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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 JUNE 30, 2003
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 2000
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 [ ]
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Securities Exchange Act of 1934).
Yes [X] No [ ]
As of August 6, 2003, 31,078,668 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 -- June 30, 2003 (unaudited) and December 31, 2002....................... 4
CONSOLIDATED STATEMENTS OF OPERATIONS -- Three Months and Six Months Ended
June 30, 2003 and 2002 (unaudited)....................................................... 5
CONSOLIDATED STATEMENTS OF CASH FLOWS -- Six Months Ended
June 30, 2003 and 2002 (unaudited)....................................................... 6
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)........................................... 7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations....... 19
Item 3. Quantitative and Qualitative Disclosures About Market Risk.................................. 33
Item 4. Controls and Procedures..................................................................... 35
PART II. OTHER INFORMATION.......................................................................... 35
Item 4. Submission of Matters to a Vote of Security Holders......................................... 35
Item 6. Exhibits and Reports on Form 8-K:........................................................... 36
(a) Exhibits:............................................................................. 36
(b) Reports on Form 8-K:.................................................................. 36
SIGNATURES........................................................................................... 37
2
FACTORS AFFECTING FORWARD LOOKING STATEMENTS
All of the estimates and assumptions contained in 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 2. Management's Discussion
and Analysis of Financial Condition and Results of Operations" relating to our
anticipated capital expenditures, future cash flows and borrowings, pursuit of
potential future acquisition opportunities and sources of funding for
exploration and development are forward looking statements. Although we believe
that these forward-looking statements are based on reasonable assumptions, our
expectations may not occur and the anticipated future results may not 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 writedowns 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 10-K.
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
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
JUNE 30, DECEMBER 31,
2003 2002
----------- ------------
(UNAUDITED)
ASSETS:
Cash and cash equivalents ........................................................... $ 106,647 $ 18,031
Accounts receivable ................................................................. 111,134 81,313
Accounts receivable -- Affiliate .................................................... 7,448 3,106
Derivative financial instruments .................................................... 6,831 --
Inventories ......................................................................... 1,547 1,432
Prepayments and other ............................................................... 288 7,596
----------- -----------
Total current assets ........................................................... 233,895 111,478
Natural gas and oil properties, full cost method
Unevaluated properties ........................................................... 102,196 96,192
Properties subject to amortization ............................................... 2,005,380 1,828,160
Other property and equipment ........................................................ 11,420 10,699
----------- -----------
2,118,996 1,935,051
Less: Accumulated depreciation, depletion and amortization .......................... 995,718 912,637
----------- -----------
1,123,278 1,022,414
Derivative financial instruments .................................................... 4,878 --
Other non-current assets ............................................................ 7,659 4,924
----------- -----------
Other assets ................................................................... 12,537 4,924
TOTAL ASSETS ................................................................... $ 1,369,710 $ 1,138,816
=========== ===========
LIABILITIES:
Accounts payable and accrued expenses ............................................... $ 92,085 $ 78,175
Notes payable ....................................................................... 100,000 --
Derivative financial instruments .................................................... 54,361 35,005
Asset retirement obligation ......................................................... 4,510 --
----------- -----------
Total current liabilities ...................................................... 250,956 113,180
Long-term debt and notes ............................................................ 195,000 252,000
Derivative financial instruments .................................................... 9,928 3,767
Deferred federal income taxes ....................................................... 200,503 175,963
Asset retirement obligation ......................................................... 57,301 --
Other deferred liabilities .......................................................... 2,465 1,117
----------- -----------
TOTAL LIABILITIES .............................................................. 716,153 546,027
COMMITMENTS AND CONTINGENCIES (SEE NOTE 3)
STOCKHOLDERS' EQUITY:
Common Stock, $.01 par value, 50,000,000 shares authorized and 31,078,668 shares
issued and outstanding at June 30, 2003 and 30,954,018 shares
issued and outstanding at December 31, 2002, respectively ........................ 311 310
Additional paid-in capital .......................................................... 355,971 353,454
Unearned compensation ............................................................... (64) (107)
Retained earnings ................................................................... 334,954 264,334
Accumulated other comprehensive income .............................................. (37,615) (25,202)
----------- -----------
TOTAL STOCKHOLDERS' EQUITY ..................................................... 653,557 592,789
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ..................................... $ 1,369,710 $ 1,138,816
=========== ===========
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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
2003 2002 2003 2002
--------- --------- --------- ---------
(UNAUDITED) (UNAUDITED)
REVENUES: ............................................ (restated) (restated)
Natural gas and oil revenues ...................... $ 120,388 $ 85,588 $ 248,786 $ 160,210
Other ............................................. 244 367 849 561
--------- --------- --------- ---------
Total revenues .................................. 120,632 85,955 249,635 160,771
OPERATING EXPENSES:
Lease operating ................................... 11,669 7,886 23,315 15,299
Severance tax ..................................... 3,222 2,791 7,527 4,483
Transportation expense ............................ 2,696 2,227 5,188 4,403
Asset retirement accretion expense ................ 826 -- 1,652 --
Depreciation, depletion and amortization .......... 47,724 42,044 93,378 81,848
General and administrative, net ................... 4,204 2,488 8,088 5,828
--------- --------- --------- ---------
Total operating expenses ........................ 70,341 57,436 139,148 111,861
Income from operations ............................... 50,291 28,519 110,487 48,910
Other (income) expense ............................... 3,616 -- (6,962) --
Interest expense, net ................................ 2,160 1,644 4,426 3,054
--------- --------- --------- ---------
Income before income taxes ........................... 44,515 26,875 113,023 45,856
Provision for taxes .................................. 15,592 9,221 39,631 15,668
--------- --------- --------- ---------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE .............................. $ 28,923 $ 17,654 $ 73,392 $ 30,188
Cumulative effect of change in accounting principle .. -- -- (2,772) --
--------- --------- --------- ---------
NET INCOME ........................................... $ 28,923 $ 17,654 $ 70,620 $ 30,188
========= --------- ========= =========
EARNINGS PER SHARE:
NET INCOME PER SHARE - BASIC
Income before cumulative effect of change in
accounting principle ............................ $ 0.93 $ 0.58 $ 2.37 $ 0.99
Cumulative effect of change in accounting principle -- -- (0.09) --
--------- --------- --------- ---------
Net income per share -- basic ..................... $ 0.93 $ 0.58 $ 2.28 $ 0.99
========= ========= ========= =========
NET INCOME PER SHARE -- FULLY DILUTED
Income before cumulative effect of change in
accounting principle ............................ $ 0.93 $ 0.57 $ 2.36 $ 0.98
Cumulative effect of change in accounting principle -- -- (0.09) --
--------- --------- --------- ---------
Net income per share -- fully diluted ............. $ 0.93 $ 0.57 $ 2.27 $ 0.98
========= ========= ========= =========
Weighted average shares outstanding -- basic ......... 30,987 30,516 30,974 30,501
Weighted average shares outstanding -- fully diluted.. 31,095 30,854 31,082 30,846
The accompanying notes are an integral part of these consolidated financial
statements.
5
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
SIX MONTHS ENDED JUNE 30,
2003 2002
--------- ---------
(UNAUDITED)
OPERATING ACTIVITIES:
Net income ..................................................................... $ 70,620 $ 30,188
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and amortization ....................................... 93,378 81,848
Deferred income tax expense .................................................... 39,573 16,041
Asset retirement accretion expense ............................................. 1,652 --
Debt extinguishment expense .................................................... 1,626 --
Stock compensation expense ..................................................... 101 42
Cumulative effect of change in accounting principle ............................ 2,772 --
Changes in operating assets and liabilities:
Increase in accounts receivable ............................................. (34,163) (13,093)
Increase in inventories ..................................................... (115) (365)
Decrease in prepayments and other ........................................... 7,308 2,827
(Increase) decrease in other assets .......................................... (12,398) 4,125
Increase (decrease) in accounts payable and accrued expenses ................ 13,910 (14,098)
Increase (decrease) in other liabilities .................................... 1,348 458
--------- ---------
Net cash provided by operating activities ...................................... 185,612 107,973
INVESTING ACTIVITIES:
Investment in property and equipment ........................................... (138,348) (130,935)
Dispositions ................................................................... -- 261
--------- ---------
Net cash used in investing activities .......................................... (138,348) (130,674)
FINANCING ACTIVITIES:
Proceeds from long term borrowings ............................................. 228,000 46,000
Repayments of long term borrowings ............................................. (185,000) (10,000)
Debt issuance costs ............................................................ (4,108) --
Proceeds from issuance of common stock from exercise of stock options .......... 2,460 1,180
Proceeds from issuance of common stock ......................................... 79,200 --
Repurchase of common stock ..................................................... (79,200) --
--------- ---------
Net cash provided by financing activities ...................................... 41,352 37,180
--------- ---------
Increase in cash and cash equivalents .......................................... 88,616 14,479
Cash and cash equivalents, beginning of period ................................. 18,031 8,619
--------- ---------
Cash and cash equivalents, end of period ....................................... $ 106,647 $ 23,098
========= =========
SUPPLEMENTAL INFORMATION:
Cash paid for interest ......................................................... $ 6,439 $ 6,911
========= =========
Cash paid for taxes ............................................................ $ 10,900 $ --
========= =========
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 primarily focused in South Texas,
offshore in the shallow waters of the Gulf of Mexico and in the Arkoma Basin of
Oklahoma and Arkansas with additional production located in East Texas, South
Louisiana and West Virginia.
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 intercompany balances and
transactions have been eliminated.
Interim Financial Statements
Our balance sheet at June 30, 2003 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 accounting principles generally accepted
in the United States ("GAAP") have been condensed or omitted, although we
believe that the disclosures contained herein are adequate to make the
information presented not misleading. The balance sheet at December 31, 2002 is
derived from the December 31, 2002 audited financial statements, but does not
include all disclosures required by GAAP. The financial statements included
herein 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, 2002.
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.
Use of Estimates and Restatements
The preparation of the consolidated financial statements in conformity
with GAAP requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the dates of the financial statements and the reported
amounts of revenues and expenses during the reporting periods. Our most
significant financial estimates are based on remaining proved natural gas and
oil reserves. Estimates of proved reserves are key components of our depletion
rate for natural gas and oil properties and our full cost ceiling test
limitation.
For all periods presented, we applied Emerging Issues Task Force
("EITF") No. 00-10 "Accounting for Shipping and Handling Fees and Costs."
Pursuant to our application of EITF No. 00-10, transportation expenses
previously reflected as a reduction to natural gas and oil revenues for the
three months and six months ended June 30, 2002 were added back to revenues and
reflected as a separate component of operating expense and accordingly, the
Statement of Operations has been restated for the three month and six month
periods ended June 30, 2002. The application of EITF No. 00-10 has no effect on
income from operations or net income. The table below provides a summary of the
effects of application of EITF No. 00-10 for amounts reported in for the three
month and six month periods ended June 30, 2002.
7
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
----------------------- -----------------------
PREVIOUSLY PREVIOUSLY
RESTATED REPORTED RESTATED REPORTED
-------- ---------- -------- ----------
Natural gas and oil revenues ................ $ 85,588 $ 83,361 $160,210 $155,807
Total revenues .............................. 85,955 83,728 160,771 156,368
Transportation expenses ..................... 2,227 -- 4,403 --
Total operating expenses .................... 57,436 55,209 111,861 107,458
Income from operations ...................... 28,519 28,519 48,910 48,910
Net income .................................. 17,654 17,654 30,188 30,188
Natural gas price:
Average realized price (per Mcf) ............ $ 3.28 $ 3.19 $ 3.14 $ 3.05
Average unhedged price (per Mcf) ............ 3.28 3.19 2.79 2.70
Derivative Instruments
Our hedges are designated cash flow hedges and qualify for hedge
accounting under Statements of Financial Accounting Standards ("SFAS") No. 133,
as amended, "Accounting for Derivative Instruments and Hedging Activities" and
accordingly, we carry the fair market value of our derivative instruments on the
balance sheet as either an asset or liability and defer unrealized gains or
losses in accumulated other comprehensive income. Gains and losses are
reclassified from accumulated other comprehensive income to the income statement
as a component of natural gas and oil revenues in the period the hedged
production occurs. If any ineffectiveness occurs, amounts are recorded directly
to other income or expense.
8
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Net Income per Share
Basic earnings per share ("EPS") is calculated by dividing net income
by the weighted average number of shares of common stock outstanding during the
period. No dilution for any potentially dilutive securities is included. Diluted
EPS assumes 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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
2003 2002 2003 2002
------- ------- ---------- -------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
NUMERATOR:
Income before cumulative effect of change
in accounting principle ............................... $28,923 $17,654 $ 73,392 $30,188
Cumulative effect of change in accounting principle ........ -- -- (2,772) --
------- ------- ---------- -------
Net income ................................................. $28,923 $17,654 $ 70,620 $30,188
======= ======= ========== =======
DENOMINATOR:
Weighted average shares outstanding ........................ 30,987 30,516 30,974 30,501
Add dilutive securities: Stock options ..................... 108 338 108 345
------- ------- ---------- -------
Total weighted average shares outstanding and
dilutive securities ................................... 31,095 30,854 31,082 30,846
======= ======= ========== =======
EARNINGS PER SHARE - BASIC:
Income before cumulative effect of change in
accounting principle .................................. $ 0.93 $ 0.58 $ 2.37 $ 0.99
Cumulative effect of change in accounting principle ........ -- -- (0.09) --
------- ------- ---------- -------
Net income per share - basic ............................... $ 0.93 $ 0.58 $ 2.28 $ 0.99
======= ======= ========== =======
EARNINGS PER SHARE - FULLY DILUTED:
Income before cumulative effect of change in
accounting principle .................................. $ 0.93 $ 0.57 $ 2.36 $ 0.98
Cumulative effect of change in accounting principle ........ -- -- (0.09) --
------- ------- ---------- -------
Net income per share - fully diluted ....................... $ 0.93 $ 0.57 $ 2.27 $ 0.98
======= ======= ========== =======
For the three months ended June 30, 2003 and 2002, the calculation of
shares outstanding for fully diluted EPS does not include the effect of
outstanding stock options to purchase 1,893,611 and 1,328,719 shares,
respectively, because the exercise price of these shares was greater than the
average market price for the year, which would have an antidulitive effect on
EPS. For the six month periods ended June 30, 2003 and June 30, 2002, fully
diluted EPS does not include the effect of outstanding stock options to purchase
1,898,559 shares and 1,292,234 shares, respectively, because inclusion would
have been antidulitive.
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 June 30, 2003 and 2002, respectively.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
2003 2002 2003 2002
-------- -------- -------- --------
(IN THOUSANDS)
Net income ...................................................... $ 28,923 $ 17,654 $ 70,620 $ 30,188
Other comprehensive income, net of taxes:
Unrealized gain (loss) on derivative instruments ............ 2,597 (2,157) (8,975) (35,724)
-------- -------- -------- --------
Comprehensive income ............................................ $ 31,520 $ 15,497 $ 61,645 $ (5,536)
======== ======== ======== ========
Stock Option Expense
On January 1, 2003, we adopted the fair value expense recognition
provisions of SFAS No. 123 "Accounting for Stock-Based Compensation" and as
amended by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition
and Disclosure." Under the fair value method, compensation expense for stock
options is recognized when stock options are issued. SFAS No. 148 proposes three
alternative transition methods for a voluntary change to the fair value method
under SFAS No. 123:
- Prospective Method - recognize fair value expense for all
awards granted in the year of adoption but not previous
awards;
- Modified Prospective Method - recognize fair value expense for
the unvested portion of all stock options granted, modified,
or settled since 1994 (i.e., the unvested portion of the prior
awards or those granted in the year of adoption must be
recorded using the fair value method); and
- Retroactive Restatement Method - similar to the Modified
Prospective Method except that all prior periods are restated.
We adopted SFAS No. 123 using the Prospective Method, and as a result,
we now recognize as compensation expense the fair value of all stock options
issued subsequent to December 31, 2002. For the three and six month periods
ended June 30, 2003, we recognized compensation expense of $44,000 and $58,000
for stock options granted during the period.
Prior to our January 1, 2003 adoption of SFAS No. 123, we accounted for
the incentive stock plans using the intrinsic value method prescribed under
Accounting Principles Board Opinion No. 25 and accordingly we did not recognize
compensation expense for stock options granted. Had stock options been accounted
for using the fair value method as recommended in SFAS No. 123, compensation
expense would have had the following pro forma effect on our net income and
earnings per share for the three month and six month periods ended June 30, 2003
and 2002.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
2003 2002 2003 2002
---------- ---------- ---------- ----------
Net income - as reported ..................................... $ 28,923 $ 17,654 $ 70,620 $ 30,188
Add: Stock-based compensation expense
included in net income, net of tax ................. 43 14 66 27
Less: Stock-based compensation expense using
fair value method, net of tax ...................... (1,102) (1,181) (2,189) (2,370)
---------- ---------- ---------- ----------
Net income - pro forma ....................................... $ 27,864 $ 16,487 $ 68,497 $ 27,845
========== ========== ========== ==========
Net income per share - as reported ........................... $ 0.93 $ 0.58 $ 2.37 $ 0.99
Net income per share - fully diluted - as reported ........... 0.93 0.57 2.36 0.98
Net income per share - pro forma ............................. $ 0.90 $ 0.54 $ 2.21 $ 0.91
Net income per share - fully diluted - pro forma ............. 0.90 0.53 2.20 0.90
10
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Asset Retirement Obligations
On January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations," which addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. For us, asset retirement obligations
represent the systematic, monthly accretion and depreciation of future
abandonment costs of tangible assets such as platforms, wells, service assets,
pipelines, and other facilities. SFAS 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 if a reasonable estimate of fair value can be made, and
that the corresponding cost is capitalized as part of the carrying amount of the
related long-lived asset. The liability is accreted to its then present value
each period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. Under our previous accounting method, we
included estimated future costs of abandonment and dismantlement in our full
cost amortization base and amortized these costs as a component of our depletion
expense.
Pursuant to the January 1, 2003 adoption of SFAS No. 143 we:
- recognized a charge to income during the first quarter of 2003
of $2.8 million, net of tax, for the cumulative effect of the
change in accounting principle;
- increased our total liabilities by $57.2 million to record the
asset retirement obligations ("ARO");
- increased our assets by $42.5 million to add the asset
retirement costs to the carrying amount of our natural gas and
oil properties; and
- reduced our accumulated depreciation, depletion and
amortization by $10.4 million for the amount of expense
previously recognized.
Adopting SFAS No. 143 had no impact on our reported cash flows. The
following table describes on a pro forma basis our asset retirement liability as
if SFAS No. 143 had been adopted on January 1, 2002. The ARO liability at June
30, 2003 and December 31, 2002 includes amounts classified as both current and
long-term.
2003 2002
------- -------
ARO liability at January 1, ....... $57,197 $45,759
Additions from drilling ........... 2,962 4,397
ARO accretion expense ............. 1,652 1,322
------- -------
ARO liability at June 30, ......... $61,811 $51,478
======= =======
The following table describes the pro forma effect on net income and
earnings per share for the three months and the six months ended June 30, 2002
as if SFAS No. 143 had been adopted on January 1, 2002.
Three Months Six Months
Ended Ended
June 30, 2002 June 30, 2002
------------ -------------
Net income - as reported ......................... $ 17,654 $ 30,188
Less: ARO accretion expense, net of tax .......... (430) (860)
---------- ----------
Net income - pro forma ........................... $ 17,224 $ 29,328
========== ==========
Earnings per share:
Basic - as reported .............................. $ 0.58 $ 0.99
Fully diluted - as reported ...................... 0.57 0.98
Basic - pro forma ................................ 0.56 0.96
Fully diluted - pro forma ........................ 0.56 0.95
11
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Recent Accounting Pronouncements
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 No. 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. Our adoption of SFAS No. 145 on
January 1, 2003 had no effect on our financial statements.
In June 2002, FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" which addresses accounting and
reporting for costs associated with exit or disposal activities and nullifies
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. Our adoption of SFAS No. 146 on January 1, 2003 had no effect on our
financial statements.
In November 2002, FASB issued Financial Interpretation ("FIN") No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others." FIN 45 requires certain
guarantees to be recorded at fair value, which is different from the current
practice of recording a liability only when a loss is probable and reasonably
estimable, as those terms are defined in SFAS No. 5, "Accounting for
Contingencies." FIN 45 has a dual effective date. The initial recognition and
measurement provisions are applicable on a prospective basis to guarantees
issued or modified after December 31, 2002. The disclosure requirements in the
interpretation are effective for financial statements for interim or annual
periods ending after December 15, 2002. As of our December 31, 2002 and March
31, 2003 balance sheet dates, we did not have any guarantees of indebtedness of
others and as a result, our adoption of FIN 45 did not have an effect on our
financial statements.
On April 30, 2003, FASB issued SFAS 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities," which amends and clarifies
accounting for derivative instruments, including certain derivative instruments
embedded in other contracts, and hedging activities under SFAS No. 133. The new
guidance amends SFAS 133 for decisions made:
- As a part of the Derivatives Implementation Group process that
effectively required amendments to SFAS 133;
- In connection with other FASB projects dealing with financial
instruments; and
- Regarding implementation issues raised in relation to the
application of the definition of a derivative, particularly
regarding the meaning of an "underlying" and the
characteristics of a derivative that contains financing
components.
The amendments set forth in SFAS 149 are intended to improve financial
reporting by requiring that contracts with comparable characteristics be
accounted for similarly. In particular, SFAS 149 clarifies the circumstances
under which a contract with an initial net investment meets the characteristics
of a derivative as discussed in SFAS 133. In addition, SFAS 149 clarifies when a
derivative contains a financing component that warrants special reporting is the
statement of cash flows. SFAS 149 amends certain other existing pronouncements,
resulting in more consistent reporting of contracts that are derivatives in
their entirely or that contain embedded derivatives that warrant separate
accounting.
SFAS 149 is effective for contracts entered into or modified after June
30, 2003, except as stated below, and for hedging relationships designated after
June 30, 2003. The guidance should be applied prospectively.
The provisions of SFAS 149 that relate to SFAS 133 Implementation
Issues that have been effective for fiscal quarters that began prior to June 15,
2003 should continue to be applied in accordance with their respective effective
dates. In addition, certain provisions relating to forward purchases or sales of
"when issued" securities or other securities that do not yet exist should be
applied to existing contracts as well as new contracts entered into after June
30, 2003. Our adoption of SFAS 149 will not have an effect on our financial
statements.
12
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
On May 15, 2003, FASB issued SFAS 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity,"
which aims to eliminate diversity in practice by requiring that the following
three types of "freestanding" financial instruments be reported as liabilities
by their issuers:
- Mandatorily redeemable instruments (i.e., instruments issued
in the form of shares that unconditionally obligate the issuer
to redeem the shares for cash or by transferring other
assets);
- Forward purchase contract, written put options, and other
financial instruments not in the form of shares that either
obligate or may obligate the issuer to repurchase its equity
shares and settle its obligation for cash or by transferring
other assets; and,
- Certain financial instruments that include an obligation that
(1) the issuer may or must settle by issuing a variable number
of its equity shares and (2) has a "monetary value" at
inception that (a) is fixed, (b) is tied to a market index or
other benchmark (something other than the fair value of the
issuer's equity shares), or (c) varies inversely with the fair
value of the equity shares (e.g., a written put option).
Until this pronouncement was issued, these types of instruments have
been variously presented by their issuers as liabilities, as part of equity, or
between the liabilities and equity sections (sometimes referred to as
"mezzanine" reporting) in the statement of financial position.
For our company, the provisions of SFAS 150, which also include a
number of new disclosure requirements, are effective for (1) instruments
interest into or modified after May 31, 2003 and (2) pre-existing instruments as
of the beginning of the first interim period that commences after June 15, 2003.
Our adoption of SFAS 150 has had no effect on our financial statements.
NOTE 2 -- LONG-TERM DEBT AND NOTES
JUNE 30, 2003 DECEMBER 31, 2002
------------- -----------------
(in thousands)
SENIOR DEBT:
Revolving bank credit facility, due July 2005 ............ $ 20,000 $152,000
SUBORDINATED DEBT:
8 5/8% Senior Subordinated Notes, due January 2008 ....... 100,000 100,000
7% Senior Subordinated Notes, due June 2013 .............. 175,000 --
-------- --------
Total debt and notes ............................... $295,000 $252,000
Less: amounts classified as current
8 5/8% Senior Subordinated Notes, called for redemption
July 11, 2003 ................................. 100,000 --
-------- --------
Total long-term debt and notes ..................... $195,000 $252,000
======== ========
The carrying amount of borrowings outstanding under the revolving bank
credit facility approximates fair value as the interest rates are tied to
current market rates. The market value of our $175 million 7% senior
subordinated notes issued June 10, 2003 was estimated at 100% of the carrying
value or $175 million. At June 30, 2003, the quoted market value of our $100
million of 8 5/8% senior subordinated notes was 104.715% of the $100 million
carrying value or $104.7 million as a result of our announcement on June 10,
2003 to call for early redemption the 8 5/8% notes. The premium for early
redemption of 4.313% or $4.3 million was paid on July 11, 2003.
Revolving Bank Credit Facility
We maintain a revolving bank credit facility with a syndicate of
lenders led by Wachovia Bank, National Association, as issuing bank and
administrative agent, The Bank of Nova Scotia and Fleet National Bank as
co-syndication agents and BNP Paribas as documentation agent. The credit
facility provides us with a commitment of $300 million which may be increased at
our request and with prior approval from Wachovia to a maximum of $350 million
by adding one or more lenders or by allowing one or more lenders to increase
their commitments. The credit facility is subject to borrowing base
13
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
limitations. Our current borrowing base is $300 million and is redetermined
semi-annually, with the next redetermination scheduled for October 1, 2003. Up
to $25 million of the borrowing base is available for the issuance of letters of
credit. The credit facility matures July 15, 2005, is unsecured and with the
exception of trade payables, ranks senior to all of our existing debt. At June
30, 2003, $20 million in borrowings were outstanding under the credit facility
and $9.4 million was outstanding in letter of credit obligations. Subsequent to
June 30, 2003, we repaid all outstanding borrowings of $20 million under our
revolving bank credit facility and we reduced our letter of credit obligations
to $0.4 million. As of the date of this report, outstanding borrowings and
letter of credit obligations under our revolving bank credit facility total $0.4
million.
Interest is payable on borrowings under our revolving bank credit
facility, as follows:
- on base rate loans, at a fluctuating rate, or base rate, equal
to the sum of (a) the greater of the Federal funds rate plus
0.5% or Wachovia's prime rate plus (b) a variable margin
between 0% and 0.50%, depending on the amount of borrowings
outstanding under the credit facility, or
- on fixed rate loans, a fixed rate equal to the sum of (a) a
quoted LIBOR rate divided by one minus the average maximum
rate during the interest period set for certain reserves of
member banks of the Federal Reserve System in Dallas, Texas
plus (b) a variable margin between 1.25% and 2.00%, depending
on the amount of borrowings outstanding under the credit
facility.
Interest is payable on base rate loans on the last day of each calendar quarter.
Interest on fixed rate loans is generally payable at maturity or at least every
90 days if the term of the loan exceeds three months. In addition to interest,
we must pay a quarterly commitment fee of between 0.30% and 0.50% per annum on
the unused portion of the borrowing base.
Our revolving bank 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 June 30, 2003 and December 31, 2002, we were in compliance with all
covenants.
Senior Subordinated Notes
7% Senior Subordinated Notes due June 15, 2013. On June 10, 2003, we
issued $175 million of 7% senior subordinated notes due June 15, 2013. The notes
bear interest at a rate of 7% per annum with interest payable semi-annually on
June 15 and December 15, beginning December 15, 2003. We may redeem the notes at
our option, in whole or in part, at any time on or after June 15, 2008 at a
price equal to 100% of the principal amount plus accrued and unpaid interest, if
any, plus a specified premium which decreases yearly from 3.5% in 2008 to 0% in
2011 and thereafter. In addition, at any time prior to June 15, 2006, we may
redeem up to a maximum of 35% of the aggregate principal amount with the net
proceeds of one or more equity offerings at a price equal to 107% of the
principal amount, plus accrued and unpaid interest and liquidated damages, if
any. The notes are general unsecured obligations and rank subordinate in right
of payment to all existing and future senior debt, including the revolving bank
credit facility, and will rank senior or equal in right of payment to all
existing and future subordinated indebtedness.
The indenture governing the notes contains covenants that, among other
things, restrict or limit:
- incurrence of additional indebtedness and issuance of
preferred stock;
- repayment of certain other indebtedness;
- payment of dividends or certain other distributions;
- investments and repurchases of equity;
- use of the proceeds of assets sales;
- transactions with affiliates;
- liens;
14
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
- merger or consolidation and sales or other dispositions of all
or substantially all of our assets;
- entering into agreements that restrict the ability of our
subsidiary to make certain distributions or payments; or
- guarantees by our subsidiary of certain indebtedness.
In addition, upon the occurrence of a change of control, we will be
required to offer to purchase the notes at a purchase price equal to 101% of the
aggregate principal amount, plus accrued and unpaid interest and liquidated
damages, if any.
A "change of control" is:
- the direct or indirect acquisition by any person, other than
KeySpan or its affiliates, of beneficial ownership of 35% or
more of total voting power as long as KeySpan and its
affiliates own less than the acquiring person;
- the sale, lease, transfer, conveyance or other disposition,
other than by way of merger or consolidation, in one or a
series of related transactions, of all or substantially all of
our assets to a third party other than KeySpan or its
affiliates;
- the adoption of a plan relating to our liquidation or
dissolution; or
- if, during any period of two consecutive years, individuals
who at the beginning of the period constituted our board of
directors, including any new directors who were approved by a
majority vote of directors then in office who were either
directors at the beginning of the two-year period or who were
previously so approved, cease for any reason to constitute a
majority of the members then in office.
Pursuant to a registration rights agreement relating to the notes among
us and the initial purchasers, we have agreed to:
- file a registration statement with the SEC with respect to an
offer to exchange the notes for new notes issued in a
registered offering which will have terms identical in all
material respects to the notes, except that the registered
notes will not contain terms with respect to transfer
restrictions or payment of liquidated damages, within 90 days
following the original issue date of the notes;
- use or reasonable best efforts to cause the exchange offer
registration statement to become effective under the
Securities Act of 1934 within 180 days after June 10, 2003,
the original issue date of the notes, and ;
- use or reasonable best efforts to complete the exchange offer
with 30 business days after the SEC declares the exchange
offer registration statement effective.
We received $170.9 million in net proceeds from the issuance of the
$175 million 7% senior subordinated notes. A portion of the net proceeds was
used to repay the aggregate principal of $100 million on the 8 5/8% senior
subordinated notes together with a premium of $4.3 million for early redemption.
The remaining portion of the net proceeds was used to repay $60 million in
outstanding borrowings on our revolving bank credit facility with the balance of
approximately $6.6 million being applied to working capital, a portion of which
was utilized in July to fund the payment of $4.6 million in accrued interest due
on the $100 million 8 5/8% notes.
8 5/8% Senior Subordinated Notes due January 1, 2008. On July 11, 2003,
we redeemed our $100 million 8 5/8% senior subordinated notes due January 1,
2008. The $100 million 8 5/8% senior subordinated notes were issued on March 2,
1998. The notes bore interest at a rate of 8 5/8% per annum with interest
payable semi-annually on January 1 and July 1. The $100 million 8 5/8% notes
were redeemable, at our option, in whole or in part, at any time on or after
January 1, 2003 at a price equal to 100% of the principal amount plus accrued
and unpaid interest, if any, plus a specified premium which decreases yearly
from 4.313% in 2003 to 0% in 2006. The redemption and payment of the call
premium were funded with a portion of the proceeds received from our June 10,
2003 private placement of the $175 million 7% senior subordinated notes due June
15, 2013. Upon closing of the private placement of the $175 million 7% senior
subordinated notes on June 10, 2003, the $100 million 8 5/8% notes were called.
At June 30, 2003 and pursuant to the early redemption of the $100 million notes,
we incurred debt extinguishment expenses totaling $5.9 million ($3.9 million net
of tax) consisting of the call premium of $4.3 million together with a non-cash
charge of $1.6 million for the write-off of the balance of the unamortized issue
costs. The debt extinguishment expenses of $5.9 million are included in the line
item "Other (Income) Expense" on the Statement of Operations for the three and
the six months ended June 30, 2003.
15
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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 a portion
of our South Texas production. The "high-cost/tight-gas formation" designation
will allow us to receive an abatement of severance taxes for qualifying wells in
various fields. 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. We currently estimate that the total refund will
be between $18 million to $24.5 million ($12 million to $15.9 million, net of
tax), although we can provide no assurances that the actual total refund amount
will fall within our current estimate. Since the beginning of the fourth quarter
of 2002, we have recorded refunds totaling $23.3 million ($15.1 million net of
tax). Refunds recorded during 2003 total $12.9 million ($8.4 million net of tax)
of which $2.3 million ($1.5 million net of tax) were recorded during the second
quarter. Currently, we estimate that we could record additional refunds of up to
$1.2 million ($0.8 million net of tax). Our receivables at June 30, 2003 include
$28.2 million in gross refunds of which approximately $19.4 million relates to
our working interest with the balance owed to third party royalty interests.
Subsequent to June 30, 2003, we received a check from the State of Texas for
$19.7 million that will be applied to the receivable for severance tax refunds.
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. We are currently unable to predict the outcome of the claim.
We are involved from time to time in various other claims and lawsuits
incidental to our business. In the opinion of management, the ultimate
liability, if any, in these other matters will not have a material adverse
effect on our financial position or results of operations.
NOTE 4 -- RELATED PARTY TRANSACTIONS
Issuance of 3,000,000 Shares to the Public and Concurrent Repurchase of
3,000,000 Shares from KeySpan
In connection with our initial public offering in September 1996, we
entered into a registration rights agreement with KeySpan pursuant to which we
are obligated, at KeySpan's election, to facilitate KeySpan's sale of its shares
of Company stock by registering the shares under the Securities Act of 1933 and
assisting in KeySpan's selling efforts. During February of 2003, KeySpan
notified us of its desire to sell 3,000,000 shares of their Company stock. For
the mutual convenience of the parties, we elected to effect KeySpan's sale
through our pre-existing registration statement rather than filing a separate,
new registration statement for KeySpan. To accomplish the transaction, we
simultaneously sold 3,000,000 newly issued shares of Company stock in a public
offering for net proceeds of $26.40 per share, or an aggregate $79.2 million,
and bought a like number of KeySpan's shares of Company stock for the same price
per share. We cancelled the 3,000,000 shares acquired from KeySpan immediately
following the repurchase. KeySpan reimbursed us for all costs and expenses, and
the transaction had no impact on our capitalization. The transaction was
evidenced in a stock purchase agreement, dated February 26, 2003. Our Board of
Directors approved the transaction in principle and delegated to a special,
independent committee of the Board plenary authority to negotiate the terms of,
and finally approve or veto, the transaction. In finally approving the terms of
the stock purchase agreement, the independent committee determined that the
agreement was consistent with our pre-existing obligations under our
registration rights agreement and that issuing the shares under our existing
registration statement was in the best interests of our public stockholders to
facilitate the prompt and orderly disposition of the shares. As a result of the
transactions, KeySpan's interest in our outstanding shares decreased from 66% to
56%.
16
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Acquisition of KeySpan Joint Venture Assets
In October 2002, we purchased from KeySpan a portion of the assets
developed under the joint exploration agreement with KeySpan Exploration &
Production, LLC, a subsidiary of KeySpan (see below discussion of KeySpan Joint
Venture). The acquisition consisted of interests averaging between 11.25% and
45% in 17 wells covering eight of the twelve blocks that were developed under
the joint exploration agreement from 1999 through 2002. 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 continued 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. As of September 1, 2002, the effective date of the purchase, the
estimated proved reserves associated with the interests acquired were 13.5 Bcfe.
The $26.5 million purchase price was paid in cash and financed with borrowings
under our revolving credit facility. Subsequent purchase price adjustments
totaled $1.2 million. Our acquisition of the properties was accounted for as a
transaction between entities under common control. As a result, the excess fair
value of the properties acquired of $3.1 million ($2.0 million net of tax) was
treated as a capital contribution from KeySpan and recorded as an increase to
additional paid-in capital during the fourth quarter of 2002.
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.
KeySpan Joint Venture
Effective January 1, 1999, we entered into a joint exploration
agreement with KeySpan Exploration & Production, LLC, a subsidiary of KeySpan,
to explore for natural gas and oil over an initial two-year term expiring
December 31, 2000. Under the terms of the joint venture, we contributed all of
our then undeveloped offshore acreage to the joint venture and we agreed that
KeySpan would receive 45% of our working interest in all prospects drilled under
the program. KeySpan paid 100% of actual intangible drilling costs for the joint
venture up to a specified maximum. Further, KeySpan paid 51.75% of all
additional intangible drilling costs incurred and we paid 48.25%. Revenues are
shared 55% to Houston Exploration and 45% to KeySpan.
Effective December 31, 2000, KeySpan and Houston Exploration agreed to
end the primary or exploratory term of the joint venture. As a result, KeySpan
has not participated in any of our offshore exploration prospects unless the
project involved the development or further exploitation of discoveries made
during the initial term of the joint venture. During the first half 2003,
KeySpan spent approximately $6.8 million, of which $3.8 million was spent during
the second quarter, for capital costs associated with its working interests in
properties developed under the joint venture. Costs incurred during 2003 were
related to the installation of production facilities at South Timbalier 314/317
and the completion of the initial two exploratory wells that were brought
on-line during the first quarter of 2003. In addition, during the second quarter
of 2003, KeySpan participated in the drilling of a third well on the property.
During the corresponding six month and three month periods of 2002, KeySpan
spent $14.6 million and $5.1 million, respectively.
Sale of Section 29 Tax Credits
In June 2003, we repurchased, for $2.6 million, certain interests in
producing wells that were sold in January 1997 to a subsidiary of KeySpan under
an agreement designed to monetize tax credits available under Section 29 of the
Internal Revenue Code. Section 29 provides for a tax credit from
non-conventional fuel sources such as oil produced from shale and tar sands and
natural gas produced from geopressured brine, Devonian shale, coal seams and
tight sands formations. The wells subject to the agreement are located in West
Virginia, Oklahoma and East Texas and produce from formations that qualify for
Section 29 tax credits. Pursuant to the agreement, KeySpan acquired an economic
interest in wells that qualified for the tax credits and, in exchange, we:
17
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
- retained a volumetric production payment and a net profits
interest of 100% in the properties;
- received a cash down payment of $1.4 million; and
- receive a quarterly payment of $0.75 for every dollar of tax
credit utilized.
During the term of the agreement, we managed and administered the daily
operations of the properties in exchange for an annual management fee of
$100,000. The agreement expired December 31, 2002 and as a result, we were
required to repurchase the interests in the producing wells from KeySpan.
Subsequent to the repurchase, ownership of the tax credits reverted back to us.
The income statement effect, representing benefits received from Section 29 tax
credits, was a benefit of $0.2 million and $0.3 million, respectively for the
three month and six month periods ended June 30, 2002, with no benefit for 2003.
18
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 six months ended June 30, 2003 and 2002. 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 primarily focused in South Texas,
offshore in the shallow waters of the Gulf of Mexico and in the Arkoma Basin of
Oklahoma and Arkansas with additional production located in East Texas, South
Louisiana and West Virginia.
At December 31, 2002, our net proved reserves were 650 billion cubic
feet equivalent, or Bcfe, with a present value, discounted at 10% per annum, of
cash flows before income taxes of $1.3 billion. Our reserves are fully
engineered on an annual basis by independent petroleum engineers. Our focus is
natural gas. Approximately 94% of our net proved reserves at December 31, 2002
were natural gas, approximately 69% 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 principle 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 June 30, 2003, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 56% 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
Revenue Recognition and Gas Imbalances. We use the entitlements method
of accounting for the recognition of natural gas and oil revenues. Under this
method of accounting, income is recorded based on our net revenue interest in
production or nominated deliveries. We incur production gas volume imbalances in
the ordinary course of business. Net deliveries in excess of entitled amounts
are recorded as liabilities, while net under deliveries are reflected as assets.
Imbalances are reduced either by subsequent recoupment of over-and under
deliveries or by cash settlement, as required by applicable contracts.
Derivative Instruments. Our hedges are designated cash flow hedges and
qualify for hedge accounting under Statement of Financial Accounting Standards
("SFAS") No. 133, as amended, "Accounting for Derivative Instruments and Hedging
Activities" and, accordingly, we carry the fair market value of our derivative
instruments on the balance sheet as either an asset or liability and defer
unrealized gains or losses in accumulated other comprehensive income. Gains and
losses are reclassified from accumulated other comprehensive income to the
income statement as a component of natural gas and oil revenues in the period
the hedged production occurs. If any ineffectiveness occurs, amounts are
recorded directly to other income or expense.
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
19
depletion rate. The depletion rate is determined by dividing our total
unamortized cost base by net equivalent proved reserves at the beginning of the
quarter. Our total unamortized cost base is the sum of our:
- full cost pool; plus,
- estimates for future development costs; less,
- unevaluated properties and their related costs; less,
- estimates for salvage.
Costs associated with unevaluated properties are excluded from the amortization
base until we have made a determination as the existence of proved reserves. We
review our unevaluated properties at the end of each quarter to determine
whether the costs incurred should be reclassified to the full cost pool and
thereby subject to amortization. Sales of natural gas and oil properties are
accounted for as adjustments to the full cost pool, with no gain or loss
recognized, unless the adjustment would significantly alter the relationship
between capitalized costs and proved reserves.
Under full cost accounting rules, total capitalized costs are limited
to a ceiling equal to the present value of future net revenues, discounted at
10% per annum, plus the lower of cost or fair value of unproved properties less
income tax effects (the "ceiling limitation"). We perform a quarterly ceiling
test to evaluate whether the net book value of our full cost pool exceeds the
ceiling limitation. If capitalized costs (net of accumulated depreciation,
depletion and amortization) less 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 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 June 30, 2003
and December 31, 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 accounting principles generally accepted in the
United States of America ("GAAP") 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.
20
Accounting for Stock Option Expense
On January 1, 2003, we adopted the fair value expense recognition
provisions of SFAS No. 123 "Accounting for Stock-Based Compensation" and as
amended by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition
and Disclosure." Under the fair value method, compensation expense for stock
options is recognized when stock options are issued. SFAS No. 148 proposes three
alternative transition methods for a voluntary change to the fair value method
under SFAS No. 123. We adopted SFAS No. 123 using the Prospective Method as
defined by SFAS No. 148, and as a result, we now recognize as compensation
expense the fair value of all stock options issued subsequent to December 31,
2002 with no expense recognized for options issued in previous periods. For the
three months ended June 30, 2003, we recognized compensation expense of $44,000
for stock options granted during the period. For the corresponding six month
period of 2003, we recognized $58,000 in compensation expense for stock options.
Prior to our January 1, 2003 adoption of SFAS No. 123, we accounted for the
incentive stock plans using the intrinsic value method prescribed under
Accounting Principles Board Opinion No. 25, and accordingly, we did not
recognize compensation expense for stock options granted.
Accounting for Asset Retirement Obligations
On January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations," which addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. For us, asset retirement obligations
represent the systematic, monthly accretion and depreciation of future
abandonment costs of tangible assets such as platforms, wells, service assets,
pipelines, and other facilities. SFAS 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 if a reasonable estimate of fair value can be made, and
that the corresponding cost is capitalized as part of the carrying amount of the
related long-lived asset. The liability is accreted to its then present value
each period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. Under our previous accounting method, we
included estimated future costs of abandonment and dismantlement in our full
cost amortization base and amortized these costs as a component of our depletion
expense.
Pursuant to the January 1, 2003 adoption of SFAS No. 143 we:
- recognized a charge to income during the first quarter of 2003
of $2.8 million, net of tax, for the cumulative effect of the
change in accounting principle;
- increased our total liabilities by $57.2 million to record the
asset retirement obligations ("ARO");
- increased our assets by $42.5 million to add the asset
retirement costs to the carrying amount of our natural gas and
oil properties; and
- reduced our accumulated depreciation, depletion and
amortization by $10.4 million for the amount of expense
previously recognized.
Adopting SFAS No. 143 had no impact on our reported cash flows.
Recent Accounting Pronouncements
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 No. 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. Our adoption of SFAS No. 145 on
January 1, 2003 had no effect on our financial statements.
In June 2002, FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" which 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. Our adoption of SFAS No. 146 on January 1,
2003 had no effect on our financial statements.
21
In November 2002, FASB issued Financial Interpretation ("FIN") No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others." FIN 45 requires certain
guarantees to be recorded at fair value, which is different from the current
practice of recording a liability only when a loss is probable and reasonably
estimable, as those terms are defined in SFAS No. 5, "Accounting for
Contingencies." FIN 45 has a dual effective date. The initial recognition and
measurement provisions are applicable on a prospective basis to guarantees
issued or modified after December 31, 2002. The disclosure requirements in the
interpretation are effective for financial statements for interim or annual
periods ending after December 15, 2002. As of our December 31, 2002 and March
31, 2003 balance sheet dates, we did not have any guarantees of indebtedness of
others and as a result, our adoption of FIN 45 did not have an effect on our
financial statements.
On April 30, 2003, FASB issued SFAS 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities," which amends and clarifies
accounting for derivative instruments, including certain derivative instruments
embedded in other contracts, and hedging activities under SFAS No. 133. The new
guidance amends SFAS 133 for decisions made:
- As a part of the Derivatives Implementation Group process that
effectively required amendments to SFAS 133;
- In connection with other FASB projects dealing with financial
instruments; and
- Regarding implementation issues raised in relation to the
application of the definition of a derivative, particularly
regarding the meaning of an "underlying" and the
characteristics of a derivative that contains financing
components.
The amendments set forth in SFAS 149 are intended to improve financial
reporting by requiring that contracts with comparable characteristics be
accounted for similarly. In particular, SFAS 149 clarifies the circumstances
under which a contract with an initial net investment meets the characteristics
of a derivative as discussed in SFAS 133. In addition, SFAS 149 clarifies when a
derivative contains a financing component that warrants special reporting is the
statement of cash flows. SFAS 149 amends certain other existing pronouncements,
resulting in more consistent reporting of contracts that are derivatives in
their entirely or that contain embedded derivatives that warrant separate
accounting.
SFAS 149 is effective for contracts entered into or modified after June
30, 2003, except as stated below, and for hedging relationships designated after
June 30, 2003. The guidance should be applied prospectively.
The provisions of SFAS 149 that relate to SFAS 133 Implementation
Issues that have been effective for fiscal quarters that began prior to June 15,
2003 should continue to be applied in accordance with their respective effective
dates. In addition, certain provisions relating to forward purchases or sales of
"when issued" securities or other securities that do not yet exist should be
applied to existing contracts as well as new contracts entered into after June
30, 2003. Our adoption of SFAS 149 will not have an effect on our financial
statements.
On May 15, 2003, FASB issued SFAS 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity,"
which aims to eliminate diversity in practice by requiring that the following
three types of "freestanding" financial instruments be reported as liabilities
by their issuers:
- Mandatorily redeemable instruments (i.e., instruments issued
in the form of shares that unconditionally obligate the issuer
to redeem the shares for cash or by transferring other
assets);
- Forward purchase contract, written put options, and other
financial instruments not in the form of shares that either
obligate or may obligate the issuer to repurchase its equity
shares and settle its obligation for cash or by transferring
other assets; and,
- Certain financial instruments that include an obligation that
(1) the issuer may or must settle by issuing a variable number
of its equity shares and (2) has a "monetary value" at
inception that (a) is fixed, (b) is tied to a market index or
other benchmark (something other than the fair value of the
issuer's equity shares), or (c) varies inversely with the fair
value of the equity shares (e.g., a written put option).
Until this pronouncement was issued, these types of instruments have
been variously presented by their issuers as liabilities, as part of equity, or
between the liabilities and equity sections (sometimes referred to as
"mezzanine" reporting) in the statement of financial position.
For our company, the provisions of SFAS 150, which also include a
number of new disclosure requirements, are effective for (1) instruments
interest into or modified after May 31, 2003 and (2) pre-existing instruments as
of the beginning of the first interim period that commences after June 15, 2003.
Our adoption of SFAS 150 has had no effect on our financial statements.
22
RECENT DEVELOPMENTS
Increase in Capital Expenditure Budget for 2003
At the quarterly meeting of our Board of Directors held July 29, 2003,
our 2003 capital expenditure budget was increased by $26 million to $312
million. We plan to spend two-thirds of the increase in South Texas and the
balance in the Arkoma Basin.
Stephen W. McKessy Elected Director
Stephen W. McKessy was elected to our Board of Directors at the
quarterly meeting held July 29, 2003. Upon Mr. McKessy's election to the Board,
the size of our Board was increased from 10 to 11 members. Mr. McKessy is a
retired Vice Chairman of PricewaterhouseCoopers where he worked from 1960 to
1997. During his 37 years with the firm he held various management positions,
including serving as a member of the firm's management committee. He was also
the regional managing partner for the firm's businesses in the New York area. A
graduate of St. John's University in New York, McKessy currently serves on the
advisory board for the college of business administration. Mr. McKessy is a
board member of KeySpan Energy Corporation.
Rocky Mountain Exploration
During the first half 2003, we acquired approximately 85,000 net
undeveloped acres in located onshore in Rocky Mountain region of the
northwestern Untied States. The acreage is located in southwestern Montana, the
Green River Basin of southwestern Wyoming and in the Uinta Basin of northeast
Utah. In April 2003, we opened an office in Denver, Colorado that is currently
staffed by one geo-scientist to coordinate prospect flow. We are planning to
drill 3 to 5 wells during the fourth quarter of 2003. The wells planned will be
less than 5,000 feet in depth. As June 30, 2003, we incurred approximately $3.4
million in leasehold acquisition costs related to the acreage acquired.
Issuance of $175 Million 7% Notes due 2013 and Redemption of $100 Million 8 5/8%
Notes due 2008
On June 10, 2003, we issued $175 million of 7% senior subordinated
notes due June 15, 2013. The notes bear interest at a rate of 7% per annum with
interest payable semi-annually on June 15 and December 15, beginning December
15, 2003. The notes are general unsecured obligations and rank subordinate in
right of payment to all existing and future senior debt, including the revolving
bank credit facility, and will rank senior or equal in right of payment to all
existing and future subordinated indebtedness. We may redeem the notes at our
option, in whole or in part, at any time on or after June 15, 2008 at a price
equal to 100% of the principal amount plus accrued and unpaid interest, if any,
plus a specified premium which decreases yearly from 3.5% in 2008 to 0% in 2011
and thereafter. In addition, at any time prior to June 15, 2006, we may redeem
up to a maximum of 35% of the aggregate principal amount of the notes with the
net proceeds of one or more equity offerings at a price equal to 107% of the
principal amount, plus accrued and unpaid interest and liquidated damages, if
any.
We received $170.9 million in net proceeds from the issuance of the
notes. A portion of the net proceeds was used to repay the aggregate principal
of $100 million on the 8 5/8% senior subordinated notes together with a premium
of $4.3 million for early redemption. The remaining portion of the net proceeds
was used to repay $60 million in outstanding borrowings on our revolving bank
credit facility with the balance of approximately $6.6 million being applied to
working capital, a portion of which was utilized in July to fund the payment of
$4.6 million in accrued interest due on the notes. At June 30, 2003 and pursuant
to the early redemption of the $100 million notes, we incurred debt
extinguishment expenses totaling $5.9 million ($3.9 million net of tax) for the
call premium of $4.3 million together with a non-cash charge of $1.6 million for
the write-off of the balance of the unamortized issue costs. The debt
extinguishment expenses of $5.9 million are included in the line item "Other
(Income) Expense on the Statement of Operations for the three and the six months
ended June 30, 2003.
Pursuant to a registration rights agreement relating to the 7% senior
subordinated notes among us and the initial purchasers, we have agreed to file a
registration statement with the SEC for the offer to exchange the notes for new
notes registered under the Securities Act which will have terms identical in all
material respects to the existing notes.
23
Issuance of 3,000,000 Shares to the Public and Concurrent Repurchase of
3,000,000 Shares from KeySpan
In connection with our initial public offering in September 1996, we
entered into a registration rights agreement with KeySpan pursuant to which we
are obligated, at KeySpan's election, to facilitate KeySpan's sale of its shares
of Company stock by registering the shares under the Securities Act of 1933 and
assisting in KeySpan's selling efforts. During February of 2003, KeySpan
notified us of its desire to sell 3,000,000 shares of their Company stock. For
the mutual convenience of the parties, we elected to effect KeySpan's sale
through our pre-existing registration statement rather than filing a separate,
new registration statement for KeySpan. To accomplish the transaction, we
simultaneously sold 3,000,000 newly issued shares of Company stock in a public
offering for net proceeds of $26.40 per share, or an aggregate $79.2 million,
and bought a like number of KeySpan's shares of Company stock for the same price
per share. We cancelled the 3,000,000 shares acquired from KeySpan immediately
following the repurchase. KeySpan reimbursed us for all costs and expenses, and
the transaction had no impact on our capitalization. The transaction was
evidenced in a stock purchase agreement, dated February 26, 2003. Our Board of
Directors approved the transaction in principle and delegated to a special,
independent committee of the Board plenary authority to negotiate the terms of,
and finally approve or veto, the transaction. In finally approving the terms of
the stock purchase agreement, the independent committee determined that the
agreement was consistent with our pre-existing obligations under our
registration rights agreement and that issuing the shares under our existing
registration statement was in the best interests of our public stockholders to
facilitate the prompt and orderly disposition of the shares. As a result of the
transactions, KeySpan's interest in our outstanding shares decreased from 66% to
56%.
As KeySpan has announced in the past, it does not consider certain
businesses contained in its energy investments segment, including its investment
in Houston Exploration, a part of its core asset group. KeySpan has stated in
the past that it may sell or otherwise dispose of all or a portion of its
non-core assets, including all or a portion of its common stock ownership in our
company. As stated above, on February 20, 2003 KeySpan sold to us 3,000,000
shares of our common stock it owned, reducing its ownership percentage from
approximately 66% to 56%. KeySpan has stated that based on market conditions, it
cannot predict when, or if, any additional sales or dispositions of all or a
part of its remaining ownership interest in us may take place.
24
RESULTS OF OPERATIONS
The following table sets forth our historical natural gas and oil production
data during the periods indicated:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
2003 2002 2003 2002
---------- ---------- ---------- ----------
PRODUCTION:
Natural gas (MMcf) ............................... 24,634 24,450 49,019 48,345
Oil (MBbls) ...................................... 328 222 585 382
Total (MMcfe) .................................... 26,602 25,782 52,529 50,637
Average daily production (MMcfe/day) ............. 292 283 290 280
AVERAGE SALES PRICES:
Natural gas (per Mcf) realized(1) ................ $ 4.54 $ 3.28 $ 4.73 $ 3.14
Natural gas (per Mcf) unhedged ................... 5.16 3.28 5.76 2.79
Oil (per Bbl) realized(1) ........................ 26.18 24.04 28.55 22.05
Oil (per Bbl) unhedged ........................... 25.95 24.04 29.24 22.05
OPERATING EXPENSES (PER MCFE):
Lease operating .................................. $ 0.44 $ 0.31 $ 0.44 $ 0.30
Severance tax .................................... 0.12 0.11 0.14 0.09
Transportation expense ........................... 0.10 0.09 0.10 0.09
Depreciation, depletion and amortization ......... 1.79 1.63 1.78 1.62
Asset retirement accretion ....................... 0.03 -- 0.03 --
General and administrative, net .................. 0.16 0.10 0.15 0.12
- ----------
(1) Reflects the effects of hedging.
RECENT FINANCIAL AND OPERATING RESULTS
Comparison of Three Months Ended June 30, 2003 and 2002
Production. Our production increased 3% from 25,782 million cubic feet
equivalent, or MMcfe, for the three months ended June 30, 2002 to 26,602 MMcfe
for the three months ended June 30, 2003. Average daily production was 292
MMcfe/day during the second quarter of 2003 compared to 283 MMcfe/day during the
second quarter of 2002.
Onshore, our daily production rates increased 15% from an average of
149 MMcfe/day during the second quarter of 2002 to an average of 171 MMcfe/day
during the corresponding three months of 2003. The increase in onshore
production is primarily attributable to 23 MMcfe/day in newly developed
production in South Texas. Production from our other onshore areas remained
relatively unchanged at 32 MMcfe/day during the second quarter of 2003 compared
to 33 MMcfe/day during the second quarter of 2002. In total, average daily
production during the second quarter of 2003 decreased slightly to 171 MMcfe/day
as compared to production during the first quarter of 2003 of 173 MMcfe/day.
Offshore, our production decreased 10% from an average of 134 MMcfe/day
during the second quarter of 2002 to an average of 121 MMcfe/day during the
second quarter of 2003. Production declines due to maturing reservoirs from
existing key fields, Mustang Island A-31/32, West Cameron 587, South Marsh
Island 253 and North Padre Island 883, were greater than incremental production
added from new wells and facilities brought on-line since the end of the second
quarter of 2002 at Vermilion 408, East Cameron 81/84, East Cameron 82/83,
Mustang Island 785 and South Timbalier 314/317. The year-over-year production
decline is partially the result of shifting approximately $40 million of our
2002 offshore capital expenditure program to our onshore region to facilitate
the May 2002 acquisition of producing properties in South Texas from Burlington
Resources. However, during the second quarter of 2003 offshore production
increased by 5% to 121 MMcfe/day from 115 MMcfe/day during the first quarter of
2003. The increase was due in part to an increase in production at South
Timbalier 314/317, a successful recompletion at High Island 38 completed in the
first quarter of 2003
25
and the resolution of downstream pipeline problems during January and February
at Vermilion 408.
Natural Gas and Oil Revenues. Natural gas and oil revenues increased
41% from $85.6 million for the second quarter of 2002 to $120.4 million for the
second quarter of 2003 as a result of a 38% increase in average realized natural
gas prices, from $3.28 per Mcf during the second quarter of 2002 to $4.54 per
Mcf in the second quarter of 2003 and an increase in average realized oil prices
of 9% for the same period from $24.04 per barrel, or Bbl, to $26.18 per barrel,
combined with a 48% increase in production during the current quarter.
Natural Gas Prices. As a result of hedging activities during the second
quarter of 2003, we realized an average gas price of $4.54 per Mcf, which was
88% of the average unhedged natural gas price of $5.16 for the period. As a
result, natural gas and oil revenues for the three months ended June 30, 2003
were $15.4 million lower than the revenues we would have achieved if hedges had
not been in place during the period. For the corresponding quarter of 2002, our
hedging activities resulted in $12,000 of additional natural gas revenues, and,
as a result, our average realized natural gas price and unhedged natural gas
price were equal at $3.28 per Mcf.
Oil Prices. During the second quarter of 2003, we realized an average
oil price of $26.18 per Bbl, which was 101% of the average unhedged price of
$25.95 per Bbl for the period. As a result, natural gas and oil revenues for the
three months ended June 30, 2003 were $73,000 higher than the revenues we would
have achieved if hedges had not been in place during the period. We had no oil
hedges in place during second quarter of 2002 and realized an average oil price
of $24.04 per Bbl.
Lease Operating Expenses and Severance Tax. Lease operating expenses
increased 48% from $7.9 million for the three months ended June 30, 2002 to
$11.7 million for the corresponding three months of 2003. On an Mcfe basis,
lease operating expenses increased 42% from $0.31 per Mcfe during the second
quarter of 2002 to $0.44 per Mcfe during the second quarter of 2003. The
increase in both lease operating expenses and lease operating expense on a per
unit basis for 2003 is primarily attributable to the continued expansion of our
operations both onshore and offshore. Our overall operating expenses are
increasing as we add new wells and facilities and continue to maintain
production from existing properties. Since the end of the second quarter of
2002, we added approximately 100 new wells from exploration and development
drilling. Specifically, ad valorem taxes increased as onshore property values
are higher than prior year as a result of higher commodity prices. South
Timbalier 314/317 was placed on-line during the first quarter of 2003 and is
inherently more costly to operate, as it is a crude oil producing property. We
are incurring additional fees to process natural gas from new wells at East
Cameron 81/83/84. And finally, we have added compression in South Texas and at
several offshore platforms to enhance production capabilities from existing
wells.
Severance tax, which is a function of volume and revenues generated
from onshore production, increased from $2.8 million for the second quarter of
2002 to $3.2 million for the corresponding period of 2003. On an Mcfe basis,
severance tax increased 9% from $0.11 per Mcfe during the second quarter of 2002
to $0.12 per Mcfe during the second quarter of 2003. Despite our reduced
severance tax rate for a portion of our South Texas production pursuant to the
"high-cost/tight-gas formation" designation received in July 2002 (see "Other
(Income) and Expense" below), severance tax expense and severance tax per Mcfe
increased during the second quarter of 2003 due to the 57% increase in average
wellhead prices for natural gas from $3.28/Mcf during the second quarter of 2002
to $5.16/Mcf during the second quarter of 2003 combined with a 14% increase in
onshore production for the same period of 2003.
Transportation Expense. We applied EITF No. 00-10 "Accounting for
Shipping and Handling Fees and Costs" for all periods presented. Pursuant to our
application of EITF No. 00-10, transportation expenses for the three months
ended June 30, 2002 that were previously reflected as a reduction of natural gas
and oil revenues were added back to the related revenues and reclassified as a
separate component of operating expense. The application of EITF No. 00-10 had
no effect on operating income or net income. Transportation expense for the
second quarter of 2003 increased 11% on an Mcfe basis from $0.09 during the
second quarter of 2002 to $0.10 for the second quarter of 2003. The increase
reflects an increase in volume, primarily in South Texas, that is subject to
transportation fee agreements the current quarter.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 14% from $42.0 million for the three months ended
June 30, 2002 to $47.7 million for the three months ended June 30, 2003.
Depreciation, depletion and amortization expense per Mcfe increased 10% from
$1.63 for the three months ended June 30, 2002 to $1.79 for the corresponding
three months in 2003. 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 as the costs associated with
several unproved properties designated as unevaluated were reclassified into our
amortization base
26
without incremental reserve additions at the end of 2002. In addition, our
estimated future development costs at December 31, 2002, increased approximately
22% from prior year estimates due to the addition of more proved undeveloped
reserves into our total proved reserve base.
Asset Retirement Accretion. Pursuant to our January 1, 2003 adoption of
SFAS No. 143, "Asset Retirement Obligations," we incurred asset retirement
accretion expense of $0.8 million, $0.03 per Mcfe, during the second quarter of
2003. The accretion expense represents the systematic, monthly accretion and
depreciation of future abandonment costs of tangible assets such as platforms,
wells, service assets, pipelines, and other facilities.
General and Administrative Expenses, Net of Capitalized General and
Administrative and Overhead Reimbursements. Our net general and administrative
expenses increased 68% from $2.5 million for the three months ended June 30,
2002 to $4.2 million for the three months ended June 30, 2003. These amounts are
net of overhead reimbursements received from other working interest owners of
$0.3 million and $0.4 million for the three months ended June 30, 2002 and 2003,
respectively, and capitalized general and administrative expenses of $3.1
million and $2.9 million for the respective periods. Aggregate general and
administrative expenses increased by $1.6 million or 27% from $5.9 million
during the second quarter of 2002 to $7.5 million for the second quarter of
2003. The increase in aggregate general and administrative expense is due
primarily to the expansion of our workforce which corresponds to the continued
expansion of our operations. As our workforce expands, we have experienced an
increase in salaries and related employee benefit expenses together with an
increase in our incentive compensation expense. In addition, our rent expense
has increased as we expanded our leased office space in downtown Houston to
accommodate our growing workforce. Finally, our legal, audit and accounting
expenses increased as we implemented new corporate governance policies and
engaged an outside firm to perform internal auditing functions.
On an Mcfe basis, net general and administrative expenses increased 60%
from $0.10 during the second quarter of 2002 to $0.16 per Mcfe during the second
quarter of 2003. The higher rate per Mcfe during the second quarter of 2003
reflects the increase in our aggregate general and administrative expenses
offset in part by a 6% decrease in capitalized expenses during the second
quarter of 2003 which is a result of a change in the mix of types of general and
administrative expenses we are incurring. We are incurring more expenses that
are not directly related to our oil and gas exploration and development
operations.
Other Income and Expense. For the second quarter of 2003, Other Income
and Expense includes two components: (i) debt extinguishment expenses totaling
$5.9 million ($3.9 million net of tax); and (ii) income of $2.3 million ($1.5
million net of tax) related to refunds of prior year's severance tax expense.
Upon completion of the private placement of our $175 million 7% senior
subordinated notes due June 2013 on June 10, 2003, we called our $100 million
8 5/8% senior subordinated notes due 2008 for redemption. We incurred a premium
for early redemption of the $100 million 8 5/8% notes of $4.3 million together
with a non-cash charge of $1.6 million to write-off the balance of the
unamortized costs associated with issuing the $100 million notes.
In July 2002, we applied for and received from the Railroad Commission
of Texas a "high-cost/tight-gas formation" designation for a portion of our
South Texas production. The "high-cost/tight-gas formation" designation allows
us to receive an abatement of severance taxes for qualifying wells in various
fields. 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. As of the date of our report, we are estimating
that we could receive refunds of up to an additional $1.2 million ($0.8 million
net of tax), although there can be no assurances that actual amounts collected
will equal our estimates.
Interest Expense, Net of Capitalized Interest. Interest expense, net of
capitalized interest, increased 38% from $1.6 million during the second quarter
of 2002 to $2.2 million during the second quarter of 2003. Aggregate interest
expense increased from $3.6 million during the second quarter of 2002 to $4.0
million during the second quarter of 2003. Our average borrowings and interest
rates were $229.5 million and 6.43% during the second quarter of 2003 compared
to $261.1 million and 5.28% during the second quarter of 2002. For the current
quarter, our average borrowings decreased and our average interest rate
increased as we replaced our existing fixed debt of $100 million at 8 5/8%
with new fixed debt of $175 million at 7% and used excess proceeds from the
newly issued debt to repay outstanding borrowings under our revolving bank
credit facility which bears interest at lower rates that averaged 3.3% during
both the second quarter of 2003 and 2002. In addition, the increase in net
interest expense for the second quarter of 2003 reflects a decrease in
capitalized
27
interest. Capitalized interest decreased 10% from $2.0 million during the second
quarter of 2002 to $1.8 million during the second quarter of 2003 and is a
result of a decrease in our unevaluated property balance from $139.1 million at
June 30,, 2002 to $102.2 million at June 30, 2003. Our capitalized interest,
which is a function of unevaluated properties, decreased during the quarter
corresponding to a decrease in our unevaluated property balance as several
properties previously designated as unevaluated were reclassified to the
amortization base or full cost pool at the end of 2002.
Income Tax Provision. The provision for income taxes increased 70% from
$9.2 million for the second quarter of 2002 to $15.6 million for the second
quarter of 2003 due to the 65% increase in pre-tax income during the second
quarter of 2003 from $26.9 million during the second quarter of 2002 to $44.5
million during the second quarter of 2003. Pre-tax income is higher as a result
of the 41% increase in revenues and $2.3 million in other income as a result of
refunds of prior period severance tax offset in part by a 22% increase in
operating expenses, a 38% increase in net interest expense and $5.9 million in
debt extinguishment expenses.
Operating Income and Income before Cumulative Effect of Change in
Accounting Principle. For the three months ended June 30, 2003, the 38% increase
in realized natural gas prices combined with the 3% increase in production,
offset in part by a 22% increase in operating expenses, caused operating income
to increase 76% from $28.5 million during the second quarter of 2002 to $50.3
million during the second quarter of 2003. Correspondingly, income before the
cumulative effect of the change in accounting principle increased 63% from $17.7
million for the second quarter of 2002 to $28.9 million for the second quarter
of 2003.
Comparison of Six Months Ended June 30, 2003 and 2002
Production. Our production increased 4% from 50,637 million cubic feet
equivalent, or MMcfe, for the six months ended June 30, 2002 to 52,529 MMcfe for
the six months ended June 30, 2003. Average daily production was 290 MMcfe/day
during the first half of 2003 compared to 280 MMcfe/day during the first half of
2002.
Onshore, our daily production rates increased 18% from an average of
146 MMcfe/day during the first half of 2002 to an average of 172 MMcfe/day
during the corresponding six months of 2003. The increase in onshore production
is primarily attributable to 28 MMcfe/day in newly developed production from in
South Texas. Production from our other onshore areas declined slightly by 2
MMcfe/day from 34 MMcfe/day during the first half of 2002 to 32 MMcfe/day during
the first half of 2003.
Offshore, our production decreased 12% from an average of 134 MMcfe/day
during the first half of 2002 to an average of 118 MMcfe/day during the first
half of 2003. Production declines due to maturing reservoirs from existing key
fields, Mustang Island A-31/32, High Island 39, West Cameron 587 and South Marsh
Island 253, were greater than incremental production added from new wells and
facilities brought on-line since the end of the first half of 2002 at Vermilion
408, East Cameron 81/84, East Cameron 82/83, Mustang Island 785, High Island 38,
and South Timbalier 314/317. Further, we experienced a loss of an estimated 3
MMcfe/day at Vermilion 408 during a 15 day shut-in during January and February
2003 due to down stream pipeline shut-ins for repairs. The year-over-year
production decline is partially the result of shifting approximately $40 million
of our 2002 offshore capital expenditure program to our onshore region to
facilitate the May 2002 acquisition of producing properties in South Texas from
Burlington Resources.
Natural Gas and Oil Revenues. Natural gas and oil revenues increased
56% from $160.0 million during the first six months of 2002 to $248.8 million
during the first six months of 2003 as a result of a 51% increase in average
realized natural gas prices, from $3.14 per Mcf during the first half of 2002 to
$4.73 per Mcf in the first half of 2003 and an increase in average realized oil
prices of 29% for the same period from $22.05 per barrel, or Bbl, to $28.55 per
barrel, combined with a 53% increase in oil production during the current
quarter.
Natural Gas Prices. As a result of hedging activities during the first
half of 2003, we realized an average gas price of $4.73 per Mcf, which was 82%
of the average unhedged natural gas price of $5.76 for the period. As a result,
natural gas and oil revenues for the six months ended June 30, 2003 that were
$50.0 million lower than the revenues we would have achieved if hedges had not
been in place during the period. For the corresponding six months of 2002, we
realized an average gas price of $3.14 per Mcf, which was 113% of the average
unhedged natural gas price of $2.79 for the period. This resulted in natural gas
and oil revenues that were $17.0 million higher than the revenues we would have
achieved if hedges had not been in place during the period.
28
Oil Prices. During the first half of 2003, we realized an average oil
price of $28.55 per Bbl, which was 98% of the average unhedged price of $29.24
per Bbl for the period. As a result, natural gas and oil revenues for the six
months ended June 30, 2003 were $0.4 million lower than the revenues we would
have achieved if hedges had not been in place during the period. We had no oil
hedges in place during first half of 2002 and realized an average oil price of
$22.05 per Bbl.
Lease Operating Expenses and Severance Tax. Lease operating expenses
increased 52% from $15.3 million for the six months ended June 30, 2002 to $23.3
million for the corresponding six months of 2003. On an Mcfe basis, lease
operating expenses increased 47% from $0.30 per Mcfe during the first half of
2002 to $0.44 per Mcfe during the first half of 2003. The increase in both lease
operating expenses and lease operating expense on a per unit basis for 2003 is
attributable to the continued expansion of our operations both onshore and
offshore. Our overall operating expenses are increasing as we add new wells and
facilities and continue to maintain production from existing properties. Since
the end of the second quarter of 2002, we added approximately 100 new wells from
exploration and development drilling. Onshore, ad valorem taxes, compression
costs, well control insurance and contract service expenses have increased in
the current period. In addition, during the first quarter of 2003, we incurred
$1.6 million in non-recurring expenses associated with a workover in the Charco
Field. Offshore, we added new crude oil production facilities at South Timbalier
314/317 during the first quarter of 2003 and since the end of the second quarter
of 2002, we added new wells and facilities at East Cameron 81/83/84 which are
incurring incremental fees to process the natural gas. In addition, we installed
compressors at several platforms to enhance production capabilities from
existing wells.
Severance tax, which is a function of volume and revenues generated
from onshore production, increased from $4.5 million for the first six months of
2002 to $7.5 million for the corresponding period of 2003. On an Mcfe basis,
severance tax increased from $0.09 per Mcfe for the first half of 2002 to $0.14
per Mcfe during the first half of 2003. Despite our reduced severance tax rate
for a portion of our South Texas production pursuant to the "high-cost/tight-gas
formation" designation received in July 2002 (see "Other (Income) and Expense"
below), severance tax expense and severance tax per Mcfe increased during the
first six months of 2003 due to the 106% increase in average wellhead prices for
natural gas from $2.79 during the first half of 2002 to $5.76 during the first
half of 2003 combined with a 18% increase in onshore production for the first
half of 2003.
Transportation Expense. We applied EITF No. 00-10 "Accounting for
Shipping and Handling Fees and Costs" for all periods presented. Pursuant to our
application of EITF No. 00-10, transportation expenses for the six months ended
June 30, 2002 that were previously reflected as a reduction of natural gas and
oil revenues were added back to the related revenues and reclassified as a
separate component of operating expense. The application of EITF No. 00-10 had
no effect on operating income or net income. Transportation expense increased
11% on an Mcfe basis from $0.09 during the first six months of 2002 to $0.10 for
the first six months of 2003. The increase reflects an increase in volume,
primarily in South Texas, that is subject to transportation fee agreements
during 2003.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 14% from $81.8 million for the six months ended
June 30, 2002 to $93.4 million for the six months ended June 30, 2003.
Depreciation, depletion and amortization expense per Mcfe increased 10% from
$1.62 for the six months ended June 30, 2002 to $1.78 for the corresponding six
months in 2003. 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 as the costs associated with several unproved
properties designated as unevaluated were reclassified into our amortization
base without incremental reserve additions at the end of 2002. In addition, our
estimated future development costs increased approximately 22% at December 31,
2002 from prior year estimates due to the addition of more proved undeveloped
reserves into our total proved reserve base.
Asset Retirement Accretion. Pursuant to our January 1, 2003 adoption of
SFAS No. 143, "Asset Retirement Obligations," we incurred asset retirement
accretion expense of $1.6 million, $0.03 per Mcfe, for the first six months of
2003. The accretion expense represents the systematic, monthly accretion and
depreciation of future abandonment costs of tangible assets such as platforms,
wells, service assets, pipelines, and other facilities.
General and Administrative Expenses, Net of Capitalized General and
Administrative and Overhead Reimbursements. Our net general and administrative
expenses increased 40% from $5.8 million for the six months ended June 30, 2002
to $8.1 million for the six months ended June 30, 2003. These amounts are net of
overhead reimbursements received from other working interest owners of $0.9
million and $0.8 million for the six months ended June 30, 2002 and 2003,
respectively, and capitalized general and administrative expenses of $6.4
million and $6.6 million for the respective periods. Aggregate general and
administrative expenses increased by $2.4 million or 18% from $13.1 million for
the first
29
half of 2002 to $15.5 million for the first half of 2003. However, included in
aggregate expense for the first half of 2002 was approximately $0.9 million in
non-recurring charges relating to employee severance payments. Without these
non-recurring charges, aggregate general and administrative expense for the
first half of 2003 would reflect a $3.3 million or 27% increase from the first
half of 2002 and net general and administrative expenses for the first half of
2003 would reflect a $3.2 million or 65% increase. The increase in aggregate
general and administrative expense is due primarily to the expansion of our
workforce which corresponds to the continued expansion of our operations. As our
workforce expands, we have experienced an increase in salaries and related
employee benefit expenses together with an increase in our incentive
compensation expense. In addition, our rent expense has increased as we expanded
our leased office space in downtown Houston to accommodate our growing
workforce. Finally, our legal, audit and accounting expenses increased as we
implemented new corporate governance policies and engaged an outside firm to
perform internal auditing functions.
On an Mcfe basis, net general and administrative expenses increased 25%
from $0.12 during the first half of 2002 to $0.15 per Mcfe during the first half
of 2003. Without the non-recurring charges of $0.9 million incurred in the first
half of 2002 for employee severance payments, net general and administrative
expense per Mcfe would have increased by $0.05 per Mcfe or by 50% from $0.10 in
first half 2002 to $0.15 in the first half of 2003. The higher rate per Mcfe
during the first half of 2003 reflects the increase in our aggregate general and
administrative expenses.
Other Income and Expense. For the first half of 2003, Other Income and
Expense includes two components: (i) debt extinguishment expenses totaling $5.9
million ($3.9 million net of tax); and (ii) income of $12.9 million ($8.4
million net of tax) related to refunds of prior year's severance tax expense.
Upon completing the private placement of our $175 million 7% senior subordinated
notes June due 2013 on June 10, 2003, we called our $100 million 8 5/8% senior
subordinated notes due 2008 for redemption. We incurred a premium for early
redemption of the $100 million 8 5/8% notes of $4.3 million together with a
non-cash charge of $1.6 million to write-off the balance of the unamortized
costs associated with issuing the $100 million notes.
In July 2002, we applied for and received from the Railroad Commission
of Texas a "high-cost/tight-gas formation" designation for a portion of our
South Texas production. The "high-cost/tight-gas formation" designation allows
us to receive an abatement of severance taxes for qualifying wells in various
fields. 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. As of the date of our report, we are estimating
that we could receive refunds of up to an additional $1.2 million ($0.8 million
net of tax), although there can be no assurances that actual amounts collected
will equal our estimates.
Interest Expense, Net of Capitalized Interest. Interest expense, net of
capitalized interest, increased 47% from $3.0 million for the first six months
of 2002 to $4.4 million for the first six months of 2003. Aggregate interest
expense increased 6% from $7.2 million during the first half of 2002 to $7.6
million during corresponding six months of 2003. Our average borrowings and
interest rates were $255.8 million and 5.32% during the first half of 2002
compared to $239.8 million and 5.91% during the first half of 2003. The increase
in net interest expense for the current period is due in part to the higher
average rate combined with a decrease in capitalized interest. Capitalized
interest decreased 24% from $4.2 million for the first half of 2002 to $3.2
million for the first half of 2003. Our capitalized interest is a function of
unevaluated properties and the decrease corresponds to the decrease in our
unevaluated property balance from $139.1 million at June 30, 2002 to $102.2
million at June 30, 2003. Unevaluated properties are lower in the current period
as a result of several properties previously designated as unevaluated being
reclassified to the amortization base or full cost pool at the end of 2002.
Income Tax Provision. The provision for income taxes increased 152%
from $15.7 million for the first six months of 2002 to $39.6 million for the
first six months of 2003 due to the 146% increase in pre-tax income during the
first half of 2003 from $45.9 million during the first half of 2002 to $113.0
million during the first half of 2003. Pre-tax income is higher as a result of
the 55% increase in revenues and the $7.0 million in other income that resulted
from a combination of $12.9 million in severance refunds and $5.9 million in
debt extinguishment expenses. The increase in revenues and other income was
offset in part by a 24% increase in operating expenses and a 47% increase in net
interest expense.
Operating Income and Income before Cumulative Effect of Change in
Accounting Principle. For the six months ended June 30, 2003, the 51% increase
in realized natural gas prices combined with the 4% increase in production,
offset in part by a 24% increase in operating expenses, caused operating income
to increase 126% from $48.9 million during the first half
30
of 2002 to $110.5 million during the first half of 2003. Correspondingly, income
before the cumulative effect of the change in accounting principle increased
143% from $30.2 million for the first half of 2002 to $73.4 million for the
first half of 2003.
LIQUIDITY AND CAPITAL RESOURCES
We fund our operations, including capital expenditures and working
capital requirements, from cash flows from operations 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 2003. In June 2003, we took advantage of lower
interest rates and called our $100 million 8 5/8% senior subordinated notes due
January 2008 for early redemption and issued $175 million 7% senior subordinated
notes due June 2023. We received $170.9 million in net proceeds from the private
placement of the $175 million 7% senior subordinated notes. Of the net proceeds
received, we transferred $104.3 million directly to the trustee who placed the
funds in a short-term investment vehicle for use in the July 11, 2003 repayment
of the aggregate principal of $100 million on the 8 5/8% senior subordinated
notes together with a premium of $4.3 million for early redemption of the notes.
The remaining portion of the net proceeds was used to repay $60 million in
outstanding borrowings on our revolving bank credit facility with the balance of
approximately $6.6 million being applied to working capital, a portion of which
was utilized in July 2003 to fund the payment to the trustee of $4.6 million in
accrued interest due on the $100 million 8 5/8% notes.
Cash Flows. As of June 30, 2003, we had working capital deficit of
$17.1 million and $260.6 million of borrowing capacity available under our
revolving bank credit facility. Our working capital deficit is due to the fair
value of a portion of our derivative financial instruments of $54.4 million that
is classified as a current liability. Net cash provided by operating activities
for the first six months of 2003 was $185.6 million compared to $108 million
during the first six months of 2002. The 72% increase in net cash provided by
operating activities was due to an increase in net income caused primarily by
higher realized natural gas prices and an increase in production volumes for the
half 2003 together with an increase in operating assets and current liabilities.
For the first half of 2003, the increase in operating assets was caused
primarily by an increase in receivables for natural gas revenues due to
comparatively higher gas prices and production volumes together with our
receivable at June 30, 2003 for severance tax refunds totaling $28.2 million.
Current liabilities (excluding the fair value of derivatives which is a non-cash
item) increased due to a higher level of drilling activity in the first half of
2003 as compared to the first half of 2002. For the first six months of 2003,
funds used in investing activities consisted of $138.3 million for net cash
investments in property and equipment, which compares to $130.9 million spent
during the first six months of 2002. Proceeds from long-term borrowings
increased our cash position during the first half of 2003 by a net $43 million.
We issued $175 million in 7% senior subordinated notes and repaid a net $132
million in borrowings under our revolving bank credit facility. For the
corresponding six months of 2002, net cash increased by $36 million from
incremental borrowings under our revolving bank credit facility. During the
current period, we incurred $4.1 million in costs related to the issuance of the
new $175 million 7% senior subordinated notes. Cash increased by $2.5 million
and $1.2 million, respectively, during the first half of 2003 and 2002 due to
proceeds received from the issuance of common stock from the exercise of stock
options. In addition, during the first quarter of 2003, we sold 3 million newly
issued shares of our common stock in a public offering for net proceeds of $79.2
million, and simultaneously repurchased the same number of shares from KeySpan
for $79.2 million. As a result of these operating, investing and financing
activities, cash and cash equivalents increased $88.6 million from $18.0 million
at December 31, 2002 to $106.6 million at June 30, 2003. The cash balance at
June 30, 2003 includes a temporary cash investment of $104.3 million that was
used on July 11, 2003 for the repayment of $100 million in aggregate principal
together with a $4.3 million early redemption premium for the 8 5/8% senior
subordinated notes.
Investments in Property and Equipment. During the half of 2003, we
invested $137.7 million in natural gas and oil properties and $0.8 million for
other property and office equipment. During the six months of 2003, we completed
the drilling of 72 gross wells (55.9 net) of which 53 (41.7 net) were successful
and 19 (14.2 net) were unsuccessful with an additional 14 wells (12 net) in
progress at the end to the quarter. Our investments in natural gas and oil
properties included $30.3 million in exploration costs, $79.2 million in
development costs and $28.2 in leasehold acquisition costs. Leasehold
acquisition costs include among other things, costs incurred for seismic,
capitalized interest and capitalized general and administrative costs. During
the six months of 2003 and 2002, we capitalized a total of $9.8 million and
$10.6 million, respectively, in interest and general and administrative
expenses.
Future Capital Requirements. At the quarterly meeting of our Board of
Directors held July 29, 2003, our 2003 capital expenditure budget of $286
million was increased by $26 million to $312 million. We are planning to spend
two-thirds of the increase in South Texas and the balance in the Arkoma Basin.
As of June 30, 2003, we had spent approximately 48% of our initial capital
expenditure budget of $286 million for 2003. We do not include property
acquisition costs in our
31
capital expenditure budget because the size and timing of capital requirements
for acquisitions are inherently unpredictable. The capital expenditure budget
includes exploration and development costs associated with projects in progress
or planned for the upcoming year and amounts are contingent upon drilling
success. We have estimated our current asset retirement obligations to be $4.5
million. No assurances can be made that amounts budgeted will equal actual
amounts spent. 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 believe cash flows from operations and borrowings under our
credit facility will be sufficient to fund these expenditures. We intend to
continue to selectively seek acquisition opportunities both offshore and onshore
although we may not be able to identify and make acquisitions of proved reserves
on terms we consider favorable.
Revolving Bank Credit Facility. We maintain a revolving bank credit
facility with a syndicate of lenders led by Wachovia Bank, National Association,
as issuing bank and administrative agent, The Bank of Nova Scotia and Fleet
National Bank as co-syndication agents and BNP Paribas as documentation agent.
The credit facility provides us with a commitment of $300 million which may be
increased at our request and with prior approval from Wachovia to a maximum of
$350 million by adding one or more lenders or by allowing one or more lenders to
increase their commitments. The credit facility is subject to borrowing base
limitations. Our current borrowing base is $300 million and is redetermined
semi-annually, with the next redetermination scheduled for October 1, 2003. Up
to $25 million of the borrowing base is available for the issuance of letters of
credit. The credit facility matures July 15, 2005, is unsecured and with the
exception of trade payables, ranks senior to all of our existing debt.
At June 30, 2003, outstanding borrowings under our revolving bank
credit facility were $20 million together with $9.4 million in outstanding
letter of credit obligations. A $9 million letter of credit was issued to a
counter party to cover a margin call pursuant to a natural gas hedge contract.
Subsequent to June 30, 2003, we repaid all outstanding borrowings under our
revolving bank credit facility of $20 million and reduced our letter of credit
obligations to $0.4 million. As of the date of this report, outstanding
borrowings and letter of credit obligations under our revolving bank credit
facility total $0.4 million.
Senior Subordinated Notes. On June 10, 2003, we issued in a private
placement $175 million 7% senior subordinated notes due June 15, 2013. The notes
bear interest at a rate of 7% per annum with interest payable semi-annually on
June 15 and December 15, beginning December 15, 2003. We may redeem the notes at
our option, in whole or in part, at any time on or after June 15, 2008 at a
price equal to 100% of the principal amount plus accrued and unpaid interest, if
any, plus a specified premium which decreases yearly from 3.5% in 2008 to 0% in
2011 and thereafter. In addition, at any time prior to June 15, 2006, we may
redeem up to a maximum of 35% of the aggregate principal amount with the net
proceeds of one or more equity offerings at a price equal to 107% of the
principal amount, plus accrued and unpaid interest and liquidated damages, if
any. The notes are general unsecured obligations and rank subordinate in right
of payment to all existing and future senior debt, including the revolving bank
credit facility, and will rank senior or equal in right of payment to all
existing and future subordinated indebtedness.
Upon closing of the $175 million 7% senior subordinated notes on June
10, 2003, we called our $100 million 8 5/8% notes due January 1, 2008 for
redemption. The redemption of the $100 million in aggregate principal and
payment of the premium for early redemption were funded with a portion of the
proceeds received from the $175 million 7% senior subordinated notes and was
completed on July 11, 2003. The $100 million 8 5/8% senior subordinated notes
were issued on March 2, 1998. The notes bore interest at a rate of 8 5/8% per
annum with interest payable semi-annually on January 1 and July 1. The $100
million 8 5/8% notes were redeemable, at our option, in whole or in part, at any
time on or after January 1, 2003 at a price equal to 100% of the principal
amount plus accrued and unpaid interest, if any, plus a specified premium which
decreases yearly from 4.313% in 2003 to 0% in 2006. At June 30, 2003 and
pursuant to the early redemption of the $100 million notes, we incurred debt
extinguishment expenses totaling $5.9 million ($3.9 million net of tax) for the
call premium of $4.3 million together with a non-cash charge of $1.6 million for
the write-off of the balance of the unamortized issue costs. Total debt
extinguishment expense of $5.9 million is included in the line item "Other
(Income)Expense" on our Statement of Operations for the three month and six
month periods ended June 30, 2003.
32
Contractual Obligations and Other Commercial Commitments
The table below summarizes our contractual obligations and commercial
commitments at June 30, 2003. We have no "off-balance sheet" financing
arrangements.
AT JUNE 30, 2003
PAYMENTS DUE BY PERIOD
-----------------------------------------
CONTRACTUAL OBLIGATIONS 1 - 3 YEARS 4 - 5 YEARS AFTER 5 YEARS
- ----------------------------------------------------------------------------------------------------
($ IN THOUSANDS)
Revolving bank credit facility ........................ $ 20,000 $ -- $ --
8 5/8% senior subordinated notes, paid July 11, 2003 .. 100,000 -- --
7% senior subordinated notes, due June 2013 ........... -- -- 175,000
Operating leases ...................................... 2,829 2,331 2,111
-------- -------- --------
Total contractual obligations ..................... $122,829 $ 2,331 $177,111
======== ======== ========
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.
We may be subject to margin calls under our hedge contracts; however, we
believe, we have sufficient liquidity to cover these margin calls, if any.
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 six month period from January 1 to June 30, 2003
and 2002, respectively. Stated amounts do not reflect the effects of taxes.
CHANGE IN FAIR VALUE OF DERIVATIVES INSTRUMENTS 2003 2002
- ----------------------------------------------------------------------------------------------
(in thousands)
Fair value of contracts at January 1 ............................ $(38,772) $ 53,771
(Gain) loss on contracts realized ............................... 50,446 (16,978)
Fair value of new contracts when entered into during period ..... 5,288 --
(Decrease) increase in fair value of all open contracts ......... (69,542) (37,982)
-------- --------
Fair value of contracts outstanding at June 30, ................. $(52,580) $ (1,189)
======== ========
33
Natural Gas. The following table summarizes, on a monthly basis, our
hedges currently in place for the remainder of 2003 and calendar 2004. For the
remaining six months of 2003, we have hedged approximately 67% of our estimated
production or a total of 190,000 MMBtu/day at a floor of $3.417/MMBtu and a
ceiling of $4.548/MMBtu. For each month of 2004, we have also hedged
approximately 67% of our estimated production or a total of 200,000 MMBtu/day.
For the three months January through March 2004, our floor will average
$4.375/MMBtu on 200,000 MMBtu/day and our ceiling will average $5.045/MMBtu on
100,000 MMBtu/day, with no ceiling on the remaining 100,000 MMBtu/day. For the
remaining nine months of 2004, our floor will average $4.125/MMBtu on 200,000
MMBtu/day and our ceiling will average $6.023/MMBtu on 200,000 MMBtu/day. All
amounts in the table below are in thousands, except for prices.
OPTIONS - PUTS FIXED PRICE SWAPS COLLARS
----------------------- --------------------------- -----------------------------
VOLUME NYMEX VOLUME NYMEX VOLUME NYMEX
PERIOD (MMBTU) CONTRACT PRICE (MMBTU) CONTRACT PRICE (MMBTU) CONTRACT PRICE
- -------------------------------------------- ------- --------------- -----------------------------
AVG FLOOR AVG CEILING
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
January 2004 3,100 $ 5.000 3,100 3.750 5.045
February 2004 2,900 5.000 2,900 3.750 5.045
March 2004 3,100 5.000 3,100 3.750 5.045
April 2004 6,000 4.125 6.023
May 2004 6,200 4.125 6.023
June 2004 6,000 4.125 6.023
July 2004 6,200 4.125 6.023
August 2004 6,200 4.125 6.023
September 2004 6,000 4.125 6.023
October 2004 6,200 4.125 6.023
November 2004 6,000 4.125 6.023
December 2004 6,200 $4.125 $6.023
For natural gas, transactions are settled based upon the New York
Mercantile Exchange or NYMEX price on the final trading day of the month. For
oil, our swaps are settled against the average NYMEX price of oil for the
calendar month rather than the last day of the month. In order to determine fair
market value of our derivative instruments, we obtain mark-to-market quotes from
external counterparties.
With respect to any particular swap transaction, the counterparty is
required to make a payment to us if the settlement price for any settlement
period is less than the swap price for the transaction, and we are required to
make payment to the counterparty if the settlement price for any settlement
period is greater than the swap price for the transaction. For any particular
collar transaction, the counterparty is required to make a payment to us if the
settlement price for any settlement period is below the floor price for the
transaction, and we are required to make payment to the counterparty if the
settlement price for any settlement period is above the ceiling price for the
transaction. We are not required to make or receive any payment in connection
with a collar transaction if the settlement price is between the floor and the
ceiling. For our put option contracts, 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 period.
34
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. 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-15 of the Exchange Act), as of the end of the
period covered by this report. Based on that evaluation, our principal executive
officer and principal financial officer concluded that our disclosure controls
and procedures are effective. There have been no changes in our internal control
over financial reporting that
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On May 15, 2003, we held our annual meeting of stockholders. All matters brought
for a vote before the shareholders as listed in our proxy statement were
approved as follows:
1. The election of the following 10 Directors to serve until our
next annual meeting:
DIRECTOR VOTES FOR VOTES WITHHELD
- -------------------------------------------------------------
Gordon F. Ahalt 29,361,641 250,357
Robert B. Catell 26,225,712 3,386,286
David G. Elkins 29,362,541 249,457
Robert J. Fani 26,205,872 3,406,126
William G. Hargett 29,343,946 268,052
Harold R. Logan, Jr. 29,362,641 249,357
Gerald Luterman 29,343,356 268,642
H. Neil Nichols 29,343,256 268,742
James Q. Riordan 29,361,041 256,957
Donald C. Vaughn 29,406,792 205,206
2. The appointment of Deloitte & Touche LLP as our independent
public accountants for the fiscal year ending December 31,
2003.
VOTES FOR VOTES AGAINST ABSTAINED
- ----------------------------------------------
29,474,885 133,263 3,850
35
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K:
(a) Exhibits filed here with:
EXHIBITS DESCRIPTION
- ------------- -------------------------------------------------------------
10.1* -- First Amendment to Credit Agreement among The Houston
Exploration Company, the lenders Wachovia Bank, National
Association, as issuing bank and as administrative agent, The
Bank of Nova Scotia and Fleet National Bank, as
co-syndication agents; and BNP Paribas, as documentation
agent, effective June 5, 2003.
4.1 -- Indenture, dated as of June 10, 2003, between The Houston
Exploration Company and the Bank of New York, as Trustee,
with respect to the 7% Senior Subordinated Notes due 2013.
(Exhibit 4.2 to our Registration Statement on Form S-4
(Registration No. 333-106836) and incorporated by
reference).
4.2 -- Registration Rights Agreement dated as of June 5, 2003,
among The Houston Exploration Company and Wachovia
Securities, Inc., Lehman Brothers Inc., BNP Paribas
Securities Corp., Fleet Securities, Inc. and Scotia Capital
(USA) Inc., as Initial Purchasers. (Exhibit 4.5 to our
Registration Statement on Form S-4 (Registration No.
333-106836) and incorporated by reference).
31.1* -- Certification of William G. Hargett, Chief Executive Officer,
as required pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
31.2* -- Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 302
of the Sarbanes - Oxley Act of 2002.
32.1* -- Certification of William G. Hargett, Chief Executive Officer,
of 2002. as required pursuant to Section 906 of the Sarbanes
-Oxley Act
32.2* -- Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
* -- Filed herewith.
(b) Reports on Form 8-K:
Current Report on Form 8-K filed on February 21, 2003 to
provide information in Item 5. - Other Events regarding a
press release issued on February 21, 2003 announcing the
offering by Houston Exploration of 3,000,000 shares of common
stock in an underwritten public offering and concurrent
repurchase of a like number of shares from KeySpan.
Current Report on Form 8-K filed February 26, 2003 to provide
information in Item 5. - Other Events regarding the
Underwriting Agreement between Houston Exploration and J.P.
Morgan Securities, Inc. dated February 20, 2003 for the
issuance and sale of 3,000,000 shares to the public and the
Stock Purchase Agreement among Houston Exploration, KeySpan
Corporation and THEC Holdings Corp. dated as of February 20,
2003 and in Item 7. - Financial Statements and Exhibits
regarding the Underwriting Agreement and the Stock Purchase
Agreement.
Current Report on Form 8-K filed on May 2, 2003 required by
Item 12 and filed under Item 9 - Regulation FD Disclosure of
our earnings release for the first quarter of 2003.
Current Report on Form 8-K filed on May 13, 2003 required by
Item 5 - Other Events to amend the Current Reports filed Form
8-K for events dated February 20, 2003 and February 26, 2003
and to add exhibits 5.1 - Opinion of Andrews & Kurth L.L.P.
and 23.1 - Consent of Andrews & Kurth L.L.P.
Current Report on Form 8-K filed on May 23, 2003 to provide
information under Item 9 - Regulation FD Disclosure of our
press release dated May 21,2003 announcing the results of a
Gulf of Mexico discovery at High Island 115.
Current Report on Form 8-K filed on June 2, 2003 to provide
information required by Item 5 - Other Events and Regulation
FD Disclosure of selected financial data and a reconciliation
of non-GAAP financial measures to GAAP measures.
Current Report on Form 8-K filed on July 18, 2003 to provide
information required by Item 5 - Other Events and Regulation
FD Disclosure of our press release announcing the completion
of the redemption of our $100 million 8 5/8% senior
subordinated notes due January 2008.
Current Report on Form 8-K filed on August 6, 2003 to provide
information required by Item 12 - Results of Operations and
Financial Condition of earnings release for the second quarter
of 2003.
36
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: August 7, 2003 William G. Hargett
President and Chief Executive Officer
By: /s/ John H. Karnes
------------------------------------------------------
Date: August 7, 2003 John H. Karnes
Senior Vice President and Chief Financial Officer
By: /s/ James F. Westmoreland
------------------------------------------------------
Date: August 7, 2003 James F. Westmoreland
Vice President and Chief Accounting Officer
37
INDEX TO EXHIBITS
EXHIBITS DESCRIPTION
- ------------- -----------------------------------------------------------------------
10.1* -- First Amendment to Credit Agreement among The Houston
Exploration Company, the lenders Wachovia Bank, National
Association, as issuing bank and as administrative agent, The
Bank of Nova Scotia and Fleet National Bank, as
co-syndication agents; and BNP Paribas, as documentation
agent, effective June 5, 2003.
4.1 -- Indenture, dated as of June 10, 2003, between The Houston
Exploration Company and the Bank of New York, as Trustee,
with respect to the 7% Senior Subordinated Notes due 2013.
(Exhibit 4.2 to our Registration Statement on Form S-4
(Registration No. 333-106836) and incorporated by
reference).
4.2 -- Registration Rights Agreement dated as of June 5, 2003,
among The Houston Exploration Company and Wachovia
Securities, Inc., Lehman Brothers Inc., BNP Paribas
Securities Corp., Fleet Securities, Inc. and Scotia Capital
(USA) Inc., as Initial Purchasers. (Exhibit 4.5 to our
Registration Statement on Form S-4 (Registration No.
333-106836) and incorporated by reference).
31.1* -- Certification of William G. Hargett, Chief Executive Officer,
as required pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
31.2* -- Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 302
of the Sarbanes - Oxley Act of 2002.
32.1* -- Certification of William G. Hargett, Chief Executive Officer,
as required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2* -- Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
* -- Filed herewith