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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 SEPTEMBER 30, 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
__________________________________
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 November 13, 2002, 30,692,895 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 .................................................................... 4
CONSOLIDATED BALANCE SHEETS -- September 30, 2002 (unaudited) and December 31, 2001............................ 4
CONSOLIDATED STATEMENTS OF OPERATIONS -- Three Months and Six Months Ended
September 30, 2002 and 2001(unaudited)................................................................ 5
CONSOLIDATED STATEMENTS OF CASH FLOWS -- Six Months Ended
September 30, 2002 and 2001 (unaudited)............................................................... 6
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS................................................................. 7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................. 15
Item 3. Quantitative and Qualitative Disclosures About Market Risk............................................ 28
Item 4. Controls and Procedures............................................................................... 30
PART II. OTHER INFORMATION.................................................................................... 31
Item 6. Exhibits and Reports on Form 8-K:..................................................................... 31
(a) Exhibits:....................................................................................... 31
(b) Reports on Form 8-K:............................................................................ 31
SIGNATURES..................................................................................................... 32
CERTIFICATIONS................................................................................................. 33
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,
actual results and developments may not conform to our expectations 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)
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------- ------------
(UNAUDITED)
ASSETS:
Cash and cash equivalents...................................................... $ 5,453 $ 8,619
Accounts receivable............................................................ 70,853 43,847
Accounts receivable -- Affiliate............................................... 822 635
Derivative financial instruments - current..................................... -- 53,771
Inventories.................................................................... 1,483 1,149
Prepayments and other.......................................................... 2,513 2,959
---------- ----------
Total current assets...................................................... 81,124 110,980
Natural gas and oil properties, full cost method
Unevaluated properties...................................................... 130,438 177,987
Properties subject to amortization.......................................... 1,712,849 1,493,293
Other property and equipment................................................... 9,986 8,265
---------- ----------
1,853,273 1,679,545
Less: Accumulated depreciation, depletion and amortization..................... (865,161) (740,784)
---------- ----------
988,112 938,761
Other assets................................................................... 4,534 9,351
---------- ----------
TOTAL ASSETS.............................................................. $1,073,770 $1,059,092
========== ==========
LIABILITIES:
Accounts payable and accrued expenses.......................................... $ 69,788 $ 76,666
Derivative financial instruments............................................... 14,645 --
---------- ----------
Total current liabilities................................................. 84,433 76,666
Long-term debt and notes....................................................... 247,000 244,000
Derivative financial instruments............................................... 4,533 --
Deferred federal income taxes.................................................. 170,791 172,169
Other deferred liabilities..................................................... 636 376
---------- ----------
TOTAL LIABILITIES......................................................... 507,393 493,211
COMMITMENTS AND CONTINGENCIES (SEE NOTE 3)
STOCKHOLDERS' EQUITY:
Common Stock, $.01 par value, 50,000,000 shares authorized and 30,585,635
shares issued and outstanding at September 30, 2002 and 30,463,230 shares
issued and outstanding at December 31, 2001, respectively................... 306 305
Additional paid-in capital..................................................... 339,366 336,977
Unearned compensation.......................................................... (129) (192)
Retained earnings.............................................................. 239,300 193,840
Accumulated other comprehensive income (loss).................................. (12,466) 34,951
---------- ----------
TOTAL STOCKHOLDERS' EQUITY................................................ 566,377 565,881
---------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY................................ $1,073,770 $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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
2002 2001 2002 2001
-------- -------- -------- --------
(UNAUDITED) (UNAUDITED)
REVENUES:
Natural gas and oil revenues................ $81,721 $78,150 $237,528 $301,062
Other....................................... 250 345 811 1,083
------- ------- -------- --------
Total revenues............................ 81,971 78,495 238,339 302,145
OPERATING EXPENSES:
Lease operating............................. 8,694 6,436 23,993 19,440
Severance tax............................... 2,798 1,771 7,281 9,500
Depreciation, depletion and amortization.... 42,350 32,102 124,198 92,365
General and administrative, net............. 2,669 3,792 8,497 14,371
------- ------- -------- --------
Total operating expenses.................. 56,511 44,101 163,969 135,676
Income from operations........................ 25,460 34,394 74,370 166,469
Other expense................................. -- -- -- 119
Interest expense, net......................... 2,277 213 5,331 2,683
------- ------- -------- --------
Income before income taxes.................... 23,183 34,181 69,039 163,667
Provision for taxes........................... 7,911 11,651 23,579 57,938
------- ------- -------- --------
NET INCOME.................................... $15,272 $22,530 $ 45,460 $105,729
======= ======= ======== ========
Net income per share -- basic................. $ 0.50 $ 0.74 $ 1.49 $ 3.50
======= ======= ======== ========
Net income per share -- fully diluted......... $ 0.50 $ 0.73 $ 1.47 $ 3.45
======= ======= ======== ========
Weighted average shares outstanding........... 30,540 30,368 30,514 30,167
Weighted average shares outstanding --
fully diluted............................... 30,830 30,769 30,840 30,609
The accompanying notes are an integral part of these consolidated
financial statements.
5
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
NINE MONTHS ENDED SEPTEMBER 30,
2002 2001
------------ -----------
(UNAUDITED)
OPERATING ACTIVITIES:
Net income................................................................... $ 45,460 $ 105,729
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and amortization..................................... 124,198 92,365
Deferred income tax expense.................................................. 24,154 58,573
Stock compensation expense................................................... 63 43
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable................................. (27,193) 72,027
(Increase) decrease in inventories......................................... (334) 190
Decrease (increase) in prepayments and other............................... 446 (904)
Decrease (increase) in other assets ....................................... 4,817 (4,788)
Decrease in accounts payable and accrued expenses.......................... (6,878) (9,010)
Increase (decrease) in other liabilities................................... 260 (30)
--------- ---------
Net cash provided by operating activities.................................... 164,993 314,195
INVESTING ACTIVITIES:
Investment in property and equipment......................................... (178,860) (244,884)
Dispositions ................................................................ 5,311 --
--------- ---------
Net cash used in investing activities........................................ (173,549) (244,884)
FINANCING ACTIVITIES:
Proceeds from long term borrowings........................................... 46,000 83,000
Repayments of long term borrowings........................................... (43,000) (168,000)
Proceeds from issuance of common stock....................................... 2,390 8,910
--------- ---------
Net cash used in financing activities........................................ 5,390 (76,090)
--------- ---------
Increase (decrease) in cash and cash equivalents............................. (3,166) (6,779)
Cash and cash equivalents, beginning of period............................... 8,619 9,675
--------- ---------
Cash and cash equivalents, end of period..................................... $ 5,453 $ 2,896
========= =========
Cash paid for interest....................................................... $ 13,417 $ 13,945
========= =========
Cash paid for taxes.......................................................... $ -- $ --
========= =========
The accompanying notes are an integral part of these consolidated
financial statements.
6
THE HOUSTON EXPLORATION COMPANY
NOTES TO 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 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 a mix of:
- high potential offshore exploration and exploitation;
- lower risk exploitation and development drilling onshore; and
- selective acquisitions both offshore and onshore.
At December 31, 2001, our net proved reserves were 608 billion cubic
feet equivalent or Bcfe, with a present value, discounted at 10% per annum, of
cash flows before income taxes of $714 million. Our reserves are fully
engineered on an annual basis by independent petroleum engineers. Our focus is
natural gas. Approximately 93% of our net proved reserves at December 31, 2001
were natural gas, approximately 74% of which 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 and
sold approximately 34% of our shares to the public with KeySpan retaining the
balance. As of September 30, 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 September 30, 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 in any material respect. 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 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
On October 16, 2002, our Board of Directors resolved that effective
January 1, 2003, we will adopt Statement of Financial Accounting Standards
("SFAS") No. 123, "Accounting for Stock - Based Compensation." We will adopt
SFAS No. 123 prospectively and as a result, we will record as compensation
expense the fair value of all stock options issued subsequent to January 1,
2003. Currently, we account for stock options using the intrinsic value method
prescribed under Accounting Principles Board Opinion 25 and accordingly, we do
not recognize compensation expense for stock options. Based on our current
estimates, we do not expect the effect of recognizing compensation expense from
the issuance of options to have a material impact on our financial position,
results of operations or cash flows.
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. 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 and at this time cannot
reasonably estimate the effect of the adoption of this statement.
In April 2002 the Financial Accounting Standards Board ("FASB") issued
SFAS No. 145, "Rescission of FASB Statements No. 4, No. 44, and No. 64,
Amendment to FASB Statement No. 13 and Technical Corrections." SFAS No. 145
streamlines the reporting of debt extinguishments and requires that only gains
and losses from extinguishments meeting the criteria in Accounting Policies
Board Opinion 30 would be classified as extraordinary. Thus, gains or losses
arising from extinguishments that are part of a company's recurring operations
would not be reported as an extraordinary item. SFAS No. 145 is effective for
fiscal years beginning after May 15, 2002. At this time, we do not expect the
adoption of SFAS No. 145 to have a material impact on our financial position,
results of operations or cash flows.
SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities" was issued in June 2002 and addresses accounting and reporting for
costs associated with exit or disposal activities and nullifies Emerging Issues
Task Force ("EITF") Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for
a cost associated with an exit or disposal activity be recognized when the
liability is incurred. Under Issue 94-3, a liability for an exit cost was
recognized at the date of an entity's commitment to an exit plan. Under SFAS No.
146, the objective for initial measurement of the liability is fair value. SFAS
No. 146 is effective for exit or disposal activities that are initiated after
December 31, 2002. At this time, we do not expect that the adoption of SFAS No.
146 to have a material impact on our financial position, results of operations
or cash flows.
Hedging Contracts
We utilize derivative commodity instruments to hedge future sales
prices on a portion of our natural gas and oil production in order to achieve a
more predictable cash flow and to reduce our exposure to adverse price
fluctuations. We do not hold derivatives 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
8
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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 are designed to meet
the criteria for hedge accounting treatment under SFAS No. 133, "Accounting for
Derivative Instruments 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. 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 or became ineffective as defined by SFAS 133, any gains
or losses would be currently recognized in earnings.
At September 30, 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 represented a deferred loss of $19.2 million. As a
result, at September 30, 2002, we have recorded a liability of $19.2 million
($12.5 million, net of taxes) to our balance sheet. Of the total liability,
$14.7 million presents a current liability for the hedge contracts in place for
the months October 2002 through September 2003 and $4.5 million represents a
non-current liability for hedge contracts in place for the months October 2003
through December 2003. Correspondingly, the September 30, 2002 balance of
accumulated other comprehensive income reflects a net debit of $12.5 million
(net of related deferred taxes of $6.7 million) which represents the fair market
value of our total deferred hedge loss, net of tax, as of that date.
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 a
positive $53.8 million. As a result, our balance sheet at December 31, 2001
reflected 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 as of that date.
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 and gives pro forma effect to 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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
2002 2001 2002 2001
-------- ------- -------- -------
(in thousands, except per share data)
Net income $15,272 $22,530 $45,460 $105,729
======= ======= ======= ========
Weighted average shares outstanding.......... 30,540 30,368 30,514 30,167
Add dilutive securities:
Options.................................... 290 401 326 442
------- ------- ------- --------
Total weighted average shares outstanding
and dilutive securities.................... 30,830 30,769 30,840 30,609
======= ======= ======= ========
Net income per share......................... $ 0.50 $ 0.74 $ 1.49 $ 3.50
======= ======= ======= ========
Net income per share - fully diluted......... $ 0.50 $ 0.73 $ 1.47 $ 3.45
======= ======= ======= ========
9
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Comprehensive Income
The table below summarizes our Comprehensive Income for the three month
and six month periods ended September 30, 2002 and 2001, respectively.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
2002 2001 2002 2001
--------- -------- -------- --------
(in thousands)
Net income $ 15,272 $22,530 $ 45,460 $105,729
Other comprehensive income, net of taxes:
Unrealized gain (loss) on derivative
instruments (11,693) 31,037 (47,417) 51,121
-------- ------- -------- --------
Comprehensive income......................... $ 3,579 $53,567 $ (1,957) $156,850
======== ======= ======== ========
NOTE 2 -- LONG-TERM DEBT AND NOTES
SEPTEMBER 30, 2002 DECEMBER 31, 2001
------------------ -----------------
(in thousands)
SENIOR DEBT:
Bank revolving credit facility, due July 2005.... $147,000 $144,000
SUBORDINATED DEBT:
8 5/8% Senior Subordinated Notes, due January 2008 100,000 100,000
-------- --------
Total long-term debt and notes................. $247,000 $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 September 30, 2002, the quoted market value of the
Company's $100 million of 8 5/8% Senior Subordinated Notes was 102.6% of the
$100 million carrying value or $102.6 million.
Credit Facility
New Credit Facility. We entered into a new revolving bank credit
facility dated as of July 15, 2002 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 new credit facility replaced our previous $250
million revolving credit facility maintained with a syndicate of lenders led by
JPMorgan Chase, National Association and provides us with an initial commitment
of $300 million. The initial $300 million commitment can 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 new credit facility is subject to borrowing base limitations,
and the borrowing base has been set at $300 million and will be redetermined
semi-annually, with the next redetermination scheduled for April 1, 2003. Up to
$25 million of the borrowing base is available for the issuance of letters of
credit. The new credit facility matures July 15, 2005, is unsecured and with the
exception of trade payables, ranks senior to all of our existing debt. Following
the closing of the new credit facility on July 18, 2002, funds were drawn on the
new facility and used to repay total outstanding borrowings under the previous
credit facility of $170 million. At September 30, 2002, $147 million in
borrowings were outstanding under the new facility and $0.4 million was
outstanding in letter of credit obligations. Subsequent to September 30, 2002,
we borrowed an additional $17 million under the new facility. The subsequent
borrowings were used to fund a portion of the $26.5 million purchase price of
incremental working
10
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
interests in offshore producing properties acquired on October 11, 2002 from a
subsidiary of KeySpan (see Note 4 -- Related Party Transactions -- Acquisition
of KeySpan Joint Venture Assets.) At November 13, 2002, outstanding borrowings
and letter of credit obligations under the new credit facility totaled $164.4
million.
Interest is payable on borrowings under our 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 .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.
Our credit facility contains 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 70% of our natural gas production during any
12-month period.
As of September 30, 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:
- 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 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
11
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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
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 our Charco
Field in South Texas. The "high-cost/tight-gas formation" designation will allow
us to receive an abatement of severance taxes for qualifying wells in the Charco
Field. For qualifying wells, production will be either exempt from tax or taxed
at a reduced rate until certain capital costs are recovered. For qualifying
wells, we will also be entitled to a refund of severance taxes paid during a
designated prior 48-month period. Applications for refund are submitted on a
well-by-well basis to the State Comptroller's Office and due to timing of the
acceptance of applications, we are unable to project the 48-month look-back
period for qualifying refunds. Subject to acceptance of the applications, we are
currently estimating that the total refund, for both current year and prior
periods, will be between $18 million to $23 million ($12 million to $15 million,
net of tax), although we can provide no assurances that the actual total refund
amount will fall within our current estimate. Of the total refund, we estimate
that between $5 million to $6 million ($3 million to $4 million, net of tax)
would reduce 2002 severance tax expense and the balance would relate to prior
periods. We anticipate the acceptance of the applications and the related cash
collection of the refunds will begin during the fourth quarter of 2002 and will
continue through the first half of 2003. In addition, based on the
"high-cost/tight gas formation" designation, we expect that severance taxes paid
on production in our Charco Field will be lower in future periods due to the
reduced rate; however, we are unable to estimate the impact at this time.
Legal Proceedings
On August 18, 2002, a complaint styled Victor Ramirez, Santiago
Ramirez, Jr., Oswaldo H. Ramirez and Javier Ramirez as Co-Trustees of the
Ramirez Mineral Trust v. The Houston Exploration Company, cause number 5,207,
was filed in the district court of the 49th Judicial District in Zapata County,
Texas. The complaint alleges that we trespassed by drilling the No. 7 RMT well
to a depth in excess of our lease rights and commingled production by producing
from the excess depth. The plaintiffs claim damages for trespass and conversion
in excess of $6 million and further seek to recover exemplary damages in excess
of $18 million. No reserve has been established for the claim, as we are
currently unable to predict the outcome of the claim.
We are involved from time to time in various claims and lawsuits
incidental to our business. In our opinion, 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, 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 of $7.7 million in 2000 and $20.7 million
during 1999. 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. 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
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
12
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
joint venture. In addition, effective with the termination of the exploratory
term of the joint venture, we have not received any further reimbursement from
KeySpan for general and administrative costs.
During the initial two-year term of the joint venture, we drilled a
total of 21 wells: 17 exploratory wells and four development wells. Five of the
wells drilled were unsuccessful. During 2001, KeySpan participated in the
drilling of three additional wells, all of which were successful. These wells
further developed or delineated reservoirs discovered during the initial term of
the joint venture. During the first nine months of 2002, KeySpan participated in
four wells, all of which were successful and provided further exploitation of
previous discoveries, and spent $18.1 million in capital costs compared to $13.5
million spent during the first nine months of 2001. For the third quarter of
2002, KeySpan spent $3.5 million in capital costs compared to $3.4 million spent
during the corresponding quarter of 2001.
Acquisition of KeySpan Joint Venture Assets
On October 11, 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. 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. The interests purchased were in the following blocks: Vermilion 408, East
Cameron 81 and 84, High Island 115, Galveston Island 190 and 389, Matagorda
Island 704 and North Padre Island 883. KeySpan has retained its 45% interest in
four blocks: South Timbalier 314 and 317 and Mustang Island 725 and 726 as these
blocks are in various stages of development. KeySpan has committed to continuing
its participation in the ongoing development of these blocks which includes the
completion of the platform and production facilities at South Timbalier 314/317
together with possible further developmental drilling at both South Timbalier
314/317 and Mustang Island 725/726; however, it is possible that we could
purchase the blocks in the future. As of September 1, 2002, the effective date
of the purchase, the estimated proved reserves associated with the interests
acquired were 13.5 Bcfe. Daily production for the interests acquired averages
approximately 15 million cubic feet equivalents per day (MMcfe/d). The $26.5
million purchase price was paid in cash and financed with borrowings under our
new revolving credit facility.
Our Board of Directors appointed a special committee, comprised
entirely of independent directors to review the proposed transaction with
KeySpan. For assistance, the special committee retained special outside legal
counsel as well as the financial advisory firm of Petrie Parkman & Co. In
addition, the special committee discussed the history and terms of the
transaction with our senior management. After completing its review, the special
committee unanimously concluded that the transaction was advisable and in our
best interests and that the terms of the transaction were at least as favorable
to us as terms that would have been obtainable at the time in a comparable
transaction with an unaffiliated party. In reaching its decision, the special
committee considered numerous factors in consultation with its financial and
legal advisors. The special committee also took into account the opinion
delivered to it by Petrie Parkman & Co. to the effect that the consideration to
be paid by us in the transaction was fair to us from a financial point of view.
NOTE 5 -- ACQUISITIONS
ACQUISITION OF KEYSPAN JOINT VENTURE ASSETS - (SEE NOTE -- 4 RELATED PARTY
TRANSACTIONS.)
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 North East
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
13
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
purchase price adjustment of $3.9 million, was financed by borrowings under our
revolving bank credit facility. Production from the acquired properties for the
month of September 2002 averaged 12 MMcfe/day, net to the interests acquired.
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 represents interests in 22 producing wells with reserves of
approximately 5 Bcfe and average daily production of 2 Mcfe/day, net to our
interest. Proceeds from the sale were used to repay borrowings under our new
revolving bank credit facility.
We retained the North East Thompsonville Field, located in Jim Hogg
County, and the South Laredo Field, located in Webb County. The North East
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.
14
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
and the nine months ended September 30, 2002 and 2001. Please refer to our
consolidated financial statements and notes thereto included elsewhere in this
report for more detailed information 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 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 a mix of:
- high potential offshore exploration and exploitation;
- lower risk exploitation and development drilling onshore; and
- selective acquisitions both offshore and onshore.
At December 31, 2001, our net proved reserves were 608 billion cubic
feet equivalent or Bcfe, with a present value, discounted at 10% per annum, of
cash flows before income taxes of $714 million. Our reserves are fully
engineered on an annual basis by independent petroleum engineers. Our focus is
natural gas. Approximately 93% of our net proved reserves at December 31, 2001
were natural gas, approximately 74% 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 and
sold approximately 34% of our shares to the public with KeySpan retaining the
balance. As of September 30, 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 natural gas and oil 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 and commodity prices may fluctuate widely
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. Our total unamortized cost base is the sum of (i) our full cost pool;
less (ii) our unevaluated properties and their related costs which are excluded
from the amortization base until we have made a determination as to the
existence of proved reserves; plus (iii) estimates for future development costs
as well as future abandonment and dismantlement costs. 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
15
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 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 September 30, 2002, we estimated that we had a
full cost ceiling "cushion", whereby the carrying value of our full cost pool
was less than 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 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. Further, any estimates of natural gas and oil reserves and
their values are inherently uncertain for numerous reasons, 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, and these revisions 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.
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 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. Historically, we
have not experienced credit losses on our receivables; however, recent market
conditions resulting in downgrades to credit ratings of energy merchants have
affected the liquidity of several of our purchasers. As of August 1, 2002, we
are no longer selling natural gas and oil to CenterPoint Energy Incorporated
(formerly Reliant Energy Incorporated) and Dynegy Inc. We are continuing to sell
gas to Williams Companies, Inc. which has posted a letter of credit to secure
their performance under the purchase contracts. Based on the current demand for
natural gas and oil, we do not expect that termination of sales to these
companies would have a material adverse effect on our ability to sell our
production at favorable market prices.
16
Further, our natural gas futures and swap contracts also expose us to
credit risk in the event of nonperformance by counterparties. Generally, these
contracts are with major investment grade financial institutions and
historically we have not experienced material credit losses. In July 2002, our
outstanding swap and option contracts with Williams were assigned to Bank of
America. 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; however, as a result of our hedging
activities we may be exposed to greater credit risk in the future.
New Accounting Pronouncements
On October 16, 2002, our Board of Directors resolved that effective
January 1, 2003, we will adopt Statement of Financial Accounting Standards
("SFAS") No. 123, "Accounting for Stock - Based Compensation." We will adopt
SFAS No. 123 prospectively and as a result, we will record as compensation
expense the fair value of all stock options issued subsequent to January 1,
2003. Currently, we account for stock options using the intrinsic value method
prescribed under Accounting Principles Board Opinion 25 and accordingly, we do
not recognize compensation expense for stock options. Based on our current
estimates, we do not expect the effect of recognizing compensation expense from
the issuance of options to have a material impact on our financial position,
results of operations or cash flows.
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. 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 and at this time we cannot reasonably estimate the effect
of the adoption of this statement.
In April 2002 the Financial Accounting Standards Board ("FASB") issued
SFAS No. 145, "Rescission of FASB Statements No. 4, No. 44, and No. 64,
Amendment to FASB Statement No. 13 and Technical Corrections." SFAS No. 145
streamlines the reporting of debt extinguishments and requires that only gains
and losses from extinguishments meeting the criteria in Accounting Policies
Board Opinion 30 would be classified as extraordinary. Thus, gains or losses
arising from extinguishments that are part of a company's recurring operations
would not be reported as an extraordinary item. SFAS No. 145 is effective for
fiscal years beginning after May 15, 2002. At this time, we do not expect the
adoption of SFAS No. 145 to have a material impact on our financial position,
results of operations or cash flows.
SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities" was issued in September 2002 and addresses accounting and reporting
for costs associated with exit or disposal activities and nullifies Emerging
Issues Task Force ("EITF") Issue No. 94-3, "Liability Recognition for Certain
Employee Termination Benefits and Other Costs to Exit an Activity (including
Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a
liability for a cost associated with an exit or disposal activity be recognized
when the liability is incurred. Under Issue 94-3, a liability for an exit cost
was recognized at the date of an entity's commitment to an exit plan. Under SFAS
No 146, fair value is the objective for initial measurement of the liability.
SFAS No. 146 is effective for exit or disposal activities that are initiated
after December 31, 2002. At this time, we do not expect the adoption of SFAS No.
146 to have a material impact on our financial position, results of operations
or cash flows.
17
Acquisitions
KeySpan Joint Venture Assets. On October 11, 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. 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. The interests purchased were in
the following blocks: Vermilion 408, East Cameron 81 and 84, High Island 115,
Galveston Island 190 and 389, Matagorda Island 704 and North Padre Island 883.
KeySpan has retained its 45% interest in four blocks: South Timbalier 314 and
317 and Mustang Island 725 and 726. as these blocks are in various stages of
development. KeySpan has committed to continuing its participation in the
ongoing development of these blocks which includes the completion of the
platform and production facilities at South Timbalier 314/317 together with
possible further developmental drilling at both South Timbalier 314/317 and
Mustang Island 725/726; however, it could be a possibility that we could
purchase the blocks in the future. As of September 1, 2002, the effective date
of the purchase, the estimated proved reserves associated with the interests
acquired were 13.5 Bcfe. Daily production for the interests acquired averages
approximately 15 million cubic feet equivalents per day (MMcfe/d). The $26.5
million purchase price was paid in cash and financed with borrowings under our
new revolving credit facility.
Our Board of Directors appointed a special committee, comprised
entirely of independent directors to review the proposed transaction with
KeySpan. For assistance, the special committee retained special outside legal
counsel as well as the financial advisory firm of Petrie Parkman & Co. In
addition, the special committee discussed the history and terms of the
transaction with our senior management. After completing its review, the special
committee unanimously concluded that the transaction was advisable and in our
best interests and that the terms of the transaction were at least as favorable
to us as terms that would have been obtainable at the time in a comparable
transaction with an unaffiliated party. In reaching its decision, the special
committee considered numerous factors in consultation with its financial and
legal advisors. The special committee also took into account the opinion
delivered to it by Petrie Parkman & Co. to the effect that the consideration to
be paid by us in the transaction was fair to us from a financial point of view.
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
North East 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. Production from the
acquired properties for the month of September 2002 is averaging 12.0 MMcfe/day,
net to the interests acquired.
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 as the effective date of the
transaction was January 1, 2002. These fields, located in Wharton and Calhoun
counties, respectively, are outside our current area of focus in South Texas.
The sale represents interests in 22 producing wells with reserves of
approximately 5 Bcfe and average daily production of 2 Mcfe/day, net to our
interest. Proceeds from the sale were used to repay borrowings under our
revolving bank credit facility.
We retained the North East Thompsonville Field, located in Jim Hogg
County, and the South Laredo Field, located in Webb County. The North East
Thompsonville Field has 10 wells producing wells from the Wilcox formation, all
of which we operate, and represents approximately 70% of the proved reserves and
75% of the current production associated with the acquisition. 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
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
18
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%. As of January 1, 2002,
total net proved reserves relating to these properties were 80 Bcfe. Beginning
January 1, 2002, we initiated an active drilling and workover program under
which we have drilled 26 development wells, with 21 wells successfully completed
and currently producing, three dry holes and two in progress. Average daily
production has increased from approximately 19 MMcfe/day, net to the interests
acquired, in January 2002 to 36 MMcfe/day, net to our interests, in September
2002. Currently we have two drilling rigs under contract, which we plan to keep
utilized for the remainder of 2002.
Other Recent Developments
Joint Offshore Exploration Program. Effective September 1, 2002, we
entered into a joint offshore exploration agreement with El Paso Production Oil
& Gas USA, L.P., a subsidiary of El Paso Corporation. Under the terms of the
agreement, El Paso will initially contribute up to $50 million for land, seismic
and drilling costs in exchange for 50% of our working interest in up to six
specified prospects that we have developed. El Paso will pay 100% of the
drilling costs to casing point or 100% of the "dry hole costs". El Paso will
operate four of the proposed wells and we will operate the remaining two. Under
the terms of the agreement, El Paso has the option to extend the exploration
agreement beyond the initial six well program. As of the date of this report, we
have successfully drilled two wells in the program: East Cameron 82 A-3 and East
Cameron 83 A-3. Hook-up of these wells is currently in progress and initial
production is expected in the second half of November 2002. Our next two wells
under the joint exploration agreement are currently drilling at Matagorda 652 #1
and East Cameron 82 #6. The final two wells in the program are scheduled for the
first quarter of 2003, the first at Murdock Pass in Texas state waters and the
second at High Island 115 for which we have an obligation of $5 million for dry
hole costs.
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 our Charco Field in South Texas. The "high-cost/tight-gas
formation" designation will allow us to receive an abatement of severance taxes
for qualifying wells in the Charco Field. For qualifying wells, production will
be either exempt from tax or taxed at a reduced rate until certain capital costs
are recovered. For qualifying wells, we will also be entitled to a refund of
severance taxes paid during a designated prior 48-month period. Applications for
refund are submitted on a well-by-well basis to the State Comptroller's Office
and due to timing of the acceptance of applications, we are unable to project
the 48-month look-back period for qualifying refunds. Subject to acceptance of
the applications, we are currently estimating that the total refund, for both
current year and prior periods, will be between $18 million to $23 million ($12
million to $15 million, net of tax), although we can provide no assurances that
the actual total refund amount will fall within our current estimate. Of the
total refund, we estimate that between $5 million to $6 million ($3 million to
$4 million, net of tax) would reduce 2002 severance tax expense and the balance
would relate to prior periods. We anticipate the acceptance of the applications
and the related cash collection of the refunds will begin during the fourth
quarter of 2002 and will continue through the first half of 2003. In addition,
based on the "high-cost/tight-gas formation" designation, we expect that
severance taxes paid on production in our Charco Field will be lower in future
periods due to the reduced rate; however, we are unable to estimate the impact
at this time.
Arkansas Downspacing. In September 2002, we presented evidence to the
Arkansas Oil and Gas Commission that our Chismville and Booneville Fields
located principally in Franklin, Sebastian and Logan counties were areas of
highly fragmented and complicated geology and that because of the complex
geology, denser drilling was necessary to fully exploit the reserve potential.
The Arkansas Oil and Gas Commission issued a favorable ruling that will allow
downspacing from 640 acres to 160 acres on future wells. Pursuant to the ruling,
we are planning to increase our 2003 drilling program in Arkoma from
approximately 20 wells planned for 2002 to approximately 30 wells for 2003. In
addition to allowing for the drilling of more wells on our acreage, the ruling
will allow us to place completed wells on-line at faster rates than we are now
experiencing.
Proved Reserves Inquiry. The SEC is currently in the process of
obtaining information from oil and gas exploration companies operating offshore
in the Gulf Of Mexico, including our company, to review the methodologies used
to determine proved reserves in an initial offshore discovery situation. The
SEC's regulations allow companies to recognize proved reserves if economic
producibility is supported by either an actual production flow test or
conclusive formation testing. Without a production flow test, compelling
technical data must exist to book proved reserves in a discovery situation. In
offshore situations where production flow tests are extremely expensive, the
industry has increasingly depended on advanced technology to provide compelling
testing data for a conclusive formation test. In October 2002, we responded to
the SEC's inquiry and provided the all requested information. Currently, we
estimate that approximately 1% of our total proved reserves at December 31,
2001, the date of our most recently available fully engineered reserve report,
related to an initial discovery situation where proved reserves were booked
based on conclusive formation tests rather than production flow tests. At this
time, we are unable to predict the outcome and the results of the SEC's inquiry,
but we do not expect the inquiry or its outcome to have a material effect on our
proved reserves or our financial results.
19
RESULTS OF OPERATIONS
The following table sets forth our historical natural gas and oil
production data during the periods indicated:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ------------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
PRODUCTION:
Natural gas (MMcf)......................... 24,245 21,332 72,590 64,722
Oil (MBbls)................................ 218 117 600 328
Total (MMcfe).............................. 25,553 22,034 76,190 66,690
Average daily production (MMcfe/day)....... 278 240 279 244
AVERAGE SALES PRICES:
Natural gas (per Mcf) realized(1).......... $ 3.14 $ 3.53 $ 3.08 $ 4.53
Natural gas (per Mcf) unhedged............. 2.99 2.71 2.80 4.71
Oil (per Bbl).............................. 25.77 24.74 23.40 24.59
OPERATING EXPENSES (PER MCFE):
Lease operating............................ $ 0.34 $ 0.29 $ 0.31 $ 0.29
Severance tax.............................. 0.11 0.08 0.10 0.14
Depreciation, depletion and amortization... 1.66 1.46 1.63 1.38
General and administrative, net(2)......... 0.10 0.17 0.11 0.22
--------------------------------
(1) Reflects the effects of hedging.
(2) For the three months and nine months ended September 30, 2001, net
general and administrative expense includes one-time payments
totaling $1.5 million and $5.2 million, respectively in connection
with the termination of employment contracts.
RECENT FINANCIAL AND OPERATING RESULTS
COMPARISON OF THREE MONTHS ENDED SEPTEMBER 30, 2002 AND 2001
Production. Our production increased 16% from 22,034 million cubic feet
equivalent, or MMcfe, for the three months ended September 30, 2001 to 25,553
MMcfe for the three months ended September 30, 2002. The increase in production
was primarily attributable to new production from properties acquired in South
Texas since December 31, 2001 and new production generated from the subsequent
development and workover program initiated on these acquired properties during
2002. The increase in onshore production for the third quarter of 2002 was
offset in part by a decline in offshore production caused primarily by
production shut-ins during the month of September 2002 caused by Tropical Storms
Faye and Isidore.
Onshore, our daily production rates increased 39% from an average of
112 MMcfe/day during the third quarter of 2001 to an average of 156 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
36 MMcfe/day of the increase, and from the properties purchased on May 30, 2002
from Burlington Resources, which accounts for 12 MMcfe/day of the increase for
the quarter. Production at our Charco Field increased slightly from 77 MMcfe/day
during the third quarter of 2001 to 78 MMcfe/day during the third quarter of
2002. Production from our Arkoma, East Texas and West Virginia fields decreased
from an average of 28 MMcfe/day during the third quarter of 2001 to 24 MMcfe/day
during the third quarter of 2002. The decrease is primarily related to our
Arkoma Field properties and is due to a late start of our developmental drilling
program for 2002 combined with delays in obtaining allowable production rates
for newly completed wells from the Arkansas Oil and Gas Commission. We expect
Arkoma production to
20
increase during the fourth quarter of 2002 as our backlog of completed wells
receives approval for production from the State of Arkansas. In addition, we
expect that the favorable downsizing ruling that we received in September 2002
will alleviate some of the waiting period we are currently experiencing for
bringing newly completed wells on-line. Production in South Louisiana decreased
from 7 MMcfe/day during the third quarter of 2001 to 6 MMcfe/day during the
third quarter of 2002.
Offshore, our production decreased 5% from an average of 128 MMcfe/day
during the third quarter of 2001 to an average of 122 MMcfe/day during the third
quarter of 2002. This decrease is primarily attributable to the affects of
tropical weather during the third quarter of 2002. In September 2002, offshore
production was shut-in due to Tropical Storms Faye and Isidore. In total, we
lost an estimated 350 MMcfe caused by storm related shut-ins during the month of
September 2002, which equates to approximately 4 MMcfe/day for the quarter.
Absent the affects of shut-ins due to tropical weather, overall offshore
production decreased by approximately 2% from the third quarter of 2001.
Production declines from existing properties were greater than production
increases from newly developed production at South Marsh Island 253 and Mustang
Island 785, which were added during the fourth quarter of 2001 combined with
production at Vermilion 408, which was brought on-line during January 2002, and
East Cameron 81, which has had a series of four wells brought on-line during the
first nine months of 2002.
Natural Gas and Oil Revenues. Natural gas and oil revenues increased 5%
from $78.1 million for the third quarter of 2001 to $81.7 million for the third
quarter of 2002 as a result of a 16% increase in production offset in part by an
11% decrease in average realized natural gas prices, from $3.53 per Mcf during
the third quarter of 2001 to $3.14 per Mcf in the third quarter of 2002.
Natural Gas Prices. For the third quarter of 2002, we realized an
average gas price of $3.14 per Mcf that was 105% of our average unhedged natural
gas price of $2.99 per Mcf. As a result of hedging activities, natural gas and
oil revenues for the third quarter of 2002 were $3.5 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 $3.53 per Mcf, which was 130% of the average unhedged natural gas price
of $2.71 per Mcf that otherwise would have been received, resulting in natural
gas and oil revenues that were $17.5 million higher 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 36% from $6.4 million for the three months ended September 30, 2001 to
$8.7 million for the corresponding three months of 2002. On an Mcfe basis, lease
operating expenses increased from $0.29 per Mcfe during the third quarter of
2001 to $0.34 per Mcfe during the third quarter of 2002. The increase in both
lease operating expenses and lease operating expenses per unit is attributable
to the continued expansion of our operations both onshore combined with an
increase in expenses during the third quarter of 2002.
Onshore operations expanded with the acquisition of approximately 304
new producing wells in South Texas with 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
primary cause for the increase in our onshore lease operating expenses is due to
the increase in ad valorem taxes. Ad valorem taxes increased more than 50%
during 2002 due to the fact that 2002 property valuations are based on revenues
generated from the properties during 2001. On an annualized basis, revenues
generated during 2001 were at record levels due to higher than normal natural
gas prices during the first six months of the year. Offshore, our lease
operating expenses have increased as well, due to the addition of new oil
production facilities at Vermilion 408 which are inherently more costly to
operate, new natural gas facilities at East Cameron 81 and the implementation of
compression projects to enhance production capabilities at several of our
existing facilities.
Severance tax, which is a function of volume and revenues generated
from onshore production, increased 56% from $1.8 million for the third quarter
of 2001 to $2.8 million for the third quarter of 2002. On an Mcfe basis,
severance tax increased 38% from $0.08 per Mcfe for the third quarter of 2001 to
$0.11 per Mcfe during the third quarter of 2002. The increase in severance tax
expense and severance tax per Mcfe is primarily attributable to the increase in
our onshore production during 2002 combined with wellhead prices that were 10%
higher during the third quarter of 2002 as compared to the third quarter of
2001.
21
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 32% from $32.1 million for the three months ended
September 30, 2001 to $42.3 million for the three months ended September 30,
2002. Depreciation, depletion and amortization expense per Mcfe increased 14%
from $1.46 for the three months ended September 30, 2001 to $1.66 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. Our depletion rate has increased during 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 pool with the
addition of fewer new reserves from exploration and developmental drilling
together with an overall increase in our finding and development costs. We
believe that higher finding costs are 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. Because the
Outer Continental Shelf is a mature producing area, it is becoming increasingly
more difficult to find and develop new reserves at historical costs.
General and Administrative Expenses, Net of Capitalized General and
Administrative Expenses and Overhead Reimbursements. General and administrative
expenses, net of overhead reimbursements received from other working interest
owners of $0.3 million for both the three months ended September 30, 2001 and
2002 and capitalized general and administrative expenses directly related to oil
and gas exploration and development activities of $2.6 million and $3.4 million
for the three months ended September 30, 2001 and 2002, respectively, decreased
29% from $3.8 million for the three months ended September 30, 2001 to $2.7
million for the three months ended September 30, 2002. Aggregate general and
administrative expenses decreased 4% from $6.7 million for the third quarter of
2001 to $6.4 million for the third quarter of 2002. However, included in both
aggregate and net general and administrative expense for the third quarter of
2001 is a one-time charge of $1.5 million paid in connection with the
termination of an employment contract. Absent this $1.5 million charge taken in
the third quarter of 2001, aggregate general and administrative expenses would
have been $5.2 million during the third quarter of 2001 compared to $6.4 million
during the third quarter of 2002, reflecting a 23% increase for the current
quarter. The increase in aggregate expense is primarily a result of the
expansion of our workforce and office space in Houston during the first nine
months of 2002 combined with an increase in employee benefit expenses, legal,
consulting and accounting fees. As a result of the increase in aggregate general
and administrative expenses, we capitalized more general and administrative
expense during the third quarter of 2002. Absent the $1.5 million charge, net
general and administrative expenses would have been $2.3 million for the third
quarter 2001 compared to $2.7 million for the third quarter of 2002, reflecting
a 17% increase.
On an Mcfe basis, net general and administrative expenses decreased 41%
from $0.17 during the third quarter of 2001 to $0.10 per Mcfe during the third
quarter of 2002. Absent the $1.5 million charge taken in the third quarter of
2001 for the termination of an employment contract, net general and
administrative expense per Mcfe would have been $0.10 per Mcfe. Although both
aggregate and net general and administrative expenses increased from the third
quarter of 2001, the rate per Mcfe, as adjusted, is comparable due to the
increase in production during the third quarter of 2002.
Interest Expense, Net of Capitalized Interest. Interest expense, net of
capitalized interest, increased from $0.2 million for the three months ended
September 30, 2001 to $2.3 million for the corresponding three months of 2002.
Aggregate interest increased 31% from $3.2 million during the third quarter of
2001 to $4.2 million during the third quarter of 2002. Aggregate interest is
higher during the third quarter of 2002 due to a combination of higher average
borrowings of $264 million for the third quarter of 2002 compared to $163
million during the third quarter of 2001 offset in part by lower average
interest rates of 5.48% during the third quarter of 2002 compared to 7.27%
during the third quarter of 2001. Capitalized interest decreased 33% from $3.0
million for the third quarter of 2001 to $2.0 million for the third quarter of
2002 and corresponds to the decrease in exploratory drilling during the third
quarter of 2002. Our capitalized interest is a function of exploratory drilling
and unevaluated properties, both of which were at lower levels during the third
quarter of 2002.
Income Tax Provision. The provision for income taxes decreased 32% from
$11.7 million for the third quarter of 2001 to $7.9 million for the
corresponding three months of 2002 due to the 32% decrease in pre-tax income
during the third quarter of 2002 from $34.2 million during the third quarter of
2001 to $23.2 million during
22
the third quarter of 2002 as a result of high natural gas revenues offset by
increases in both operating and interest expenses.
Operating Income and Net Income. Operating income decreased 26% from
$34.4 million during the third quarter of 2001 to $25.5 million during the third
quarter of 2002 as a result of a 4% increase in total revenues caused primarily
by a 16% increase in production offset only in part by an 11% decrease in
natural gas prices combined with a 28% increase in operating expenses.
Corresponding to the decrease in operating income, net income decreased 32% from
$22.5 million for the third quarter of 2001 to $15.3 million for the third
quarter of 2002 and includes the effects of higher interest expense and lower
taxes.
COMPARISON OF NINE MONTHS ENDED SEPTEMBER 30, 2002 AND 2001
Production. Our production increased 14% from 66,690 million cubic feet
equivalent, or MMcfe, for the nine months ended September 30, 2001 to 76,190
MMcfe for the nine months ended September 30, 2002. The increase in production
was primarily attributable to newly acquired onshore production pursuant to our
two South Texas producing property acquisitions made since December 31, 2001
together with newly developed onshore and offshore production brought on-line
since the end of the third quarter of 2001.
Onshore, our daily production rates increased 25% from an average of
119 MMcfe/day during the first nine months of 2001 to an average of 149
MMcfe/day during the corresponding nine months of 2002. Properties acquired from
Conoco Inc. on December 31, 2001 accounted for an increase of 28 MMcfe/day for
2002 and properties acquired on May 30, 2002 from Burlington Resources accounted
for an increase of 6 MMcfe/day for the nine month period. Production from our
Charco Field in South Texas decreased slightly by 2% or 2 MMcfe/day from 84
MMcfe/day during the first nine months of 2001 to 82 MMcfe/day during the first
nine months of 2002. Production from all other onshore areas (Arkoma, East
Texas, West Virginia and South Louisiana) decreased from an average of 35
MMcfe/day during the first nine months of 2001 to 30 MMcfe/day during the
corresponding period of 2002 primarily a result of a decrease in production in
Arkoma and South Louisiana. The decrease in Arkoma production is due to a late
start of our developmental drilling program for 2002 combined with delays in
obtaining allowable production rates for newly completed wells from the Arkansas
Oil and Gas Commission. We expect Arkoma production to increase during the
fourth quarter of 2002 as our backlog of wells drilled and completed during 2002
receives production approval from the State of Arkansas. In addition, we expect
that the favorable downsizing ruling that we received in September 2002 will
alleviate some of the waiting period we are currently experiencing for bringing
new wells on-line. The decrease in production from our South Louisiana
properties during the first nine months of 2002 is due in part to mechanical
problems with compressors combined with natural reservoir decline.
Offshore, our production increased 4% from an average of 125 MMcfe/day
during the first nine months of 2001 to an average of 130 MMcfe/day during the
first nine months of 2002. The increase in production is due to new natural gas
production at South Marsh Island 253, High Island 39 and Mustang Island 785, all
of which came on-line during the second half of 2001, combined with new
production at Vermilion 408, which came on-line during January 2002, and new
production at East Cameron 81 with a series of four new wells coming on-line
throughout the first nine months of 2002. New production was offset in part by
production decreases in existing properties.
Natural Gas and Oil Revenues. Natural gas and oil revenues decreased
21% from $301.1 million for the first nine months of 2001 to $237.5 million for
the first nine months of 2002 as a result of a 32% decrease in average realized
natural gas prices, from $4.53 per Mcf during the first nine months of 2001 to
$3.08 per Mcf in the first nine months of 2002, offset in part by a 14% increase
in production for the same period.
Natural Gas Prices. As a result of hedging activities, we realized an
average gas price of $3.08 per Mcf for the nine months ended September 30, 2002,
which was 110% of the average unhedged natural gas price of $2.80 that otherwise
would have been received, resulting in natural gas and oil revenues for the nine
months ended September 30, 2002 that were $20.5 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 $4.53
per Mcf, which was 96% of the average unhedged natural gas price of $4.71 that
otherwise would have been
23
received, resulting in natural gas and oil revenues that were $11.8 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 23% from $19.4 million for the nine months ended September 30, 2001 to
$24.0 million for the corresponding nine months of 2002. On an Mcfe basis, lease
operating expenses increased from $0.29 per Mcfe during the first nine months of
2001 to $0.31 per Mcfe during the first nine months 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
onshore and offshore as we acquired approximately 304 producing wells in South
Texas since the beginning of 2002 and we added new offshore oil and natural gas
production facilities since the third quarter of 2001. In addition, we
implemented compression programs at several of our offshore production
facilities during 2002 to enhance production capabilities. Finally, onshore ad
valorem taxes have increased more than 50% during 2002 due to the fact that 2002
property valuations are based on revenues generated from the properties during
2001 and revenues generated during 2001 were at record levels due to higher than
normal natural gas prices.
Severance tax, which is a function of volume and revenues generated
from onshore production, decreased 23% from $9.5 million for the first nine
months of 2001 to $7.3 million for the corresponding period of 2002. On an Mcfe
basis, severance tax decreased from $0.14 per Mcfe for the first nine months of
2001 to $0.10 per Mcfe during the first nine months of 2002. The decrease in
severance tax expense and severance tax per Mcfe is primarily due to wellhead
prices that were 41% lower during the first nine months of 2002 as compared to
wellhead prices received during the first nine months of 2001 offset only in
part by the 25% increase in onshore production during the first nine months of
2002.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 34% from $92.4 million for the nine months ended
September 30, 2001 to $124.2 million for the nine months ended September 30,
2002. Depreciation, depletion and amortization expense per Mcfe increased 18%
from $1.38 for the nine months ended September 30, 2001 to $1.63 for the
corresponding nine month period of 2002. The increase in depreciation, depletion
and amortization expense was a result of higher production volumes combined with
a higher depletion rate. Our depletion rate has increased during 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 pool with the
addition of fewer new reserves from exploration and developmental drilling
together with an overall increase in our finding and development costs. We
believe that higher finding costs are 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. Because the
Outer Continental Shelf is a mature producing area, it is becoming increasingly
more difficult to find and develop new reserves at historical costs.
General and Administrative Expenses, Net of Capitalized General and
Administrative Expenses and Overhead Reimbursements. General and administrative
expenses, net of overhead reimbursements received from other working interest
owners of $0.9 million and $1.2 million for the nine months ended September 30,
2001 and 2002, respectively, and capitalized general and administrative expenses
directly related to oil and gas exploration and development activities of $10.0
million and $9.8 million, respectively, for the nine months ended September 30,
2001 and 2002, decreased 41% from $14.4 million for the nine months ended
September 30, 2001 to $8.5 million for the nine months ended September 30, 2002.
Aggregate general and administrative expenses decreased 23% from $25.3 million
for the first nine months of 2001 to $19.5 million for corresponding period of
2002. Included in aggregate and net administrative expenses for the first nine
months of 2001 were payments totaling $5.2 million made in connection with the
termination of former executive officers' employment contracts.
Excluding the one-time charges taken for the termination of employment
contracts totaling $5.2 million during the first nine months of 2001, aggregate
general and administrative expenses would have been $20.1 million compared to
$19.5 million for the first nine months of 2002, reflecting a 3% decrease for
the current nine month period. The decrease for 2002 is due to higher
compensation expenses incurred during 2001 with the payment of a special bonus
to all employees in January 2001 offset in part by an increase in expenses
incurred during the current nine month period pursuant to the expansion of our
workforce and office space combined with an increase in legal,
24
consulting and accounting fees. Excluding these same one-time charges of $5.2
million incurred during the first nine months of 2001, net general and
administrative expenses would reflect a decrease of 8% from $9.2 million during
the first nine months of 2001 to $8.5 million for the corresponding period of
2002. The decrease in net general and administrative expenses during 2002 is due
to the 3% decrease in aggregate general and administrative expense combined with
an increase in overhead reimbursements received from third parties during the
first nine months. The increase in overhead reimbursements is due to an increase
in the number of producing properties that we operate. The decrease in
capitalized general and administrative expenses during the first nine months of
2002 is a result of the change in the mix of types of expenses being incurred.
We incurred more expense such as consulting and legal fees that are not directly
related to our natural gas and oil finding and development activities.
On an Mcfe basis, net general and administrative expenses decreased 50%
from $0.22 during the first nine months of 2001 to $0.11 per Mcfe during the
first nine months of 2002. Excluding the one-time charges taken in the first
nine months of 2001 for the termination of employment contracts totaling $5.2
million, net general and administrative expenses on a per Mcfe basis would have
decreased approximately 21% or $0.03 per Mcfe from $0.14 per Mcfe for the first
nine months of 2001 to $0.11 per Mcfe for the corresponding nine months of 2002.
The decline in the adjusted rate per Mcfe corresponds to the 14% increase in
production volume during the first nine months of 2002.
Other Income and Expense. During the first nine months of 2002 we had
no other income or expense items. However, during the first nine months of 2001,
we incurred an additional $119,000 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.
KeySpan currently holds approximately 67% of our outstanding common
stock. As KeySpan has announced in the past, they do not consider the businesses
contained in their energy investments segment, including their investment in
Houston Exploration, a part of their core asset group. KeySpan has stated in the
past that they may sell or otherwise dispose of all or a portion of their
non-core assets, but cannot predict when, or if, any such sale or disposition
may take place.
Interest Expense, Net of Capitalized Interest. Interest expense, net of
capitalized interest, increased 96% from $2.7 million for the first nine months
of 2001 to $5.3 million for the first nine months of 2002. Aggregate interest
expense decreased 3% from $11.9 during the first nine months of 2001 to $11.5
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 7.69% during the first nine months of 2001 to an average borrowing rate of
5.37% during the first nine months of 2002 offset in part by an increase in our
average borrowings from $194 million during the first nine months of 2001 to an
average of $259 million for the corresponding period of 2002. Capitalized
interest decreased 33% from $9.2 million for the first nine months of 2001 to
$6.2 million for the first nine months of 2002 and corresponds to the decrease
in aggregate interest expense combined with a decrease in exploratory drilling
during the first nine months of 2002. Our capitalized interest is a function of
exploratory drilling and unevaluated properties, both of which were at lower
levels during the first nine months of 2002.
Income Tax Provision. The provision for income taxes decreased 59% from
$57.9 million for the first nine months of 2001 to $23.6 million for the first
nine months of 2002 due to the 58% decrease in pre-tax income during the first
nine months of 2002 from $163.7 million during the first nine months of 2001 to
$69.0 million during the first nine months of 2002 as a result of the
combination of a decrease in natural gas revenues and increases in both
operating expenses and net interest expense.
Operating Income and Net Income. Operating income decreased 55% from
$166.5 million during the first nine months of 2001 to $74.4 million for
corresponding nine months of 2002 as a result of a decrease in revenues caused
by a 32% decrease in realized natural gas prices offset only in part by the 14%
increase in production combined with a 21% increase in operating expenses.
Corresponding to the decrease in operating income, net
25
income decreased 57% from $105.7 million for the first nine months of 2001 to
$45.5 million for the first nine months of 2002 and includes the effects of
higher interest expense and lower taxes.
LIQUIDITY AND CAPITAL RESOURCES
We currently fund our operations, acquisitions, capital expenditures
and working capital requirements from cash flows from operations, 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 the remainder of 2002 and
2003.
Cash Flows From Operations. As of September 30, 2002, we had a working
capital deficit of $3.3 million and $152.6 million of borrowing capacity
available under our revolving bank credit facility. The working capital deficit
is due to the classification as a current liability of $14.6 million relating to
the current portion of the fair market value of our hedge positions. Net cash
provided by operating activities for the nine months ended September 30, 2002
was $165.0 million compared to $314.2 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 caused primarily by lower realized natural gas prices
during the nine months of 2002, offset in part by an increase in production for
the corresponding period combined and (ii) a decrease in current assets and
current liabilities which is related to the timing of cash receipts and
payments. For the first nine months of 2002, funds used in investing activities
consisted of $173.5 million for net investments in property and equipment, which
compares to $244.9 million spent during the corresponding period of 2001. Our
cash position increased during the first nine months of 2002 as a result of net
borrowings under our revolving bank credit facility of $3 million compared to
repayments totaling $85 million during the nine months of 2001. Cash increased
by $2.4 million and $8.9 million, respectively, during the first nine 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 $3.2 million from $8.6 million at December 31, 2001 to
$5.4 million at September 30, 2002.
Investments in Property and Equipment. During the first nine months of
2002, we invested $177.3 million in natural gas and oil properties and $1.7
million for other property and equipment, which includes the expansion of our
Houston office space together with upgrades to our information technology
systems and equipment. Included in our natural gas and oil property additions
was $14.3 million for exploration, $90.3 million for development drilling,
workovers and construction of platforms and pipelines, $44.5 million for
producing property acquisitions and $28.2 million for other leasehold and
leasehold acquisition costs which includes seismic, capitalized interest and
capitalized general and administrative costs. During the first nine months of
2002 we sold non-core oil and gas assets totaling $5.3 million, of which $5.0
million related to the sale of the McFarlan and Maude Traylor Fields purchased
in May 2002 as part of the group of properties acquired from Burlington
Resources.
Our capital expenditure budget for 2002, set by our Board of Directors,
is $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 have allocated a
portion of our 2002 capital expenditure budget to include the May 30, 2002
acquisition of producing properties in South Texas from Burlington Resources of
$44.5 million and the October 11, 2002 acquisition of interests in offshore
properties from KeySpan for $26.5 million. We are planning to repay the
borrowings made under our credit facility for these two acquisitions 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 currently 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 we may not be able to
identify and make acquisitions of proved reserves on terms we consider
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
26
combination thereof. Depending on market conditions and our capital needs, we
may utilize the shelf registration in order to raise capital. We would expect
to 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 entered into a new revolving bank
credit facility dated as of July 15, 2002 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 new credit facility replaced our previous
$250 million revolving credit facility maintained with a syndicate of lenders
led by JPMorgan Chase, National Association and provides us with an initial
commitment of $300 million. The initial $300 million commitment can 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 new credit facility is subject to borrowing base
limitations, and our borrowing base has been set at $300 million and will be
redetermined semi-annually, with the next redetermination scheduled for April 1,
2003. Up to $25 million of the borrowing base is available for the issuance of
letters of credit. The new credit facility matures July 15, 2005, is unsecured
and with the exception of trade payables, ranks senior to all of our existing
debt.
At September 30, 2002, outstanding borrowings under our revolving
credit facility were $147 million together with $0.4 million in outstanding
letter of credit obligations. Subsequent to September 30, 2002, we borrowed an
additional $17 million under the new facility. The subsequent borrowings were
used to fund a portion of the $26.5 million purchase price of incremental
working interests in offshore producing properties acquired on October 11, 2002
from KeySpan. At November 13, 2002, outstanding borrowings and letter of credit
obligations under the new credit facility totaled $164.4 million.
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.
27
ITEM 3. 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 and historically, we have not experienced
credit losses. 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; however, as a result of
our hedging activities we may be exposed to greater credit risk in the future.
Our hedges are cash flow hedges and qualify for hedge accounting under
SFAS 133 and, accordingly, we carry the fair market value of our derivative
instruments on the balance sheet as either an asset or liability and defer
unrealized gains or losses 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 for the nine month periods from January 1 to September
30, 2002 and 2001, respectively, and does not reflect the effects of taxes.
CHANGE IN FAIR VALUE OF DERIVATIVES INSTRUMENTS 2002 2001
----------------------------------------------- ---- ----
(in thousands)
Fair value of contracts at January 1.............................. $ 53,771 $(75,069)
(Gain) loss on contracts realized................................. (20,515) 11,771
Fair value of new contracts when entered into during period....... -- 5,931
(Decrease) increase in fair value of all open contracts........... (52,434) 136,015
-------- --------
Fair value of contracts outstanding at September 30,.............. $(19,178) $ 78,648
======== ========
28
Natural Gas. The following table summarizes, on a monthly basis, our
hedges currently in place for 2002 and 2003. All amounts are in thousands,
except for prices. For the remaining months of 2002, we have hedged
approximately 63% 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 first
three months of 2003, we have 185,000 MMBtu/day hedged at an effective floor of
$3.428 and an effective ceiling of $4.574. For the remaining nine months of
2003, we have 190,000 MMBtu/day hedged at an effective floor of $3.417 and
effective ceiling of $4.548.
FIXED PRICE SWAPS COLLARS
------------------- ------------------------------------
NYMEX NYMEX
VOLUME CONTRACT VOLUME CONTRACT PRICE
PERIOD (MMbtu) PRICE (MMbtu) AVG FLOOR AVG CEILING
------ -------- -------- ------- --------- -----------
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 4,495 3.493 4.954
February 2003 1,120 3.194 4,060 3.493 4.954
March 2003 1,240 3.194 4,495 3.493 4.954
April 2003 1,200 3.194 4,500 3.476 4.909
May 2003 1,240 3.194 4,650 3.476 4.909
June 2003 1,200 3.194 4,500 3.476 4.909
July 2003 1,240 3.194 4,650 3.476 4.909
August 2003 1,240 3.194 4,650 3.476 4.909
September 2003 1,200 3.194 4,500 3.476 4.909
October 2003 1,240 3.194 4,650 3.476 4.909
November 2003 1,200 3.194 4,500 3.476 4.909
December 2003 1,240 $3.194 4,650 $3.476 $4.909
Oil. Subsequent to September 30, 2002, we entered into an oil swap as
described in the following table. All amounts are in thousands, except for
prices. The swap covers the first three months of 2003 for 1,000 barrels per day
with a contract price of $28.50.
FIXED PRICE SWAPS COLLARS
------------------- --------------------------------------
NYMEX NYMEX
VOLUME CONTRACT VOLUME CONTRACT PRICE
PERIOD (MBbl) PRICE (MBbl) AVG FLOOR AVG CEILING
------ ------ -------- ------ ---------- -----------
January 2003 31 $28.50 -- -- --
February 2003 28 28.50 -- -- --
March 2003 31 28.50 -- -- --
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
29
payment to the counterparty if the settlement price for any settlement period is
greater than the swap price for the transaction. For any particular collar
transaction, the counterparty is required to make a payment to us if the
settlement price for any settlement period is below the floor price for the
transaction, and we are required to make payment to the counterparty if the
settlement price for any settlement period is above the ceiling price for the
transaction. We are not required to make or receive any payment in connection
with a collar transaction if the settlement price is between the floor and the
ceiling. For option contracts, we have the option, but not the obligation, to
buy contracts at the strike price up to the day before the last trading day for
that NYMEX contract.
ITEM 4. 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. Within the 90 days prior to the date of
this report, we carried out an evaluation, under the supervision and with the
participation of 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). Based on that evaluation, our
principal executive officer and principal financial officer concluded that our
disclosure controls and procedures are effective. There have been no significant
changes in our internal controls or in other factors that could significantly
affect these controls subsequent to the date of their evaluation, including any
corrective actions with regard to significant deficiencies or material
weaknesses.
30
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K:
(a) Exhibits:
EXHIBITS DESCRIPTION
--------
99.1 -- Certification of William G. Hargett, Chief Executive Officer,
as required pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
99.2 -- Certification of James F. Westmoreland, Chief Accounting
Officer, as required pursuant to Section 906 of the Sarbanes -
Oxley Act of 2002.
(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.
31
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: November 13, 2002 William G. Hargett
President and Chief Executive Officer
By: /s/ James F. Westmoreland
---------------------------------------------
Date: November 13, 2002 James F. Westmoreland
Vice President, Chief Accounting Officer
and Secretary
32
CERTIFICATIONS
I, William G. Hargett, certify that:
1. I have reviewed this quarterly report on Form 10-Q of The Houston
Exploration Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: November 13, 2002
/s/ William G. Hargett
-------------------------------
William G. Hargett,
President and Chief Executive Officer
33
I, James F. Westmoreland, certify that:
1. I have reviewed this quarterly report on Form 10-Q of The Houston
Exploration Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: November 13, 2002
/s/ James F. Westmoreland
-------------------------
James F. Westmoreland,
Chief Accounting Officer
34
EXHIBIT INDEX
EXHIBITS DESCRIPTION
--------
99.1 -- Certification of William G. Hargett, Chief Executive Officer,
as required pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
99.2 -- Certification of James F. Westmoreland, Chief Accounting
Officer, as required pursuant to Section 906 of the Sarbanes -
Oxley Act of 2002.