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, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER: 000-32261
ATP OIL & GAS CORPORATION
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 76-0362774
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
4600 POST OAK PLACE, SUITE 200
HOUSTON, TEXAS 77027
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
(ZIP CODE)
(713) 622-3311
(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 ___
The number of shares outstanding of Registrant's common stock, par value $0.001,
as of August 10, 2001, was 20,287,944.
ATP OIL & GAS CORPORATION
TABLE OF CONTENTS
PAGE
----
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets:
June 30, 2001 and December 31, 2000........................... 3
Consolidated Statements of Operations:
For the three and six months ended June 30, 2001 and 2000..... 4
Consolidated Statements of Cash Flows:
For the six months ended June 30, 2001 and 2000............... 5
Notes to Consolidated Financial Statements...................... 6
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.......................... 11
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK... 18
PART II. OTHER INFORMATION........................................... 20
2
ITEM 1. FINANCIAL STATEMENTS
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)
June 30, December 31,
2001 2000
--------- ---------
(unaudited)
Assets
Current assets:
Cash and cash equivalents.................................................... $ 8,076 $ 18,136
Accounts receivable (net of allowance of $723 and $443, respectively)........ 19,305 32,542
Deferred tax asset........................................................... 2,838 -
Commodity contracts and other derivatives.................................... 2,530 -
Other current assets......................................................... 2,656 2,597
--------- ---------
Total current assets....................................................... 35,405 53,275
--------- ---------
Oil and gas properties:.......................................................
Oil and gas properties (using the successful efforts method of accounting)... 291,363 209,548
Less: Accumulated depletion and impairment................................... (150,082) (110,823)
--------- ---------
Oil and gas properties, net................................................ 141,281 98,725
--------- ---------
Furniture and fixtures (net of accumulated depreciation)...................... 683 487
Deferred tax asset............................................................ 9,224 7,652
Other assets, net............................................................. 2,312 1,854
--------- ---------
Total assets............................................................... $ 188,905 $ 161,993
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable and accruals................................................ $ 69,942 $ 49,799
Current maturities of long-term debt......................................... 10,000 -
Commodity contracts and other derivatives.................................... 1,113 7,248
Other deferred obligations................................................... 63 63
--------- ---------
Total current liabilities.................................................. 81,118 57,110
Long-term debt................................................................ 50,000 27,750
Non-recourse borrowings....................................................... - 88,779
Deferred revenue.............................................................. 1,390 1,481
Other long-term liabilities and deferred obligations.......................... 38 52
--------- ---------
Total liabilities.......................................................... 132,546 175,172
--------- ---------
Shareholders' equity (deficit):
Preferred stock: $0.001 par value, 10,000,000 shares authorized;
none issued and outstanding................................................ - -
Common stock: $0.001 par value, 100,000,000 shares authorized;
20,363,784 issued and 20,287,944 outstanding at June 30, 2001
and 14,285,714 issued and outstanding at December 31, 2000................. 20 14
Additional paid in capital................................................... 79,478 38
Accumulated deficit.......................................................... (16,893) (13,231)
Accumulated other comprehensive loss......................................... (5,335) -
Treasury stock, at cost...................................................... (911) -
--------- ---------
Total shareholders' equity (deficit)....................................... 56,359 (13,179)
--------- ---------
Total liabilities and shareholders' equity (deficit)....................... $ 188,905 $ 161,993
========= =========
See accompanying notes to the consolidated financial statements.
3
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, Except Per Share Amounts)
(Unaudited)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------ -------------------
2001 2000 2001 2000
------- ------- -------- -------
Revenue:
Oil and gas production....................... $29,005 $22,838 $ 67,510 $36,733
Gas sold - marketing......................... 2,030 1,687 4,968 2,919
Gain on sale of oil and gas properties....... - 33 - 33
------- ------- -------- -------
Total revenues.............................. 31,035 24,558 72,478 39,685
------- ------- -------- -------
Costs and operating expenses:
Lease operating expenses..................... 4,919 3,482 7,725 6,422
Gas purchased - marketing.................... 1,981 1,621 4,867 2,802
General and administrative expenses.......... 2,135 1,144 4,050 2,738
Non-cash compensation expense................ 882 - 2,466 -
Depreciation, depletion and amortization..... 14,072 10,728 25,104 16,695
Impairment on oil and gas properties......... 5,705 6,255 14,183 6,255
------- ------- -------- -------
Total costs and operating expenses.......... 29,694 23,230 58,395 34,912
------- ------- -------- -------
Net income from operations.................... 1,341 1,328 14,083 4,773
------- ------- -------- -------
Other income (expense):
Interest income.............................. 137 69 793 255
Interest expense............................. (1,713) (3,099) (5,021) (5,146)
Gain (loss) on derivative instruments........ 6,351 (2,513) (14,162) (2,513)
------- ------- -------- -------
Total other income (expense)................ 4,775 (5,543) (18,390) (7,404)
------- ------- -------- -------
Net income (loss) before income taxes and
extraordinary item........................... 6,116 (4,215) (4,307) (2,631)
Income tax (expense) benefit:
Current...................................... 59 - - -
Deferred..................................... (2,362) 1,473 1,247 918
------- ------- -------- -------
Net income (loss) before extraordinary item... 3,813 (2,742) (3,060) (1,713)
Extraordinary item, net of tax................ (602) - (602) -
------- ------- -------- -------
Net income (loss)............................. $ 3,211 $(2,742) $ (3,662) $(1,713)
======= ======= ======== =======
Basic earnings (loss) per common share:
Income (loss) before extraordinary item...... $ 0.19 $ (0.19) $ (0.16) $ (0.12)
Extraordinary item, net of tax............... (0.03) - (0.03) -
------- ------- -------- -------
Net income (loss) per common share........... $ 0.16 $ (0.19) $ (0.19) $ (0.12)
======= ======= ======== =======
Diluted earnings (loss) per common share:
Income (loss) before extraordinary item...... $ 0.19 $ (0.19) $ (0.16) $ (0.12)
Extraordinary item, net of tax............... (0.03) - (0.03) -
------- ------- -------- -------
Net income (loss) per common share........... $ 0.16 $ (0.19) $ (0.19) $ (0.12)
======= ======= ======== =======
Weighted average number of common shares:
Basic........................................ 20,287 14,286 19,093 14,286
======= ======= ======== =======
Diluted...................................... 20,705 14,286 19,093 14,286
======= ======= ======== =======
See accompanying notes to the consolidated financial statements.
4
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
SIX MONTHS ENDED
JUNE 30,
--------------------
2001 2000
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss.................................................... $ (3,662) $ (1,713)
Adjustments to reconcile net loss to net cash
provided by operating activities -
Depreciation, depletion and amortization.................. 25,104 16,695
Impairment of oil and gas properties...................... 14,183 6,255
Amortization of deferred financing costs.................. 308 150
Extraordinary item........................................ 926 -
Deferred tax asset........................................ (1,572) (918)
Non-cash compensation expense............................. 2,466 -
Gain on sale of oil and gas properties.................... - (33)
Other non-cash items...................................... (64) 424
Changes in assets and liabilities -
Accounts receivable and other.............................. 13,178 (13,739)
Restricted cash............................................ - 471
Net (assets) liabilities from risk management activities... (16,774) 2,032
Accounts payable and accruals.............................. 20,070 15,150
Other long-term assets..................................... (282) -
Other long-term liabilities and deferred credits........... (105) (69)
-------- --------
Net cash provided by operating activities.................... 53,776 24,705
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions and acquisitions of oil and gas properties........ (81,933) (40,534)
Additions to furniture and fixtures......................... (288) (148)
-------- --------
Net cash used in investing activities........................ (82,221) (40,682)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from initial public offering....................... 78,330 -
Payment of offering costs................................... (893) -
Proceeds from long-term debt................................ 65,000 3,300
Payments of long-term debt.................................. (32,750) (1,500)
Proceeds from non-recourse borrowings....................... 3,359 13,461
Payments of non-recourse borrowings......................... (92,138) (8,768)
Deferred financing costs.................................... (1,777) (100)
Treasury stock purchases.................................... (911) -
Other....................................................... 165 -
-------- --------
Net cash provided by financing activities.................... 18,385 6,393
-------- --------
Decrease in cash and cash equivalents........................ (10,060) (9,584)
Cash and cash equivalents, beginning of period............... 18,136 17,779
-------- --------
Cash and cash equivalents, end of period..................... $ 8,076 $ 8,195
======== ========
Supplemental disclosures of cash flow information:
Cash paid during the period for interest.................... $ 909 $ 1,411
======== ========
Cash paid during the period for taxes....................... $ - $ 497
======== ========
See accompanying notes to the consolidated financial statements.
5
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
NOTE 1 -- ORGANIZATION
ATP Oil & Gas Corporation ("ATP"), a Texas corporation, was formed on August
8, 1991 and is engaged primarily in the acquisition, development and operation
of oil and gas properties. We operate in one business segment which is oil and
gas development and production.
The accompanying financial statements and related notes present our
consolidated financial position as of June 30, 2001 and December 31, 2000, the
results of our operations for the three months and six months ended June 30,
2001 and 2000 and cash flows for the six months ended June 30, 2001 and 2000.
The financial statements have been prepared in accordance with the instructions
to interim reporting as prescribed by the Securities and Exchange Commission
("SEC"). All adjustments, consisting only of normal recurring adjustments, that
in the opinion of management were necessary for a fair statement of the results
for the interim periods, have been reflected. All significant intercompany
transactions have been eliminated. Certain reclassifications have been made to
prior period amounts to conform to current period presentation. The results of
operations for the three and six months ended June 30, 2001 should not be taken
as indicative of the results to be expected for the full year. The interim
financial statements should be read in conjunction with our consolidated
financial statements and notes thereto presented in our 2000 Annual Report on
Form 10-K.
Initial Public Offering
On February 5, 2001, we priced our initial public offering of 6.0 million
shares of common stock and commenced trading the following day. After payment of
the underwriting discount we received net proceeds of $78.3 million on February
9, 2001, excluding offering costs of approximately $1.5 million.
NOTE 2 -- ADOPTION OF SFAS 133
Effective January 1, 2001, we adopted the Financial Accounting Standards Board
("FASB") Statement of Financial Accounting Standard ("SFAS") No. 133, Accounting
for Derivative Instruments and Hedging Activities ("SFAS 133") and SFAS No. 138,
Accounting for Certain Derivative Instruments and Certain Hedging Activities
("SFAS 138"), an amendment to SFAS 133. SFAS 133 and 138 require that
derivatives be reported on the balance sheet at fair value and, if the
derivative is not designated as a hedging instrument, changes in fair value must
be recognized in earnings in the period of change. If the derivative is
designated as a hedge and to the extent such hedge is determined to be
effective, changes in fair value are either (a) offset by the change in fair
value of the hedged asset or liability (if applicable) or (b) reported as a
component of other comprehensive income (loss) in the period of change, and
subsequently recognized in earnings when the offsetting hedged transaction
occurs. We use derivatives to hedge the price of crude oil and natural gas and
effective January 1, 2001, we account for the changes in market value of these
derivatives through current earnings. This method will result in increased
earnings volatility associated with commodity price fluctuations. Gains and
losses on all derivative instruments related to accumulated other comprehensive
income (loss) are included in other income (expense) on the consolidated
financial statements.
On January 1, 2001, in accordance with the transition provisions of SFAS 133,
we recorded a non-cash loss of $52.7 million ($34.3 million after tax) in
accumulated other comprehensive loss, representing the cumulative effect of an
accounting change to recognize at fair value all cash flow type derivatives.
Also on January 1, 2001, we recorded derivative liabilities of $52.7 million.
During the first six months of 2001, losses of $44.6 million ($29.0 million
after tax) were reclassified from accumulated other comprehensive loss to
earnings. The remaining after-tax loss of $5.3 million recorded in other
comprehensive loss will be reclassified to earnings during the last six months
of the year ended December 31, 2001 as the transactions are settled. Prior to
the adoption of this standard, we included gains and losses on hedging
instruments as a component of revenue. As of June 30, 2001, the fair market
value of our derivatives consisted of a $2.5 million asset and a $1.1 million
liability.
6
Note 3 -- Recent Accounting Pronouncements
In June 2001, the FASB approved SFAS No. 141 "Business Combinations" ("SFAS
141"), No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142") and No. 143
"Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 141 requires
all business combinations completed after June 30, 2001, be accounted for under
the purchase method. This standard also establishes for all business
combinations made after June 30, 2001, specific criteria for the recognition of
intangible assets separately from goodwill. SFAS 141 also requires that the
excess of fair value of acquired assets over cost (negative goodwill) be
recognized immediately as an extraordinary gain, rather than deferred and
amortized. We will account for all future business combinations under SFAS 141.
SFAS 142 addresses the accounting for goodwill and other intangible assets
after an acquisition. The most significant changes made by SFAS 142 are: 1)
goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must be
tested for impairment at least annually; and 3) the amortization period for the
intangible assets with finite lives will no longer be limited to forty years. We
will adopt SFAS 142 effective January 1, 2002, as required. Additionally, SFAS
142 requires that unamortized negative goodwill associated with investments
accounted for under the equity method and acquired before July 1, 2001, be
recognized in income as a cumulative effect of change in accounting principle.
Adoption of this standard will have no impact on our financial position or
results of operations.
SFAS 143 provides accounting requirements for retirement obligations
associated with tangible long-lived assets, including: 1) the timing of
liability recognition; 2) initial measurement of the liability; 3) allocation of
asset retirement cost to expense; 4) subsequent measurement of the liability;
and 5) financial statement disclosures. SFAS 143 requires that an asset
retirement cost should be capitalized as part of the cost of the related long-
lived asset and subsequently allocated to expense using a systematic and
rational method. We will adopt the Statement effective January 1, 2003. The
transition adjustment resulting from the adoption of SFAS 143 will be reported
as a cumulative effect of a change in accounting principle. At this time, we
cannot reasonably estimate the effect of the adoption of this statement on
either our financial position or results of operations.
NOTE 4 -- ACQUISITION OF OIL & GAS PROPERTIES
Gulf of Mexico. In the first half of 2001, we acquired twelve properties in
the Gulf of Mexico region. Nine of the properties were acquired in the first
quarter and three in the second quarter. Eight of the above properties were
producing when acquired, with additional development operations planned during
2001 and 2002.
Southern Gas Basin of the U.K. North Sea. In October 2000, we entered into a
letter of intent to acquire interests in three properties in the Southern Gas
Basin of the U.K. North Sea. In the first quarter of 2001 we acquired two of
the three properties covered by the October 2000 letter of intent. We acquired
the third property in the second quarter of 2001. None of these properties are
currently producing.
The total acquisition costs during 2001 for the above properties were
approximately $23.9 million.
7
NOTE 5 -- LONG-TERM DEBT
Our long-term debt as of June 30, 2001 and December 31, 2000 consisted of the
following (in thousands):
JUNE 30, DECEMBER 31,
2001 2000
-------- ------------
Credit facility.............................. $ 60,000 $ 27,750
Non-recourse borrowings...................... - 88,779
-------- --------
Total long-term debt........................ 60,000 116,529
Less current maturities of long-term debt... (10,000) -
-------- --------
$ 50,000 $116,529
======== ========
In March 2001, we repaid our then existing bank credit facility and in April
2001 we repaid the full amount borrowed under the non-recourse development
program credit agreement. Concurrent with the repayment of our non-recourse
agreement, we negotiated with the lender to terminate the overriding royalty
interest on all properties previously financed by the lender in exchange for a
lump-sum payment of approximately $5.6 million.
Upon repayment of our former credit and non-recourse facilities, we entered
into a new $100.0 million senior-secured revolving credit facility in April
2001. The amount available for borrowing under the facility is limited to the
loan value, as determined by the bank, of oil and gas properties pledged under
the facility. The borrowing base at June 30, 2001 was $60.0 million. This
facility is secured by substantially all of our oil and gas properties, as well
as by approximately two-thirds of the capital stock of our U.K. subsidiary. If
our outstanding balance exceeds our borrowing base at any time, we are required
to repay such excess within 30 days and our interest rate during the time an
excess exists is increased by 2.00%.
Advances under the credit facility can be in the form of either base rate
loans or Eurodollar loans. The interest on a base rate loan is a fluctuating
rate equal to the higher of the Federal funds rate plus 0.5% and the bank base
rate, plus a margin of 0.00%, 0.25% or 0.75% depending on the amount outstanding
under the credit agreement. The interest on a Eurodollar loan is equal to the
Eurodollar rate, plus a margin of 1.50%, 1.75%, 2.00%, 2.25% or 2.75% depending
on the amount outstanding under the credit facility. The credit facility
matures in December 2003. Our credit facility contains conditions and
restrictive provisions, among other things, (1) prohibiting us to enter into any
arrangement to sell or transfer any of our material property, (2) prohibiting a
merger into or consolidation with any other person or sell or dispose of all or
substantially all of our assets, and (3) maintaining certain financial ratios.
At June 30, 2001, we were in compliance with all terms of the agreement.
Effective June 29, 2001, we issued a promissory note to a purchaser for a face
principal amount of $31.3 million which matures in June 2005 and bears interest
at a fixed rate of 11.5% per annum. The note is secured by second priority
liens on substantially all of our oil and gas properties and is subordinated in
right of payment to our existing senior indebtedness. We executed an agreement
in connection with the note which contains conditions and restrictive provisions
and requires the maintenance of certain financial ratios. Upon consent of the
purchaser, which shall not be unreasonably withheld, the note may be repaid
prior to the maturity date with an additional repayment premium, based on the
percentage of the principal amount paid, ranging from 4.5% during the first year
to 16.5% in the final year of payment. At maturity, a payment premium of 16.5%
is required. In July 2001, we received proceeds of $30.0 million in
consideration for the issuance of the note.
8
NOTE 6 -- EARNINGS PER SHARE
Basic earnings per share is computed by dividing net income (loss) available
to common shareholders by the weighted average number of common shares
outstanding during the period. Diluted earnings per share is determined on the
assumption that outstanding stock options have been converted using the average
price for the period. For purposes of computing diluted earnings per share in a
period which a loss occurs, potential common shares have been excluded from the
computation of weighted average common shares outstanding because their effect
is antidilutive.
Basic and diluted net income (loss) per share is computed based on the
following information (in thousands, except per share amounts):
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------ -------------------
2001 2000 2001 2000
------- ------- ------- -------
Net income (loss)............................... $ 3,211 $(2,742) $(3,662) $(1,713)
======= ======= ======= =======
Weighted average shares outstanding - basic..... 20,287 14,286 19,093 14,286
Effect of dilutive securities - stock options... 418 - - -
------- ------- ------- -------
Weighted average shares outstanding - diluted... 20,705 14,286 19,093 14,286
======= ======= ======= =======
Net income (loss) per share - basic............. $ 0.16 $ (0.19) $ (0.19) $ (0.12)
======= ======= ======= =======
Net income (loss) per share - diluted........... $ 0.16 $ (0.19) $ (0.19) $ (0.12)
======= ======= ======= =======
NOTE 7 -- STOCK OPTION COMPENSATION
We recorded a non-cash charge to compensation expense of approximately $2.5
million for the six months ended June 30, 2001, for options granted since
September 1999 through the date of our initial public offering on February 5,
2001, as well as for certain options granted prior to September 1999 and
exercised during the current period. The expense will be recognized in the
periods in which the options vest. Each option is divided into three equal
portions corresponding to the three vesting dates, with the related non-cash
compensation expense amortized straight-line method over the period between the
initial public offering and the vesting date of the options.
During the second quarter, the first option vesting date occurred, allowing
option holders the opportunity to exercise one-third of their options. Of those
options exercised during the second quarter, certain optionees elected to
receive cash upon exercise of their options, whereby we purchased 75,840 shares
and recorded such purchase as treasury stock using the cost method.
NOTE 8 -- EXTRAORDINARY ITEM
For the six months ended June 30, 2001, we recognized an extraordinary loss,
net of tax of $0.3 million, related to the early extinguishment of our non-
recourse borrowings.
9
NOTE 9 -- COMPREHENSIVE INCOME (LOSS)
Comprehensive income (loss) consists of net income (loss), as reflected on the
consolidated statement of operations, and other gains and losses affecting
stockholders' equity that are excluded from net income (loss). We recorded other
comprehensive income (loss) for the first time in the first quarter of 2001.
Total comprehensive income (loss) for the three months and six months ended June
30, 2001 is as follows (in thousands):
THREE MONTHS SIX MONTHS
ENDED ENDED
JUNE 30, JUNE 30,
2001 2001
------------- --------------
Net income (loss)......................................................... $3,211 $ (3,662)
------ --------
Other comprehensive income (loss), net of tax:
Cumulative effect of change in accounting principle - January 1, 2001... - (34,252)
Reclassification adjustment for settled contracts....................... 4,765 28,981
Foreign currency translation adjustment................................. 11 (64)
------ --------
Other comprehensive income (loss)...................................... 4,776 (5,335)
------ --------
Comprehensive income (loss)............................................... $7,987 $ (8,997)
====== ========
There were no items in other comprehensive income (loss) during 2000.
10
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
ATP Oil & Gas Corporation ("ATP") was incorporated in Texas in 1991. We are
engaged in the acquisition, development and production of natural gas and oil
properties in the outer continental shelf of the Gulf of Mexico, in the shallow-
deep waters of the Gulf of Mexico and in the Southern Gas Basin of the U.K.
North Sea. We primarily focus our efforts on natural gas and oil properties
with proved undeveloped reserves that are economically attractive to us but are
not strategic to major or exploration-oriented independent oil and gas
companies. We attempt to achieve a high return on our investment in these
properties by limiting our up-front acquisition costs and by developing our
acquisitions quickly.
On February 5, 2001, we priced our initial public offering of 6.0 million
shares of common stock and commenced trading the following day. After payment of
the underwriting discount we received net proceeds of $78.3 million on February
9, 2001, excluding offering costs of approximately $1.5 million. We used the
net proceeds from our initial public offering, together with the proceeds from
our new credit facility, to repay all of our outstanding debt under our
development program credit agreement and our prior bank credit facility and to
acquire natural gas and oil properties.
RESULTS OF OPERATIONS
Prior to the January 1, 2001 adoption of Financial Accounting Standards Board
("FASB") Statement of Financial Accounting Standard ("SFAS") No. 133, Accounting
for Derivative Instruments and Hedging Activities ("SFAS 133") and SFAS No. 138,
Accounting for Certain Derivative Instruments and Certain Hedging Activities
("SFAS 138"), an amendment to SFAS 133, we previously included the effects of
our risk management activities as an offset to revenue. Upon adoption of the
standard, any gains or losses from these activities are now included in other
income (expense), as we have elected not to account for our hedging activities
under the hedge accounting provisions allowed in the standard. For comparative
purposes though, the following table sets forth selected financial and operating
information for our natural gas and oil operations inclusive of the effects of
risk management activities:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------ ------------------
2001 2000 2001 2000
------- ------- -------- -------
Production:
Natural gas (MMcf)................................. 5,634 7,189 10,786 11,804
Oil and condensate (MBbls)......................... 94 125 203 178
------- ------- -------- -------
Total (Mmcfe)..................................... 6,201 7,942 12,001 12,874
Revenues (in thousands):
Natural gas........................................ $26,571 $25,371 $ 62,125 $37,558
Effects of risk management activities (1).......... (5,455) (5,414) (28,709) (5,083)
------- ------- -------- -------
Total............................................. $21,116 $19,957 $ 33,416 $32,475
======= ======= ======== =======
Oil and condensate................................. $ 2,434 $ 3,456 $ 5,385 $ 4,989
Effects of risk management activities.............. - (575) - (731)
------- ------- -------- -------
Total............................................. $ 2,434 $ 2,881 $ 5,385 $ 4,258
======= ======= ======== =======
Natural gas, oil and condensate.................... $29,005 $28,827 $ 67,510 $42,547
Effects of risk management activities (1).......... (5,455) (5,989) (28,709) (5,814)
------- ------- -------- -------
Total............................................. $23,550 $22,838 $ 38,801 $36,733
======= ======= ======== =======
Table continued on following page
11
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------ ------------------
2001 2000 2001 2000
------- ------- -------- -------
Average sales price per unit:
Natural gas (per Mcf).............................. $ 4.72 $ 3.53 $ 5.76 $ 3.18
Effects of risk management activities (per Mcf).... (0.97) (0.75) (2.66) (0.43)
------- ------- -------- -------
Total............................................. $ 3.75 $ 2.78 $ 3.10 $ 2.75
======= ======= ======== =======
Oil and condensate (per Bbl)....................... $ 25.75 $ 27.55 $ 26.56 $ 27.96
Effects of risk management activities (per Bbl).... - (4.58) - (4.10)
------- ------- -------- -------
Total............................................. $ 25.75 $ 22.97 $ 26.56 $ 23.86
======= ======= ======== =======
Natural gas, oil and condensate (per Mcfe)......... $ 4.68 $ 3.63 $ 5.62 $ 3.30
Effects of risk management activities (per Mcfe)... (0.88) (0.75) (2.39) (0.45)
------- ------- -------- -------
Total............................................. $ 3.80 $ 2.88 $ 3.23 $ 2.85
======= ======= ======== =======
Expenses (per Mcfe):
Lease operating expense............................ $ 0.79 $ 0.44 $ 0.64 $ 0.50
General and administrative......................... 0.34 0.14 0.34 0.21
Depreciation, depletion and amortization........... 2.27 1.35 2.09 1.30
- -------------
(1) For 2001, represents the net loss on the settlement of derivatives
attributable to production of 6,201 Mmcfe and 12,001 Mmcfe for the three
and six months ended June 30, 2001, respectively.
Three Months Ended June, 2001 Compared with Three Months Ended June 30, 2000
For the three months ended June 30, 2001, we reported net income of $3.2
million, or $0.16 per basic and diluted share, on total revenue of $31.0
million, as compared with a net loss of $2.7 million, or $0.19 per basic and
diluted share, on total revenue of $30.5 million (excluding hedging effects) in
the second quarter of 2000. Adjusted EBITDA in the second quarter of 2001 was
$16.7 million compared with $17.9 million in the second quarter of 2000.
Adjusted EBITDA means earnings before interest expense, income taxes,
depreciation, depletion and amortization, impairments on oil and gas properties,
unrealized gains and losses, non-cash compensation expenses and extraordinary
items. Our Adjusted EBITDA margin was 65% in the second quarter of 2001 and 73%
for the same period in 2000. Adjusted EBITDA margin represents Adjusted EBITDA
divided by revenues which are inclusive of any realized derivative gains and
losses. Adjusted EBITDA is not a calculation based on generally accepted
accounting principles and may not be comparable to other similarly titled
measures of other companies.
Oil and Gas Revenue. Excluding the effects of risk management activities, our
revenue from natural gas and oil production for the second quarter of 2001
increased over the same period in 2000 from $28.8 million to $29.0 million. This
increase was primarily due to an approximate 34% increase in natural gas prices
partially offset by a 22% decrease in production. The decrease in production
volumes from 7.9 Bcfe to 6.2 Bcfe was attributable to natural declines in our
producing properties. Risk management activities, which were included in oil
and gas revenues in 2000 but excluded in compliance with SFAS 133 in 2001, would
have reduced oil and natural gas revenues by $5.4 million, or $0.88 per Mcfe in
the second quarter of 2001 compared with $6.0 million, or $0.75 per Mcfe, in the
second quarter of 2000.
Marketing Revenue. Revenues from natural gas marketing activities increased to
$2.0 million in the second quarter of 2001 as compared to $1.7 million in the
second quarter of 2000. This increase was due to an increase in the sales price
per MMBtu. The average sales price per MMBtu increased from $3.71 in the second
quarter of 2000 to $4.46 in the second quarter of 2001.
12
Lease Operating Expense. Our lease operating expenses for the second quarter
of 2001 increased to $4.9 million from $3.5 million in the second quarter of
2000. This increase was primarily the result of increased geological and
geophysical expenses as well as an increase in workover activities.
Gas Purchased-Marketing. Our cost of purchased gas was $2.0 million for the
second quarter of 2001 compared to $1.6 million for the second quarter of 2000.
The average cost increased from $3.56 per MMbtu in 2000 to $4.36 per MMbtu in
2001.
General and Administrative Expense. General and administrative expense
increased to $2.1 million for the second quarter of 2001 compared to $1.1
million for the same period in 2000. The primary reason for the increase was the
result of higher compensation and related expenses due to an increase in the
number of employees from 23 at the end of the second quarter of 2000 to 44 at
the end of the second quarter of 2001. In addition, our U.K. office was opened
in the third quarter of 2000.
Non-Cash Compensation Expense. In the second quarter of 2001, we recorded a
non-cash charge to compensation expense of approximately $0.9 million for
options granted since September 1999 through the date of our initial public
offering on February 5, 2001, as well as for certain options granted prior to
September 1999 and exercised during the current period. The expense will be
amortized using the straight-line method over the period between the initial
public offering and the vesting date of the options.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion and
amortization expense increased 31% from $10.7 million in the second quarter 2000
to $14.1 million in the second quarter 2001.
Impairment Expense. As of June 30, 2001, the future undiscounted cash flows
were less than their individual net book value on four of our properties. As a
result, we recorded impairments of $5.7 million in the second quarter of 2001.
These impairments were primarily the result of reductions in expected future
undiscounted cash flows on each property due to lower natural gas prices at June
30, 2001. For the second quarter of 2000, we recorded an impairment of $6.3
million related to one property as a result of a reduction in recoverable
reserves.
Other Income (Expense). In the second quarter of 2001, we recorded a gain on
derivative instruments of $6.4 million comprised of a realized loss of $5.4
million and an unrealized gain of $11.8 million. The realized loss represents
derivative contracts settled in the second quarter of 2001, while the offsetting
gain represents the change in the fair market value of the open derivative
positions at June 30, 2001. Prior to the adoption of SFAS 133, realized gains or
losses were recorded as a component of revenue.
Interest expense for the second quarter of 2001 decreased to $1.7 million from
$3.1 million in the comparable quarter of 2000 primarily due to lower borrowing
levels in 2001. We did not capitalize any interest for the three months ended
June 30, 2001 or 2000.
Six Months Ended June 30, 2001 Compared with Six Months Ended June 30, 2000
For the six months ended June 30, 2001, we reported a net loss of $3.7
million, or $0.19 per basic and diluted share, on total revenue of $72.5
million, as compared with a net loss of $1.7 million, or $0.12 per basic and
diluted share, on total revenue of $45.5 million (excluding hedging effects) in
the first half of 2000. Adjusted EBITDA in the first half of 2001 was $28.3
million compared with $27.5 million in the first half of 2000. Our Adjusted
EBITDA margin was 64% in the first half of 2001 and 69% in the first half of
2000.
13
Oil and Gas Revenue. Excluding the effects of risk management activities, our
revenue from natural gas and oil production for the first half of 2001 increased
approximately 59% over the same period in 2000, from $42.5 million to $67.5
million. This increase was primarily due to an approximate 81% increase in
natural gas prices, partially offset by a 7% decrease in production. The
decrease in production volumes from 12.9 Bcfe to 12.0 Bcfe was attributable to
natural declines in our producing properties. Risk management activities, which
were included in oil and gas revenues in 2000 but excluded in compliance with
SFAS 133 in 2001, would have reduced oil and natural gas revenues by $28.7
million, or $2.39 per Mcfe in the first half of 2001 compared with $5.8 million,
or $0.45 per Mcfe in the first half of 2000.
Marketing Revenue. Revenues from natural gas marketing activities increased to
$5.0 million in the first half of 2001 as compared to $2.9 million in the first
half of 2000. This increase was due to an increase in the sales price per MMBtu.
The average sales price per MMBtu increased from $3.21 in the first half of 2000
to $5.49 in the first half of 2001.
Lease Operating Expense. Our lease operating expenses for the first half of
2001 increased to $7.7 million from $6.4 million in the first half of 2000.
This increase was primarily the result of increased geological and geophysical
expenses as well as an increase in workover activities.
Gas Purchased-Marketing. Our cost of purchased gas was $4.9 million for the
first half of 2001 compared to $2.8 million for the first half of 2000. The
average cost increased from $3.08 per MMbtu in 2000 to $5.38 per MMbtu in 2001.
General and Administrative Expense. General and administrative expense
increased to $4.1 million for the first half of 2001 compared to $2.7 million
for the same period in 2000. The primary reason for the increase was the result
of higher compensation and related expenses due to an increase in the number of
employees from 23 at the end of the first half of 2000 to 44 at the end of first
half of 2001. In addition, our U.K. office was opened in the third quarter of
2000.
Non-cash Compensation Expense. In the first half of 2001, we recorded a non-
cash charge to compensation expense of approximately $2.5 million for options
granted since September 1999 through the date of our initial public offering on
February 5, 2001, as well as for certain options granted prior to September 1999
and exercised during the current period. The expense will be amortized using
the straight-line method over the period between the initial public offering and
the vesting date of the options.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion and
amortization expense increased 50% from $16.7 million in the first half of 2000
to $25.1 million in the first half of 2001.
Impairment Expense. As of June 30, 2001, the future undiscounted cash flows
were less than their individual net book value on five of our properties. As a
result, we recorded impairments of $14.2 million in the first six months of
2001. These impairments were primarily the result of drilling a non-commercial
development well and a reduction in expected future undiscounted cash flows on
the other properties due to lower natural gas prices at June 30, 2001. For the
first half of 2000, we recorded an impairment of $6.3 million related to one
property as a result of a reduction in recoverable reserves.
Other Income (Expense). In the first six months of 2001, we recorded a loss on
derivative instruments of $14.2 million comprised of a realized loss of $28.3
million and an unrealized gain of $14.1 million. The realized loss represents
derivative contracts settled in the first half of 2001, while the offsetting
gain represents the change in the fair market value of the open derivative
positions at June 30, 2001. Prior to the adoption of SFAS 133, realized gains or
losses were recorded as a component of revenue.
Interest expense decreased from the first half of 2000 compared to the first
half of 2001. We capitalized none and $0.7 million of interest for the six
months ended June 30, 2001 and 2000, respectively.
14
LIQUIDITY AND CAPITAL RESOURCES
General
We have financed our acquisition and development activity through a
combination of project-based development arrangements, bank borrowings and
proceeds from our February 2001 initial public offering, as well as cash from
operations. We believe that our capital resources, cash flow from operations
and borrowings under our existing or new credit facilities will be sufficient to
fund short-term liquidity as well as fund ongoing capital expenditures for the
foreseeable future. However, future cash flows are subject to a number of
variables including the level of production and oil and natural gas prices. No
assurance can be given that operations and other capital resources will provide
cash in sufficient amounts to maintain planned levels of operations and capital
expenditures.
Cash Flows
SIX MONTHS ENDED,
JUNE 30,
------------------
2001 2000
------- ------
(in millions)
Cash provided by (used in)
Operating activities........ $ 53.8 $ 24.7
Investing activities........ (82.2) (40.7)
Financing activities........ 18.4 6.4
Cash provided by operating activities in the first half of 2001 primarily
reflects increased price realizations, partially offset by net cash used in
price risk management activities.
Cash used in investing activities totaled $82.2 million in the first half of
2001 as compared to $40.7 million in the same period of 2000. The 2001 amount
includes expenditures on oil and gas properties of $81.9 million, of which $23.9
million was used for the acquisition of fifteen properties in the Gulf of Mexico
and Southern Gas Basin area of the U.K. North Sea, $5.6 million was used to
purchase the overriding royalty interests associated with our non-recourse debt
and $52.4 million was used for development. Comparable expenditures for
acquisition and development in 2000 were $2.3 million and $38.3 million,
respectively.
Cash provided from financing activities includes the proceeds from our initial
public offering in February 2001 of $78.3 million including the underwriters'
discount. We also incurred costs of approximately $0.9 million in connection
with the offering, which in addition to costs incurred in the fourth quarter of
2000, totaled approximately $1.5 million. Financing activities also included
the repayment of our prior credit facilities of $119.9 million and proceeds of
$65.0 million from our new credit facility.
Credit Agreements
In March 2001, we repaid our then existing bank credit facility and in April
2001 we repaid the full amount borrowed under the non-recourse development
program credit agreement. Concurrent with the repayment, we negotiated with the
lender to terminate the overriding royalty interest on all properties previously
financed by the lender in exchange for a lump-sum payment of approximately $5.6
million.
Upon repayment of our former credit and non-recourse facilities, we entered
into a new $100.0 million senior-secured revolving credit facility in April
2001. The amount available for borrowing under the facility is limited to the
loan value, as determined by the bank, of oil and gas properties pledged under
the facility. The borrowing base at June 30, 2001 was $60.0 million. This
facility is secured by substantially all of our oil and gas properties, as well
as by approximately two-thirds of the capital stock of our U.K. subsidiary. If
our outstanding balance exceeds our borrowing base at any time, we are required
to repay such excess within 30 days and our interest rate during the time an
excess exists is increased by 2.00%.
15
Advances under the credit facility can be in the form of either base rate
loans or Eurodollar loans. The interest on a base rate loan is a fluctuating
rate equal to the higher of the Federal funds rate plus 0.5% and the bank base
rate, plus a margin of 0.00%, 0.25% or 0.75% depending on the amount outstanding
under the credit agreement. The interest on a Eurodollar loan is equal to the
Eurodollar rate, plus a margin of 1.50%, 1.75%, 2.00%, 2.25% or 2.75% depending
on the amount outstanding under the credit facility. The credit facility
matures in December 2003. Our credit facility contains conditions and
restrictive provisions, among other things, (1) prohibiting us to enter into any
arrangement to sell or transfer any of our material property, (2) prohibiting a
merger into or consolidation with any other person or sell or dispose of all or
substantially all of our assets, and (3) maintaining certain financial ratios.
At June 30, 2001, we were in compliance with all terms of the agreement.
Effective June 29, 2001, we issued a promissory note to a purchaser for a face
principal amount of $31.3 million which matures in June 2005 and bears interest
at a fixed rate of 11.5% per annum. The note is secured by second priority liens
on substantially all of our oil and gas properties and is subordinated in right
of payment to our existing senior indebtedness. We executed an agreement in
connection with the note which contains conditions and restrictive provisions
and requires the maintenance of certain financial ratios. Upon consent of the
purchaser, which shall not be unreasonably withheld, the note may be repaid
prior to the maturity date with an additional repayment premium, based on the
percentage of the principal amount paid, ranging from 4.5% during the first year
to 16.5% in the final year of payment. At maturity, a payment premium of 16.5%
is required. In July 2001, we received proceeds of $30.0 million in
consideration for the issuance of the note. The promissory note was originally
scheduled to close in June 2001, but due to Tropical Storm Allison disrupting
the operations of certain participants in the transaction, the closing did not
take place until July 2001.
At June 30, 2001, we had a working capital deficit of $45.7 million. The funds
from the promissory note significantly decreased this deficit as all of the
proceeds are classified as long-term debt. The remaining deficit after the
closing will be eliminated through the normal course of operating cash flows.
The borrowing base under the $100.0 million credit facility is currently under
review. As a result of recent increases in our oil and gas reserves and several
properties projected to begin production in the third quarter of 2001, we
anticipate that the borrowing base will be increased from its current level. In
addition, we are pursuing the sale of several non-core properties which we
believe will be consummated in the third or fourth quarter of 2001. We continue
to pursue other sources of funds to decrease our working capital deficit. Our
ability to complete development projects, acquire additional property interests
and eliminate current obligations in a timely manner may be impacted by this
situation.
2001 Acquisitions
Gulf of Mexico. In the first half of 2001, we acquired twelve properties in
the Gulf of Mexico region. Nine of the properties were acquired in the first
quarter and three in the second quarter. Eight of the above properties were
producing when acquired, with additional development operations planned during
2001 and 2002.
Southern Gas Basin of the U.K. North Sea. In October 2000, we entered into a
letter of intent to acquire interests in three properties in the Southern Gas
Basin of the U.K. North Sea. In the first quarter of 2001 we acquired two of
the three properties covered by the October 2000 letter of intent. We acquired
the third property in the second quarter of 2001. None of these properties are
currently producing.
The total acquisition costs during 2001 for the above properties were
approximately $23.9 million.
16
ADOPTION OF SFAS 133
Effective January 1, 2001, we adopted SFAS No. 133 and SFAS No. 138, an
amendment to SFAS 133. SFAS 133 and 138 require that derivatives be reported on
the balance sheet at fair value and, if the derivative is not designated as a
hedging instrument, changes in fair value must be recognized in earnings in the
period of change. If the derivative is designated as a hedge and to the extent
such hedge is determined to be effective, changes in fair value are either (a)
offset by the change in fair value of the hedged asset or liability (if
applicable) or (b) reported as a component of other comprehensive income (loss)
in the period of change, and subsequently recognized in earnings when the
offsetting hedged transaction occurs. We use derivatives to hedge the price of
crude oil and natural gas and effective January 1, 2001, we account for the
changes in market value of these derivatives through current earnings. This
method will result in increased earnings volatility associated with commodity
price fluctuations. Gains and losses on all derivative instruments related to
accumulated other comprehensive income (loss) are included in other income
(expense) on the consolidated financial statements.
On January 1, 2001, in accordance with the transition provisions of SFAS 133,
we recorded a non-cash loss of $52.7 million ($34.3 million after tax) in
accumulated other comprehensive loss, representing the cumulative effect of an
accounting change to recognize at fair value all cash flow type derivatives.
Also on January 1, 2001, we recorded derivative liabilities of $52.7 million.
During the first six months of 2001, losses of $44.6 million ($29.0 million
after tax) were reclassified from accumulated other comprehensive loss to
earnings. The remaining after-tax loss of $5.3 million recorded in other
comprehensive loss will be reclassified to earnings during the last six months
of the year ended December 31, 2001 as the transactions are settled. Prior to
the adoption of this standard, we included gains and losses on hedging
instruments as a component of revenue. As of June 30, 2001, the fair market
value of our derivatives consisted of a $2.5 million asset and a $1.1 million
liability.
Recent Accounting Pronouncements
In June 2001, the FASB approved SFAS No. 141 "Business Combinations" ("SFAS
141"), No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142") and No. 143
"Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 141 requires
all business combinations completed after June 30, 2001, be accounted for under
the purchase method. This standard also establishes for all business
combinations made after June 30, 2001, specific criteria for the recognition of
intangible assets separately from goodwill. SFAS 141 also requires that the
excess of fair value of acquired assets over cost (negative goodwill) be
recognized immediately as an extraordinary gain, rather than deferred and
amortized. We will account for all future business combinations under SFAS 141.
SFAS 142 addresses the accounting for goodwill and other intangible assets
after an acquisition. The most significant changes made by SFAS 142 are: 1)
goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must be
tested for impairment at least annually; and 3) the amortization period for the
intangible assets with finite lives will no longer be limited to forty years. We
will adopt SFAS 142 effective January 1, 2002, as required. Additionally, SFAS
142 requires that unamortized negative goodwill associated with investments
accounted for under the equity method and acquired before July 1, 2001, be
recognized in income as a cumulative effect of change in accounting principle.
Adoption of this standard will have no impact on our financial position or
results of operations.
17
SFAS 143 provides accounting requirements for retirement obligations
associated with tangible long-lived assets, including: 1) the timing of
liability recognition; 2) initial measurement of the liability; 3) allocation of
asset retirement cost to expense; 4) subsequent measurement of the liability;
and 5) financial statement disclosures. SFAS 143 requires that an asset
retirement cost should be capitalized as part of the cost of the related long-
lived asset and subsequently allocated to expense using a systematic and
rational method. We will adopt the Statement effective January 1, 2003. The
transition adjustment resulting from the adoption of SFAS 143 will be reported
as a cumulative effect of a change in accounting principle. At this time, we
cannot reasonably estimate the effect of the adoption of this statement on
either our financial position or results of operations.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
We are exposed to various market risks, including volatility in natural gas
and oil commodity prices and interest rates. To manage such exposure, we monitor
our expectations of future commodity prices and interest rates when making
decisions with respect to risk management. All of our derivative contracts are
entered into with major financial or oil and gas institutions and the risk of
credit loss is considered insignificant.
Commodity Price Risk. Our revenues, profitability and future growth depend
substantially on prevailing prices for natural gas and oil. Prices also affect
the amount of cash flow available for capital expenditures and our ability to
borrow and raise additional capital. The amount we can borrow under our bank
credit facility is subject to periodic re-determination based in part on
changing expectations of future prices. Lower prices may also reduce the amount
of natural gas and oil that we can economically produce. We currently sell most
of our natural gas and oil production under price sensitive or market price
contracts. To reduce exposure to fluctuations in natural gas and oil prices and
to achieve more predictable cash flow, we periodically enter into derivative
arrangements that usually consist of swaps or price collars that are settled in
cash. However, these contracts also limit the benefits we would realize if
commodity prices increase. We generally acquire properties at prices that are
below the value of estimated reserves at the then current natural gas and oil
prices. We will enter into short term derivative arrangements if we are able to
obtain commodity contracts at prices sufficient to secure an acceptable internal
rate of return on a particular property or on a group of properties. All of our
commodity derivative financial instruments are accounted for on a mark-to-market
basis beginning January 1, 2001 upon adoption of SFAS 133 and SFAS 138 discussed
previously.
As of June 30, 2001, we had the following financial hedges on natural gas in
place:
SWAPS COLLARS AND OPTIONS
--------- ------------------------
AVERAGE AVERAGE AVERAGE AVERAGE
MMBTU/DAY $/MMBTU MMBTU/DAY $/MMBTU
--------- ------- --------- ------------
Period:
Third quarter 2001.... 28,400 2.84 9,300 5.10 to 6.15
Fourth quarter 2001... 9,300 2.87 3,100 5.10 to 6.15
We have no hedges that extend beyond October 2001.
In addition to the above financial hedges on natural gas, we also have in
place a written call option contract that provides us a price for natural gas
above the then prevailing market price, but with a ceiling price. For the period
July 2001 through October 2001, we receive NYMEX settlement plus $0.15 with a
ceiling price of $ 3.50 per MMBtu on 10,000 MMBtu per day.
Interest Rate Risk. We are exposed to changes in interest rates. Changes in
interest rates affect the interest earned on our cash and cash equivalents and
the interest rate paid on borrowings under the credit agreements. Under our
current policies, we do not use interest rate derivative instruments to manage
exposure to interest rate changes.
18
FORWARD-LOOKING STATEMENTS AND ASSOCIATED RISKS
Some of the information included in this quarterly report includes
assumptions, expectations, projections, intentions or beliefs about future
events. These statements are intended as "forward-looking statements" under the
Private Securities Litigation Reform Act of 1995. We caution that assumptions,
expectations, projections, intentions and beliefs about future events may and
often do vary from actual results and the differences can be material.
All statements in this document that are not statements of historical fact are
forward looking statements. Forward looking statements include, but are not
limited to:
. projected operating or financial results;
. budgeted or projected capital expenditures;
. statements about pending or recent acquisitions, including the anticipated
closing dates;
. expectations regarding our planned expansions and the availability of
acquisition opportunities;
. statements about the expected drilling of wells and other planned development
activities;
. expectations regarding natural gas and oil markets in the United States and
the United Kingdom; and
. timing and amount of future production of natural gas and oil.
When used in this document, the words "anticipate," "estimate," "project,"
"forecast," "may," "should," and "expect" reflect forward-looking statements.
There can be no assurance that actual results will not differ materially from
those expressed or implied in such forward looking statements. Some of the key
factors which could cause actual results to vary from those expected include:
. the timing and extent of changes in natural gas and oil prices;
. the timing of planned capital expenditures and availability of acquisitions;
. the inherent uncertainties in estimating proved reserves and forecasting
production results;
. operational factors affecting the commencement or maintenance of producing
wells, including catastrophic weather related damage, unscheduled outages or
repairs, or unanticipated changes in drilling equipment costs or rig
availability;
. the condition of the capital markets generally, which will be affected by
interest rates, foreign currency fluctuations and general economic
conditions;
. cost and other effects of legal and administrative proceedings, settlements,
investigations and claims, including environmental liabilities which may not
be covered by indemnity or insurance; and
. other U.S. or United Kingdom regulatory or legislative developments which
affect the demand for natural gas or oil generally, increase the
environmental compliance cost for our production wells or impose liabilities
on the owners of such wells.
19
PART II. OTHER INFORMATION
Items 1, 3, 4 & 5 are not applicable and have been omitted.
Item 2. Changes in Securities and Use of Proceeds
On September 18, 2000, we filed a registration statement on Form S-1 (File No.
333-46034) relating to an initial public offering of 6,000,000 shares of our
common stock for an aggregate offering price of $84.0 million. On February 5,
2001, the registration statement on Form S-1 was declared effective. The public
offering price was $14.00 per share of common stock, and the underwriting
discounts and commissions were $0.94 per share of common stock. The offering
closed on February 9, 2001. The proceeds from the offering, after deducting the
underwriting discounts and commissions, but before deducting expenses associated
with the offering, were $78.3 million. Our net offering proceeds, after
deducting the underwriting discounts, commissions and expenses associated with
the offering, were $76.8 million.
We used the net proceeds from our initial public offering, together with the
proceeds from our new credit facility, to repay all of our outstanding debt
under our development program credit agreement and our prior bank credit
facility and to acquire natural gas and oil properties.
The managing underwriters for the offering were Lehman Brothers, CIBC World
Markets Corp., Dain Rauscher Incorporated, Raymond James & Associates, Inc. and
Fidelity Capital Markets, a division of National Financial Services LLC.
Item 6 - Exhibits and Reports on Form 8-K
A. Exhibits
10.1 First Amendment to Credit Agreement dated June 29, 2001, among ATP Oil
& Gas Corporation and BNP Paribas, as Agent, and the Lenders Signatory
thereto.
10.2 Second Amendment to Credit Agreement dated June 29, 2001, among ATP
Oil & Gas Corporation and BNP Paribas, as Agent, and the Lenders
Signatory thereto.
10.3 Note Purchase Agreement dated June 29, 2001 between ATP Oil & Gas
Corporation and Aquila Energy Capital Corporation.
10.4 Intercreditor and Subordination Agreement dated June 29, 2001, among
ATP Oil & Gas Corporation, Aquila Energy Capital Corporation, BNP
Paribas, as Agent, and the Lenders Signatory thereto.
10.5 Third Amendment to Credit Agreement dated June 30, 2001, among ATP Oil
and Gas Corporation and BNP Paribas, as agent, and the Lenders
Signatory thereto.
B. Reports on Form 8-K - None.
20
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned and thereunto duly authorized.
ATP Oil & Gas Corporation
Date: August 14, 2001 By: /s/ Albert L. Reese, Jr.
------------------------
Albert L. Reese, Jr.
Senior Vice President and Chief
Financial Officer
21