year ended December 30, 2001 File No.
001-11899).10.25(2)
    
    
    
    Employment Agreement dated November 18, 2002 between The Houston
Exploration Company and John H. Karnes (incorporated by reference from
Exhibit 10.26 to the original filing on February 20, 2003 of our Annual
Report on Form 10-K for the year ended December 30, 2002 File No.
001-11899).10.26(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).10.27
    
    
    
    Revolving Credit Facility between The Houston Exploration Company and
Wachovia Bank, National Association, as issuing bank and administrative
agent, Bank of Nova Scotia and Fleet National Bank as co-syndication
agents and BNP Paribas as documentation agent dated July 15, 2002 (filed
as Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended
June 30, 2002 File No. 001-11899).10.28
    
    
    
    First Amendment to Credit Agreement among The Houston Exploration
Company, the lenders Wachovia Bank, National Association, as issuing bank
and as administrative agent, The Bank of Nova Scotia and Fleet National
Bank, as co-syndication agents; and BNP Paribas, as documentation agent,
effective June 5, 2003 (filed as Exhibit 10.1 to our Quarterly Report on
Form 10-Q for the quarter ended June 30, 2003 File No. 001-11899).10.29
    
    
    
    Second Amendment to Credit Agreement among The Houston Exploration
Company, the lenders named therein, Wachovia Bank, National Association,
as issuing bank and as administrative agent, The Bank of Nova Scotia and
Fleet National Bank, as co-syndication agents; and BNP Paribas, as
documentation agent, effective September 3, 2003 (filed as Exhibit 10.1 to
our Quarterly Report on Form 10-Q for the quarter ended September 30, 2003
File No. 001-11899).10.30
    
    
    
    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 and incorporated by reference.10.31(1)(2)
    
    
    
    Amended and Restated 2002 Long-Term Incentive Plan effective May
17, 2002, adopted October 26, 2003.
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##### Table of Contents



EXHIBITS
    
    
    
    DESCRIPTION12.1(1)
    
    
    
    Computation of ratio of earnings to fixed charges.21.1(1)
    
    
    
    Subsidiary of Houston Exploration.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 200232.1(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. F-38