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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ________ TO ________
COMMISSION FILE NO. 001-11899
---------------------------------
THE HOUSTON EXPLORATION COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 22-2674487
(STATE OR OTHER JURISDICTION OF (IRS EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
1100 LOUISIANA STREET, SUITE 2000
HOUSTON, TEXAS 77002-5215
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES AND ZIP CODE)
(713) 830-6800
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
---------------------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Securities Exchange Act of 1934).
Yes [X] No [ ]
As of August 6, 2003, 31,078,668 shares of Common Stock, par value $.01
per share, were outstanding.
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THE HOUSTON EXPLORATION COMPANY
TABLE OF CONTENTS
Page
----
FACTORS AFFECTING FORWARD LOOKING STATEMENTS......................................................... 3
PART I. FINANCIAL INFORMATION....................................................................... 4
Item 1. Consolidated Financial Statements .......................................................... 4
CONSOLIDATED BALANCE SHEETS -- June 30, 2003 (unaudited) and December 31, 2002....................... 4
CONSOLIDATED STATEMENTS OF OPERATIONS -- Three Months and Six Months Ended
June 30, 2003 and 2002 (unaudited)....................................................... 5
CONSOLIDATED STATEMENTS OF CASH FLOWS -- Six Months Ended
June 30, 2003 and 2002 (unaudited)....................................................... 6
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)........................................... 7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations....... 19
Item 3. Quantitative and Qualitative Disclosures About Market Risk.................................. 33
Item 4. Controls and Procedures..................................................................... 35
PART II. OTHER INFORMATION.......................................................................... 35
Item 4. Submission of Matters to a Vote of Security Holders......................................... 35
Item 6. Exhibits and Reports on Form 8-K:........................................................... 36
(a) Exhibits:............................................................................. 36
(b) Reports on Form 8-K:.................................................................. 36
SIGNATURES........................................................................................... 37
2
FACTORS AFFECTING FORWARD LOOKING STATEMENTS
All of the estimates and assumptions contained in this Quarterly Report
constitute forward looking statements as that term is defined in Section 27A of
the Securities Act of 1993 and Section 21E of the Securities Exchange Act of
1934. These forward-looking statements generally are accompanied by words such
as "anticipate," "believe," "expect," "estimate," "project" or similar
expressions. All statements under the caption "Item 2. Management's Discussion
and Analysis of Financial Condition and Results of Operations" relating to our
anticipated capital expenditures, future cash flows and borrowings, pursuit of
potential future acquisition opportunities and sources of funding for
exploration and development are forward looking statements. Although we believe
that these forward-looking statements are based on reasonable assumptions, our
expectations may not occur and the anticipated future results may not be
achieved. A number of factors could cause our actual future results to differ
materially from the anticipated future results expressed in this Quarterly
Report. These factors include, among other things, the volatility of natural gas
and oil prices, the requirement to take writedowns if natural gas and oil prices
decline, our ability to meet our substantial capital requirements, our
substantial outstanding indebtedness, the uncertainty of estimates of natural
gas and oil reserves and production rates, our ability to replace reserves, and
our hedging activities. For additional discussion of these risks, uncertainties
and assumptions, see "Items 1. and 2. Business and Properties" and "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" contained in our Annual Report on Form 10-K.
In this Quarterly Report, unless the context requires otherwise, when
we refer to "we", "us" or "our", we are describing The Houston Exploration
Company and its subsidiary on a consolidated basis.
3
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
JUNE 30, DECEMBER 31,
2003 2002
----------- ------------
(UNAUDITED)
ASSETS:
Cash and cash equivalents ........................................................... $ 106,647 $ 18,031
Accounts receivable ................................................................. 111,134 81,313
Accounts receivable -- Affiliate .................................................... 7,448 3,106
Derivative financial instruments .................................................... 6,831 --
Inventories ......................................................................... 1,547 1,432
Prepayments and other ............................................................... 288 7,596
----------- -----------
Total current assets ........................................................... 233,895 111,478
Natural gas and oil properties, full cost method
Unevaluated properties ........................................................... 102,196 96,192
Properties subject to amortization ............................................... 2,005,380 1,828,160
Other property and equipment ........................................................ 11,420 10,699
----------- -----------
2,118,996 1,935,051
Less: Accumulated depreciation, depletion and amortization .......................... 995,718 912,637
----------- -----------
1,123,278 1,022,414
Derivative financial instruments .................................................... 4,878 --
Other non-current assets ............................................................ 7,659 4,924
----------- -----------
Other assets ................................................................... 12,537 4,924
TOTAL ASSETS ................................................................... $ 1,369,710 $ 1,138,816
=========== ===========
LIABILITIES:
Accounts payable and accrued expenses ............................................... $ 92,085 $ 78,175
Notes payable ....................................................................... 100,000 --
Derivative financial instruments .................................................... 54,361 35,005
Asset retirement obligation ......................................................... 4,510 --
----------- -----------
Total current liabilities ...................................................... 250,956 113,180
Long-term debt and notes ............................................................ 195,000 252,000
Derivative financial instruments .................................................... 9,928 3,767
Deferred federal income taxes ....................................................... 200,503 175,963
Asset retirement obligation ......................................................... 57,301 --
Other deferred liabilities .......................................................... 2,465 1,117
----------- -----------
TOTAL LIABILITIES .............................................................. 716,153 546,027
COMMITMENTS AND CONTINGENCIES (SEE NOTE 3)
STOCKHOLDERS' EQUITY:
Common Stock, $.01 par value, 50,000,000 shares authorized and 31,078,668 shares
issued and outstanding at June 30, 2003 and 30,954,018 shares
issued and outstanding at December 31, 2002, respectively ........................ 311 310
Additional paid-in capital .......................................................... 355,971 353,454
Unearned compensation ............................................................... (64) (107)
Retained earnings ................................................................... 334,954 264,334
Accumulated other comprehensive income .............................................. (37,615) (25,202)
----------- -----------
TOTAL STOCKHOLDERS' EQUITY ..................................................... 653,557 592,789
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ..................................... $ 1,369,710 $ 1,138,816
=========== ===========
The accompanying notes are an integral part of these consolidated financial
statements.
4
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
2003 2002 2003 2002
--------- --------- --------- ---------
(UNAUDITED) (UNAUDITED)
REVENUES: ............................................ (restated) (restated)
Natural gas and oil revenues ...................... $ 120,388 $ 85,588 $ 248,786 $ 160,210
Other ............................................. 244 367 849 561
--------- --------- --------- ---------
Total revenues .................................. 120,632 85,955 249,635 160,771
OPERATING EXPENSES:
Lease operating ................................... 11,669 7,886 23,315 15,299
Severance tax ..................................... 3,222 2,791 7,527 4,483
Transportation expense ............................ 2,696 2,227 5,188 4,403
Asset retirement accretion expense ................ 826 -- 1,652 --
Depreciation, depletion and amortization .......... 47,724 42,044 93,378 81,848
General and administrative, net ................... 4,204 2,488 8,088 5,828
--------- --------- --------- ---------
Total operating expenses ........................ 70,341 57,436 139,148 111,861
Income from operations ............................... 50,291 28,519 110,487 48,910
Other (income) expense ............................... 3,616 -- (6,962) --
Interest expense, net ................................ 2,160 1,644 4,426 3,054
--------- --------- --------- ---------
Income before income taxes ........................... 44,515 26,875 113,023 45,856
Provision for taxes .................................. 15,592 9,221 39,631 15,668
--------- --------- --------- ---------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE .............................. $ 28,923 $ 17,654 $ 73,392 $ 30,188
Cumulative effect of change in accounting principle .. -- -- (2,772) --
--------- --------- --------- ---------
NET INCOME ........................................... $ 28,923 $ 17,654 $ 70,620 $ 30,188
========= --------- ========= =========
EARNINGS PER SHARE:
NET INCOME PER SHARE - BASIC
Income before cumulative effect of change in
accounting principle ............................ $ 0.93 $ 0.58 $ 2.37 $ 0.99
Cumulative effect of change in accounting principle -- -- (0.09) --
--------- --------- --------- ---------
Net income per share -- basic ..................... $ 0.93 $ 0.58 $ 2.28 $ 0.99
========= ========= ========= =========
NET INCOME PER SHARE -- FULLY DILUTED
Income before cumulative effect of change in
accounting principle ............................ $ 0.93 $ 0.57 $ 2.36 $ 0.98
Cumulative effect of change in accounting principle -- -- (0.09) --
--------- --------- --------- ---------
Net income per share -- fully diluted ............. $ 0.93 $ 0.57 $ 2.27 $ 0.98
========= ========= ========= =========
Weighted average shares outstanding -- basic ......... 30,987 30,516 30,974 30,501
Weighted average shares outstanding -- fully diluted.. 31,095 30,854 31,082 30,846
The accompanying notes are an integral part of these consolidated financial
statements.
5
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
SIX MONTHS ENDED JUNE 30,
2003 2002
--------- ---------
(UNAUDITED)
OPERATING ACTIVITIES:
Net income ..................................................................... $ 70,620 $ 30,188
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and amortization ....................................... 93,378 81,848
Deferred income tax expense .................................................... 39,573 16,041
Asset retirement accretion expense ............................................. 1,652 --
Debt extinguishment expense .................................................... 1,626 --
Stock compensation expense ..................................................... 101 42
Cumulative effect of change in accounting principle ............................ 2,772 --
Changes in operating assets and liabilities:
Increase in accounts receivable ............................................. (34,163) (13,093)
Increase in inventories ..................................................... (115) (365)
Decrease in prepayments and other ........................................... 7,308 2,827
(Increase) decrease in other assets .......................................... (12,398) 4,125
Increase (decrease) in accounts payable and accrued expenses ................ 13,910 (14,098)
Increase (decrease) in other liabilities .................................... 1,348 458
--------- ---------
Net cash provided by operating activities ...................................... 185,612 107,973
INVESTING ACTIVITIES:
Investment in property and equipment ........................................... (138,348) (130,935)
Dispositions ................................................................... -- 261
--------- ---------
Net cash used in investing activities .......................................... (138,348) (130,674)
FINANCING ACTIVITIES:
Proceeds from long term borrowings ............................................. 228,000 46,000
Repayments of long term borrowings ............................................. (185,000) (10,000)
Debt issuance costs ............................................................ (4,108) --
Proceeds from issuance of common stock from exercise of stock options .......... 2,460 1,180
Proceeds from issuance of common stock ......................................... 79,200 --
Repurchase of common stock ..................................................... (79,200) --
--------- ---------
Net cash provided by financing activities ...................................... 41,352 37,180
--------- ---------
Increase in cash and cash equivalents .......................................... 88,616 14,479
Cash and cash equivalents, beginning of period ................................. 18,031 8,619
--------- ---------
Cash and cash equivalents, end of period ....................................... $ 106,647 $ 23,098
========= =========
SUPPLEMENTAL INFORMATION:
Cash paid for interest ......................................................... $ 6,439 $ 6,911
========= =========
Cash paid for taxes ............................................................ $ 10,900 $ --
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
6
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 1 -- SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Organization
We are an independent natural gas and oil company engaged in the
exploration, development, exploitation and acquisition of domestic natural gas
and oil properties. Our operations are primarily focused in South Texas,
offshore in the shallow waters of the Gulf of Mexico and in the Arkoma Basin of
Oklahoma and Arkansas with additional production located in East Texas, South
Louisiana and West Virginia.
Principles of Consolidation
The consolidated financial statements include the accounts of The
Houston Exploration Company and its wholly owned subsidiary, Seneca Upshur
Petroleum Company (collectively the "Company"). All intercompany balances and
transactions have been eliminated.
Interim Financial Statements
Our balance sheet at June 30, 2003 and the statements of operations and
cash flows for the periods indicated herein have been prepared without audit,
pursuant to the rules and regulations of the Securities and Exchange Commission.
Certain information and footnote disclosures normally included in financial
statements prepared in accordance with accounting principles generally accepted
in the United States ("GAAP") have been condensed or omitted, although we
believe that the disclosures contained herein are adequate to make the
information presented not misleading. The balance sheet at December 31, 2002 is
derived from the December 31, 2002 audited financial statements, but does not
include all disclosures required by GAAP. The financial statements included
herein should be read in conjunction with the Consolidated Financial Statements
and Notes thereto included in our Annual Report on Form 10-K for the year ended
December 31, 2002.
In the opinion of our management, all adjustments, consisting of normal
recurring accruals, necessary to present fairly the information in the
accompanying financial statements have been included. The results of operations
for such interim periods are not necessarily indicative of the results for the
full year.
Use of Estimates and Restatements
The preparation of the consolidated financial statements in conformity
with GAAP requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the dates of the financial statements and the reported
amounts of revenues and expenses during the reporting periods. Our most
significant financial estimates are based on remaining proved natural gas and
oil reserves. Estimates of proved reserves are key components of our depletion
rate for natural gas and oil properties and our full cost ceiling test
limitation.
For all periods presented, we applied Emerging Issues Task Force
("EITF") No. 00-10 "Accounting for Shipping and Handling Fees and Costs."
Pursuant to our application of EITF No. 00-10, transportation expenses
previously reflected as a reduction to natural gas and oil revenues for the
three months and six months ended June 30, 2002 were added back to revenues and
reflected as a separate component of operating expense and accordingly, the
Statement of Operations has been restated for the three month and six month
periods ended June 30, 2002. The application of EITF No. 00-10 has no effect on
income from operations or net income. The table below provides a summary of the
effects of application of EITF No. 00-10 for amounts reported in for the three
month and six month periods ended June 30, 2002.
7
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
----------------------- -----------------------
PREVIOUSLY PREVIOUSLY
RESTATED REPORTED RESTATED REPORTED
-------- ---------- -------- ----------
Natural gas and oil revenues ................ $ 85,588 $ 83,361 $160,210 $155,807
Total revenues .............................. 85,955 83,728 160,771 156,368
Transportation expenses ..................... 2,227 -- 4,403 --
Total operating expenses .................... 57,436 55,209 111,861 107,458
Income from operations ...................... 28,519 28,519 48,910 48,910
Net income .................................. 17,654 17,654 30,188 30,188
Natural gas price:
Average realized price (per Mcf) ............ $ 3.28 $ 3.19 $ 3.14 $ 3.05
Average unhedged price (per Mcf) ............ 3.28 3.19 2.79 2.70
Derivative Instruments
Our hedges are designated cash flow hedges and qualify for hedge
accounting under Statements of Financial Accounting Standards ("SFAS") No. 133,
as amended, "Accounting for Derivative Instruments and Hedging Activities" and
accordingly, we carry the fair market value of our derivative instruments on the
balance sheet as either an asset or liability and defer unrealized gains or
losses in accumulated other comprehensive income. Gains and losses are
reclassified from accumulated other comprehensive income to the income statement
as a component of natural gas and oil revenues in the period the hedged
production occurs. If any ineffectiveness occurs, amounts are recorded directly
to other income or expense.
8
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Net Income per Share
Basic earnings per share ("EPS") is calculated by dividing net income
by the weighted average number of shares of common stock outstanding during the
period. No dilution for any potentially dilutive securities is included. Diluted
EPS assumes and gives pro forma effect to the conversion of all potentially
dilutive securities and is calculated by dividing net income, as adjusted, by
the weighted average number of shares of common stock outstanding plus all
potentially dilutive securities.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
2003 2002 2003 2002
------- ------- ---------- -------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
NUMERATOR:
Income before cumulative effect of change
in accounting principle ............................... $28,923 $17,654 $ 73,392 $30,188
Cumulative effect of change in accounting principle ........ -- -- (2,772) --
------- ------- ---------- -------
Net income ................................................. $28,923 $17,654 $ 70,620 $30,188
======= ======= ========== =======
DENOMINATOR:
Weighted average shares outstanding ........................ 30,987 30,516 30,974 30,501
Add dilutive securities: Stock options ..................... 108 338 108 345
------- ------- ---------- -------
Total weighted average shares outstanding and
dilutive securities ................................... 31,095 30,854 31,082 30,846
======= ======= ========== =======
EARNINGS PER SHARE - BASIC:
Income before cumulative effect of change in
accounting principle .................................. $ 0.93 $ 0.58 $ 2.37 $ 0.99
Cumulative effect of change in accounting principle ........ -- -- (0.09) --
------- ------- ---------- -------
Net income per share - basic ............................... $ 0.93 $ 0.58 $ 2.28 $ 0.99
======= ======= ========== =======
EARNINGS PER SHARE - FULLY DILUTED:
Income before cumulative effect of change in
accounting principle .................................. $ 0.93 $ 0.57 $ 2.36 $ 0.98
Cumulative effect of change in accounting principle ........ -- -- (0.09) --
------- ------- ---------- -------
Net income per share - fully diluted ....................... $ 0.93 $ 0.57 $ 2.27 $ 0.98
======= ======= ========== =======
For the three months ended June 30, 2003 and 2002, the calculation of
shares outstanding for fully diluted EPS does not include the effect of
outstanding stock options to purchase 1,893,611 and 1,328,719 shares,
respectively, because the exercise price of these shares was greater than the
average market price for the year, which would have an antidulitive effect on
EPS. For the six month periods ended June 30, 2003 and June 30, 2002, fully
diluted EPS does not include the effect of outstanding stock options to purchase
1,898,559 shares and 1,292,234 shares, respectively, because inclusion would
have been antidulitive.
9
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Comprehensive Income
The table below summarizes our Comprehensive Income for the three month
and six month periods ended June 30, 2003 and 2002, respectively.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
2003 2002 2003 2002
-------- -------- -------- --------
(IN THOUSANDS)
Net income ...................................................... $ 28,923 $ 17,654 $ 70,620 $ 30,188
Other comprehensive income, net of taxes:
Unrealized gain (loss) on derivative instruments ............ 2,597 (2,157) (8,975) (35,724)
-------- -------- -------- --------
Comprehensive income ............................................ $ 31,520 $ 15,497 $ 61,645 $ (5,536)
======== ======== ======== ========
Stock Option Expense
On January 1, 2003, we adopted the fair value expense recognition
provisions of SFAS No. 123 "Accounting for Stock-Based Compensation" and as
amended by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition
and Disclosure." Under the fair value method, compensation expense for stock
options is recognized when stock options are issued. SFAS No. 148 proposes three
alternative transition methods for a voluntary change to the fair value method
under SFAS No. 123:
- Prospective Method - recognize fair value expense for all
awards granted in the year of adoption but not previous
awards;
- Modified Prospective Method - recognize fair value expense for
the unvested portion of all stock options granted, modified,
or settled since 1994 (i.e., the unvested portion of the prior
awards or those granted in the year of adoption must be
recorded using the fair value method); and
- Retroactive Restatement Method - similar to the Modified
Prospective Method except that all prior periods are restated.
We adopted SFAS No. 123 using the Prospective Method, and as a result,
we now recognize as compensation expense the fair value of all stock options
issued subsequent to December 31, 2002. For the three and six month periods
ended June 30, 2003, we recognized compensation expense of $44,000 and $58,000
for stock options granted during the period.
Prior to our January 1, 2003 adoption of SFAS No. 123, we accounted for
the incentive stock plans using the intrinsic value method prescribed under
Accounting Principles Board Opinion No. 25 and accordingly we did not recognize
compensation expense for stock options granted. Had stock options been accounted
for using the fair value method as recommended in SFAS No. 123, compensation
expense would have had the following pro forma effect on our net income and
earnings per share for the three month and six month periods ended June 30, 2003
and 2002.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
2003 2002 2003 2002
---------- ---------- ---------- ----------
Net income - as reported ..................................... $ 28,923 $ 17,654 $ 70,620 $ 30,188
Add: Stock-based compensation expense
included in net income, net of tax ................. 43 14 66 27
Less: Stock-based compensation expense using
fair value method, net of tax ...................... (1,102) (1,181) (2,189) (2,370)
---------- ---------- ---------- ----------
Net income - pro forma ....................................... $ 27,864 $ 16,487 $ 68,497 $ 27,845
========== ========== ========== ==========
Net income per share - as reported ........................... $ 0.93 $ 0.58 $ 2.37 $ 0.99
Net income per share - fully diluted - as reported ........... 0.93 0.57 2.36 0.98
Net income per share - pro forma ............................. $ 0.90 $ 0.54 $ 2.21 $ 0.91
Net income per share - fully diluted - pro forma ............. 0.90 0.53 2.20 0.90
10
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Asset Retirement Obligations
On January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations," which addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. For us, asset retirement obligations
represent the systematic, monthly accretion and depreciation of future
abandonment costs of tangible assets such as platforms, wells, service assets,
pipelines, and other facilities. SFAS No. 143 requires that the fair value of a
liability for an asset's retirement obligation be recorded in the period in
which it is incurred if a reasonable estimate of fair value can be made, and
that the corresponding cost is capitalized as part of the carrying amount of the
related long-lived asset. The liability is accreted to its then present value
each period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. Under our previous accounting method, we
included estimated future costs of abandonment and dismantlement in our full
cost amortization base and amortized these costs as a component of our depletion
expense.
Pursuant to the January 1, 2003 adoption of SFAS No. 143 we:
- recognized a charge to income during the first quarter of 2003
of $2.8 million, net of tax, for the cumulative effect of the
change in accounting principle;
- increased our total liabilities by $57.2 million to record the
asset retirement obligations ("ARO");
- increased our assets by $42.5 million to add the asset
retirement costs to the carrying amount of our natural gas and
oil properties; and
- reduced our accumulated depreciation, depletion and
amortization by $10.4 million for the amount of expense
previously recognized.
Adopting SFAS No. 143 had no impact on our reported cash flows. The
following table describes on a pro forma basis our asset retirement liability as
if SFAS No. 143 had been adopted on January 1, 2002. The ARO liability at June
30, 2003 and December 31, 2002 includes amounts classified as both current and
long-term.
2003 2002
------- -------
ARO liability at January 1, ....... $57,197 $45,759
Additions from drilling ........... 2,962 4,397
ARO accretion expense ............. 1,652 1,322
------- -------
ARO liability at June 30, ......... $61,811 $51,478
======= =======
The following table describes the pro forma effect on net income and
earnings per share for the three months and the six months ended June 30, 2002
as if SFAS No. 143 had been adopted on January 1, 2002.
Three Months Six Months
Ended Ended
June 30, 2002 June 30, 2002
------------ -------------
Net income - as reported ......................... $ 17,654 $ 30,188
Less: ARO accretion expense, net of tax .......... (430) (860)
---------- ----------
Net income - pro forma ........................... $ 17,224 $ 29,328
========== ==========
Earnings per share:
Basic - as reported .............................. $ 0.58 $ 0.99
Fully diluted - as reported ...................... 0.57 0.98
Basic - pro forma ................................ 0.56 0.96
Fully diluted - pro forma ........................ 0.56 0.95
11
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Recent Accounting Pronouncements
In April 2002, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 145, "Rescission of FASB Statements No. 4, No. 44, and No. 64,
Amendment to FASB Statement No. 13 and Technical Corrections." SFAS No. 145
streamlines the reporting of debt extinguishments and requires that only gains
and losses from extinguishments meeting the criteria in Accounting Policies
Board Opinion No. 30 would be classified as extraordinary. Thus, gains or losses
arising from extinguishments that are part of a company's recurring operations
would not be reported as an extraordinary item. SFAS No. 145 is effective for
fiscal years beginning after May 15, 2002. Our adoption of SFAS No. 145 on
January 1, 2003 had no effect on our financial statements.
In June 2002, FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" which addresses accounting and
reporting for costs associated with exit or disposal activities and nullifies
EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination
Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred
in a Restructuring)." SFAS No. 146 requires that a liability for a cost
associated with an exit or disposal activity be recognized when the liability is
incurred. Under Issue 94-3, a liability for an exit cost was recognized at the
date of an entity's commitment to an exit plan. Under SFAS No. 146, fair value
is the objective for initial measurement of the liability. SFAS No. 146 is
effective for exit or disposal activities that are initiated after December 31,
2002. Our adoption of SFAS No. 146 on January 1, 2003 had no effect on our
financial statements.
In November 2002, FASB issued Financial Interpretation ("FIN") No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others." FIN 45 requires certain
guarantees to be recorded at fair value, which is different from the current
practice of recording a liability only when a loss is probable and reasonably
estimable, as those terms are defined in SFAS No. 5, "Accounting for
Contingencies." FIN 45 has a dual effective date. The initial recognition and
measurement provisions are applicable on a prospective basis to guarantees
issued or modified after December 31, 2002. The disclosure requirements in the
interpretation are effective for financial statements for interim or annual
periods ending after December 15, 2002. As of our December 31, 2002 and March
31, 2003 balance sheet dates, we did not have any guarantees of indebtedness of
others and as a result, our adoption of FIN 45 did not have an effect on our
financial statements.
On April 30, 2003, FASB issued SFAS 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities," which amends and clarifies
accounting for derivative instruments, including certain derivative instruments
embedded in other contracts, and hedging activities under SFAS No. 133. The new
guidance amends SFAS 133 for decisions made:
- As a part of the Derivatives Implementation Group process that
effectively required amendments to SFAS 133;
- In connection with other FASB projects dealing with financial
instruments; and
- Regarding implementation issues raised in relation to the
application of the definition of a derivative, particularly
regarding the meaning of an "underlying" and the
characteristics of a derivative that contains financing
components.
The amendments set forth in SFAS 149 are intended to improve financial
reporting by requiring that contracts with comparable characteristics be
accounted for similarly. In particular, SFAS 149 clarifies the circumstances
under which a contract with an initial net investment meets the characteristics
of a derivative as discussed in SFAS 133. In addition, SFAS 149 clarifies when a
derivative contains a financing component that warrants special reporting is the
statement of cash flows. SFAS 149 amends certain other existing pronouncements,
resulting in more consistent reporting of contracts that are derivatives in
their entirely or that contain embedded derivatives that warrant separate
accounting.
SFAS 149 is effective for contracts entered into or modified after June
30, 2003, except as stated below, and for hedging relationships designated after
June 30, 2003. The guidance should be applied prospectively.
The provisions of SFAS 149 that relate to SFAS 133 Implementation
Issues that have been effective for fiscal quarters that began prior to June 15,
2003 should continue to be applied in accordance with their respective effective
dates. In addition, certain provisions relating to forward purchases or sales of
"when issued" securities or other securities that do not yet exist should be
applied to existing contracts as well as new contracts entered into after June
30, 2003. Our adoption of SFAS 149 will not have an effect on our financial
statements.
12
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
On May 15, 2003, FASB issued SFAS 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity,"
which aims to eliminate diversity in practice by requiring that the following
three types of "freestanding" financial instruments be reported as liabilities
by their issuers:
- Mandatorily redeemable instruments (i.e., instruments issued
in the form of shares that unconditionally obligate the issuer
to redeem the shares for cash or by transferring other
assets);
- Forward purchase contract, written put options, and other
financial instruments not in the form of shares that either
obligate or may obligate the issuer to repurchase its equity
shares and settle its obligation for cash or by transferring
other assets; and,
- Certain financial instruments that include an obligation that
(1) the issuer may or must settle by issuing a variable number
of its equity shares and (2) has a "monetary value" at
inception that (a) is fixed, (b) is tied to a market index or
other benchmark (something other than the fair value of the
issuer's equity shares), or (c) varies inversely with the fair
value of the equity shares (e.g., a written put option).
Until this pronouncement was issued, these types of instruments have
been variously presented by their issuers as liabilities, as part of equity, or
between the liabilities and equity sections (sometimes referred to as
"mezzanine" reporting) in the statement of financial position.
For our company, the provisions of SFAS 150, which also include a
number of new disclosure requirements, are effective for (1) instruments
interest into or modified after May 31, 2003 and (2) pre-existing instruments as
of the beginning of the first interim period that commences after June 15, 2003.
Our adoption of SFAS 150 has had no effect on our financial statements.
NOTE 2 -- LONG-TERM DEBT AND NOTES
JUNE 30, 2003 DECEMBER 31, 2002
------------- -----------------
(in thousands)
SENIOR DEBT:
Revolving bank credit facility, due July 2005 ............ $ 20,000 $152,000
SUBORDINATED DEBT:
8 5/8% Senior Subordinated Notes, due January 2008 ....... 100,000 100,000
7% Senior Subordinated Notes, due June 2013 .............. 175,000 --
-------- --------
Total debt and notes ............................... $295,000 $252,000
Less: amounts classified as current
8 5/8% Senior Subordinated Notes, called for redemption
July 11, 2003 ................................. 100,000 --
-------- --------
Total long-term debt and notes ..................... $195,000 $252,000
======== ========
The carrying amount of borrowings outstanding under the revolving bank
credit facility approximates fair value as the interest rates are tied to
current market rates. The market value of our $175 million 7% senior
subordinated notes issued June 10, 2003 was estimated at 100% of the carrying
value or $175 million. At June 30, 2003, the quoted market value of our $100
million of 8 5/8% senior subordinated notes was 104.715% of the $100 million
carrying value or $104.7 million as a result of our announcement on June 10,
2003 to call for early redemption the 8 5/8% notes. The premium for early
redemption of 4.313% or $4.3 million was paid on July 11, 2003.
Revolving Bank Credit Facility
We maintain a revolving bank credit facility with a syndicate of
lenders led by Wachovia Bank, National Association, as issuing bank and
administrative agent, The Bank of Nova Scotia and Fleet National Bank as
co-syndication agents and BNP Paribas as documentation agent. The credit
facility provides us with a commitment of $300 million which may be increased at
our request and with prior approval from Wachovia to a maximum of $350 million
by adding one or more lenders or by allowing one or more lenders to increase
their commitments. The credit facility is subject to borrowing base
13
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
limitations. Our current borrowing base is $300 million and is redetermined
semi-annually, with the next redetermination scheduled for October 1, 2003. Up
to $25 million of the borrowing base is available for the issuance of letters of
credit. The credit facility matures July 15, 2005, is unsecured and with the
exception of trade payables, ranks senior to all of our existing debt. At June
30, 2003, $20 million in borrowings were outstanding under the credit facility
and $9.4 million was outstanding in letter of credit obligations. Subsequent to
June 30, 2003, we repaid all outstanding borrowings of $20 million under our
revolving bank credit facility and we reduced our letter of credit obligations
to $0.4 million. As of the date of this report, outstanding borrowings and
letter of credit obligations under our revolving bank credit facility total $0.4
million.
Interest is payable on borrowings under our revolving bank credit
facility, as follows:
- on base rate loans, at a fluctuating rate, or base rate, equal
to the sum of (a) the greater of the Federal funds rate plus
0.5% or Wachovia's prime rate plus (b) a variable margin
between 0% and 0.50%, depending on the amount of borrowings
outstanding under the credit facility, or
- on fixed rate loans, a fixed rate equal to the sum of (a) a
quoted LIBOR rate divided by one minus the average maximum
rate during the interest period set for certain reserves of
member banks of the Federal Reserve System in Dallas, Texas
plus (b) a variable margin between 1.25% and 2.00%, depending
on the amount of borrowings outstanding under the credit
facility.
Interest is payable on base rate loans on the last day of each calendar quarter.
Interest on fixed rate loans is generally payable at maturity or at least every
90 days if the term of the loan exceeds three months. In addition to interest,
we must pay a quarterly commitment fee of between 0.30% and 0.50% per annum on
the unused portion of the borrowing base.
Our revolving bank credit facility contains negative covenants that
place restrictions and limits on, among other things, the incurrence of debt,
guaranties, liens, leases and certain investments. The credit facility also
restricts and limits our ability to pay cash dividends, to purchase or redeem
our stock and to sell or encumber our assets. Financial covenants require us to,
among other things:
- maintain a ratio of earnings before interest, taxes,
depreciation, depletion and amortization ("EBITDA") to cash
interest payments of at least 3.00 to 1.00;
- maintain a ratio of total debt to EBITDA of not more than 3.50
to 1.00; and
- not hedge more than 70% of our natural gas production during
any 12-month period.
As of June 30, 2003 and December 31, 2002, we were in compliance with all
covenants.
Senior Subordinated Notes
7% Senior Subordinated Notes due June 15, 2013. On June 10, 2003, we
issued $175 million of 7% senior subordinated notes due June 15, 2013. The notes
bear interest at a rate of 7% per annum with interest payable semi-annually on
June 15 and December 15, beginning December 15, 2003. We may redeem the notes at
our option, in whole or in part, at any time on or after June 15, 2008 at a
price equal to 100% of the principal amount plus accrued and unpaid interest, if
any, plus a specified premium which decreases yearly from 3.5% in 2008 to 0% in
2011 and thereafter. In addition, at any time prior to June 15, 2006, we may
redeem up to a maximum of 35% of the aggregate principal amount with the net
proceeds of one or more equity offerings at a price equal to 107% of the
principal amount, plus accrued and unpaid interest and liquidated damages, if
any. The notes are general unsecured obligations and rank subordinate in right
of payment to all existing and future senior debt, including the revolving bank
credit facility, and will rank senior or equal in right of payment to all
existing and future subordinated indebtedness.
The indenture governing the notes contains covenants that, among other
things, restrict or limit:
- incurrence of additional indebtedness and issuance of
preferred stock;
- repayment of certain other indebtedness;
- payment of dividends or certain other distributions;
- investments and repurchases of equity;
- use of the proceeds of assets sales;
- transactions with affiliates;
- liens;
14
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
- merger or consolidation and sales or other dispositions of all
or substantially all of our assets;
- entering into agreements that restrict the ability of our
subsidiary to make certain distributions or payments; or
- guarantees by our subsidiary of certain indebtedness.
In addition, upon the occurrence of a change of control, we will be
required to offer to purchase the notes at a purchase price equal to 101% of the
aggregate principal amount, plus accrued and unpaid interest and liquidated
damages, if any.
A "change of control" is:
- the direct or indirect acquisition by any person, other than
KeySpan or its affiliates, of beneficial ownership of 35% or
more of total voting power as long as KeySpan and its
affiliates own less than the acquiring person;
- the sale, lease, transfer, conveyance or other disposition,
other than by way of merger or consolidation, in one or a
series of related transactions, of all or substantially all of
our assets to a third party other than KeySpan or its
affiliates;
- the adoption of a plan relating to our liquidation or
dissolution; or
- if, during any period of two consecutive years, individuals
who at the beginning of the period constituted our board of
directors, including any new directors who were approved by a
majority vote of directors then in office who were either
directors at the beginning of the two-year period or who were
previously so approved, cease for any reason to constitute a
majority of the members then in office.
Pursuant to a registration rights agreement relating to the notes among
us and the initial purchasers, we have agreed to:
- file a registration statement with the SEC with respect to an
offer to exchange the notes for new notes issued in a
registered offering which will have terms identical in all
material respects to the notes, except that the registered
notes will not contain terms with respect to transfer
restrictions or payment of liquidated damages, within 90 days
following the original issue date of the notes;
- use or reasonable best efforts to cause the exchange offer
registration statement to become effective under the
Securities Act of 1934 within 180 days after June 10, 2003,
the original issue date of the notes, and ;
- use or reasonable best efforts to complete the exchange offer
with 30 business days after the SEC declares the exchange
offer registration statement effective.
We received $170.9 million in net proceeds from the issuance of the
$175 million 7% senior subordinated notes. A portion of the net proceeds was
used to repay the aggregate principal of $100 million on the 8 5/8% senior
subordinated notes together with a premium of $4.3 million for early redemption.
The remaining portion of the net proceeds was used to repay $60 million in
outstanding borrowings on our revolving bank credit facility with the balance of
approximately $6.6 million being applied to working capital, a portion of which
was utilized in July to fund the payment of $4.6 million in accrued interest due
on the $100 million 8 5/8% notes.
8 5/8% Senior Subordinated Notes due January 1, 2008. On July 11, 2003,
we redeemed our $100 million 8 5/8% senior subordinated notes due January 1,
2008. The $100 million 8 5/8% senior subordinated notes were issued on March 2,
1998. The notes bore interest at a rate of 8 5/8% per annum with interest
payable semi-annually on January 1 and July 1. The $100 million 8 5/8% notes
were redeemable, at our option, in whole or in part, at any time on or after
January 1, 2003 at a price equal to 100% of the principal amount plus accrued
and unpaid interest, if any, plus a specified premium which decreases yearly
from 4.313% in 2003 to 0% in 2006. The redemption and payment of the call
premium were funded with a portion of the proceeds received from our June 10,
2003 private placement of the $175 million 7% senior subordinated notes due June
15, 2013. Upon closing of the private placement of the $175 million 7% senior
subordinated notes on June 10, 2003, the $100 million 8 5/8% notes were called.
At June 30, 2003 and pursuant to the early redemption of the $100 million notes,
we incurred debt extinguishment expenses totaling $5.9 million ($3.9 million net
of tax) consisting of the call premium of $4.3 million together with a non-cash
charge of $1.6 million for the write-off of the balance of the unamortized issue
costs. The debt extinguishment expenses of $5.9 million are included in the line
item "Other (Income) Expense" on the Statement of Operations for the three and
the six months ended June 30, 2003.
15
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 3 -- COMMITMENTS AND CONTINGENCIES
Severance Tax Refund
During July 2002, we applied for and received from the Railroad
Commission of Texas a "high-cost/tight-gas formation" designation for a portion
of our South Texas production. The "high-cost/tight-gas formation" designation
will allow us to receive an abatement of severance taxes for qualifying wells in
various fields. For qualifying wells, production will be either exempt from tax
or taxed at a reduced rate until certain capital costs are recovered. For
qualifying wells, we will also be entitled to a refund of severance taxes paid
during a designated prior 48-month period. Applications for refund are submitted
on a well-by-well basis to the State Comptroller's Office and due to timing of
the acceptance of applications, we are unable to project the 48-month look-back
period for qualifying refunds. We currently estimate that the total refund will
be between $18 million to $24.5 million ($12 million to $15.9 million, net of
tax), although we can provide no assurances that the actual total refund amount
will fall within our current estimate. Since the beginning of the fourth quarter
of 2002, we have recorded refunds totaling $23.3 million ($15.1 million net of
tax). Refunds recorded during 2003 total $12.9 million ($8.4 million net of tax)
of which $2.3 million ($1.5 million net of tax) were recorded during the second
quarter. Currently, we estimate that we could record additional refunds of up to
$1.2 million ($0.8 million net of tax). Our receivables at June 30, 2003 include
$28.2 million in gross refunds of which approximately $19.4 million relates to
our working interest with the balance owed to third party royalty interests.
Subsequent to June 30, 2003, we received a check from the State of Texas for
$19.7 million that will be applied to the receivable for severance tax refunds.
Legal Proceedings
On August 18, 2002, a complaint styled Victor Ramirez, Santiago
Ramirez, Jr., Oswaldo H. Ramirez and Javier Ramirez as Co-Trustees of the
Ramirez Mineral Trust v. The Houston Exploration Company, cause number 5,207,
was filed in the district court of the 49th Judicial District in Zapata County,
Texas. The complaint alleges that we trespassed by drilling the No. 7 RMT well
to a depth in excess of our lease rights and commingled production by producing
from the excess depth. The plaintiffs claim damages for trespass and conversion
in excess of $6 million and further seek to recover exemplary damages in excess
of $18 million. We are currently unable to predict the outcome of the claim.
We are involved from time to time in various other claims and lawsuits
incidental to our business. In the opinion of management, the ultimate
liability, if any, in these other matters will not have a material adverse
effect on our financial position or results of operations.
NOTE 4 -- RELATED PARTY TRANSACTIONS
Issuance of 3,000,000 Shares to the Public and Concurrent Repurchase of
3,000,000 Shares from KeySpan
In connection with our initial public offering in September 1996, we
entered into a registration rights agreement with KeySpan pursuant to which we
are obligated, at KeySpan's election, to facilitate KeySpan's sale of its shares
of Company stock by registering the shares under the Securities Act of 1933 and
assisting in KeySpan's selling efforts. During February of 2003, KeySpan
notified us of its desire to sell 3,000,000 shares of their Company stock. For
the mutual convenience of the parties, we elected to effect KeySpan's sale
through our pre-existing registration statement rather than filing a separate,
new registration statement for KeySpan. To accomplish the transaction, we
simultaneously sold 3,000,000 newly issued shares of Company stock in a public
offering for net proceeds of $26.40 per share, or an aggregate $79.2 million,
and bought a like number of KeySpan's shares of Company stock for the same price
per share. We cancelled the 3,000,000 shares acquired from KeySpan immediately
following the repurchase. KeySpan reimbursed us for all costs and expenses, and
the transaction had no impact on our capitalization. The transaction was
evidenced in a stock purchase agreement, dated February 26, 2003. Our Board of
Directors approved the transaction in principle and delegated to a special,
independent committee of the Board plenary authority to negotiate the terms of,
and finally approve or veto, the transaction. In finally approving the terms of
the stock purchase agreement, the independent committee determined that the
agreement was consistent with our pre-existing obligations under our
registration rights agreement and that issuing the shares under our existing
registration statement was in the best interests of our public stockholders to
facilitate the prompt and orderly disposition of the shares. As a result of the
transactions, KeySpan's interest in our outstanding shares decreased from 66% to
56%.
16
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Acquisition of KeySpan Joint Venture Assets
In October 2002, we purchased from KeySpan a portion of the assets
developed under the joint exploration agreement with KeySpan Exploration &
Production, LLC, a subsidiary of KeySpan (see below discussion of KeySpan Joint
Venture). The acquisition consisted of interests averaging between 11.25% and
45% in 17 wells covering eight of the twelve blocks that were developed under
the joint exploration agreement from 1999 through 2002. The interests purchased
were in the following blocks: Vermilion 408, East Cameron 81 and 84, High Island
115, Galveston Island 190 and 389, Matagorda Island 704 and North Padre Island
883. KeySpan has retained its 45% interest in four blocks: South Timbalier 314
and 317 and Mustang Island 725 and 726 as these blocks are in various stages of
development. KeySpan has committed to continued participation in the ongoing
development of these blocks which includes the completion of the platform and
production facilities at South Timbalier 314/317 together with possible further
developmental drilling at both South Timbalier 314/317 and Mustang Island
725/726. As of September 1, 2002, the effective date of the purchase, the
estimated proved reserves associated with the interests acquired were 13.5 Bcfe.
The $26.5 million purchase price was paid in cash and financed with borrowings
under our revolving credit facility. Subsequent purchase price adjustments
totaled $1.2 million. Our acquisition of the properties was accounted for as a
transaction between entities under common control. As a result, the excess fair
value of the properties acquired of $3.1 million ($2.0 million net of tax) was
treated as a capital contribution from KeySpan and recorded as an increase to
additional paid-in capital during the fourth quarter of 2002.
Our Board of Directors appointed a special committee, comprised
entirely of independent directors, to review the proposed transaction with
KeySpan. For assistance, the special committee retained special outside legal
counsel as well as the financial advisory firm of Petrie Parkman & Co. In
addition, the special committee discussed the history and terms of the
transaction with our senior management. After completing its review, the special
committee unanimously concluded that the transaction was advisable and in our
best interests and that the terms of the transaction were at least as favorable
to us as terms that would have been obtainable at the time in a comparable
transaction with an unaffiliated party. In reaching its decision, the special
committee considered numerous factors in consultation with its financial and
legal advisors. The special committee also took into account the opinion
delivered to it by Petrie Parkman & Co. to the effect that the consideration to
be paid by us in the transaction was fair to us from a financial point of view.
KeySpan Joint Venture
Effective January 1, 1999, we entered into a joint exploration
agreement with KeySpan Exploration & Production, LLC, a subsidiary of KeySpan,
to explore for natural gas and oil over an initial two-year term expiring
December 31, 2000. Under the terms of the joint venture, we contributed all of
our then undeveloped offshore acreage to the joint venture and we agreed that
KeySpan would receive 45% of our working interest in all prospects drilled under
the program. KeySpan paid 100% of actual intangible drilling costs for the joint
venture up to a specified maximum. Further, KeySpan paid 51.75% of all
additional intangible drilling costs incurred and we paid 48.25%. Revenues are
shared 55% to Houston Exploration and 45% to KeySpan.
Effective December 31, 2000, KeySpan and Houston Exploration agreed to
end the primary or exploratory term of the joint venture. As a result, KeySpan
has not participated in any of our offshore exploration prospects unless the
project involved the development or further exploitation of discoveries made
during the initial term of the joint venture. During the first half 2003,
KeySpan spent approximately $6.8 million, of which $3.8 million was spent during
the second quarter, for capital costs associated with its working interests in
properties developed under the joint venture. Costs incurred during 2003 were
related to the installation of production facilities at South Timbalier 314/317
and the completion of the initial two exploratory wells that were brought
on-line during the first quarter of 2003. In addition, during the second quarter
of 2003, KeySpan participated in the drilling of a third well on the property.
During the corresponding six month and three month periods of 2002, KeySpan
spent $14.6 million and $5.1 million, respectively.
Sale of Section 29 Tax Credits
In June 2003, we repurchased, for $2.6 million, certain interests in
producing wells that were sold in January 1997 to a subsidiary of KeySpan under
an agreement designed to monetize tax credits available under Section 29 of the
Internal Revenue Code. Section 29 provides for a tax credit from
non-conventional fuel sources such as oil produced from shale and tar sands and
natural gas produced from geopressured brine, Devonian shale, coal seams and
tight sands formations. The wells subject to the agreement are located in West
Virginia, Oklahoma and East Texas and produce from formations that qualify for
Section 29 tax credits. Pursuant to the agreement, KeySpan acquired an economic
interest in wells that qualified for the tax credits and, in exchange, we:
17
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
- retained a volumetric production payment and a net profits
interest of 100% in the properties;
- received a cash down payment of $1.4 million; and
- receive a quarterly payment of $0.75 for every dollar of tax
credit utilized.
During the term of the agreement, we managed and administered the daily
operations of the properties in exchange for an annual management fee of
$100,000. The agreement expired December 31, 2002 and as a result, we were
required to repurchase the interests in the producing wells from KeySpan.
Subsequent to the repurchase, ownership of the tax credits reverted back to us.
The income statement effect, representing benefits received from Section 29 tax
credits, was a benefit of $0.2 million and $0.3 million, respectively for the
three month and six month periods ended June 30, 2002, with no benefit for 2003.
18
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion is intended to assist in an understanding of
our historical financial position and results of operations for the three months
and the six months ended June 30, 2003 and 2002. Please refer to our
consolidated financial statements and notes thereto included elsewhere in this
report for more detailed information in conjunction with the following
discussion.
GENERAL
We are an independent natural gas and oil company engaged in the
exploration, development, exploitation and acquisition of domestic natural gas
and oil properties. Our operations are primarily focused in South Texas,
offshore in the shallow waters of the Gulf of Mexico and in the Arkoma Basin of
Oklahoma and Arkansas with additional production located in East Texas, South
Louisiana and West Virginia.
At December 31, 2002, our net proved reserves were 650 billion cubic
feet equivalent, or Bcfe, with a present value, discounted at 10% per annum, of
cash flows before income taxes of $1.3 billion. Our reserves are fully
engineered on an annual basis by independent petroleum engineers. Our focus is
natural gas. Approximately 94% of our net proved reserves at December 31, 2002
were natural gas, approximately 69% of which were classified as proved
developed. We operate approximately 85% of our properties.
We began exploring for natural gas and oil in December 1985 on behalf
of The Brooklyn Union Gas Company. Brooklyn Union is an indirect wholly owned
subsidiary of KeySpan Corporation. KeySpan, a member of the Standard & Poor's
500 Index, is a diversified energy provider whose principle natural gas
distribution and electric generation operations are located in the Northeastern
United States. In September 1996, we completed our initial public offering and
sold approximately 34% of our shares to the public, with KeySpan retaining the
balance. As of June 30, 2003, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 56% of the outstanding shares of our
common stock.
As an independent oil and gas producer, our revenue, profitability and
future rate of growth are substantially dependent upon prevailing prices for
natural gas and oil, our ability to find and produce natural gas and oil and our
ability to control and reduce costs, all of which are dependent upon numerous
factors beyond our control, such as economic, political and regulatory
developments and competition from other sources of energy. The energy markets
have historically been very volatile and commodity prices may fluctuate widely
in the future. A substantial or extended decline in natural gas and oil prices
or poor drilling results could have a material adverse effect on our financial
position, results of operations, cash flows, quantities of natural gas and oil
reserves that may be economically produced and access to capital.
Critical Accounting Policies and Use of Estimates
Revenue Recognition and Gas Imbalances. We use the entitlements method
of accounting for the recognition of natural gas and oil revenues. Under this
method of accounting, income is recorded based on our net revenue interest in
production or nominated deliveries. We incur production gas volume imbalances in
the ordinary course of business. Net deliveries in excess of entitled amounts
are recorded as liabilities, while net under deliveries are reflected as assets.
Imbalances are reduced either by subsequent recoupment of over-and under
deliveries or by cash settlement, as required by applicable contracts.
Derivative Instruments. Our hedges are designated cash flow hedges and
qualify for hedge accounting under Statement of Financial Accounting Standards
("SFAS") No. 133, as amended, "Accounting for Derivative Instruments and Hedging
Activities" and, accordingly, we carry the fair market value of our derivative
instruments on the balance sheet as either an asset or liability and defer
unrealized gains or losses in accumulated other comprehensive income. Gains and
losses are reclassified from accumulated other comprehensive income to the
income statement as a component of natural gas and oil revenues in the period
the hedged production occurs. If any ineffectiveness occurs, amounts are
recorded directly to other income or expense.
Full Cost Accounting. We use the full cost method to account for our
natural gas and oil properties. Under full cost accounting, all costs incurred
in the acquisition, exploration and development of natural gas and oil reserves
are capitalized into a "full cost pool." Capitalized costs include costs of all
unproved properties, internal costs directly related to our natural gas and oil
activities and capitalized interest. We amortize these costs using a
unit-of-production method. We compute the provision for depreciation, depletion
and amortization quarterly by multiplying production for the quarter by a
19
depletion rate. The depletion rate is determined by dividing our total
unamortized cost base by net equivalent proved reserves at the beginning of the
quarter. Our total unamortized cost base is the sum of our:
- full cost pool; plus,
- estimates for future development costs; less,
- unevaluated properties and their related costs; less,
- estimates for salvage.
Costs associated with unevaluated properties are excluded from the amortization
base until we have made a determination as the existence of proved reserves. We
review our unevaluated properties at the end of each quarter to determine
whether the costs incurred should be reclassified to the full cost pool and
thereby subject to amortization. Sales of natural gas and oil properties are
accounted for as adjustments to the full cost pool, with no gain or loss
recognized, unless the adjustment would significantly alter the relationship
between capitalized costs and proved reserves.
Under full cost accounting rules, total capitalized costs are limited
to a ceiling equal to the present value of future net revenues, discounted at
10% per annum, plus the lower of cost or fair value of unproved properties less
income tax effects (the "ceiling limitation"). We perform a quarterly ceiling
test to evaluate whether the net book value of our full cost pool exceeds the
ceiling limitation. If capitalized costs (net of accumulated depreciation,
depletion and amortization) less deferred taxes are greater than the discounted
future net revenues or ceiling limitation, a writedown or impairment of the full
cost pool is required. A writedown of the carrying value of the full cost pool
is a non-cash charge that reduces earnings and impacts stockholders' equity in
the period of occurrence and typically results in lower depreciation, depletion
and amortization expense in future periods. Once incurred, a writedown is not
reversible at a later date.
The ceiling test is calculated using natural gas and oil prices in
effect as of the balance sheet date, held constant over the life of the
reserves. We use derivative financial instruments that qualify for hedge
accounting under SFAS No. 133 to hedge against the volatility of natural gas
prices, and in accordance with current Securities and Exchange Commission
guidelines, we include estimated future cash flows from our hedging program in
our ceiling test calculation. In calculating our ceiling test at June 30, 2003
and December 31, 2002, we estimated that we had a full cost ceiling "cushion",
whereby the carrying value of our full cost pool was less than the ceiling
limitation. No writedown is required when a cushion exists. Natural gas prices
continue to be volatile and the risk that we will be required to write down our
full cost pool increases when natural gas prices are depressed or if we have
significant downward revisions in our estimated proved reserves.
Use of Estimates. The preparation of the consolidated financial
statements in conformity with accounting principles generally accepted in the
United States of America ("GAAP") requires our management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the dates of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Our most significant financial estimates are based on
remaining proved natural gas and oil reserves. Estimates of proved reserves are
key components of our depletion rate for natural gas and oil properties and our
full cost ceiling limitation.
Natural gas and oil reserve quantities represent estimates only. Under
full cost accounting, we use reserve estimates to determine our full cost
ceiling limitation as well as our depletion rate. We estimate our proved
reserves and future net revenues using sales prices estimated to be in effect as
of the date we make the reserve estimates. We hold the estimates constant
throughout the life of the properties, except to the extent a contract
specifically provides for escalation. Natural gas prices, which have fluctuated
widely in recent years, affect estimated quantities of proved reserves and
future net revenues. Further, any estimates of natural gas and oil reserves and
their values are inherently uncertain for numerous reasons, including many
factors beyond our control. Reservoir engineering is a subjective process of
estimating underground accumulations of natural gas and oil that cannot be
measured in an exact manner. The accuracy of any reserve estimate is a function
of the quality of available data and of engineering and geological
interpretation and judgment. In addition, estimates of reserves may be revised
based upon actual production, results of future development and exploration
activities, prevailing natural gas and oil prices, operating costs and other
factors, and these revisions may be material. Reserve estimates are highly
dependent upon the accuracy of the underlying assumptions. Actual future
production may be materially different from estimated reserve quantities and the
differences could materially affect future amortization of natural gas and oil
properties.
20
Accounting for Stock Option Expense
On January 1, 2003, we adopted the fair value expense recognition
provisions of SFAS No. 123 "Accounting for Stock-Based Compensation" and as
amended by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition
and Disclosure." Under the fair value method, compensation expense for stock
options is recognized when stock options are issued. SFAS No. 148 proposes three
alternative transition methods for a voluntary change to the fair value method
under SFAS No. 123. We adopted SFAS No. 123 using the Prospective Method as
defined by SFAS No. 148, and as a result, we now recognize as compensation
expense the fair value of all stock options issued subsequent to December 31,
2002 with no expense recognized for options issued in previous periods. For the
three months ended June 30, 2003, we recognized compensation expense of $44,000
for stock options granted during the period. For the corresponding six month
period of 2003, we recognized $58,000 in compensation expense for stock options.
Prior to our January 1, 2003 adoption of SFAS No. 123, we accounted for the
incentive stock plans using the intrinsic value method prescribed under
Accounting Principles Board Opinion No. 25, and accordingly, we did not
recognize compensation expense for stock options granted.
Accounting for Asset Retirement Obligations
On January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations," which addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. For us, asset retirement obligations
represent the systematic, monthly accretion and depreciation of future
abandonment costs of tangible assets such as platforms, wells, service assets,
pipelines, and other facilities. SFAS No. 143 requires that the fair value of a
liability for an asset's retirement obligation be recorded in the period in
which it is incurred if a reasonable estimate of fair value can be made, and
that the corresponding cost is capitalized as part of the carrying amount of the
related long-lived asset. The liability is accreted to its then present value
each period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. Under our previous accounting method, we
included estimated future costs of abandonment and dismantlement in our full
cost amortization base and amortized these costs as a component of our depletion
expense.
Pursuant to the January 1, 2003 adoption of SFAS No. 143 we:
- recognized a charge to income during the first quarter of 2003
of $2.8 million, net of tax, for the cumulative effect of the
change in accounting principle;
- increased our total liabilities by $57.2 million to record the
asset retirement obligations ("ARO");
- increased our assets by $42.5 million to add the asset
retirement costs to the carrying amount of our natural gas and
oil properties; and
- reduced our accumulated depreciation, depletion and
amortization by $10.4 million for the amount of expense
previously recognized.
Adopting SFAS No. 143 had no impact on our reported cash flows.
Recent Accounting Pronouncements
In April 2002 the Financial Accounting Standards Board ("FASB") issued
SFAS No. 145, "Rescission of FASB Statements No. 4, No. 44, and No. 64,
Amendment to FASB Statement No. 13 and Technical Corrections." SFAS No. 145
streamlines the reporting of debt extinguishments and requires that only gains
and losses from extinguishments meeting the criteria in Accounting Policies
Board Opinion No. 30 would be classified as extraordinary. Thus, gains or losses
arising from extinguishments that are part of a company's recurring operations
would not be reported as an extraordinary item. SFAS No. 145 is effective for
fiscal years beginning after May 15, 2002. Our adoption of SFAS No. 145 on
January 1, 2003 had no effect on our financial statements.
In June 2002, FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" which addresses accounting and
reporting for costs associated with exit or disposal activities and nullifies
Emerging Issues Task Force ("EITF") Issue No. 94-3, "Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires
that a liability for a cost associated with an exit or disposal activity be
recognized when the liability is incurred. Under Issue 94-3, a liability for an
exit cost was recognized at the date of an entity's commitment to an exit plan.
Under SFAS No 146, fair value is the objective for initial measurement of the
liability. SFAS No. 146 is effective for exit or disposal activities that are
initiated after December 31, 2002. Our adoption of SFAS No. 146 on January 1,
2003 had no effect on our financial statements.
21
In November 2002, FASB issued Financial Interpretation ("FIN") No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others." FIN 45 requires certain
guarantees to be recorded at fair value, which is different from the current
practice of recording a liability only when a loss is probable and reasonably
estimable, as those terms are defined in SFAS No. 5, "Accounting for
Contingencies." FIN 45 has a dual effective date. The initial recognition and
measurement provisions are applicable on a prospective basis to guarantees
issued or modified after December 31, 2002. The disclosure requirements in the
interpretation are effective for financial statements for interim or annual
periods ending after December 15, 2002. As of our December 31, 2002 and March
31, 2003 balance sheet dates, we did not have any guarantees of indebtedness of
others and as a result, our adoption of FIN 45 did not have an effect on our
financial statements.
On April 30, 2003, FASB issued SFAS 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities," which amends and clarifies
accounting for derivative instruments, including certain derivative instruments
embedded in other contracts, and hedging activities under SFAS No. 133. The new
guidance amends SFAS 133 for decisions made:
- As a part of the Derivatives Implementation Group process that
effectively required amendments to SFAS 133;
- In connection with other FASB projects dealing with financial
instruments; and
- Regarding implementation issues raised in relation to the
application of the definition of a derivative, particularly
regarding the meaning of an "underlying" and the
characteristics of a derivative that contains financing
components.
The amendments set forth in SFAS 149 are intended to improve financial
reporting by requiring that contracts with comparable characteristics be
accounted for similarly. In particular, SFAS 149 clarifies the circumstances
under which a contract with an initial net investment meets the characteristics
of a derivative as discussed in SFAS 133. In addition, SFAS 149 clarifies when a
derivative contains a financing component that warrants special reporting is the
statement of cash flows. SFAS 149 amends certain other existing pronouncements,
resulting in more consistent reporting of contracts that are derivatives in
their entirely or that contain embedded derivatives that warrant separate
accounting.
SFAS 149 is effective for contracts entered into or modified after June
30, 2003, except as stated below, and for hedging relationships designated after
June 30, 2003. The guidance should be applied prospectively.
The provisions of SFAS 149 that relate to SFAS 133 Implementation
Issues that have been effective for fiscal quarters that began prior to June 15,
2003 should continue to be applied in accordance with their respective effective
dates. In addition, certain provisions relating to forward purchases or sales of
"when issued" securities or other securities that do not yet exist should be
applied to existing contracts as well as new contracts entered into after June
30, 2003. Our adoption of SFAS 149 will not have an effect on our financial
statements.
On May 15, 2003, FASB issued SFAS 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity,"
which aims to eliminate diversity in practice by requiring that the following
three types of "freestanding" financial instruments be reported as liabilities
by their issuers:
- Mandatorily redeemable instruments (i.e., instruments issued
in the form of shares that unconditionally obligate the issuer
to redeem the shares for cash or by transferring other
assets);
- Forward purchase contract, written put options, and other
financial instruments not in the form of shares that either
obligate or may obligate the issuer to repurchase its equity
shares and settle its obligation for cash or by transferring
other assets; and,
- Certain financial instruments that include an obligation that
(1) the issuer may or must settle by issuing a variable number
of its equity shares and (2) has a "monetary value" at
inception that (a) is fixed, (b) is tied to a market index or
other benchmark (something other than the fair value of the
issuer's equity shares), or (c) varies inversely with the fair
value of the equity shares (e.g., a written put option).
Until this pronouncement was issued, these types of instruments have
been variously presented by their issuers as liabilities, as part of equity, or
between the liabilities and equity sections (sometimes referred to as
"mezzanine" reporting) in the statement of financial position.
For our company, the provisions of SFAS 150, which also include a
number of new disclosure requirements, are effective for (1) instruments
interest into or modified after May 31, 2003 and (2) pre-existing instruments as
of the beginning of the first interim period that commences after June 15, 2003.
Our adoption of SFAS 150 has had no effect on our financial statements.
22
RECENT DEVELOPMENTS
Increase in Capital Expenditure Budget for 2003
At the quarterly meeting of our Board of Directors held July 29, 2003,
our 2003 capital expenditure budget was increased by $26 million to $312
million. We plan to spend two-thirds of the increase in South Texas and the
balance in the Arkoma Basin.
Stephen W. McKessy Elected Director
Stephen W. McKessy was elected to our Board of Directors at the
quarterly meeting held July 29, 2003. Upon Mr. McKessy's election to the Board,
the size of our Board was increased from 10 to 11 members. Mr. McKessy is a
retired Vice Chairman of PricewaterhouseCoopers where he worked from 1960 to
1997. During his 37 years with the firm he held various management positions,
including serving as a member of the firm's management committee. He was also
the regional managing partner for the firm's businesses in the New York area. A
graduate of St. John's University in New York, McKessy currently serves on the
advisory board for the college of business administration. Mr. McKessy is a
board member of KeySpan Energy Corporation.
Rocky Mountain Exploration
During the first half 2003, we acquired approximately 85,000 net
undeveloped acres in located onshore in Rocky Mountain region of the
northwestern Untied States. The acreage is located in southwestern Montana, the
Green River Basin of southwestern Wyoming and in the Uinta Basin of northeast
Utah. In April 2003, we opened an office in Denver, Colorado that is currently
staffed by one geo-scientist to coordinate prospect flow. We are planning to
drill 3 to 5 wells during the fourth quarter of 2003. The wells planned will be
less than 5,000 feet in depth. As June 30, 2003, we incurred approximately $3.4
million in leasehold acquisition costs related to the acreage acquired.
Issuance of $175 Million 7% Notes due 2013 and Redemption of $100 Million 8 5/8%
Notes due 2008
On June 10, 2003, we issued $175 million of 7% senior subordinated
notes due June 15, 2013. The notes bear interest at a rate of 7% per annum with
interest payable semi-annually on June 15 and December 15, beginning December
15, 2003. The notes are general unsecured obligations and rank subordinate in
right of payment to all existing and future senior debt, including the revolving
bank credit facility, and will rank senior or equal in right of payment to all
existing and future subordinated indebtedness. We may redeem the notes at our
option, in whole or in part, at any time on or after June 15, 2008 at a price
equal to 100% of the principal amount plus accrued and unpaid interest, if any,
plus a specified premium which decreases yearly from 3.5% in 2008 to 0% in 2011
and thereafter. In addition, at any time prior to June 15, 2006, we may redeem
up to a maximum of 35% of the aggregate principal amount of the notes with the
net proceeds of one or more equity offerings at a price equal to 107% of the
principal amount, plus accrued and unpaid interest and liquidated damages, if
any.
We received $170.9 million in net proceeds from the issuance of the
notes. A portion of the net proceeds was used to repay the aggregate principal
of $100 million on the 8 5/8% senior subordinated notes together with a premium
of $4.3 million for early redemption. The remaining portion of the net proceeds
was used to repay $60 million in outstanding borrowings on our revolving bank
credit facility with the balance of approximately $6.6 million being applied to
working capital, a portion of which was utilized in July to fund the payment of
$4.6 million in accrued interest due on the notes. At June 30, 2003 and pursuant
to the early redemption of the $100 million notes, we incurred debt
extinguishment expenses totaling $5.9 million ($3.9 million net of tax) for the
call premium of $4.3 million together with a non-cash charge of $1.6 million for
the write-off of the balance of the unamortized issue costs. The debt
extinguishment expenses of $5.9 million are included in the line item "Other
(Income) Expense on the Statement of Operations for the three and the six months
ended June 30, 2003.
Pursuant to a registration rights agreement relating to the 7% senior
subordinated notes among us and the initial purchasers, we have agreed to file a
registration statement with the SEC for the offer to exchange the notes for new
notes registered under the Securities Act which will have terms identical in all
material respects to the existing notes.
23
Issuance of 3,000,000 Shares to the Public and Concurrent Repurchase of
3,000,000 Shares from KeySpan
In connection with our initial public offering in September 1996, we
entered into a registration rights agreement with KeySpan pursuant to which we
are obligated, at KeySpan's election, to facilitate KeySpan's sale of its shares
of Company stock by registering the shares under the Securities Act of 1933 and
assisting in KeySpan's selling efforts. During February of 2003, KeySpan
notified us of its desire to sell 3,000,000 shares of their Company stock. For
the mutual convenience of the parties, we elected to effect KeySpan's sale
through our pre-existing registration statement rather than filing a separate,
new registration statement for KeySpan. To accomplish the transaction, we
simultaneously sold 3,000,000 newly issued shares of Company stock in a public
offering for net proceeds of $26.40 per share, or an aggregate $79.2 million,
and bought a like number of KeySpan's shares of Company stock for the same price
per share. We cancelled the 3,000,000 shares acquired from KeySpan immediately
following the repurchase. KeySpan reimbursed us for all costs and expenses, and
the transaction had no impact on our capitalization. The transaction was
evidenced in a stock purchase agreement, dated February 26, 2003. Our Board of
Directors approved the transaction in principle and delegated to a special,
independent committee of the Board plenary authority to negotiate the terms of,
and finally approve or veto, the transaction. In finally approving the terms of
the stock purchase agreement, the independent committee determined that the
agreement was consistent with our pre-existing obligations under our
registration rights agreement and that issuing the shares under our existing
registration statement was in the best interests of our public stockholders to
facilitate the prompt and orderly disposition of the shares. As a result of the
transactions, KeySpan's interest in our outstanding shares decreased from 66% to
56%.
As KeySpan has announced in the past, it does not consider certain
businesses contained in its energy investments segment, including its investment
in Houston Exploration, a part of its core asset group. KeySpan has stated in
the past that it may sell or otherwise dispose of all or a portion of its
non-core assets, including all or a portion of its common stock ownership in our
company. As stated above, on February 20, 2003 KeySpan sold to us 3,000,000
shares of our common stock it owned, reducing its ownership percentage from
approximately 66% to 56%. KeySpan has stated that based on market conditions, it
cannot predict when, or if, any additional sales or dispositions of all or a
part of its remaining ownership interest in us may take place.
24
RESULTS OF OPERATIONS
The following table sets forth our historical natural gas and oil production
data during the periods indicated:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
2003 2002 2003 2002
---------- ---------- ---------- ----------
PRODUCTION:
Natural gas (MMcf) ............................... 24,634 24,450 49,019 48,345
Oil (MBbls) ...................................... 328 222 585 382
Total (MMcfe) .................................... 26,602 25,782 52,529 50,637
Average daily production (MMcfe/day) ............. 292 283 290 280
AVERAGE SALES PRICES:
Natural gas (per Mcf) realized(1) ................ $ 4.54 $ 3.28 $ 4.73 $ 3.14
Natural gas (per Mcf) unhedged ................... 5.16 3.28 5.76 2.79
Oil (per Bbl) realized(1) ........................ 26.18 24.04 28.55 22.05
Oil (per Bbl) unhedged ........................... 25.95 24.04 29.24 22.05
OPERATING EXPENSES (PER MCFE):
Lease operating .................................. $ 0.44 $ 0.31 $ 0.44 $ 0.30
Severance tax .................................... 0.12 0.11 0.14 0.09
Transportation expense ........................... 0.10 0.09 0.10 0.09
Depreciation, depletion and amortization ......... 1.79 1.63 1.78 1.62
Asset retirement accretion ....................... 0.03 -- 0.03 --
General and administrative, net .................. 0.16 0.10 0.15 0.12
- ----------
(1) Reflects the effects of hedging.
RECENT FINANCIAL AND OPERATING RESULTS
Comparison of Three Months Ended June 30, 2003 and 2002
Production. Our production increased 3% from 25,782 million cubic feet
equivalent, or MMcfe, for the three months ended June 30, 2002 to 26,602 MMcfe
for the three months ended June 30, 2003. Average daily production was 292
MMcfe/day during the second quarter of 2003 compared to 283 MMcfe/day during the
second quarter of 2002.
Onshore, our daily production rates increased 15% from an average of
149 MMcfe/day during the second quarter of 2002 to an average of 171 MMcfe/day
during the corresponding three months of 2003. The increase in onshore
production is primarily attributable to 23 MMcfe/day in newly developed
production in South Texas. Production from our other onshore areas remained
relatively unchanged at 32 MMcfe/day during the second quarter of 2003 compared
to 33 MMcfe/day during the second quarter of 2002. In total, average daily
production during the second quarter of 2003 decreased slightly to 171 MMcfe/day
as compared to production during the first quarter of 2003 of 173 MMcfe/day.
Offshore, our production decreased 10% from an average of 134 MMcfe/day
during the second quarter of 2002 to an average of 121 MMcfe/day during the
second quarter of 2003. Production declines due to maturing reservoirs from
existing key fields, Mustang Island A-31/32, West Cameron 587, South Marsh
Island 253 and North Padre Island 883, were greater than incremental production
added from new wells and facilities brought on-line since the end of the second
quarter of 2002 at Vermilion 408, East Cameron 81/84, East Cameron 82/83,
Mustang Island 785 and South Timbalier 314/317. The year-over-year production
decline is partially the result of shifting approximately $40 million of our
2002 offshore capital expenditure program to our onshore region to facilitate
the May 2002 acquisition of producing properties in South Texas from Burlington
Resources. However, during the second quarter of 2003 offshore production
increased by 5% to 121 MMcfe/day from 115 MMcfe/day during the first quarter of
2003. The increase was due in part to an increase in production at South
Timbalier 314/317, a successful recompletion at High Island 38 completed in the
first quarter of 2003
25
and the resolution of downstream pipeline problems during January and February
at Vermilion 408.
Natural Gas and Oil Revenues. Natural gas and oil revenues increased
41% from $85.6 million for the second quarter of 2002 to $120.4 million for the
second quarter of 2003 as a result of a 38% increase in average realized natural
gas prices, from $3.28 per Mcf during the second quarter of 2002 to $4.54 per
Mcf in the second quarter of 2003 and an increase in average realized oil prices
of 9% for the same period from $24.04 per barrel, or Bbl, to $26.18 per barrel,
combined with a 48% increase in production during the current quarter.
Natural Gas Prices. As a result of hedging activities during the second
quarter of 2003, we realized an average gas price of $4.54 per Mcf, which was
88% of the average unhedged natural gas price of $5.16 for the period. As a
result, natural gas and oil revenues for the three months ended June 30, 2003
were $15.4 million lower than the revenues we would have achieved if hedges had
not been in place during the period. For the corresponding quarter of 2002, our
hedging activities resulted in $12,000 of additional natural gas revenues, and,
as a result, our average realized natural gas price and unhedged natural gas
price were equal at $3.28 per Mcf.
Oil Prices. During the second quarter of 2003, we realized an average
oil price of $26.18 per Bbl, which was 101% of the average unhedged price of
$25.95 per Bbl for the period. As a result, natural gas and oil revenues for the
three months ended June 30, 2003 were $73,000 higher than the revenues we would
have achieved if hedges had not been in place during the period. We had no oil
hedges in place during second quarter of 2002 and realized an average oil price
of $24.04 per Bbl.
Lease Operating Expenses and Severance Tax. Lease operating expenses
increased 48% from $7.9 million for the three months ended June 30, 2002 to
$11.7 million for the corresponding three months of 2003. On an Mcfe basis,
lease operating expenses increased 42% from $0.31 per Mcfe during the second
quarter of 2002 to $0.44 per Mcfe during the second quarter of 2003. The
increase in both lease operating expenses and lease operating expense on a per
unit basis for 2003 is primarily attributable to the continued expansion of our
operations both onshore and offshore. Our overall operating expenses are
increasing as we add new wells and facilities and continue to maintain
production from existing properties. Since the end of the second quarter of
2002, we added approximately 100 new wells from exploration and development
drilling. Specifically, ad valorem taxes increased as onshore property values
are higher than prior year as a result of higher commodity prices. South
Timbalier 314/317 was placed on-line during the first quarter of 2003 and is
inherently more costly to operate, as it is a crude oil producing property. We
are incurring additional fees to process natural gas from new wells at East
Cameron 81/83/84. And finally, we have added compression in South Texas and at
several offshore platforms to enhance production capabilities from existing
wells.
Severance tax, which is a function of volume and revenues generated
from onshore production, increased from $2.8 million for the second quarter of
2002 to $3.2 million for the corresponding period of 2003. On an Mcfe basis,
severance tax increased 9% from $0.11 per Mcfe during the second quarter of 2002
to $0.12 per Mcfe during the second quarter of 2003. Despite our reduced
severance tax rate for a portion of our South Texas production pursuant to the
"high-cost/tight-gas formation" designation received in July 2002 (see "Other
(Income) and Expense" below), severance tax expense and severance tax per Mcfe
increased during the second quarter of 2003 due to the 57% increase in average
wellhead prices for natural gas from $3.28/Mcf during the second quarter of 2002
to $5.16/Mcf during the second quarter of 2003 combined with a 14% increase in
onshore production for the same period of 2003.
Transportation Expense. We applied EITF No. 00-10 "Accounting for
Shipping and Handling Fees and Costs" for all periods presented. Pursuant to our
application of EITF No. 00-10, transportation expenses for the three months
ended June 30, 2002 that were previously reflected as a reduction of natural gas
and oil revenues were added back to the related revenues and reclassified as a
separate component of operating expense. The application of EITF No. 00-10 had
no effect on operating income or net income. Transportation expense for the
second quarter of 2003 increased 11% on an Mcfe basis from $0.09 during the
second quarter of 2002 to $0.10 for the second quarter of 2003. The increase
reflects an increase in volume, primarily in South Texas, that is subject to
transportation fee agreements the current quarter.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 14% from $42.0 million for the three months ended
June 30, 2002 to $47.7 million for the three months ended June 30, 2003.
Depreciation, depletion and amortization expense per Mcfe increased 10% from
$1.63 for the three months ended June 30, 2002 to $1.79 for the corresponding
three months in 2003. The increase in depreciation, depletion and amortization
expense was a result of higher production volumes combined with a higher
depletion rate. Our depletion rate has increased as the costs associated with
several unproved properties designated as unevaluated were reclassified into our
amortization base
26
without incremental reserve additions at the end of 2002. In addition, our
estimated future development costs at December 31, 2002, increased approximately
22% from prior year estimates due to the addition of more proved undeveloped
reserves into our total proved reserve base.
Asset Retirement Accretion. Pursuant to our January 1, 2003 adoption of
SFAS No. 143, "Asset Retirement Obligations," we incurred asset retirement
accretion expense of $0.8 million, $0.03 per Mcfe, during the second quarter of
2003. The accretion expense represents the systematic, monthly accretion and
depreciation of future abandonment costs of tangible assets such as platforms,
wells, service assets, pipelines, and other facilities.
General and Administrative Expenses, Net of Capitalized General and
Administrative and Overhead Reimbursements. Our net general and administrative
expenses increased 68% from $2.5 million for the three months ended June 30,
2002 to $4.2 million for the three months ended June 30, 2003. These amounts are
net of overhead reimbursements received from other working interest owners of
$0.3 million and $0.4 million for the three months ended June 30, 2002 and 2003,
respectively, and capitalized general and administrative expenses of $3.1
million and $2.9 million for the respective periods. Aggregate general and
administrative expenses increased by $1.6 million or 27% from $5.9 million
during the second quarter of 2002 to $7.5 million for the second quarter of
2003. The increase in aggregate general and administrative expense is due
primarily to the expansion of our workforce which corresponds to the continued
expansion of our operations. As our workforce expands, we have experienced an
increase in salaries and related employee benefit expenses together with an
increase in our incentive compensation expense. In addition, our rent expense
has increased as we expanded our leased office space in downtown Houston to
accommodate our growing workforce. Finally, our legal, audit and accoun