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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM__________ TO__________
COMMISSION FILE NO. 001-11899
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THE HOUSTON EXPLORATION COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 22-2674487
(STATE OR OTHER JURISDICTION OF (IRS EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
1100 LOUISIANA STREET, SUITE 2001
HOUSTON, TEXAS 77002-5215
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES AND ZIP CODE)
(713) 830-6800
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
---------------------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
As of April 29, 2002, 30,498,580 shares of Common Stock, par value $.01
per share, were outstanding.
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THE HOUSTON EXPLORATION COMPANY
TABLE OF CONTENTS
Page
----
FACTORS AFFECTING FORWARD LOOKING STATEMENTS..................................................................... 3
Part I. FINANCIAL INFORMATION................................................................................... 4
Item 1. Consolidated Financial Statements (unaudited)........................................................... 4
CONSOLIDATED BALANCE SHEETS -- March 31, 2002 and December 31, 2001..................................... 4
CONSOLIDATED STATEMENTS OF OPERATIONS -- Three Months Ended
March 31, 2002 and 2001.............................................................................. 5
CONSOLIDATED STATEMENTS OF CASH FLOWS -- Three Months Ended
March 31, 2002 and 2001.............................................................................. 6
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations...................13
Item 3. Quantitative and Qualitative Disclosures About Market Risk...............................................19
PART II. OTHER INFORMATION.......................................................................................22
Item 6. Exhibits and Reports on Form 8-K:.......................................................................22
(a) Exhibits:.........................................................................................22
(b) Reports on Form 8-K:..............................................................................22
SIGNATURES.......................................................................................................23
-2-
FACTORS AFFECTING FORWARD LOOKING STATEMENTS
All of the estimates and assumptions contained in this Quarterly Report
and in the documents we have incorporated by reference into this Quarterly
Report constitute forward looking statements as that term is defined in Section
27A of the Securities Act of 1993 and Section 21E of the Securities Exchange Act
of 1934. These forward-looking statements generally are accompanied by words
such as "anticipate," "believe," "expect," "estimate," "project" 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 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 assumptions, our
expectations may not occur and we cannot guarantee that the anticipated future
results will be achieved. A number of factors could cause our actual future
results to differ materially from the anticipated future results expressed in
this Quarterly Report. 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
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 our Annual Report on Form 10K.
In this Quarterly Report, unless the context requires otherwise, when
we refer to "we", "us" or "our", we are describing The Houston Exploration
Company and its subsidiary on a consolidated basis.
-3-
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
MARCH 31, DECEMBER 31,
2002 2001
----------- -----------
(UNAUDITED)
ASSETS:
Cash and cash equivalents........................................................... $ 182 $ 8,619
Accounts receivable................................................................. 56,652 43,847
Accounts receivable -- Affiliate.................................................... 2,021 635
Derivative financial instruments.................................................... 7,257 53,771
Inventories......................................................................... 1,202 1,149
Prepayments and other............................................................... 1,193 2,959
------------ ------------
Total current assets........................................................... 68,507 110,980
Natural gas and oil properties, full cost method
Unevaluated properties........................................................... 156,609 177,987
Properties subject to amortization............................................... 1,561,338 1,493,293
Other property and equipment........................................................ 9,142 8,265
------------ ------------
1,727,089 1,679,545
Less: Accumulated depreciation, depletion and amortization.......................... (780,618) (740,784)
---------- ----------
946,471 938,761
Other assets........................................................................ 7,724 9,351
------------ ------------
TOTAL ASSETS................................................................... $ 1,022,702 $ 1,059,092
=========== ===========
LIABILITIES:
Accounts payable and accrued expenses............................................... $ 62,006 $ 76,666
------------ -----------
Total current liabilities...................................................... 62,006 76,666
Long-term debt and notes............................................................ 249,000 244,000
Derivative financial instruments.................................................... 5,128 --
Deferred federal income taxes....................................................... 160,733 172,169
Other deferred liabilities.......................................................... 333 376
-------------- -------------
TOTAL LIABILITIES.............................................................. 477,200 493,211
COMMITMENTS AND CONTINGENCIES (SEE NOTE 3)
STOCKHOLDERS' EQUITY:
Common Stock, $.01 par value, 50,000,000 shares authorized and 30,498,580 shares
issued and outstanding at March 31, 2002 and 30,463,230 shares
issued and outstanding at December 31, 2001, respectively........................ 305 305
Additional paid-in capital.......................................................... 337,610 336,977
Unearned compensation............................................................... (171) (192)
Retained earnings................................................................... 206,374 193,840
Accumulated other comprehensive income.............................................. 1,384 34,951
----------- -------------
TOTAL STOCKHOLDERS' EQUITY..................................................... 545,502 565,881
---------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY..................................... $1,022,702 $1,059,092
========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
-4-
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
THREE MONTHS ENDED MARCH 31,
2002 2001
--------- ---------
(UNAUDITED)
REVENUES:
Natural gas and oil revenues............................................... $ 72,446 $ 123,996
Other...................................................................... 194 346
--------- ---------
Total revenues........................................................... 72,640 124,342
OPERATING EXPENSES:
Lease operating............................................................ 7,413 6,245
Severance tax.............................................................. 1,692 4,714
Depreciation, depletion and amortization................................... 39,804 30,219
General and administrative, net............................................ 3,340 7,965
--------- ---------
Total operating expenses................................................. 52,249 49,143
Income from operations........................................................ 20,391 75,199
Other (income) and expense.................................................... -- (1,381)
Interest expense, net......................................................... 1,410 1,927
--------- ---------
Income before income taxes.................................................... 18,981 74,653
Provision for federal income taxes............................................ 6,447 27,309
--------- ---------
NET INCOME.................................................................... $ 12,534 $ 47,344
========= =========
Net income per share.......................................................... $ 0.41 $ 1.58
========= =========
Net income per share -- assuming dilution..................................... $ 0.41 $ 1.55
========= =========
Weighted average shares outstanding........................................... 30,485 29,963
Weighted average shares outstanding -- assuming dilution...................... 30,837 30,502
The accompanying notes are an integral part of these consolidated financial
statements
-5-
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
THREE MONTHS ENDED MARCH 31,
2002 2001
----------- ---------
(UNAUDITED)
OPERATING ACTIVITIES:
Net income................................................................... $ 12,534 $ 47,344
Adjustments to reconcile net income to net cash provided by
Operating activities:
Depreciation, depletion and amortization..................................... 39,804 30,219
Deferred income tax expense.................................................. 6,639 27,519
Stock compensation expense................................................... 21 --
Changes in operating assets and liabilities:
(Increase)decrease in accounts receivable................................. (14,191) 39,437
Increase in inventories................................................... (53) (324)
Decrease(increase) in prepayments and other............................... 1,766 (862)
Decrease in other assets and liabilities.................................. 1,584 78
Decrease in accounts payable and accrued expenses......................... (14,660) (30,274)
----------- ---------
Net cash provided by operating activities.................................... 33,444 113,137
INVESTING ACTIVITIES:
Investment in property and equipment......................................... (47,760) (63,024)
Dispositions ................................................................ 246 --
----------- ---------
Net cash used in investing activities........................................ (47,514) (63,024)
FINANCING ACTIVITIES:
Proceeds from long term borrowings........................................... 9,000 57,000
Repayments of long term borrowings........................................... (4,000) (102,000)
Proceeds from issuance of common stock....................................... 633 2,882
----------- ---------
Net cash used in financing activities........................................ 5,633 (42,118)
Decrease(increase) in cash and cash equivalents.............................. (8,437) 7,995
Cash and cash equivalents, beginning of period............................... 8,619 9,675
Cash and cash equivalents, end of period..................................... $ 182 $ 17,670
=========== =========
Cash paid for interest....................................................... $ 5,553 $ 7,280
=========== =========
Cash paid for taxes.......................................................... $ -- $ --
=========== =========
The accompanying notes are an integral part of these consolidated financial
statements.
-6-
THE HOUSTON EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 1 -- SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Organization
We are an independent natural gas and oil company engaged in the
exploration, development, exploitation and acquisition of domestic natural gas
and oil properties. Our operations are currently focused offshore in the Gulf of
Mexico and onshore in South Texas, the Arkoma Basin of Oklahoma and Arkansas,
South Louisiana, the Appalachian Basin in West Virginia and East Texas. Our
strategy is to utilize our technical expertise to continue to increase reserves,
production and cash flows through the application of a three-pronged approach
that combines an effective mix of:
o high potential offshore exploration and exploitation;
o lower risk, high impact exploitation and development drilling
onshore; and
o selective opportunistic acquisitions both offshore and onshore
At December 31, 2001, our net proved reserves were 608 billion cubic
feet equivalent or Bcfe, with a discounted present value of cash flows before
income taxes of $714 million. Our focus is natural gas. Approximately 93% of our
net proved reserves at December 31, 2001 were natural gas of which approximately
74% of our net proved reserves were classified as proved developed. We operate
approximately 85% of our properties.
We began exploring for natural gas and oil in December 1985 on behalf of
The Brooklyn Union Gas Company. Brooklyn Union is an indirect wholly owned
subsidiary 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. As of
March 31, 2002, THEC Holdings Corp., an indirect wholly owned subsidiary of
KeySpan, owned approximately 67% of the outstanding shares of our common stock.
Principles of Consolidation
The consolidated financial statements include the accounts of The
Houston Exploration Company and its wholly owned subsidiary, Seneca Upshur
Petroleum Company (collectively the "Company"). All significant intercompany
balances and transactions have been eliminated.
Interim Financial Statements
Our balance sheet at March 31, 2002 and the statements of operations
and cash flows for the periods indicated herein have been prepared without
audit, pursuant to the rules and regulations of the Securities and Exchange
Commission. Certain information and footnote disclosures normally included in
financial statements prepared in accordance with generally accepted accounting
principles have been condensed or omitted, although we believe that the
disclosures contained herein are adequate to make the information presented not
misleading. The balance sheet at December 31, 2001 is derived from the December
31, 2001 audited financial statements, but does not include all disclosures
required by generally accepted accounting principles. The Interim Financial
Statements should be read in conjunction with the Consolidated Financial
Statements and Notes thereto included in our Annual Report on Form 10-K for the
year ended December 31, 2001.
In the opinion of our management, all adjustments, consisting of normal
recurring accruals, necessary to present fairly the information in the
accompanying financial statements have been included. The results of operations
for such interim periods are not necessarily indicative of the results for the
full year.
Reclassifications and Use of Estimates
The preparation of the consolidated financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
-7-
THE HOUSTON EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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. Certain reclassifications of prior year
items have been made to conform with current year presentation.
New Accounting Pronouncements
Statement of Financial Accounting Standards "SFAS" No. 143, "Accounting
for Asset Retirement Obligations," addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. SFAS No. 143 will be effective for us January
1, 2003 and early adoption is encouraged. SFAS No. 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 and the corresponding cost capitalized by
increasing 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. Currently, we include estimated future costs of abandonment and
dismantlement in our full cost amortization base and amortize these costs as a
component of our depletion expense. We are evaluating the impact the new
standard will have on our financial statements.
Hedging Contracts
We utilize derivative commodity instruments to hedge future sales
prices on a portion of our natural gas production in order to achieve a more
predictable cash flow and to reduce our exposure to adverse price fluctuations.
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 from possible favorable price movements. Hedging
instruments that we use include swaps, costless collars and options, which we
generally place with major financial institutions that we believe are minimal
credit risks. Our hedging strategies meet the criteria for hedge accounting
treatment under SFAS No. 133, "Accounting for Derivative and Hedging
Activities". Accordingly, we mark-to-market our derivative instruments at the
end of each quarter, and defer the effective portion of the gain or loss on the
change in fair value of our derivatives in Accumulated Other Comprehensive
Income, a component of Stockholders' Equity. We recognize gains and losses when
the underlying transaction is completed, at which time these gains and losses
are reclassified from accumulated other comprehensive income and included in
earnings as a component of natural gas revenues in accordance with the
underlying hedged transaction. If hedging instruments cease to meet the criteria
for deferred recognition, any gains or losses would be currently recognized in
earnings.
At March 31, 2002, we estimated, using the New York Mercantile
Exchange, or NYMEX, index price strip as of that date that the fair market value
of our derivative instruments was $2.1 million. As a result, our balance sheet
at March 31, 2002 reflects an asset of $7.2 million, representing the current
portion of our hedge position and a liability of $5.1, representing the
long-term portion of our hedge position with a corresponding credit of $1.4
million (net of related deferred taxes of $0.7 million) in accumulated other
comprehensive income, representing the fair market value of our total deferred
hedge gain.
At December 31, 2001, we estimated, using the NYMEX, index price strip
as of that date that the fair market value of our derivative instruments was
$53.8 million. As a result, our balance sheet at December 31, 2001 reflects an
asset of $53.8 million with a corresponding credit of $34.9 million (net of
related deferred taxes of $18.9 million) in accumulated other comprehensive
income, representing the fair market value of our deferred hedge gain.
-8-
THE HOUSTON EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Net Income Per Share
Basic earnings per share ("EPS") is calculated by dividing net income
by the weighted average number of shares of common stock outstanding during the
period. No dilution for any potentially dilutive securities is included. Diluted
EPS assumes the conversion of all potentially dilutive securities and is
calculated by dividing net income, as adjusted, by the weighted average number
of shares of common stock outstanding plus all potentially dilutive securities.
THREE MONTHS ENDED MARCH 31,
2002 2001
--------------- --------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Net income....................................... $ 12,534 $ 47,344
=============== ==============
Weighted average shares outstanding.............. 30,485 29,963
Add dilutive securities:
Options..................................... 352 539
--------------- --------------
Total weighted average shares outstanding and dilutive
securities....................................... 30,837 30,502
=============== ==============
Net income per share............................. $ 0.41 $ 1.58
============== ==============
Net income per share - assuming dilution......... $ 0.41 $ 1.55
============== ==============
Comprehensive Income
The table below summarizes our Comprehensive Income for the three
months ended March 31, 2002 and 2001.
THREE MONTHS ENDED MARCH 31,
2002 2001
--------------- --------------
(IN THOUSANDS)
Net income....................................... $ 12,534 $ 47,344
Other comprehensive income, net of taxes:
Unrealized loss on derivative instruments (33,567) (5,298)
--------------- --------------
Comprehensive income............................. $ (21,033) $ 42,046
=============== ==============
NOTE 2 -- LONG-TERM DEBT AND NOTES
MARCH 31, 2002 DECEMBER 31, 2001
-------------- -----------------
(IN THOUSANDS)
SENIOR DEBT:
Bank revolving credit facility, due 2003......... $ 149,000 $ 144,000
SUBORDINATED DEBT:
8 5/8% Senior Subordinated Notes, due 2008....... 100,000 100,000
--------------- -----------------
Total long-term debt and notes.............. $ 249,000 $ 244,000
=============== =================
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 March 31, 2002, the quoted market value of the
Company's $100 million of 8 5/8% Senior Subordinated Notes was 99.6% of the $100
million carrying value or $99.6 million.
-9-
THE HOUSTON EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Credit Facility
We maintain a revolving bank credit facility with a syndicate of
lenders led by JPMorgan Chase, National Association. The credit facility, as
amended, provides a maximum commitment of $250 million, subject to borrowing
base limitations. At March 31, 2002, the borrowing base amount was $250 million.
Up to $2.0 million of the borrowing base is available for the issuance of
letters of credit to support performance guarantees. The credit facility matures
on April 15, 2003 and is unsecured. At March 31, 2002, $149 million was
outstanding under the credit facility and $0.4 million was outstanding in letter
of credit obligations. Subsequent to March 31, 2002, we increased our net
borrowings by an additional $1 million, bringing total borrowings and letters of
credit to $150.4 million as of April 26, 2002.
Interest is payable on borrowings under the credit facility, at our
option, at:
o a fluctuating rate, or base rate, equal to the greater of the Federal
Funds rate plus 0.5% or JP Morgan Chase's prime rate, or
o a fixed rate equal to a quoted LIBOR rate plus a variable margin of
0.875% to 1.625%, depending on the amount outstanding under the credit
facility.
Interest is payable at calendar quarters for base rate loans and at the earlier
of maturity or three months from the date of the loan for fixed rate loans. In
addition, the credit facility requires a commitment fee of:
o between 0.25% and 0.375% per annum on the unused portion of the
designated borrowing base, and
o an additional fee equal to 33% of the commitment fee on the daily
average amount by which the total amount of commitments exceeds the
designated borrowing base.
The credit facility contains covenants, including restrictions on liens
and financial covenants which require us to, among other things, maintain:
o an interest coverage ratio of 2.5 to 1.0 of earnings before interest,
taxes and depreciation to cash interest;
o a total debt to capitalization ratio of less than 60%, exclusive of
non-cash charges; and
o sets a maximum limit of 70% on the amount of natural gas production we
may hedge during any 12-month period.
In addition to maintenance of financial ratios, the credit facility restricts
cash dividends and/or purchase or redemption of our stock. The credit facility
also restricts the encumbering of our oil and gas assets or the pledging of
those assets as collateral. As of March 31, 2002, we were in compliance with all
covenants.
Senior Subordinated Notes
On March 2, 1998, we issued $100 million of 8 5/8% senior subordinated
notes due January 1, 2008. The notes bear interest at a rate of 8 5/8% per annum
with interest payable semi-annually on January 1 and July 1. We may redeem the
notes 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 which decreases yearly from 4.313% in
2003 to 0% after January 1, 2006 if the notes are redeemed prior to January 1,
2006. 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, if any. A "change of
control" is:
o 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;
-10-
THE HOUSTON EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
o 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;
o the adoption of a plan relating to our liquidation or dissolution; or
o if, during any period of two consecutive years, individuals who at the
beginning of this period constituted our board of directors, including
any new directors who were approved by a majority vote of the
stockholders, cease for any reason to constitute a majority of the
members then in office.
The notes are general unsecured obligations and rank subordinate in
right of payment to all existing and future senior debt, including the credit
facility, and will rank senior or equal in right of payment to all existing and
future subordinated indebtedness.
NOTE 3 -- COMMITMENTS AND CONTINGENCIES
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.
NOTE 4 -- RELATED PARTY TRANSACTIONS
KeySpan Joint Venture
Effective January 1, 1999, together with KeySpan, 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 KeySpan received 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 of $7.7 million in 2000 and $20.7 million
during 1999 and KeySpan paid 51.75% of all additional intangible drilling costs
incurred and we paid 48.25%. Revenues are shared 55% Houston Exploration and 45%
to KeySpan. In addition, we received reimbursements from KeySpan for a portion
of our general and administrative costs.
Effective December 31, 2000, KeySpan and Houston Exploration agreed to
end the primary or exploratory term of the joint venture. As a result, KeySpan
will not participate in any of our offshore exploration prospects unless the
project involves the development or further exploitation of discoveries made
during the initial term of the joint venture. In addition, effective with the
termination of the exploratory term of the joint venture, we will not receive
any reimbursement from KeySpan for general and administrative costs.
During the initial two-year term of the joint drilling program, we
drilled a total of 21 wells under the terms of the joint venture: 17 exploratory
wells and four development wells. Five of the wells drilled were unsuccessful.
During 2001, KeySpan participated in three additional wells, all of which were
successful and further developed or delineated reservoirs discovered during the
initial term of the joint venture. For 2002, KeySpan has committed to a capital
budget of $15 million for development projects associated with its working
interests in wells drilled under the joint venture during 1999, 2000 and 2001.
During the first three months of 2002, KeySpan participated in three wells and
spent $9.5 million in capital costs compared to $2.7 million spent during the
first three months of 2001. All three wells were successful and provided further
exploitation of previous discoveries.
-11-
THE HOUSTON EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 5 -- SUBSEQUENT EVENTS
Burlington Acquisition.
On April 19, 2002, we agreed to purchase from Burlington Resources Inc.
natural gas and oil producing properties and associated gathering pipelines,
together with undeveloped acreage, 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 North East Thompsonville, South
Laredo, McFarlan and Maude Traylor Fields. The properties purchased represent
interests in approximately 146 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 will operate approximately 23% of the producing
wells acquired. The $48.1 million purchase price, which is subject to a purchase
price adjustment at the closing of the transaction scheduled for May 31, 2002,
will be financed by borrowings under our revolving bank credit facility. Current
production (for the month of March 2002) is averaging 16.0 MMcfe/day, net to the
interests acquired.
-12-
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion is intended to assist in an understanding of
our historical financial position and results of operations for the three months
ended March 31, 2002 and 2001. Our consolidated financial statements and notes
thereto included elsewhere in this report contains detailed information that
should be referred to in conjunction with the following discussion.
GENERAL
We are an independent natural gas and oil company engaged in the
exploration, development, exploitation and acquisition of domestic natural gas
and oil properties. Our operations are currently focused offshore in the Gulf of
Mexico and onshore in South Texas, the Arkoma Basin of Oklahoma and Arkansas,
South Louisiana, the Appalachian Basin in West Virginia and East Texas. Our
strategy is to utilize our technical expertise to continue to increase reserves,
production and cash flows through the application of a three-pronged approach
that combines an effective mix of:
o high potential offshore exploration and exploitation;
o lower risk, high impact exploitation and development drilling onshore;
and
o selective opportunistic acquisitions both offshore and onshore
At December 31, 2001, our net proved reserves were 608 billion cubic
feet equivalent or Bcfe, with a discounted present value of cash flows before
income taxes of $714 million. Our focus is natural gas. Approximately 93% of our
net proved reserves at December 31, 2001 were natural gas of which approximately
74% of our net proved reserves were classified as proved developed. We operate
approximately 85% of our properties.
We began exploring for natural gas and oil in December 1985 on behalf
of The Brooklyn Union Gas Company. Brooklyn Union is an indirect wholly owned
subsidiary 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. As of
March 31, 2002, THEC Holdings Corp., an indirect wholly owned subsidiary of
KeySpan, owned approximately 67% of the outstanding shares of our common stock.
As an independent oil and gas producer, our revenue, profitability and
future rate of growth are substantially dependent upon prevailing prices for
natural gas and oil, our ability to find and produce hydrocarbons and our
ability to control and reduce costs, all of which are dependent upon numerous
factors beyond our control, such as economic, political and regulatory
developments and competition from other sources of energy. The energy markets
have historically been very volatile, as evidenced by the recent volatility of
natural gas and oil prices, and there can be no assurance that commodity prices
will not widely fluctuate in the future. 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
access to capital.
Critical Accounting Policies and Use of Estimates
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. Unevaluated properties and related costs are excluded from our
amortization base until we have made a determination as to the existence of
proved reserves. Our amortization base includes estimates for future development
costs as well as future abandonment and dismantlement costs.
-13-
Under full cost accounting rules, total capitalized costs are limited
to a ceiling of the present value of future net revenues, discounted at 10%,
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 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, held constant over the life of the
reserves. We use derivative financial instruments that qualify for hedge
accounting under Statement of Financial Accounting Standards ("SFAS") No. 133 to
hedge against the volatility of natural gas prices, and in accordance with
current 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 March 31, 2002, we estimated that we had a full
cost ceiling "cushion", whereby the carrying value of our full cost pool was
less that the ceiling limitation. No writedown is required when a cushion
exists. Natural gas prices continue to be volatile and the risk that we will be
required to write down our full cost pool increases when natural gas prices are
depressed or if we have significant downward revisions in our estimated proved
reserves.
Use of Estimates. The preparation of the consolidated financial
statements in conformity with generally accepted accounting principles requires
our 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
Natural gas and oil reserve quantities represent estimates only. Under
full cost accounting, we use reserve estimates to determine our full cost
ceiling limitation as well as our depletion rate. We estimate our 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 prices, which have fluctuated
widely in recent years, affect estimated quantities of proved reserves and
future net revenues. Any estimates of natural gas and oil reserves and their
values are inherently uncertain, including many factors beyond our control.
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. In addition,
estimates of reserves may be revised based upon actual production, results of
future development and exploration activities, prevailing natural gas and oil
prices, operating costs and other factors, which revision may be material.
Reserve estimates are highly dependent upon the accuracy of the underlying
assumptions. Actual future production may be materially different from estimated
reserve quantities and the differences could materially affect future
amortization of natural gas and oil properties.
New Accounting Pronouncements
Statement of Financial Accounting Standards "SFAS" No. 143, "Accounting
for Asset Retirement Obligations," addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. SFAS No. 143 will be effective for us January
1, 2003 and early adoption is encouraged. SFAS No. 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 and the corresponding cost capitalized by
increasing 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. Currently, we include estimated future costs of abandonment and
dismantlement in our full cost amortization base and amortize these costs as a
component of our depletion expense. We are evaluating the impact the new
standard will have on our financial statements.
-14-
Recent Acquisitions
Within the last four months, we have expanded our existing operations
in South Texas with two producing property acquisitions. Over the last five
years, South Texas has been an area providing strategic growth in both reserves
and production for our company. Together, these two acquisitions have added
approximately 122 Bcfe in total proved reserves and will add an estimated 35
MMcfe/day in average daily production
Burlington Acquisition. On April 19, 2002, we agreed to purchase from
Burlington Resources Inc. natural gas and oil producing properties and
associated gathering pipelines, together with undeveloped acreage, 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
North East Thompsonville, South Laredo, McFarlan and Maude Traylor Fields. The
properties purchased represent interests in approximately 146 producing wells
and total proved reserves of 42 Bcfe as of January 1, 2002, the effective date
of the transaction. Our average working interest will be 35% and we will operate
approximately 23% of the producing wells acquired. The $48.1 million purchase
price, which is subject to a purchase price adjustment at the closing of the
transaction scheduled for May 31, 2002, will be financed by borrowings under our
revolving bank credit facility. Current production (for the month of March 2002)
is averaging 16.0 MMcfe/day, net to the interests acquired.
Conoco Acquisition. On December 31, 2001, we completed the purchase
from Conoco Inc. of natural gas and oil properties and associated gathering
pipelines and equipment, together with developed and undeveloped acreage,
located in the Webb and Zapata counties of South Texas. The $69 million cash
purchase price was 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 we acquired. Our average working
interest is 87%. Total proved reserves as of January 1, 2002 were 80 Bcfe and
current production (for the month of March 2002) is averaging 19.0 MMcfe/day,
net to our interest. Beginning January 1, 2002, we initiated an active drilling
and workover program. To date we drilled nine development wells, with six wells
successfully completed, one dry hole and two in progress. Currently we have two
drilling rigs under contract, which we plan to keep utilized for the remainder
of 2002.
-15-
RESULTS OF OPERATIONS
The following table sets forth our historical natural gas and oil
production data during the periods indicated:
THREE MONTHS ENDED MARCH 31,
2002 2001
-------- --------
PRODUCTION:
Natural gas (MMcf).......................... 23,895 22,095
Oil (MBbls)................................. 160 112
Total (MMcfe)............................... 24,855 22,767
Average daily production (MMcfe/day)........ 276 253
AVERAGE SALES PRICES:
Natural gas (per Mcf) realized(1)........... $ 2.90 $ 5.48
Natural gas (per Mcf) unhedged.............. 2.19 6.86
Oil (per Bbl)............................... 19.28 25.58
OPERATING EXPENSES (PER MCFE):
Lease operating............................. $ 0.30 $ 0.27
Severance tax............................... 0.07 0.21
Depreciation, depletion and amortization.... 1.60 1.33
General and administrative, net(2).......... 0.13 0.35
-----------------------
(1) Reflects the effects of hedging.
(2) For the three months ended March 31, 2001, includes one-time
payments in connection with the termination of employment
contracts for retiring executives.
RECENT FINANCIAL AND OPERATING RESULTS
COMPARISON OF THREE MONTHS ENDED MARCH 31, 2002 AND 2001
Production. Our production increased 9% from 22,767 million cubic feet
equivalent, or MMcfe, for the three months ended March 31, 2001 to 24,855 MMcfe
for the three months ended March 31, 2002. The increase in production was
primarily attributable to newly developed offshore production brought on-line
since the end of the first quarter of 2001 combined with newly acquired onshore
production pursuant to the December 31, 2001 acquisition of properties in South
Texas from Conoco Inc.
Offshore, our production increased 6% from an average of 126 MMcfe/day
during the first quarter of 2001 to an average of 134 MMcfe/day during the first
quarter of 2002. This increase is primarily attributable to new natural gas
production at South March Island 253 and High Island 39, both of which came
on-line during the second half of 2001, combined with new oil production at
Vermilion 408, which came on-line during January 2002.
Onshore, our daily production rates increased 12% from an average of
127 MMcfe/day during the first quarter of 2001 to an average of 142 MMcfe/day
during the corresponding three months of 2002. The onshore production increase
is primarily attributable to newly acquired production from the South Texas
properties purchased from Conoco Inc. on December 31, 2001, which accounts for
19 MMcfe/day of the increase, offset in part by a combined 4 MMcfe/day decrease
in production from our existing onshore properties, primarily as a result of a
drop in production from our Charco Field which produced at an average rate of 93
MMcfe/day during the first quarter of 2001 compared to an average of 87
MMcfe/day during the first quarter of 2002.
Natural Gas and Oil Revenues. Natural gas and oil revenues decreased
42% from $124.0 million for the first three months of 2001 to $72.4 million for
the first three months of 2002 as a result of a 47% decrease in average realized
natural gas prices, from $5.48 per Mcf during the first quarter of 2001 to $2.90
per Mcf in the first quarter
-16-
of 2002, offset in part by a 9% increase in production for the same period.
Natural Gas Prices. As a result of hedging activities, we realized an
average gas price of $2.90 per Mcf for the three months ended March 31, 2002,
which was 132% of the average unhedged natural gas price of $2.19 that otherwise
would have been received, resulting in natural gas and oil revenues for the
three months ended March 31, 2002 that were $17.0 million higher than the
revenues we would have achieved if hedges had not been in place during the
period. For the corresponding period during 2001, we realized an average gas
price of $5.48 per Mcf, which was 80% of the average unhedged natural gas price
of $6.86 that otherwise would have been received, resulting in natural gas and
oil revenues that were $30.5 million lower than the revenues we would have
achieved if hedges had not been in place during the period.
Lease Operating Expenses and Severance Tax. Lease operating expenses
increased 17% from $6.3 million for the three months ended March 31, 2001 to
$7.4 million for the corresponding three months of 2002. On an Mcfe basis, lease
operating expenses increased from $0.27 per Mcfe during the first quarter of
2001 to $0.30 per Mcfe during 2001 the first quarter of 2002. The increase in
both lease operating expenses and lease operating expense on a per unit basis
for 2002 is attributable to the continued expansion of our operations both
offshore and onshore as new offshore production facilities have been added since
the second half of 2001 and onshore operations have expanded with the purchase
of approximately 159 new wells in South Texas on December 31, 2001. Specific
increases were in the areas of well control insurance premiums and onshore ad
valorem taxes. Severance tax, which is a function of volume and revenues
generated from onshore production, decreased from $4.7 million for the first
three months of 2001 to $1.7 million for the corresponding period of 2002. On an
Mcfe basis, severance tax decreased from $0.21 per Mcfe for the first quarter of
2001 to $0.07 per Mcfe during the first quarter of 2002. The decrease in
severance tax expense and severance tax per Mcfe is primarily due to higher
natural gas prices received during the first three months of 2001 as compared to
prices received during the first three months of 2002 offset in part by an
increase in onshore production for the first quarter of 2002.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 32% from $30.2 million for the three months ended
March 31, 2001 to $39.8 million for the three months ended March 31, 2002.
Depreciation, depletion and amortization expense per Mcfe increased 20% from
$1.33 for the three months ended March 31, 2001 to $1.60 for the corresponding
three months in 2002. The increase in depreciation, depletion and amortization
expense was a result of higher production volumes combined with a higher
depletion rate. The higher depletion rate during the first quarter of 2002 is a
result of the addition of fewer new reserves from exploration and developmental
drilling.
General and Administrative Expenses. General and administrative
expenses, net of overhead reimbursements received from other working interest
owners of $0.3 million and $0.6 million for the three months ended March 31,
2001 and 2002, respectively, decreased 59% from $8.0 million for the three
months ended March 31, 2001 to $3.3 million for the three months ended March 31,
2002. Included in general and administrative expense for the first quarter of
2001 were payments totaling $5.2 million made in connection with the termination
of former executive officers' employment contracts. We capitalized general and
administrative expenses directly related to oil and gas exploration and
development activities of $4.9 million and $3.3 million, respectively, for the
three months ended March 31, 2001 and 2002. The decrease in capitalized general
and administrative expenses is a result of lower aggregate general and
administrative expenses during the first quarter of 2002. Excluding the one-time
charges taken for the termination of employment contracts totaling $5.2 million
during the first quarter of 2001, aggregate general and administrative expenses
would have been $7.9 million for the first quarter of 2001 compared to $7.2
million for the first quarter of 2002, reflecting a decrease of 9% which was due
primarily to a decrease in incentive compensation (first quarter of 2001
included the payment of a special bonus in January 2001) combined with the
reorganization of our geologic and geophysical department during the first
quarter of 2002.
On an Mcfe basis, general and administrative expenses decreased 63%
from $0.35 during the first quarter of 2001 to $0.13 per Mcfe during the first
quarter of 2002. Excluding the one-time charges taken for the termination of
employment contracts totaling $5.2 million, general and administrative expenses
on a per Mcfe basis would have increased 8% from $0.12 for the first quarter of
2001 to $0.13 for the first quarter of 2002. The higher rate per Mcfe during the
first quarter of 2002 reflects a decrease in the amount of general and
administrative expenses capitalized during the first quarter of 2002 offset in
part by an increase in production for the first quarter of 2002.
-17-
Other Income and Expense. For the first quarter of 2001, we recognized
other income of $1.4 million relating to the reversal of a portion of $1.8
million in certain reserves that had been established during the first quarter
of 2000 in connection with the review of strategic alternatives for our company.
In September 1999, together with KeySpan, our majority stockholder, we announced
our intention to review strategic alternatives for our company and KeySpan's
investment in our company. KeySpan was assessing our role within its future
strategic plan, and was considering a full range of strategic transactions
including the possible sale of all or a portion of our assets. On February 25,
2001, we announced, together with KeySpan, that the review of strategic
alternatives for Houston Exploration was complete. KeySpan announced that it
planned to retain its equity position in our company for the foreseeable future;
however, KeySpan considers its investment in Houston Exploration a non-core
asset.
Interest Expense, Net. Interest expense, net of capitalized interest,
decreased 26% from $1.9 million for the first three months of 2001 to $1.4
million for the first three months of 2002. Aggregate interest expense decreased
29% from $5.1 during the first quarter of 2001 to $3.6 million during the
corresponding period of 2002. The decrease in aggregate interest is due to a
decrease in interest rates from an average borrowing rate of 8.17% during the
first quarter of 2001 to 5.36% during the first quarter of 2002. Capitalized
interest decreased 29% from $3.1 million for the first quarter of 2001 to $2.2
million for the first quarter of 2002 and corresponds to the decrease in
aggregate interest expense combined with a decrease in exploratory drilling
during the first quarter of 2002 (our capitalized interest is a function of
exploratory drilling and unevaluated properties, both of which were at lower
levels during the first quarter of 2002).
Income Tax Provision. The provision for income taxes decreased 77% from
$27.3 million for the first three months of 2001 to $6.4 million for the first
three months of 2002 due to the 75% decrease in pre-tax income during the first
quarter of 2002 from $74.7 million during the first quarter of 2001 to $19.0
million during the first quarter of 2002 as a result of the combination of lower
natural gas prices, an increase in production, a decrease in interest expense
offset in part by a marginal increase in operating expenses.
Operating Income and Net Income. For the three months ended March 31,
2002, the 47% decrease in realized natural gas prices combined with the 9%
increase in production, offset in part by a 6% increase in operating expenses,
caused operating income to decrease 73% from $75.2 million during the first
quarter of 2001 to $20.4 million during the first quarter of 2002.
Correspondingly, net income decreased 74% from $47.3 million for the first
quarter of 2001 to $12.5 million for the first quarter of 2002 and reflects
lower interest expense and lower taxes.
LIQUIDITY AND CAPITAL RESOURCES
We have historically funded our operations, acquisitions, capital
expenditures and working capital requirements from cash flows from operations,
equity capital from KeySpan as well as public sources, public debt and bank
borrowings. We believe cash flows from operations and borrowings under our
revolving bank credit facility will be sufficient to fund our planned capital
expenditures and operating expenses during 2002.
Cash Flows From Operations. At of March 31, 2002, we had working
capital of $6.5 million and $100.6 million of borrowing capacity available under
our revolving bank credit facility. Net cash provided by operating activities
for the three months ended March 31, 2002 was $33.4 million compared to $113.1
million during the corresponding period of 2001. The decrease in net cash
provided by operating activities was due to (i) a decrease in net income and
deferred taxes due to the decrease in realized natural gas prices from an
average $5.48 per Mcf during the first quarter of 2001 to $2.90 during the first
quarter of 2002, offset in part by a 9% increase in production for the
corresponding period combined with (ii) a decrease in current assets and current
liabilities which is related to the timing of cash receipts and payments. Funds
used in investing activities consisted of $47.5 million for net investments in
property and equipment, which compares to $63.0 million spent during the
corresponding period of 2001. Our cash position increased during the first
quarter of 2002 as a result of net borrowings under our revolving bank credit
facility of $5 million compared to repayments totaling $45 million during the
first quarter of 2001. Cash increased by $0.6 million and $2.9 million,
respectively, during the first three months of 2002 and 2001 due to proceeds
received from the issuance of common stock from the exercise of stock options.
As a result of these activities, cash and cash equivalents decreased $8.4
million from $8.6 million at December 31, 2001 to $0.2 million at March 31,
2002.
-18-
Capital Expenditures. During the first three months of 2002, we
invested a $46.9 million in natural gas and oil properties and $0.9 million for
other property and equipment, which includes the expansion of our Houston office
space. Included in our natural gas and oil property additions was $7.5 million
for exploration, $28.5 million for development drilling, workovers and
construction of platforms and pipelines and $10.9 million for leasehold and
leasehold acquisition costs which includes seismic, capitalized interest and
capitalized general and administrative costs. Our capital expenditure budget for
2002 has been set at $250 million. Typically, we do not include property
acquisition costs in our capital expenditure budget as the size and timing of
capital requirements for property acquisitions are inherently unpredictable.
However, we will allocate a portion of our 2002 capital expenditure budget to
include the April 19, 2002 acquisition of producing properties in South Texas
from Burlington Resources as we plan to repay the borrowings made under our
credit facility for the $48.1 million purchase price from cash flows generated
from operations. The capital expenditure budget includes development costs
associated with recent acquisitions and discoveries and amounts are contingent
upon drilling success. No significant abandonment or dismantlement costs are
anticipated in 2002. We will continue to evaluate our capital spending plans
throughout the year. Actual levels of capital expenditures may vary
significantly due to a variety of factors, including drilling results, natural
gas prices, industry conditions and outlook and future acquisitions of
properties. We intend to continue to selectively seek acquisition opportunities
for proved reserves with substantial exploration and development potential both
offshore and onshore, although there can be no assurance that we will be able to
identify and make acquisitions of proved reserves on terms it considers
favorable.
Shelf Registration. On May 20, 1999, we filed a "shelf" registration
with the Securities and Exchange Commission to offer and sell in one or more
offerings up to a total offering amount of $250 million in securities which
could include shares of our common stock, shares of preferred stock or unsecured
debt securities or a combination thereof. Depending on market conditions and our
capital needs, we may utilize the shelf registration in order to raise capital.
We would use the net proceeds received from the sale of any securities for the
repayment of debt and/or to fund an acquisition. We may not be able to
consummate any offerings under the shelf registration statement on acceptable
terms.
Capital Structure
Revolving Bank Credit Facility. We maintain a revolving bank credit
facility with a syndicate of lenders led by JP Morgan Chase, National
Association. The credit facility provides a maximum commitment of $250 million,
which may be limited by the amount of the borrowing base. At March 31, 2002, the
borrowing base was $250 million. Up to $2.0 million of the borrowing base is
available for the issuance of letters of credit to support performance
guarantees. The credit facility matures on April 15, 2003 and is unsecured. At
March 31, 2002, $149 million was outstanding under the credit facility and $0.4
million was outstanding in letter of credit obligations. Subsequent to March 31,
2002, we increased our net borrowings by an additional $1 million, bringing
total borrowings and letters of credit to $150.4 million as of April 26, 2002.
Senior Subordinated Notes. On March 2, 1998, we issued $100 million of
8 5/8% Senior Subordinated Notes due January 1, 2008. The notes bear interest at
a rate of 8 5/8% per annum with interest payable semi-annually on January 1 and
July 1. We may redeem the notes 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 which
decreases yearly from 4.313% in 2003 to 0% after January 1, 2006 if the notes
are redeemed prior to January 1, 2006. 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, if any. The notes are general unsecured obligations and rank
subordinate in right of payment to all existing and future senior debt,
including the credit facility, and will rank senior or equal in right of payment
to all existing and future subordinated indebtedness.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Natural Gas Hedging. We utilize derivative commodity instruments to
hedge future sales prices on a portion of our natural gas 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
-19-
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 financial institutions that we
believe are minimal credit risks. Our hedges are cash flow hedges and qualify
for hedge accounting under SFAS 133 and, accordingly, we carry the fair market
value of our derivative instruments on the balance sheet as either an asset or
liability and defer 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.
The following table summarizes the change in the fair value of our
derivative instruments from January 1, 2002 to March 31, 2002.
CHANGE IN FAIR VALUE OF DERIVATIVES INSTRUMENTS 2002
--------------------------------------------------------------------------
(in thousands)
Fair value of contracts at January 1........................... $ 53,771
Gain on contracts realized..................................... 16,966
Change or decrease in fair values.............................. (68,608)
---------
Fair value of contracts outstanding at March 31................ $ 2,129
=========
-20-
The following table summarizes on a monthly basis our hedges for 2002
and 2003. All amounts are in thousands, except for prices. For the remaining
months of 2002, we have hedged approximately 70% of our estimated production or
a total of 190,000 MMBtu/day at an effective floor of $3.389 and an effective
ceiling of $4.801. For the year 2003, we have 60,000 MMBtu/day hedged at an
effective floor of $3.229 and an effective ceiling of $3.486.
FIXED PRICE SWAPS COLLARS
-------------------- -----------------------------------
NYMEX NYMEX
VOLUME CONTRACT VOLUME CONTRACT PRICE
PERIOD (MMBTU) PRICE (MMBTU) AVG FLOOR AVG CEILING
------ ------- -------- ------- --------- -----------
April 2002 900 3.010 4,800 3.561 5.137
May 2002 930 3.010 4,960 3.561 5.137
June 2002 900 3.010 4,800 3.561 5.137
July 2002 930 3.010 4,960 3.561 5.137
August 2002 930 3.010 4,960 3.561 5.137
September 2002 900 3.010 4,800 3.561 5.137
October 2002 930 3.010 4,960 3.561 5.137
November 2002 900 3.010 4,800 3.561 5.137
December 2002 930 3.010 4,960 3.561 5.137
January 2003 1,240 3.194 620 3.300 4.070
February 2003 1,120 3.194 580 3.300 4.070
March 2003 1,240 3.194 620 3.300 4.070
April 2003 1,200 3.194 600 3.300 4.070
May 2003 1,240 3.194 620 3.300 4.070
June 2003 1,200 3.194 600 3.300 4.070
July 2003 1,240 3.194 620 3.300 4.070
August 2003 1,240 3.194 620 3.300 4.070
September 2003 1,200 3.194 600 3.300 4.070
October 2003 1,240 3.194 620 3.300 4.070
November 2003 1,200 3.194 600 3.300 4.070
December 2003 1,240 3.194 620 3.300 4.070
These hedging transactions are settled based upon the New York
Mercantile Exchange or NYMEX price on the final trading day of the month. In
order to determine fair market value of our derivative instruments, we obtain
market-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.
-21-
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K:
(a) Exhibits:
EXHIBITS DESCRIPTION
-------- -----------
*10.1 -- Fourth Amendment to the Amended and Restated Revolving Credit
Facility between The Houston Exploration Company and
JPMorgan Chase Bank, National Association, as agent, dated
April 19, 2002.
---------------------------
* Filed herewith.
(b) Reports on Form 8-K:
Current Report on Form 8-K filed on March 25, 2002 to provide
new information regarding hedges for the years ended December
31, 2002 and 2003 in Item 5 - Other Events.
Current Report on Form 8-K filed April 5, 2002 to provide
information regarding change of certifying accountant in Item
4. Changes in Registrant's Certifying Accountant.
-22-
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned, hereunto duly authorized.
THE HOUSTON EXPLORATION COMPANY
By: /s/ William G. Hargett
--------------------------------------
Date: April 29, 2002 William G. Hargett
President and Chief Executive Officer
By: /s/ James F. Westmoreland
--------------------------------------
Date: April 29, 2002 James F. Westmoreland
Vice President, Chief Accounting
Officer and Secretary
-23-
INDEX TO EXHIBITS
EXHIBITS DESCRIPTION
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*10.1 -- Fourth Amendment to the Amended and Restated Revolving Credit
Facility between The Houston Exploration Company and
JPMorgan Chase Bank, National Association, as agent, dated
April 19, 2002.
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* Filed herewith.