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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 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 November 10, 2003, 31,274,798 shares of Common Stock, par value
$.01 per share, were outstanding.
THE HOUSTON EXPLORATION COMPANY
TABLE OF CONTENTS
Page
----
FACTORS AFFECTING FORWARD LOOKING STATEMENTS.................................................................... 3
PART I. FINANCIAL INFORMATION.................................................................................. 4
Item 1. Consolidated Financial Statements ..................................................................... 4
CONSOLIDATED BALANCE SHEETS -- September 30, 2003 (unaudited) and December 31, 2002............................. 4
CONSOLIDATED STATEMENTS OF OPERATIONS -- Three Months and Nine Months Ended
September 30, 2003 and 2002 (unaudited)............................................................. 5
CONSOLIDATED STATEMENTS OF CASH FLOWS -- Nine Months Ended
September 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.................. 17
Item 3. Quantitative and Qualitative Disclosures About Market Risk............................................. 33
Item 4. Controls and Procedures................................................................................ 35
Item 6. Exhibits and Reports on Form 8-K:...................................................................... 33
(a) Exhibits:........................................................................................ 34
(b) Reports on Form 8-K:............................................................................. 34
SIGNATURES...................................................................................................... 36
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)
SEPTEMBER 30, DECEMBER 31,
2003 2002
--------------------------------
(UNAUDITED)
ASSETS:
Cash and cash equivalents......................................................... $ 13,199 $ 18,031
Accounts receivable............................................................... 80,802 86,713
Accounts receivable -- Affiliate.................................................. 8,610 3,106
Derivative financial instruments.................................................. 11,105 --
Inventories....................................................................... 1,532 1,432
Prepayments and other............................................................. 2,704 2,196
----------- -----------
Total current assets......................................................... 117,952 111,478
Natural gas and oil properties, full cost method
Unevaluated properties......................................................... 107,361 96,192
Properties subject to amortization............................................. 2,076,060 1,828,160
Other property and equipment...................................................... 11,609 10,699
----------- -----------
2,195,030 1,935,051
Less: Accumulated depreciation, depletion and amortization........................ 1,043,107 912,637
----------- -----------
1,151,923 1,022,414
Derivative financial instruments.................................................. 2,646 --
Other non-current assets.......................................................... 24,527 4,924
----------- -----------
Other assets................................................................. 27,173 4,924
TOTAL ASSETS................................................................. $ 1,297,048 $ 1,138,816
=========== ===========
LIABILITIES:
Accounts payable and accrued expenses............................................. $ 82,275 $ 78,175
Derivative financial instruments.................................................. 21,560 35,005
Asset retirement obligation....................................................... 4,573 --
----------- -----------
Total current liabilities.................................................... 108,408 113,180
Long-term debt and notes.......................................................... 175,000 252,000
Derivative financial instruments.................................................. 4,492 3,767
Deferred federal income taxes..................................................... 227,602 175,963
Asset retirement obligation....................................................... 59,954 --
Other deferred liabilities........................................................ 2,585 1,117
----------- -----------
TOTAL LIABILITIES............................................................ 578,041 546,027
COMMITMENTS AND CONTINGENCIES (SEE NOTE 3)
STOCKHOLDERS' EQUITY:
Common Stock, $.01 par value, 50,000,000 shares authorized and 31,265,098 shares
issued and outstanding at September 30, 2003 and 30,954,018 shares
issued and outstanding at December 31, 2002, respectively...................... 313 310
Additional paid-in capital........................................................ 360,497 353,454
Unearned compensation............................................................. (43) (107)
Retained earnings................................................................. 369,673 264,334
Accumulated other comprehensive income............................................ (11,433) (25,202)
----------- -----------
TOTAL STOCKHOLDERS' EQUITY................................................... 719,007 592,789
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY................................... $ 1,297,048 $ 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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
2003 2002 2003 2002
---------------------------- ---------------------------
(UNAUDITED) (UNAUDITED)
REVENUES: (restated) (restated)
Natural gas and oil revenues.......................... $ 118,459 $ 83,955 $ 367,245 $ 244,165
Other................................................. 428 250 1,277 811
---------- ---------- ---------- ----------
Total revenues...................................... 118,887 84,205 368,522 244,976
OPERATING EXPENSES:
Lease operating....................................... 10,221 8,694 33,536 23,993
Severance tax......................................... 3,468 2,798 10,995 7,281
Transportation expense................................ 2,576 2,234 7,764 6,637
Asset retirement accretion expense.................... 827 -- 2,479 --
Depreciation, depletion and amortization.............. 47,327 42,350 140,705 124,198
General and administrative, net....................... 5,437 2,669 13,525 8,497
---------- ---------- ---------- ----------
Total operating expenses............................ 69,856 58,745 209,004 170,606
Income from operations................................... 49,031 25,460 159,518 74,370
Other (income) expense................................... (6,238) -- (13,200) --
Interest expense, net.................................... 1,842 2,277 6,268 5,331
---------- ---------- ---------- ----------
Income before income taxes............................... 53,427 23,183 166,450 69,039
Provision for taxes...................................... 18,708 7,911 58,339 23,579
---------- ---------- ---------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE.................................. $ 34,719 $ 15,272 $ 108,111 $ 45,460
Cumulative effect of change in accounting principle...... -- -- (2,772) --
---------- ---------- ---------- ----------
NET INCOME............................................... $ 34,719 $ 15,272 $ 105,339 $ 45,460
========== ========== ========== ==========
EARNINGS PER SHARE:
NET INCOME PER SHARE - BASIC
Income before cumulative effect of change in
accounting principle................................ $ 1.12 $ 0.50 $ 3.48 $ 1.49
Cumulative effect of change in accounting principle... -- -- (0.09) --
---------- ---------- ---------- ----------
Net income per share -- basic......................... $ 1.12 $ 0.50 $ 3.39 $ 1.49
========== ========== ========== ==========
NET INCOME PER SHARE -- FULLY DILUTED
Income before cumulative effect of change in
accounting principle................................ $ 1.11 $ 0.50 $ 3.47 $ 1.47
Cumulative effect of change in accounting principle -- -- (0.09) --
---------- ---------- ---------- ----------
Net income per share -- fully diluted................. $ 1.11 $ 0.50 $ 3.38 $ 1.47
========== ========== ========== ==========
Weighted average shares outstanding -- basic............. 31,117 30,540 31,022 30,514
Weighted average shares outstanding -- fully diluted..... 31,236 30,830 31,134 30,840
5
The accompanying notes are an integral part of these
consolidated financial statements.
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
NINE MONTHS ENDED SEPTEMBER 30,
2003 2002
---------------------------------
(UNAUDITED)
OPERATING ACTIVITIES:
Net income................................................................. $ 105,339 $ 45,460
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and amortization................................... 140,705 124,198
Deferred income tax expense................................................ 56,425 24,154
Asset retirement accretion expense......................................... 2,479 --
Debt extinguishment expense................................................ 1,626 --
Stock compensation expense................................................. 514 63
Cumulative effect of change in accounting principle........................ 2,772 --
Changes in operating assets and liabilities:
Increase in accounts receivable......................................... 407 (27,193)
Increase in inventories................................................. (100) (334)
Decrease in prepayments and other....................................... (508) 446
(Increase) decrease in other assets ..................................... (17,136) 4,817
Increase (decrease) in accounts payable and accrued expenses............ 4,100 (6,878)
Increase in other liabilities........................................... 1,468 260
---------- ----------
Net cash provided by operating activities.................................. 298,091 164,993
INVESTING ACTIVITIES:
Investment in property and equipment....................................... (212,933) (178,860)
Deposit paid for property acquisition...................................... (15,000) --
Dispositions............................................................... -- 5,311
---------- ----------
Net cash used in investing activities...................................... (227,933) (173,549)
FINANCING ACTIVITIES:
Proceeds from long term borrowings......................................... 246,000 46,000
Repayments of long term borrowings......................................... (323,000) (43,000)
Debt issuance costs........................................................ (4,586) --
Proceeds from issuance of common stock from exercise of stock options...... 6,596 2,390
Proceeds from issuance of common stock..................................... 79,200 --
Repurchase of common stock................................................. (79,200) --
---------- ----------
Net cash (used in) provided by financing activities........................ (74,990) 5,390
---------- ----------
Decrease in cash and cash equivalents...................................... (4,832) (3,166)
Cash and cash equivalents, beginning of period............................. 18,031 8,619
---------- ----------
Cash and cash equivalents, end of period................................... $ 13,199 $ 5,453
========== ==========
SUPPLEMENTAL INFORMATION:
Cash paid for interest..................................................... $ 11,278 $ 13,417
========== ==========
Cash paid for taxes........................................................ $ 14,800 $ --
========== ==========
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 September 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.
New Accounting Pronouncements
SFAS 141, "Business Combinations" and SFAS 142, "Goodwill and
Intangible Assets," became effective on July 1, 2001 and January 1, 2002,
respectively. These new standards emphasize a more precise evaluation of assets
and clarify that more assets should be distinguished and classified between
tangible and intangible. We understand that the issue is under evaluation as to
whether provisions of SFAS 141 and SFAS 142 may call for mineral rights held
under lease or other contractual arrangements to be classified in the balance
sheet as intangible assets together with cash costs of oil and gas leasehold
interests acquired. The issue is under review, because it is believed that no
oil and gas exploration and production company has changed its tangible asset
balance sheet classification of mineral rights or leasehold costs upon adoption
of SFAS Nos. 141 and 142, including us. If these types of leasehold costs (both
proved and unevaluated) are determined to be intangible assets, they would be
classified separately from oil and natural gas properties as intangible assets
on our balance sheets. This issue relates only to balance sheet classification
and presentation and will not have an effect on cash flows or results of
operations. At September 30, 2003, if we applied the interpretation currently
under discussion, undeveloped leasehold costs of $80.6 million and developed
leasehold costs of $110.1 million, net of accumulated amortization, would be
reclassified from tangibles to intangibles, representing costs incurred since
June 30, 2001, the effective date of SFAS 141. At December 31, 2002, we had
undeveloped leasehold costs of $49.5 million and developed leasehold costs of
$111.5 million, net of accumulated amortization, that would be reclassified from
tangibles to intangibles. We will continue to classify our oil and gas leasehold
costs as tangible oil and natural gas properties until further guidance is
provided.
7
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Use of Estimates, Reclassifications and Restatements
Use of Estimates. 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.
Reclassifications. Certain reclassifications have been made to prior
period financial statements to conform with the current period presentation.
Restatements. 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 nine months ended September 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 nine month periods ended September 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 nine month periods ended September 30, 2002.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2002 SEPTEMBER 30, 2002
---------------------------- -----------------------------
PREVIOUSLY PREVIOUSLY
RESTATED REPORTED RESTATED REPORTED
--------- ---------- ---------- -----------
Natural gas and oil revenues........... $ 83,955 $ 81,721 $ 244,165 $ 237,528
Total revenues......................... 84,205 81,971 244,976 238,339
Transportation expenses................ 2,234 -- 6,637 --
Total operating expenses............... 58,745 56,511 170,606 163,969
Income from operations................. 25,460 25,460 74,370 74,370
Net income............................. 15,272 15,272 45,460 45,460
Natural gas price:
Average realized price (per Mcf) ...... $ 3.23 $ 3.14 $ 3.17 $ 3.08
Average unhedged price (per Mcf)....... 3.09 2.99 2.89 2.80
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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
2003 2002 2003 2002
---------- ---------- ----------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
NUMERATOR:
Income before cumulative effect of change
in accounting principle........................... $ 34,719 $ 15,272 $ 108,111 $ 45,460
Cumulative effect of change in accounting principle.... -- -- (2,772) --
---------- ---------- ----------- ----------
Net income............................................. $ 34,719 $ 15,272 $ 105,339 $ 45,460
========== ========== =========== ==========
DENOMINATOR:
Weighted average shares outstanding.................... 31,117 30,540 31,022 30,514
Add dilutive securities: Stock options................ 119 290 112 326
---------- ---------- ----------- ----------
Total weighted average shares outstanding and
dilutive securities............................... 31,236 30,830 31,134 30,840
========== ========== =========== ==========
EARNINGS PER SHARE - BASIC:
Income before cumulative effect of change in
accounting principle.............................. $ 1.12 $ 0.50 $ 3.48 $ 1.49
Cumulative effect of change in accounting principle.... -- -- (0.09) --
---------- ---------- ----------- ----------
Net income per share - basic........................... $ 1.12 $ 0.50 $ 3.39 $ 1.49
========== ========== =========== ==========
EARNINGS PER SHARE - FULLY DILUTED:
Income before cumulative effect of change in
accounting principle.............................. $ 1.11 $ 0.50 $ 3.47 $ 1.47
Cumulative effect of change in accounting principle.... -- -- (0.09) --
---------- ---------- ----------- ----------
Net income per share - fully diluted................... $ 1.11 $ 0.50 $ 3.38 $ 1.47
========== ========== =========== ==========
For the three months ended September 30, 2003 and 2002, the calculation
of shares outstanding for fully diluted EPS does not include the effect of
outstanding stock options to purchase 1,843,150 and 1,330,609 shares,
respectively, because the exercise price of these shares was greater than the
average market price for the period, which would have an antidulitive effect on
EPS. For the nine month periods ended September 30, 2003 and September 30, 2002,
fully diluted EPS does not include the effect of outstanding stock options to
purchase 1,880,107 shares and 1,321,557 shares, respectively, because inclusion
would have been antidulitive.
Comprehensive Income
The table below summarizes our Comprehensive Income for the three month
and nine month periods ended September 30, 2003 and 2002, respectively.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
2003 2002 2003 2002
-------- --------- -------- ---------
(IN THOUSANDS)
Net income.............................................. $ 34,719 $ 15,272 $ 105,339 $ 45,460
Other comprehensive income, net of taxes:...............
Unrealized gain (loss) on derivative instruments.... 26,182 (11,693) 13,769 (47,417)
-------- --------- --------- --------
Comprehensive income.................................... $ 60,901 $ 3,579 $ 119,108 $ (1,957)
======== ========= ========= ========
9
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Stock Option Expense
On January 1, 2003, we adopted the fair value expense recognition
provisions of SFAS 123 "Accounting for Stock-Based Compensation" and as amended
by SFAS 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 148 proposes three alternative
transition methods for a voluntary change to the fair value method under SFAS
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 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 nine month periods ended
September 30, 2003, we recognized compensation expense of $0.4 million and $0.5
million, respectively, for stock options granted during these periods.
Prior to our January 1, 2003 adoption of SFAS 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 123, compensation expense
would have had the following pro forma effect on our net income and earnings per
share for the three month and nine month periods ended September 30, 2003 and
2002.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
2003 2002 2003 2002
------------------------ ---------------------------
Net income - as reported.............................. $ 34,719 $ 15,272 $ 105,339 $ 45,460
Add: Stock-based compensation expense
included in net income, net of tax.......... 268 14 334 41
Less: Stock-based compensation expense using
fair value method, net of tax............... (1,107) (1,163) (2,189) (3,533)
--------- --------- --------- ----------
Net income - pro forma................................ $ 33,880 $ 14,123 $ 103,484 $ 41,968
========= ========= ========= ==========
Net income per share - as reported.................... $ 1.12 $ 0.50 $ 3.39 $ 1.49
Net income per share - fully diluted - as reported.... 1.11 0.50 3.38 1.47
Net income per share - pro forma...................... $ 1.09 $ 0.46 $ 3.34 $ 1.38
Net income per share - fully diluted - pro forma...... 1.08 0.46 3.32 1.36
10
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Asset Retirement Obligations
On January 1, 2003, we adopted SFAS 143, "Accounting for Asset
Retirement Obligations," which addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. For us, asset retirement obligations
represent the systematic, monthly accretion and depreciation of future
abandonment costs of tangible assets such as platforms, wells, service assets,
pipelines, and other facilities. SFAS 143 requires that the fair value of a
liability for an asset's retirement obligation be recorded in the period in
which it is incurred if a reasonable estimate of fair value can be made, and
that the corresponding cost is capitalized as part of the carrying amount of the
related long-lived asset. The liability is accreted to its then present value
each period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. 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 143 we:
- recognized a charge to income during the first quarter of 2003 of
$2.8 million, net of tax, for the cumulative effect of the change in
accounting principle;
- increased our total liabilities by $57.2 million to record the asset
retirement obligations ("ARO");
- increased our assets by $42.5 million to add the asset retirement
costs to the carrying amount of our natural gas and oil properties;
and
- reduced our accumulated depreciation, depletion and amortization by
$10.4 million for the amount of expense previously recognized.
Adopting SFAS 143 had no impact on our reported cash flows. The
following table describes on a pro forma basis our asset retirement liability as
if SFAS 143 had been adopted on January 1, 2002. The ARO liability at September
30, 2003 and December 31, 2002 includes amounts classified as both current and
long-term.
For the Nine Month Period
-------------------------------
2003 2002
------------ -----------
ARO liability at January 1,............................ $ 57,197 $ 45,759
Additions from drilling................................ 4,852 6,595
ARO accretion expense ................................. 2,478 1,984
------------ -----------
ARO liability at September 30,......................... $ 64,527 $ 54,338
============ ===========
The following table describes the pro forma effect on net income and
earnings per share for the three months and the nine months ended September 30,
2002 as if SFAS 143 had been adopted on January 1, 2002.
Three Months Nine Months
Ended Ended
September 30, September 30,
2002 2002
------------ -----------
Net income - as reported ............................ $ 15,272 $ 45,460
Less: ARO accretion expense, net of tax............. 430 1,290
------------ -----------
Net income - pro forma............................... $ 14,842 $ 44,170
============ ===========
Earnings per share:
Basic - as reported.................................. $ 0.50 $ 1.49
Fully diluted - as reported.......................... 0.50 1.47
Basic - pro forma ................................... 0.49 1.45
Fully diluted - pro forma............................ 0.48 1.43
11
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 2 -- LONG-TERM DEBT AND NOTES
SEPTEMBER 30, 2003 DECEMBER 31, 2002
------------------ -----------------
(in thousands)
SENIOR DEBT:
Revolving bank credit facility, due July 15, 2005............ $ -- $ 152,000
SUBORDINATED DEBT:
8 5/8% Senior Subordinated Notes, due January 1, 2008........ -- 100,000
7% Senior Subordinated Notes, due June 15, 2013.............. 175,000 --
----------- -------------
Total long-term debt and notes......................... $ 175,000 $ 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.
Revolving Bank Credit Facility
We maintain a revolving bank credit facility with a syndicate of
lenders led by Wachovia Bank, National Association, as issuing bank and
administrative agent, The Bank of Nova Scotia and Fleet National Bank as
co-syndication agents and BNP Paribas as documentation agent. The credit
facility provides us with a commitment of $300 million which may be increased at
our request and with prior approval from Wachovia to a maximum of $350 million
by adding one or more lenders or by allowing one or more lenders to increase
their commitments. The credit facility is subject to borrowing base limitations.
Our current borrowing base is $300 million and is redetermined semi-annually,
with the next redetermination scheduled for April 1, 2004. Up to $25 million of
the borrowing base is available for the issuance of letters of credit. The
credit facility matures July 15, 2005, is unsecured and with the exception of
trade payables, ranks senior to our 7% senior subordinated notes. At September
30, 2003, we had no outstanding borrowings under the credit facility and $0.4
million was outstanding in letter of credit obligations. Subsequent to September
30, 2003, we borrowed a net $115 million under the credit facility. These
borrowings were used to fund a portion of the purchase price for the acquisition
of producing properties from Transworld Exploration and Production Inc. that
closed on October 15, 2003 (see Note 5 - Acquisitions.) At November 10, 2003,
the date of this report, outstanding borrowings and letter of credit obligations
under our revolving bank credit facility total $115.4 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 customary negative
covenants that place restrictions and limits on, among other things, the
incurrence of debt, guaranties, liens, leases and certain investments. The
credit facility also restricts and limits our ability to pay cash dividends, to
purchase or redeem our stock and to sell or encumber our assets. Financial
covenants require us to, among other things:
- maintain a ratio of earnings before interest, taxes, depreciation,
depletion and amortization ("EBITDA") to cash interest payments of
at least 3.00 to 1.00;
- maintain a ratio of total debt to EBITDA of not more than 3.50 to
1.00; and
12
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
- not hedge more than 80% of our natural gas production during any
12-month period beginning July 15, 2002 through and including December
31, 2004, and not more than 70% of our natural gas production during
any 12-month period, thereafter.
As of September 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;
- 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 our reasonable 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
13
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
- use our reasonable efforts to complete the exchange offer within 30
business days after the SEC declares the exchange offer registration
statement effective.
We received $170.4 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 $6.1 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. During the second
quarter of 2003 and pursuant to the early redemption of the $100 million notes,
we incurred debt extinguishment expenses totaling $5.9 million ($3.9 million net
of tax) consisting of the call premium of $4.3 million together with a non-cash
charge of $1.6 million for the write-off of the balance of the unamortized issue
costs of the 8 5/8% notes. The debt extinguishment expenses of $5.9 million are
included in the line item "Other (Income) Expense" on the Statement of
Operations for the nine months ended September 30, 2003.
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 allows
us to receive an abatement of severance taxes for qualifying wells in various
fields. For qualifying wells, production is either exempt from tax or taxed at a
reduced rate until certain capital costs are recovered. For qualifying wells, we
are 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. Since the beginning of the fourth quarter of 2002, we have
recorded refunds totaling $27.7 million ($18.0 million net of tax). Refunds
recorded during 2003 total $19.1 million ($12.4 million net of tax) of which
$6.2 million ($4.0 million net of tax) were recorded during the third 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 September 30, 2003 include
$16.6 million in gross refunds of which approximately $11.8 million relates to
our working interest with the balance owed to third party royalty interests.
After September 1, 2003, all refunds will be in the form of a reduction to or
credit against our current severance tax liability rather than in the form of a
cash reimbursement from the State of Texas.
Legal Proceedings
We are involved from time to time in various claims and lawsuits incidental
to our business. In the opinion of management, the ultimate liability, if any,
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
14
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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%.
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 retained a 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
reduced our acquisition price by $1.2 million. The purchase price was adjusted
for various closing items in the normal course of business, including revenues
received by and expenditures made by the seller related to the properties
acquired for the period between the effective date of the transaction (September
1, 2002) and the closing date (October 11, 2002). Our acquisition of the
properties was accounted for as a transaction between entities under common
control. As a result, the excess fair value of the properties acquired of $3.1
million ($2.0 million net of tax) was treated as a capital contribution from
KeySpan and recorded as an increase to additional paid-in capital during the
fourth quarter of 2002.
KeySpan Joint Venture
Effective January 1, 1999, we entered into a joint exploration agreement
with KeySpan Exploration & Production, LLC, a subsidiary of KeySpan, to explore
for natural gas and oil over an initial two-year term expiring December 31,
2000. Under the terms of the joint venture, we contributed all of our then
undeveloped offshore acreage to the joint venture and we agreed that KeySpan
would receive 45% of our working interest in all prospects drilled under the
program. KeySpan paid 100% of actual intangible drilling costs for the joint
venture up to a specified maximum. Further, KeySpan paid 51.75% of all
additional intangible drilling costs incurred and we paid 48.25%. Revenues are
shared 55% to Houston Exploration and 45% to KeySpan.
Effective December 31, 2000, KeySpan and Houston Exploration agreed to end
the primary or exploratory term of the joint venture. As a result, KeySpan has
not participated in any of our offshore exploration prospects unless the project
involved the development or further exploitation of discoveries made during the
initial term of the joint venture. During the first three months of 2003,
KeySpan spent approximately $9.4 million, of which $2.6 million was spent during
the third 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 nine month and three month periods of 2002, KeySpan
spent $14.6 million and $5.1 million, respectively.
15
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Sale of Section 29 Tax Credits
In June 2003, we repurchased, for $2.6 million, certain interests in
producing wells that were sold in January 1997 to a subsidiary of KeySpan under
an agreement designed to monetize tax credits available under Section 29 of the
Internal Revenue Code. Section 29 provides for a tax credit from
non-conventional fuel sources such as oil produced from shale and tar sands and
natural gas produced from geopressured brine, Devonian shale, coal seams and
tight sands formations. The wells subject to the agreement are located in West
Virginia, Oklahoma and East Texas and produce from formations that qualify for
Section 29 tax credits. Pursuant to the agreement, KeySpan acquired an economic
interest in wells that qualified for the tax credits and, in exchange, we:
- retained a volumetric production payment and a net profits
interest of 100% in the properties;
- received a cash down payment of $1.4 million; and
- receive a quarterly payment of $0.75 for every dollar of tax
credit utilized.
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 $0.6 million, respectively for the
three month and nine month periods ended September 30, 2002, with no benefit for
2003.
NOTE 5 -- ACQUISITIONS
Transworld Exploration and Production Inc.
On September 3, 2003, we entered into a purchase and sale agreement
with Transworld Exploration and Production Inc. to acquire Transworld's
shallow-water Gulf of Mexico natural gas and oil producing properties and
undeveloped acreage for $155 million, subject to customary closing adjustments.
Upon signing the purchase and sale agreement, we paid $15.5 million towards the
purchase price. The prepayment is classified and included in the line item
"Other Assets" at September 30, 2003.
On October 15, 2003, we completed the acquisition of the Transworld
properties. At closing, the $155 million purchase price was reduced by $6
million for various customary closing items, including revenues received by and
expenditures made by the seller related to the properties acquired for the
period between the effective date of the transaction, July 1, 2003, and the
closing date, October 15, 2003. The net purchase price of $149 million was paid
in cash and financed in part by cash on hand and in part by borrowings under our
revolving bank credit facility. The properties are located primarily in the
central Gulf of Mexico in less than 320 feet of water and include 21 blocks
covering 86,237 gross (64,394 net) acres. As of the October 15, 2003 closing
date, proved reserves are an estimated 88.5 billion cubic feet of natural gas
equivalent, of which 75% is natural gas. Current production is from 11 fields
and is estimated at approximately 35 million cubic feet of natural gas
equivalent per day, net to our interest. We will operate properties representing
97% of the proved reserves with an average working interest of 65%.
16
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion is intended to assist in an understanding of our
historical financial position and results of operations for the three months and
the nine months ended September 30, 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 principal natural gas
distribution and electric generation operations are located in the Northeastern
United States. In September 1996, we completed our initial public offering and
sold approximately 31% of our shares to the public. As of September 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") 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
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:
17
- 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 133 to hedge against the volatility of natural gas prices, and in
accordance with Securities and Exchange Commission guidelines, we include
estimated future cash flows from our hedging program in our ceiling test
calculation. In calculating our ceiling test at September 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.
Unevaluated Properties. The costs associated with unevaluated properties
and properties under development are not initially included in the amortization
base and relate to unproved leasehold acreage, seismic data, wells in-progress,
wells pending determination and interest capitalized for these projects.
Unevaluated leasehold costs are transferred to the amortization base with the
costs of drilling the related well or upon expiration of a lease. Costs of
seismic data are allocated to various unproved leaseholds and transferred to the
amortization base with the associated leasehold costs on a specific project
basis. Costs associated with wells in-progress and wells pending determination
are transferred to the amortization base once a determination is made whether or
not proved reserves can be assigned to the property. Costs of dry holes are
transferred to the amortization base immediately upon determination that the
well is unsuccessful. All items included in our unevaluated property balance are
assessed on a quarterly basis for possible impairment or reduction in value.
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
18
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.
Accounting for Stock Option Expense
On January 1, 2003, we adopted the fair value expense recognition
provisions of SFAS 123 "Accounting for Stock-Based Compensation" and as amended
by SFAS 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 148 proposes three alternative
transition methods for a voluntary change to the fair value method under SFAS
123. We adopted SFAS 123 using the Prospective Method as defined by SFAS 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 September 30,
2003, we recognized compensation expense of $0.4 million for stock options
granted during the period. For the corresponding nine month period of 2003, we
recognized $0.5 million in compensation expense for stock options. Prior to our
January 1, 2003 adoption of SFAS 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 143, "Accounting for Asset Retirement
Obligations," which addresses accounting and reporting for obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. For us, asset retirement obligations represent the
systematic, monthly accretion and depreciation of future abandonment costs of
tangible assets such as platforms, wells, service assets, pipelines, and other
facilities. SFAS 143 requires that the fair value of a liability for an asset's
retirement obligation be recorded in the period in which it is incurred if a
reasonable estimate of fair value can be made, and that the corresponding cost
is capitalized as part of the carrying amount of the related long-lived asset.
The liability is accreted to its then present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. If
the liability is settled for an amount other than the recorded amount, a gain or
loss is recognized. 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 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;
- increased our assets by $42.5 million to add the asset retirement
costs to the carrying amount of our natural gas and oil properties;
and
- reduced our accumulated depreciation, depletion and amortization by
$10.4 million for the amount of expense previously recognized.
Adopting SFAS 143 had no impact on our reported cash flows.
Recent Accounting Pronouncements
SFAS 141, "Business Combinations" and SFAS 142, "Goodwill and Intangible
Assets," became effective on July 1, 2001 and January 1, 2002, respectively.
These new standards emphasize a more precise evaluation of assets and clarify
that more assets should be distinguished and classified between tangible and
intangible. We understand that the issue is under evaluation as to whether
provisions of SFAS 141 and SFAS 142 may call for mineral rights held under lease
or other contractual arrangements to be classified in the balance sheet as
intangible assets together with cash costs of oil and gas leasehold interests
acquired. The issue is under review, because it is believed that no oil and gas
exploration and production company has changed its tangible asset balance sheet
classification of mineral rights or leasehold costs upon adoption of SFAS 141
and 142, including us. If these types of leasehold costs (both proved and
unevaluated) are determined to be intangible assets, they would be classified
separately from oil and natural gas properties as intangible assets on our
balance sheets. This issue relates only to balance sheet classification and
presentation and will not have an effect on cash flows or results of operations.
At September 30, 2003, if we applied the interpretation currently under
discussion, undeveloped leasehold costs of $80.6 million and developed leasehold
costs of $110.1 million, net of accumulated amortization, would be reclassified
from tangibles to intangibles, representing costs incurred since June 30,
19
2001, the effective date of SFAS 141. At December 31, 2002, we had undeveloped
leasehold costs of $49.5 million and developed leasehold costs of $111.5
million, net of accumulated amortization, that would be reclassified from
tangibles to intangibles. We will continue to classify our oil and gas leasehold
costs as tangible oil and natural gas properties until further guidance is
provided.
In January 2003, the FASB issued Financial Interpretation No. 46,
"Consolidation of Variable Interest Entities -- An Interpretation of Accounting
Research Bulletin 51" (FIN 46). FIN 46 addresses consolidation by business
enterprises of variable interest entities (VIEs) and the primary objective is to
provide guidance on the identification of, and financial reporting for, entities
over which control is achieved through means other than voting rights; such
entities are known as VIEs. FIN 46 requires an entity to consolidate a VIE if
the entity has a variable interest (or combination of variable interests) that
will absorb a majority of the entity's expected losses if they occur, receive a
majority of the entity's expected residual returns if they occur or both. This
guidance applies immediately to VIEs created after January 31, 2003, and to VIEs
in which an enterprise obtains an interest after that date. However, on October
8, 2003, the FASB decided to grant a broader deferral of the implementation of
FIN 46. Pursuant to this deferral, public companies must complete their
evaluations of VIEs that existed prior to February 1, 2003, and the
consolidation of those for which they are the primary beneficiary for financial
statements issued for the first period ending after December 15, 2003. For
calendar year companies, consolidation of previously existing VIEs will be
required in their December 31, 2003 financial statements. We are continuing to
evaluate the impact, if any, FIN 46 may have on our consolidated financial
statements; however, we do not believe that we have any VIEs.
In April 2002, the Financial Accounting Standards Board ("FASB") issued
SFAS 145, "Rescission of FASB Statements 4, 44, and 64, Amendment to FASB
Statement 13 and Technical Corrections." SFAS 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 145 is effective for fiscal years
beginning after May 15, 2002. Our adoption of SFAS 145 on January 1, 2003 had no
effect on our financial statements.
In June 2002, FASB issued SFAS 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 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
146, fair value is the objective for initial measurement of the liability. SFAS
146 is effective for exit or disposal activities that are initiated after
December 31, 2002. Our adoption of SFAS 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 previous
practice of recording a liability only when a loss is probable and reasonably
estimable, as those terms are defined in SFAS 5, "Accounting for Contingencies."
FIN 45 has a dual effective date. The initial recognition and measurement
provisions are applicable on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure requirements in the
interpretation are effective for financial statements for interim or annual
periods ending after December 15, 2002. As of our December 31, 2002 and
September 30, 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.
- In April 2003 the FASB issued SFAS 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS 149 amends and
clarifies accounting for derivative instruments, including certain
derivative instruments embedded in other contracts and hedging
activities under SFAS 133. The amendments set forth in SFAS 149
require that contracts with comparable characteristics be accounted
for similarly. SFAS 149 is generally effective for contracts entered
into or modified after June 30, 2003 (with a few exceptions) and for
hedging relationships designated after June 30, 2003. The guidance is
to be applied prospectively only. The adoption of SFAS 149 did not
impact the accounting treatment of our derivative instruments.
20
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 contracts, 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 entered 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, except for on
October 29, 2003, the FASB agreed to defer the application of paragraphs 9 and
10 of SFAS 150 to mandatorily redeemable non-controlling interests in
subsidiaries that would not be liabilities under SFAS 150 for the subsidiary.
The deferral will be for an indefinite period. As of September 30, 2003, the
provisions of SFAS 150 that are applicable to us had no effect on our financial
statements.
RECENT DEVELOPMENTS
Acquisition of Transworld Exploration and Production Inc. Properties
On October 15, 2003, we completed the acquisition of Transworld Exploration
and Production Inc.'s shallow-water Gulf of Mexico natural gas and oil producing
properties and undeveloped acreage. At closing, the $155 million purchase price
was reduced by $6 million for various customary closing items, including
revenues received by and expenditures made by the seller related to the
properties acquired for the period between the effective date of the
transaction, July 1, 2003, and the closing date, October 15, 2003. The net
purchase price of $149 million was paid in cash and financed in part by cash on
hand and in part by borrowings under our revolving bank credit facility. The
properties are located primarily in the central Gulf of Mexico in less than 320
feet of water and include 21 blocks covering 86,237 gross (64,394 net) acres. As
of the October 15, 2003 closing date, proved reserves are an estimated 88.5
billion cubic feet of natural gas equivalent, of which 75% is natural gas.
Current production is from 11 fields and is estimated at approximately 35
million cubic feet of natural gas equivalent per day, net to our interest. We
will operate properties representing 97% of the proved reserves with an average
working interest of 65%.
Timothy R. Lindsey Joins as Vice President of Exploration
On September 30, 2003, Timothy R. Lindsey joined Houston Exploration in the
newly created position of Vice President of Exploration. Mr. Lindsey's primary
responsibilities involve assessing our current and future exploration programs
and evaluating new regions within the United States for us to consider for
expansion. Immediately prior to joining Houston Exploration, Mr. Lindsey worked
for more than 27 years in various capacities at Marathon Oil Company including
senior management roles in both domestic and international exploration and
business development. Most recently he was Marathon's International Exploration
Manager. Nearly 20 years of his career were spent focusing on domestic
operations in the Rocky Mountains, onshore Gulf Coast and offshore Gulf of
Mexico areas. Mr. Lindsey holds a bachelor's degree in geology from Eastern
Washington University and completed graduate studies in economic geology at the
University of Montana. In addition, he participated in the Advanced Management
Program at the Kellogg School of Management at Northwestern University and is a
member of the American Association of Petroleum Geologists.
Rocky Mountain Exploration
During the first nine months of 2003, we acquired approximately 165,000 net
undeveloped acres located in the Rocky Mountain region of the northwestern
United States. Over 90% of the acreage is located in southwestern Montana, the
Green River Basin of southwestern Wyoming and in the Uinta Basin of northeastern
Utah. In April 2003, we opened an
21
office in Denver, Colorado that is currently staffed by two people. During the
fourth quarter of 2003, we are planning to begin drilling a well to a depth of
8,500 feet in the Uinta Basin. As of September 30, 2003, we had incurred
approximately $10.8 million in leasehold acquisition costs related to the
acreage acquired.
Issuance of $175 Million 7% Notes due 2013 and Redemption of $100 Million 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 $170.4 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?% 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 $6.1 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. During the second quarter of 2003
and pursuant to the early redemption of the $100 million notes, we incurred debt
extinguishment expenses totaling $5.9 million ($3.9 million net of tax) 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 nine months ended
September 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.
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.
22
RESULTS OF OPERATIONS
The following table sets forth our summary operating and historical natural gas
and oil production data during the periods indicated:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- ------------------------
2003 2002 2003 2002
--------- ---------- ---------- ----------
SUMMARY OPERATING INFORMATION:
Operating revenues ............................. $ 118,887 $ 84,205 $ 368,522 $ 244,976
Operating expenses ............................. 69,856 58,745 209,004 170,606
Income from operations ......................... 49,031 25,460 159,518 74,370
Net income ..................................... 34,719 15,272 105,339 45,460
PRODUCTION:
Natural gas (MMcf)......................... 24,554 24,245 73,573 72,590
Oil (MBbls)................................ 331 218 916 600
Total (MMcfe).............................. 26,540 25,553 79,069 76,190
Average daily production (MMcfe/day)....... 288 278 290 279
AVERAGE SALES PRICES:
Natural gas (per Mcf) realized (1)......... $ 4.45 $ 3.23 $ 4.64 $ 3.17
Natural gas (per Mcf) unhedged............. 4.84 3.09 5.45 2.89
Oil (per Bbl) realized (1)................. 27.70 25.77 28.24 23.40
Oil (per Bbl) unhedged..................... 27.70 25.77 28.68 23.40
OPERATING EXPENSES (PER MCFE):
Lease operating............................ $ 0.39 $ 0.34 $ 0.42 $ 0.31
Severance tax.............................. 0.13 0.11 0.14 0.10
Transportation expense..................... 0.10 0.09 0.10 0.09
Depreciation, depletion and amortization... 1.78 1.66 1.78 1.63
Asset retirement accretion................. 0.03 -- 0.03 --
General and administrative, net............ 0.20 0.10 0.17 0.11
- -----------------------
(1) Reflects the effects of hedging.
RECENT FINANCIAL AND OPERATING RESULTS
COMPARISON OF THREE MONTHS ENDED SEPTEMBER 30, 2003 AND 2002
Production. Our production increased 4% from 25,553 million cubic feet
equivalent, or MMcfe, for the three months ended September 30, 2002 to 26,540
MMcfe for the three months ended September 30, 2003. Average daily production
was 288 MMcfe/day during the third quarter of 2003 compared to 278 MMcfe/day
during the third quarter of 2002.
Onshore, our daily production rates increased 10% from an average of 156
MMcfe/day during the third quarter of 2002 to an average of 172 MMcfe/day during
the corresponding three months of 2003. The increase in onshore production is
primarily attributable to 12 MMcfe/day in newly developed production in South
Texas and 6 MMcfe/day in newly developed production in the Arkoma Basin. In
total, average daily production of 172 MMcfe/day during the third quarter of
2003 was compared to average daily production of 173 MMcfe/day and 171
MMcfe/day, respectively, during the first and second quarter of 2003.
Offshore, our production decreased 5% from an average of 122 MMcfe/day
during the third quarter of 2002 to an average of 116 MMcfe/day during the third
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 third quarter of 2002
23
at Vermilion 408, East Cameron 81/84, East Cameron 82/83, Mustang Island 785,
South Timbalier 314/317, Eugene Island, Matagorda 682, East Cameron 280, High
Island 47 and West Cameron 284. 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.
For the third quarter of 2003, offshore production of 116 MMcfe/day decreased by
4% from 121 MMcfe/day during the second quarter of 2003 and was comparable to
first quarter of 115 MMcfe/day. The decrease was due in part to various
mechanical problems including a gravel pack failure at East Cameron 83 that
caused a loss of an estimated 7 MMcfe/day for the quarter.
Natural Gas and Oil Revenues. Natural gas and oil revenues increased 41%
from $83.9 million for the third quarter of 2002 to $118.4 million for the third
quarter of 2003 primarily as a result of a 38% increase in average realized
natural gas prices, from $3.23 per Mcf during the third quarter of 2002 to $4.45
per Mcf in the third quarter of 2003 and an increase in average realized oil
prices of 7% for the same period from $25.77 per barrel, or Bbl, to $27.70 per
Bbl, combined with a 52% increase in oil production during the current quarter.
Natural Gas Prices. As a result of hedging activities during the third
quarter of 2003, we realized an average gas price of $4.45 per Mcf, which was
92% of or $0.39 lower than the average unhedged natural gas price of $4.84 for
the period. As a result, natural gas and oil revenues for the three months ended
September 30, 2003 were $9.7 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 $3.5 million
of additional natural gas revenues, and, as a result, our average realized
natural gas price was $3.23 per Mcf, which was 105% or $0.14 greater than the
average unhedged natural gas price of $3.09 per Mcf.
Lease Operating Expenses and Severance Tax. Lease operating expenses
increased 17% from $8.7 million for the three months ended September 30, 2002 to
$10.2 million for the corresponding three months of 2003. On an Mcfe basis,
lease operating expenses increased 15% from $0.34 per Mcfe during the third
quarter of 2002 to $0.39 per Mcfe during the third 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 third quarter of 2002, we added approximately
133 new wells from exploration and development drilling. Ad valorem taxes have
increased due to rising onshore property value assessments, which is a function
of higher commodity prices. Year-over-year increases in well control insurance
premiums have also contributed to the increase in operating expenses, as did new
operations at South Timbalier 314/317, which 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. In addition, we continue to incur 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 third quarter of 2002 to
$3.5 million for the corresponding period of 2003. On an Mcfe basis, severance
tax increased 18% from $0.11 per Mcfe during the third quarter of 2002 to $0.13
per Mcfe during the third 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 third quarter of 2003 due to the 57% increase in average
wellhead prices for natural gas from $3.09 per Mcf during the third quarter of
2002 to $4.84 per Mcf during the third quarter of 2003 combined with a 10%
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 September 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 third quarter of 2003 increased 11% on an Mcfe basis from $0.09
during the third quarter of 2002 to $0.10 for the third quarter of 2003. For the
current quarter, the increase reflects an increase in volume, primarily in South
Texas and Arkoma, that is subject to transportation fee agreements.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 12% from $42.3 million for the three months ended
September 30, 2002 to $47.3 million for the three months ended September 30,
2003. Depreciation, depletion and amortization expense per Mcfe increased 7%
from $1.66 for the three months ended September 30, 2002 to $1.78 for the
corresponding three months in 2003. The increase in depreciation, depletion and
24
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 since the end
of the third quarter 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 143, "Asset Retirement Obligations," we incurred asset retirement accretion
expense of $0.8 million or $0.03 per Mcfe, during the third 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 100% from $2.7 million for the three months ended September
30, 2002 to $5.4 million for the three months ended September 30, 2003. These
amounts are net of COPAS overhead reimbursements received from other working
interest owners of $0.3 million during each of the three month-periods ended
September 30, 2002 and 2003, and capitalized general and administrative expenses
of $3.4 million and $3.1 million for the corresponding three-month periods of
2002 and 2003. Aggregate general and administrative expenses increased by $2.4
million or 38% from $6.4 million during the third quarter of 2002 to $8.8
million for the third 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 increases in our incentive compensation and stock
compensation expenses. In addition, our rent expense has increased as we
expanded our leased office space in downtown Houston to accommodate our growing
workforce. Our third quarter 2003 general and administrative expenses also
included a non-recurring charge of $0.8 million related to the settlement of a
litigation matter.
On an Mcfe basis, net general and administrative expenses increased 100%
from $0.10 during the third quarter of 2002 to $0.20 per Mcfe during the third
quarter of 2003. The higher rate per Mcfe during the third quarter of 2003
reflects the increase in our aggregate general and administrative expenses and a
9% decrease in capitalized expenses during the third 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 third quarter of 2003, Other Income and
Expense is comprised of income of $6.2 million ($4.0 million net of tax) related
to refunds and interest on those refunds of prior year's severance tax expense.
In July 2002, we applied for and received from the Railroad Commission of Texas
a "high-cost/tight-gas formation" designation for a portion of our South Texas
production. 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 is either exempt from tax or taxed at a reduced
rate until certain capital costs are recovered. For qualifying wells, we are
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 estimate that we could record additional
refunds of up to $1.2 million ($0.8 million net of tax). After September 1,
2003, all refunds will be in the form of a reduction to or credit against our
current severance tax liability rather than in the form of a cash reimbursement
from the State of Texas.
Interest Expense, Net of Capitalized Interest. Interest expense, net of
capitalized interest, decreased 17% from $2.3 million during the third quarter
of 2002 to $1.9 million during the third quarter of 2003. Aggregate interest
expense decreased from $4.2 million during the third quarter of 2002 to $3.9
million during the third quarter of 2003. Our average borrowings and interest
rates were $194.9 million and 7.2%, respectively, during the third quarter of
2003 compared to $264 million and 5.48% during the third 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 2.5% during
the third quarter of 2003 and 3.7% during the third quarter of 2002. Capitalized
interest for the third quarter of 2003 was $2.0 million compared to $1.9 million
for the corresponding three months of 2002.
Income Tax Provision. The provision for income taxes increased 130% from
$7.9 million for the third quarter of 2002 to $18.7 million for the third
quarter of 2003 due to the 137% increase in pre-tax income during the third
quarter of 2003 from $23.2 million during the third quarter of 2002 to $53.4
million during the third quarter of 2003. Pre-tax income is
25
higher as a result of the 41% increase in revenues, $6.2 million in other income
as a result of refunds of prior period severance tax and a 17% decrease in
interest expense offset in part by a 19% increase in operating expenses.
Operating Income and Net Income. For the three months ended September 30,
2003, the 38% increase in realized natural gas prices combined with the 4%
increase in production, offset in part by a 19% increase in operating expenses,
caused operating income to increase 93% from $25.5 million during the third
quarter of 2002 to $49.0 million during the third quarter of 2003.
Correspondingly, net income increased 127% from $15.3 million for the third
quarter of 2002 to $34.7 million for the third quarter of 2003.
COMPARISON OF NINE MONTHS ENDED SEPTEMBER 30, 2003 AND 2002
Production. Our production increased 4% from 76,190 million cubic feet
equivalent, or MMcfe, for the nine months ended September 30, 2002 to 79,069
MMcfe for the nine months ended September 30, 2003. Average daily production was
290 MMcfe/day during the three months of 2003 compared to 279 MMcfe/day during
the corresponding period of 2002.
Onshore, our daily production rates increased 15% from an average of 149
MMcfe/day during the first nine months of 2002 to an average of 172 MMcfe/day
during the corresponding nine 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 was unchanged at 33 MMcfe/day
during both the first nine months of 2002 and 2003.
Offshore, our production decreased 9% from an average of 130 MMcfe/day
during the first nine months of 2002 to an average of 118 MMcfe/day during the
first nine months 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 third quarter of
2002 at Vermilion 408, East Cameron 81/84, East Cameron 82/83, Mustang Island
785, High Island 38, and South Timbalier 314/317, Eugene Island 159, Matagorda
682, East Cameron 280, High Island 47 and West Cameron 284. 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 50%
from $244.2 million during the first nine months of 2002 to $367.2 million
during the first nine months of 2003 as a result of a 46% increase in average
realized natural gas prices, from $3.17 per Mcf during the first nine months of
2002 to $4.64 per Mcf in the first nine months of 2003 and an increase in
average realized oil prices of 21% for the same period from $23.40 per barrel,
or Bbl, to $28.24 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 nine
months of 2003, we realized an average natural gas price of $4.64 per Mcf, which
was 85% or $0.81 per Mcfe lower than average unhedged natural gas price of $5.45
for the period. As a result, natural gas and oil revenues for the nine months
ended September 30, 2003 were $59.7 million lower than the revenues we would
have achieved if hedges had not been in place during the period. For the
corresponding nine months of 2002, we realized an average gas price of $3.17 per
Mcf, which was 110% of the average unhedged natural gas price of $2.89 for the
period. This resulted in natural gas and oil revenues that were $20.5 million
higher than the revenues we would have achieved if hedges had not been in place
during the period.
Oil Prices. During the first nine months of 2003, we realized an average
oil price of $28.24 per Bbl, which was 98% or $0.44 per Bbl lower than the
average unhedged price of $28.68 per Bbl for the period. As a result, natural
gas and oil revenues for the nine months ended September 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 nine months
of 2002 and realized an average oil price of $23.40 per Bbl.
Lease Operating Expenses and Severance Tax. Lease operating expenses
increased 40% from $24.0 million for the nine months ended September 30, 2002 to
$33.5 million for the corresponding nine months of 2003. On an Mcfe basis, lease
operating expenses increased 35% from $0.31 per Mcfe during the first nine
months of 2002 to $0.42 per Mcfe during the first nine months 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
26
expenses are increasing as we add new wells and facilities and continue to
maintain production from existing properties. Since the end of the third quarter
of 2002, we added approximately 133 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 third quarter of 2002, we have 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 $7.3 million for the first nine months of
2002 to $11.0 million for the corresponding period of 2003. On an Mcfe basis,
severance tax increased from $0.10 per Mcfe for the first nine months of 2002 to
$0.14 per Mcfe during the first nine months of 2003. Partially offset by 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 nine months of 2003 due to the 89% increase in
average wellhead prices for natural gas from $2.89 during the first nine months
of 2002 to $5.45 during the first nine months of 2003 combined with a 15%
increase in onshore production for the first nine months 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 nine months ended
September 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 nine months of 2002 to $0.10
for the first nine months of 2003. The increase reflects an increase in volume,
primarily in South Texas and Arkoma, that is subject to transportation fee
agreements during 2003.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 13% from $124.2 million for the nine months ended
September 30, 2002 to $140.7 million for the nine months ended September 30,
2003. Depreciation, depletion and amortization expense per Mcfe increased 9%
from $1.63 for the nine months ended September 30, 2002 to $1.78 for the
corresponding nine months in 2003. The increase 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 and during the third quarter of 2003. 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 to our total proved reserve base.
Asset Retirement Accretion. Pursuant to our January 1, 2003 adoption of
SFAS 143, "Asset Retirement Obligations," we incurred asset retirement accretion
expense of $2.5 million, $0.03 per Mcfe, for the first nine 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 59% from $8.5 million for the nine months ended September 30,
2002 to $13.5 million for the nine months ended September 30, 2003. These
amounts are net of COPAS overhead reimbursements received from other working
interest owners of $1.2 million for each of the nine month periods ended
September 30, 2002 and 2003 and capitalized general and administrative expenses
of $9.8 million and $9.7 million for the respective periods. Aggregate general
and administrative expenses increased by $4.9 million or 25% from $19.5 million
for the first nine months of 2002 to $24.4 million for the first nine months of
2003. However, included in aggregate expense for the first nine months 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 nine months of 2003 would reflect a $5.8
million or 31% increase from the first nine months of 2002 and net general and
administrative expenses for the first nine months of 2003 would reflect a $5.9
million or 78% 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 increases in our incentive compensation and stock compensation
expenses. In addition, our rent expense has increased as we expanded our leased
office space in downtown Houston to accommodate our growing workforce. Our
legal, audit and accounting expenses increased as we implemented new corporate
governance policies and engaged an outside firm to perform internal auditing
functions. Finally, during the third quarter of 2003, we
27
incurred a non-recurring charge of $0.8 million relating to the settlement of a
litigation matter.
On an Mcfe basis, net general and administrative expenses increased 55%
from $0.11 during the first nine months of 2002 to $0.17 per Mcfe during the
first nine months of 2003. Without the non-recurring charges of $0.9 million
incurred in the first nine months of 2002 for employee severance payments, net
general and administrative expense per Mcfe would have increased by $0.07 per
Mcfe or by 70% from $0.10 in first nine months 2002 to $0.17 in the first nine
months of 2003. The higher rate per Mcfe during the first nine months of 2003
reflects the increase in our aggregate general and administrative expenses.
Other Income and Expense. For the first nine months of 2003, Other Income
and Expense includes two components: debt extinguishment expenses totaling $5.9
million ($3.9 million net of tax); and income of $19.1 million ($12.4 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 8 5/8% senior subordinated 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 is either exempt from tax or taxed at a reduced
rate until certain capital costs are recovered. For qualifying wells, we are
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 estimate that we could record additional
refunds of up to $1.2 million ($0.8 million net of tax). After September 1,
2003, all refunds will be in the form of a reduction to or credit against our
current severance tax liability rather than in the form of a cash reimbursement
from the State of Texas.
Interest Expense, Net of Capitalized Interest. Interest expense, net of
capitalized interest, increased 19% from $5.3 million for the first nine months
of 2002 to $6.3 million for the first nine months of 2003. Aggregate interest
expense was unchanged at $11.5 million during the first nine months of both 2002
and 2003. Our average borrowings and interest rates were $224.7 million and 6.3%
during the first nine months of 2002 compared to $258.7 million and 5.4% during
the first nine months 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 16% from $6.2
million for the first nine months of 2002 to $5.2 million for the first nine
months of 2003. Our capitalized interest is a function of unevaluated properties
and the decrease corresponds to the decrease in our unevaluated property balance
from $130.4 million at September 30, 2002 to $107.4 million at September 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 147% from
$23.6 million for the first nine months of 2002 to $58.3 million for the first
nine months of 2003 due to the 141% increase in pre-tax income from $69.1
million during the first nine months of 2002 to $166.4 million during the first
nine months of 2003. Pre-tax income is higher as a result of the 50% increase in
revenues and the $13.2 million in other income as a result of $19.1 million in
severance refunds offset by $5.9 million in debt extinguishment expenses. The
increase in revenues and other income was offset in part by a 23% increase in
operating expenses and a 19% increase in net interest expense.
Operating Income and Net Income. For the nine months ended September 30,
2003, the 46% increase in realized natural gas prices combined with the 4%
increase in production, offset in part by a 23% increase in operating expenses,
caused operating income to increase 114% from $74.4 million during the first
nine months of 2002 to $159.5 million during the first nine months of 2003.
Correspondingly, net income increased 131% from $45.5 million for the first nine
months of 2002 to $105.3 million for the first nine months 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
28
took advantage of lower interest rates and issued $175 million 7% senior
subordinated notes due June 2023 and called for early redemption our $100
million 8 5/8% senior subordinated notes due January 2008. We received $170.4
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 for use in the July 11, 2003 redemption 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 $6.1 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 September 30, 2003, we had working capital of $9.5
million and $299.6 million of borrowing capacity available under our revolving
bank credit facility. Net cash provided by operating activities for the first
nine months of 2003 was $298.1 million compared to $165 million during the first
nine months of 2002. The 81% increase in net cash provided by operating
activities was largely due to the increase in cash flows before changes in
operating assets and liabilities and was a result of an increase in operating
income caused by higher realized natural gas prices and an increase in
production volumes for the nine months ended September 30, 2003. The increase in
cash from operations was reduced in part by a net increase in operating assets
and liabilities. This increase was caused primarily by an increase in other
assets. The increase in other assets was due in part to an increase of $10.7
million in deferred tax assets and $5.3 million in premiums paid for derivative
instruments for 2004. 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 nine months of 2003 as compared to the first nine
months of 2002. For the first nine months of 2003, funds used in investing
activities consisted of $227.9 million for net cash investments in property and
equipment which includes a prepayment of $15.5 million on September 3, 2003 for
the acquisition of the Transworld producing properties which closed on October
15, 2003, which compares to a net $173.5 million expended during the first nine
months of 2002. Our cash position decreased during the first nine months of 2003
by $77 million as a result of the repayment of long-term borrowings. We issued
$175 million in 7% senior subordinated notes, redeemed $100 million in 8 5/8%
notes and repaid a net $152 million in borrowings under our revolving bank
credit facility. For the corresponding nine months of 2002, cash flow increased
by $3 million from incremental borrowings under our revolving bank credit
facility. During the current nine-month period, we incurred $4.6 million in
costs related to the issuance of the new $175 million 7% senior subordinated
notes. Cash increased by $6.7 million and $2.4 million, respectively, during the
first nine months 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 decreased $4.8 million from $18.0 million at December 31, 2002 to
$13.2 million at September 30, 2003.
Investments in Property and Equipment. During the first nine months of
2003, we invested $211.7 million in natural gas and oil properties and $0.9
million for other property and office equipment. During the nine months of 2003,
we completed the drilling of 110 gross wells (84.6 net) of which 83 (64.2 net)
were successful and 27 (20.4 net) were unsuccessful with an additional 14 wells
(10.0 net) in progress at the end to the quarter. Our investments in natural gas
and oil properties included $43.3 million in exploration costs, $122.9 million
in development costs and $45.5 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 nine months of both 2003 and 2002, we capitalized a total of $14.9 million
and $16.0 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 intend to spend
two-thirds of the increase in South Texas and the balance in the Arkoma Basin.
As of September 30, 2003, we had spent approximately 68% of our initial capital
expenditure budget of $312 million for 2003. We do not include property
acquisition costs in our 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 $4.6 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.
29
Revolving Bank Credit Facility. We maintain a revolving bank credit
facility with a syndicate of lenders led by Wachovia Bank, National Association,
as issuing bank and administrative agent, The Bank of Nova Scotia and Fleet
National Bank as co-syndication agents and BNP Paribas as documentation agent.
The credit facility provides us with a commitment of $300 million which may be
increased at our request and with prior approval from Wachovia to a maximum of
$350 million by adding one or more lenders or by allowing one or more lenders to
increase their commitments. The credit facility is subject to borrowing base
limitations. Our current borrowing base is $300 million and is redetermined
semi-annually, with the next redetermination scheduled for April 1, 2004. Up to
$25 million of the borrowing base is available for the issuance of letters of
credit. The credit facility matures July 15, 2005, is unsecured and with the
exception of trade payables, ranks senior to our 7% senior subordinated notes.
At September 30, 2003, we had no outstanding borrowings under our revolving
bank credit facility and $0.4 million in outstanding letter of credit
obligations. Subsequent to September 30, 2003, we borrowed a net $115 million
under our revolving bank credit facility. These borrowings were used to fund a
portion of the remaining purchase price of the Transworld properties on October
15, 2003. At November 10, 2003, the date of this report, outstanding borrowings
and letter of credit obligations under our revolving bank credit facility total
$115.4 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 the private placement 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 July 11, 2003 redemption of the $100 million
in aggregate principal and payment of the $4.3 million premium for early
redemption were funded with a portion of the proceeds received from the $175
million 7% senior subordinated notes. 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. During the
second quarter of 2003, and pursuant to the early redemption of the $100 million
notes, we incurred debt extinguishment expenses totaling $5.9 million ($3.9
million net of tax) 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 nine month period ended September 30, 2003.
Contractual Obligations and Other Commercial Commitments
The table below summarizes our contractual obligations and commercial
commitments at September 30, 2003. We have no "off-balance sheet" financing
arrangements.
AT SEPTEMBER 30, 2003
PAYMENTS DUE BY PERIOD
------------------------------------------------------------------
CONTRACTUAL OBLIGATIONS TOTAL < 1 YEAR 1 - 3 YEARS 4 - 5 YEARS AFTER 5 YEARS
- -------------------------------------------------------------------------------------------------------------------
(unaudited and $ in thousands)
Revolving bank credit facility............... $ -- $ -- $ -- $ -- $ --
7% senior subordinated notes, due June 2013.. 175,000 -- -- -- 175,000
Operating leases............................. 8,633 306 4,346 3,060 921
---------- -------- ----------- ----------- -------------
Total contractual obligations............ $ 183,633 $ 306 $ 4,346 $ 3,060 $ 175,921
========== ======== =========== =========== =============
30
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, that 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 nine month period from January 1 to September 30,
2003 and 2002, respectively. Stated amounts do not reflect the effects of taxes.
FOR THE NINE MONTH PERIOD
CHANGE IN FAIR VALUE OF DERIVATIVES INSTRUMENTS 2003 2002
- --------------------------------------------------------------------------------------------------
(unaudited and $in thousands)
Fair value of contracts at January 1............................... $ (38,772) $ 53,771
(Gain) loss on contracts realized.................................. 60,102 (20,515)
Fair value of new contracts when entered into during period........ 5,288 --
(Decrease) increase in fair value of all open contracts............ $ (38,919) (52,434)
----------- ----------
Fair value of contracts outstanding at September 30................ $ (12,301) $ (19,178)
=========== ==========
31
Natural Gas. The following table summarizes, on a monthly basis, our hedges
currently in place through December 31, 2005. For the remaining three months of
2003, we have hedged approximately 60% of our estimated production or a total of
190,000 million British thermal units per day or 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 71% of our estimated production or a total of 240,000
MMBtu/day. For the three months January through March 2004, our floor will
average $4.472/MMBtu on 240,000 MMBtu/day and our ceiling will average
$5.021/MMBtu on 140,000 MMBtu/day, with no ceiling on the remaining 100,000
MMBtu/day. For the remaining nine months of 2004, our floor will average
$4.264/MMBtu on 240,000 MMBtu/day and our ceiling will average $5.845/MMBtu on
240,000 MMBtu/day. For each calendar month of 2005, we have a fixed price swap
of 50,000 MMBtu/day at $4.766/MMBtu. 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 FLOORAVG CEILING
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 1,240 4.960 3,100 3.750 5.045
February 2004 2,900 5.000 1,160 4.960 2,900 3.750 5.045
March 2004 3,100 5.000 1,240 4.960 3,100 3.750 5.045
April 2004 1,200 4.960 6,000 4.125 6.023
May 2004 1,240 4.960 6,200 4.125 6.023
June 2004 1,200 4.960 6,000 4.125 6.023
July 2004 1,240 4.960 6,200 4.125 6.023
August 2004 1,240 4.960 6,200 4.125 6.023
September 2004 1,200 4.960 6,000 4.125 6.023
October 2004 1,240 4.960 6,200 4.125 6.023
November 2004 1,200 4.960 6,000 4.125 6.023
December 2004 1,240 4.960 6,200 4.125 6.023
January 2005 1,550 4.766
February 2005 1,450 4.766
March 2005 1,550 4.766
April 2005 1,500 4.766
May 2005 1,550 4.766
June 2005 1,500 4.766
July 2005 1,550 4.766
August 2005 1,550 4.766
September 2005 1,500 4.766
October 2005 1,550 4.766
November 2005 1,500 4.766
December 2005 1,550 4.766
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.
32
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.
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, 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 occurred during the most recent fiscal quarter that have
materially affected, or are reasonable likely to materially affect, our internal
controls over financial reporting.
33
PART II. OTHER INFORMATION.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K:
(a) Exhibits filed here with:
EXHIBITS DESCRIPTION
10.1 (1) -- Second Amendment to Credit Agreement among The Houston
Exploration Company, the lenders named therein, Wachovia Bank,
National Association, as issuing bank and as administrative
agent, The Bank of Nova Scotia and Fleet National Bank, as
co-syndication agents; and BNP Paribas, as documentation
agent, effective September 3, 2003.
10.2 -- Purchase and Sale Agreement, dated September 3, 2003, by
and among Transworld Exploration and Production, Inc., as
Seller, and The Houston Exploration Company, as Buyer (Exhibit
2.1 to Current Report on Form 8-K dated October 15, 2003 and
incorporated by reference).
10.3 (1)(2) -- Employment Agreement by and between The Houston Exploration
Company and Timothy R. Lindsey dated September 29, 2003.
31.1 (1) -- Certification of William G. Hargett, Chief Executive
Officer, as required pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 (1) -- Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
32.1 (1) -- Certification of William G. Hargett, Chief Executive
Officer, as required pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2 (1) -- Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
(1) Filed herewith.
(2) Management contract or compensation plan.
(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.
34
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?% senior subordinated
notes due January 2008.
Current Report on Form 8-K filed on August 6, 2003 required
and filed under Item 12 - Results of Operations and Financial
Conditions of our earnings release for the second quarter of
2003
Current Report on Form 8-K filed on September 11, 2003 to
provide information required by Item 5 - Other Events and
Regulation FD Disclosure of our press release issued on
September 11, 2003 announcing the purchase of producing oil
and gas properties from Transworld Exploration and Production
Inc.
Current Report on Form 8-K filed on October 29, 2003 to
provide information required by Item 2. - Acquisition or
Disposition of Assets of our completion of the acquisition of
the oil and natural gas properties from Transworld Exploration
and Production Inc. on October 15, 2003.
35
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned, hereunto duly authorized.
THE HOUSTON EXPLORATION COMPANY
By: /s/ WILLIAM G. HARGETT
--------------------------------------
Date: November 10, 2003 William G. Hargett
President and Chief Executive Officer
By: /s/ JOHN H. KARNES
--------------------------------------
Date: November 10, 2003 John H. Karnes
Senior Vice President and Chief
Financial Officer
By: /s/ JAMES F. WESTMORELAND
--------------------------------------
Date: November 10, 2003 James F. Westmoreland
Vice President and Chief Accounting
Officer
36
INDEX TO EXHIBITS
EXHIBITS DESCRIPTION
10.1 (1) -- Second Amendment to Credit Agreement among The Houston
Exploration Company, the lenders named therein, Wachovia Bank,
National Association, as issuing bank and as administrative
agent, The Bank of Nova Scotia and Fleet National Bank, as
co-syndication agents; and BNP Paribas, as documentation
agent, effective September 3, 2003.
10.2 -- Purchase and Sale Agreement, dated September 3, 2003, by
and among Transworld Exploration and Production, Inc., as
Seller, and The Houston Exploration Company, as Buyer (Exhibit
2.1 to Current Report on Form 8-K dated October 15, 2003 and
incorporated by reference).
10.3 (1)(2) -- Employment Agreement by and between The Houston Exploration
Company and Timothy R. Lindsey dated September 29, 2003.
31.1 (1) -- Certification of William G. Hargett, Chief Executive
Officer, as required pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 (1) -- Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
32.1 (1) -- Certification of William G. Hargett, Chief Executive
Officer, as required pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2 (1) -- Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
(1) Filed herewith.
(2) Management contract or compensation plan.