================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 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 November 10, 2001, was 20,307,944.
================================================================================
ATP OIL & GAS CORPORATION
TABLE OF CONTENTS
PAGE
----
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets:
September 30, 2001 and December 31, 2000.......................... 3
Consolidated Statements of Operations:
For the three and nine months ended September 30, 2001 and 2000... 4
Consolidated Statements of Cash Flows:
For the nine months ended September 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............................................... 21
2
ITEM 1. FINANCIAL STATEMENTS
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)
September 30, December 31,
2001 2000
------------- ------------
(unaudited)
ASSETS
Current assets:
Cash and cash equivalents.................................................... $ 9,511 $ 18,136
Accounts receivable (net of allowance of $1,174 and $443, respectively)...... 15,818 32,542
Deferred tax asset........................................................... 689 -
Commodity contracts and other derivatives.................................... 2,690 -
Other current assets......................................................... 3,862 2,597
--------- ---------
Total current assets....................................................... 32,570 53,275
--------- ---------
Oil and gas properties:.......................................................
Oil and gas properties (using the successful efforts method of accounting)... 317,620 209,548
Less: Accumulated depletion and impairment................................... (164,648) (110,823)
--------- ---------
Oil and gas properties, net................................................ 152,972 98,725
--------- ---------
Furniture and fixtures (net of accumulated depreciation)...................... 800 487
Deferred tax asset............................................................ 11,950 7,652
Other assets, net............................................................. 3,407 1,854
--------- ---------
Total assets............................................................... $ 201,699 $ 161,993
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable and accruals................................................ $ 64,917 $ 49,799
Current maturities of long-term debt......................................... - -
Commodity contracts and other derivatives.................................... - 7,248
Other deferred obligations................................................... 63 63
--------- ---------
Total current liabilities.................................................. 64,980 57,110
Long-term debt................................................................ 80,046 27,750
Non-recourse borrowings....................................................... - 88,779
Commodity contracts and other derivatives..................................... 506 -
Deferred revenue.............................................................. 1,343 1,481
Other long-term liabilities and deferred obligations.......................... 243 52
--------- ---------
Total liabilities.......................................................... 147,118 175,172
--------- ---------
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;
20,383,784 issued and 20,307,944 outstanding at September 30, 2001
and 14,285,714 issued and outstanding at December 31, 2000................. 20 14
Additional paid in capital................................................... 80,036 38
Accumulated deficit.......................................................... (23,392) (13,231)
Accumulated other comprehensive loss......................................... (1,172) -
Treasury stock, at cost...................................................... (911) -
--------- ---------
Total shareholders' equity (deficit)....................................... 54,581 (13,179)
--------- ---------
Total liabilities and shareholders' equity (deficit)....................... $ 201,699 $ 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 Nine Months Ended
September 30, September 30,
------------------- ------------------
2001 2000 2001 2000
---- ---- ---- ----
Revenue:
Oil and gas production..................... $19,571 $18,357 $ 87,081 $ 55,090
Gas sold - marketing....................... 1,312 2,105 6,280 5,024
Gain on sale of oil and gas properties..... - - - 33
------- ------- -------- --------
Total revenues............................ 20,883 20,462 93,361 60,147
------- ------- -------- --------
Costs and operating expenses:
Lease operating expenses................... 2,454 1,941 9,707 8,363
Gas purchased - marketing.................. 1,260 2,054 6,127 4,856
Geological and geophysical expenses........ 764 - 1,236 -
General and administrative expenses........ 2,663 1,280 6,713 4,018
Non-cash compensation expense.............. 464 - 2,930 -
Depreciation, depletion and amortization... 13,399 13,991 38,503 30,686
Impairment on oil and gas properties....... 3,655 783 17,838 7,038
------- ------- -------- --------
Total costs and operating expenses........ 24,659 20,049 83,054 54,961
------- ------- -------- --------
Net income (loss) from operations........... (3,776) 413 10,307 5,186
------- ------- -------- --------
Other income (expense):
Interest income............................ 60 78 853 333
Interest expense........................... (2,109) (3,299) (7,130) (8,445)
Gain (loss) on derivative instruments...... (3,334) (3,729) (17,496) (6,242)
------- ------- -------- --------
Total other income (expense).............. (5,383) (6,950) (23,773) (14,354)
------- ------- -------- --------
Net loss before income taxes and
extraordinary item......................... (9,159) (6,537) (13,466) (9,168)
Income tax benefit - deferred............... 2,660 2,286 3,907 3,204
------- ------- -------- --------
Net loss before extraordinary item.......... (6,499) (4,251) (9,559) (5,964)
Extraordinary item, net of tax.............. - - (602) -
------- ------- -------- --------
Net loss.................................... $(6,499) $(4,251) $(10,161) $ (5,964)
======= ======= ======== ========
Basic and diluted earnings (loss)
per common share:
Loss before extraordinary item............ $ (0.32) $ (0.30) $ (0.49) $ (0.42)
Extraordinary item, net of tax............ - - (0.03) -
------- ------- -------- --------
Net loss per common share................. $ (0.32) $ (0.30) $ (0.52) $ (0.42)
======= ======= ======== ========
Weighted average number of common shares:
Basic and diluted 20,297 14,286 19,499 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)
Nine Months Ended
September 30,
------------------------
2001 2000
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss.................................................... $ (10,161) $ (5,964)
Adjustments to reconcile net loss to net cash
provided by operating activities -
Depreciation, depletion and amortization.................. 38,503 30,686
Impairment of oil and gas properties...................... 17,838 7,038
Amortization of deferred financing costs.................. 494 237
Extraordinary item........................................ 926 -
Deferred tax asset........................................ (4,298) (3,204)
Non-cash compensation expense............................. 2,930 -
Gain on sale of oil and gas properties.................... - (33)
Other non-cash items...................................... 220 431
Changes in assets and liabilities -
Accounts receivable and other.............................. 15,459 (13,437)
Restricted cash............................................ - 471
Net (assets) liabilities from commodity contracts and
other derivatives......................................... (11,401) 2,496
Accounts payable and accruals.............................. 15,045 17,291
Other long-term assets..................................... (3,523) (485)
Other long-term liabilities and deferred credits........... 53 (208)
--------- --------
Net cash provided by operating activities.................... 62,085 35,319
--------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions and acquisitions of oil and gas properties........ (108,378) (50,558)
Additions to furniture and fixtures......................... (480) (288)
--------- --------
Net cash used in investing activities........................ (108,858) (50,846)
--------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from initial public offering....................... 78,330 -
Payment of offering costs................................... (893) (192)
Proceeds from long-term debt................................ 95,000 15,800
Payments of long-term debt.................................. (42,750) (3,750)
Proceeds from non-recourse borrowings....................... 3,359 24,924
Payments of non-recourse borrowings......................... (92,138) (19,857)
Deferred financing costs.................................... (2,042) (111)
Treasury stock purchases.................................... (911) -
Other....................................................... 193 -
--------- --------
Net cash provided by financing activities.................... 38,148 16,814
--------- --------
Increase (decrease) in cash and cash equivalents............. (8,625) 1,287
Cash and cash equivalents, beginning of period............... 18,136 17,779
--------- --------
Cash and cash equivalents, end of period..................... $ 9,511 $ 19,066
========= ========
Supplemental disclosures of cash flow information:
Cash paid during the period for interest.................... $ 2,054 $ 1,720
========= ========
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 September 30, 2001 and December 31, 2000,
the results of our operations for the three months and nine months ended
September 30, 2001 and 2000 and cash flows for the nine months ended September
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 nine months
ended September 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 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 nine months of 2001, losses of $50.7 million ($33.0 million
after tax) were reclassified from accumulated other comprehensive loss to
earnings. The remaining after-tax loss of $1.3 million recorded in other
comprehensive loss will be reclassified to earnings during the last three months
of the year ended December 31, 2001 as the transactions
6
are settled. Prior to the adoption of this standard, we included gains and
losses on hedging instruments as a component of revenue. As of September 30,
2001, the fair market value of our derivatives consisted of a $2.7 million
current asset and a $0.5 million long-term liability.
NOTE 3 -- RECENT ACCOUNTING PRONOUNCEMENTS
In 2001, the FASB approved SFAS No. 141 "Business Combinations" ("SFAS 141"),
No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142"), No. 143
"Accounting for Asset Retirement Obligations" ("SFAS 143") and No. 144
"Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144").
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.
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.
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.
SFAS 144 provides that long-lived assets to be disposed of by sale be measured
at the lower of carrying amount or fair value less cost to sell, whether
reported in continuing operations or in discontinued operations, and broadens
the reporting of discontinued operations to include all components of an entity
with operations that can be distinguished from the rest of the entity and that
will be eliminated from the ongoing operations of the entity in a disposal
transaction. SFAS 144 is effective for fiscal years beginning after December 15,
2001.
SFAS 141 and SFAS 142 will not apply to us unless we enter into a future
business combination. We are currently assessing the impact of SFAS 143 and SFAS
144 on our financial condition and results of operations.
NOTE 4 -- ACQUISITION OF OIL & GAS PROPERTIES
Gulf of Mexico. In the first nine months of 2001, we acquired fourteen
properties in the Gulf of Mexico region. Nine of the properties were acquired
in the first quarter, three in the second quarter and two in the third quarter.
Eight of the above properties were producing when acquired, with additional
development operations planned in 2002.
Southern Gas Basin of the U.K. North Sea. In the first quarter of 2001 we
acquired two of the three properties covered by an 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 $25.2 million.
7
NOTE 5 -- LONG-TERM DEBT
Our long-term debt as of September 30, 2001 and December 31, 2000 consisted of
the following (in thousands):
September 30, December 31,
2001 2000
------------- ------------
Credit facility............................... $50,000 $ 27,750
Note payable, net of unamortized discount
of $1,204.................................... 30,046 -
Non-recourse borrowings....................... - 88,779
------- --------
Total long-term debt......................... $80,046 $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. 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.
On November 5, 2001 we amended our existing credit facility and increased our
borrowing base to $70.0 million, thereby increasing our liquidity and
flexibility. The margin on the bank base rate was increased to 0.25%, 0.50%,
0.75% or 1.00% depending on the amount outstanding under the credit agreement.
The margin on a Eurodollar loan was also increased to 2.25%, 2.50%, 2.875% or
3.125% depending on the amount outstanding under the credit agreement. The
amended facility matures in November 2003.
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. If the note is paid at maturity, the
maximum payment premium of 16.5% is required. The repayment premium is being
amortized to interest expense straight-line, over the term of the note which
approximates the effective interest method. The resulting liability is included
in other long-term liabilities on the consolidated balance sheet. In July 2001,
we received proceeds of $30.0 million in consideration for the issuance of the
note. The discount of $1.3 million is being amortized to interest expense using
the effective interest method. The amount available for borrowing under the note
is limited to the loan value of oil and gas properties pledged under the note,
as determined by the purchaser. The borrowing base is scheduled for
redetermination at least once every six months. If our outstanding balance
exceeds the borrowing base at any time, we are required to repay such excess
within 10 days subject to the provisions of the agreement.
8
NOTE 6 -- EARNINGS PER SHARE
Basic loss per share is computed by dividing net loss available to common
shareholders by the weighted average number of common shares outstanding during
the period. Diluted loss 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 loss per share is computed based on the following
information (in thousands, except per share amounts):
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- ------------------
2001 2000 2001 2000
------- ------- ------- -------
Net loss.................................................. $(6,499) $(4,251) $(10,161) $(5,964)
======= ======= ======= =======
Weighted average shares outstanding - basic and diluted... 20,297 14,286 19,499 14,286
======= ======= ======= =======
Net loss per share - basic and diluted.................... $ (0.32) $ (0.30) $ (0.52) $ (0.42)
======= ======= ======= =======
NOTE 7 -- STOCK OPTION COMPENSATION
We recorded a non-cash charge to compensation expense of approximately $2.9
million for the nine months ended September 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 the
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 nine months ended September 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 nine months ended
September 30, 2001 is as follows (in thousands):
Three Nine
Months Months
Ended Ended
September 30, September 30,
2001 2001
------------ ------------
Net loss.................................................................. $( 6,499) $(10,161)
-------- --------
Other comprehensive income (loss), net of tax:
Cumulative effect of change in accounting principle - January 1, 2001... - (34,252)
Reclassification adjustment for settled contracts....................... 3,991 32,972
Foreign currency translation adjustment................................. 172 108
------- --------
Other comprehensive income (loss)...................................... 4,163 (1,172)
------- --------
Comprehensive loss........................................................ $( 2,336) $(11,333)
======== ========
There were no items in other comprehensive income (loss) during 2000.
NOTE 10 -- LIQUIDITY, COMMITMENTS AND CONTINGENCIES
Our working capital position has improved since September 30,
2001 as a result of the renegotiation of our existing credit facility, cash
flows from operations and a reduction of expenditures related to the
curtailment of current development activity. The borrowing base under the
$100.0 million credit facility was increased from $50.0 million as of September
30, 2001 to $70.0 million on November 5, 2001. As a result of recent increases
in our oil and gas reserves and production levels, we expect that the borrowing
base will be increased from its current level at the next scheduled borrowing
base review on or about January 1, 2002, further improving our working capital
position. In response to our working capital deficit of $32.4 million as of
September 30, 2001, and lower gas prices prevailing in the third quarter and
softening development costs which we expect will continue into 2002, we have
significantly reduced our planned development activities in the third and fourth
quarters of 2001 and postponed these activities until 2002. We are currently in
negotiations with several lenders and potential investors to provide significant
additional private capital. Although there can be no assurance we will be
successful in negotiating these transactions, we believe these transactions,
combined with our current credit facility and cash flow from operating
activities will provide us with additional flexibility and liquidity, including
liquidity to meet our future development plans. If we are not successful in
closing these transactions, our ability to develop and produce our oil and gas
properties as planned will be negatively impacted.
On August 28, 2001, we signed an agreement to acquire an offshore block in the
Outer Continental Shelf of the Gulf of Mexico. Principal assets to be acquired
included interests in proved oil and gas reserves and associated wells,
platforms and facilities. The agreement contemplated a closing date of
September 28, 2001. However, due to certain circumstances including events which
transpired on September 11, 2001, we were unable to obtain necessary financing
and consummate the transaction by that date. On October 9, 2001, we entered into
an amendment to extend the agreement and scheduled closing date to October 31,
2001 to allow us to complete our financing arrangements. As contemplated by the
agreement, we released to the seller $2.0 million previously deposited in
escrow, which amount is nonrefundable, and reduced the purchase price by a
corresponding amount. In addition, we paid $1.0 million to the seller on October
23, 2001, which is non refundable. To date, the closing of the transaction has
not occurred. We are currently in discussions with the seller to complete the
transaction and are seeking to obtain the necessary financing. Included in other
current assets on the consolidated balance sheet at September 30, 2001 is $2.0
million paid into escrow prior to the end of the third quarter and subsequently
released to the seller. If the transaction is not ultimately consummated by year
end, or likely to occur, all amounts paid to the seller will be charged to
expense. In addition, we would be required to pay the seller the sum of the
difference, if any, between the purchase price, as adjusted at the date of
closing and any lower purchase price paid by a third party to acquire the block
from the seller and the costs and expenses incurred by the seller. The amount of
any such additional payment is presently not ascertainable, but would be an
expense which would reduce earnings in the period in which the obligation is
incurred. Any such payment to the seller could be material and if so, would have
a substantial negative impact on our financial position, results of operations
and cash flows.
In August 2001, Burlington Resources Inc. filed suit against us alleging
formation of a contract with us and our breach of the alleged contract. The
complaint seeks compensatory damages of approximately $1.1 million. We believe
that this claim is without merit, and we intend to defend it vigorously.
We are, in the ordinary course of business, a claimant and/or defendant in
various legal proceedings. Management does not believe that the outcome of
these legal proceedings, individually, and in the aggregate will have a
materially adverse effect on our financial condition, results of operations or
cash flows.
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 Nine Months Ended
September 30, September 30,
------------------- ---------------------
2001 2000 2001 2000
------- ------- -------- --------
Production:
Natural gas (MMcf)................................. 5,512 5,498 16,298 17,302
Oil and condensate (MBbls)......................... 165 96 368 275
------- ------- -------- --------
Total (Mmcfe).................................... 6,504 6,079 18,505 18,953
Revenues (in thousands):
Natural gas........................................ $15,574 $24,524 $ 77,699 $ 62,082
Effects of risk management activities (1).......... 2,040 (8,711) (26,669) (13,794)
------- ------- -------- --------
Total............................................ $17,614 $15,813 $ 51,030 $ 48,288
======= ======= ======== ========
Oil and condensate................................. $ 3,997 $ 2,965 $ 9,382 $ 7,954
Effects of risk management activities.............. - (421) - (1,152)
------- ------- -------- --------
Total............................................ $ 3,997 $ 2,544 $ 9,382 $ 6,802
======= ======= ======== ========
Natural gas, oil and condensate.................... $19,571 $27,489 $ 87,081 $ 70,036
Effects of risk management activities (1).......... 2,040 (9,132) (26,669) (14,946)
------- ------- -------- --------
Total............................................ $21,611 $18,357 $ 60,412 $ 55,090
======= ======= ======== ========
Table continued on following page
11
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- ---------------------
2001 2000 2001 2000
------- ------- -------- --------
Average sales price per unit:
Natural gas (per Mcf).............................. $ 2.83 $ 4.46 $ 4.77 $ 3.59
Effects of risk management activities (per Mcf).... 0.37 (1.58) (1.64) (0.80)
------- ------- -------- --------
Total............................................ $ 3.20 $ 2.88 $ 3.13 $ 2.79
======= ======= ======== ========
Oil and condensate (per Bbl)....................... $ 24.20 $ 30.61 $ 25.50 $ 28.89
Effects of risk management activities (per Bbl).... - (4.35) - (4.18)
------- ------- -------- --------
Total............................................ $ 24.20 $ 26.26 $ 25.50 $ 24.71
======= ======= ======== ========
Natural gas, oil and condensate (per Mcfe)......... $ 3.01 $ 4.52 $ 4.71 $ 3.70
Effects of risk management activities (per Mcfe)... 0.31 (1.50) (1.44) (0.79)
------- ------- -------- --------
Total............................................ $ 3.32 $ 3.02 $ 3.27 $ 2.91
======= ======= ======== ========
Expenses (per Mcfe):
Lease operating expense............................ $ 0.38 $ 0.32 $ 0.52 $ 0.44
General and administrative......................... 0.41 0.21 0.36 0.21
Depreciation, depletion and amortization........... 2.06 2.30 2.08 1.62
- ---------------
(1) For 2001, represents the net loss on the settlement of derivatives
attributable to production of 6,504 Mmcfe and 18,505 Mmcfe for the three
and nine months ended September 30, 2001, respectively.
Three Months Ended September 30, 2001 Compared with Three Months Ended
September 30, 2000
For the three months ended September 30, 2001, we reported a net loss of $6.5
million, or $0.32 per basic and diluted share, on total revenue of $20.9
million, as compared with a net loss of $4.3 million, or $0.30 per basic and
diluted share, on total revenue of $29.6 million (excluding hedging effects) in
the third quarter of 2000. Adjusted EBITDA in the third quarter of 2001 was
$15.8 million compared with $14.2 million in the third 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 expense and extraordinary items. Our
Adjusted EBITDA margin was 69% in the third quarter of 2001 and 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 third quarter of 2001
decreased from the same period in 2000 from $27.5 million to $19.6 million. This
decrease was primarily due to an approximate 37% decrease in natural gas prices
partially offset by an 8% increase in production. The increase in production
volumes from 6.1 Bcfe to 6.5 Bcfe was attributable to additional properties
acquired in 2001 and development activities completed in 2001. Risk management
activities, which were included in oil and gas revenues in 2000 but excluded in
compliance with SFAS 133 in 2001, would have increased oil and natural gas
revenues by $2.0 million, or $0.31 per Mcfe in the third quarter of 2001 and
decreased oil and natural gas revenues by $9.1 million, or $1.50 per Mcfe, in
the third quarter of 2000.
Marketing Revenue. Revenues from natural gas marketing activities decreased to
$1.3 million in the third quarter of 2001 as compared to $2.1 million in the
third quarter of 2000. This decrease was due to a decrease in the sales price
per MMBtu. The average sales price per MMBtu decreased from $4.58 in the third
quarter of 2000 to $2.85 in the third quarter of 2001.
12
Lease Operating Expense. Our lease operating expenses for the third quarter of
2001 increased to $2.5 million from $1.9 million in the third quarter of 2000.
This increase was primarily the result of an increased number of properties.
Gas Purchased-Marketing. Our cost of purchased gas was $1.3 million for the
third quarter of 2001 compared to $2.1 million for the third quarter of 2000.
The average cost decreased from $4.47 per MMBtu in 2000 to $2.74 per MMBtu in
2001.
Geological and Geophysical Expense. In the third quarter of 2001, we recorded
$0.8 million of costs related to the acquisition of 3-D seismic data purchased
for development purposes on our recently acquired properties located in the UK.
General and Administrative Expense. General and administrative expense
increased to $2.7 million for the third quarter of 2001 compared to $1.3 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 31 at the end of the third quarter of 2000 to 44 at the end of
the third quarter of 2001.
Non-Cash Compensation Expense. In the third quarter of 2001, we recorded a
non-cash charge to compensation expense of approximately $0.5 million for
options granted since September 1999 through the date of our initial public
offering on February 5, 2001. The total expected expense as of the measurement
date will be recognized in the periods in which the option vests. Each option is
divided into three equal portions corresponding to the three vesting dates
(April 10, 2001, February 9, 2002, and February 9, 2003), with the related
compensation cost for each portion amortized straight-line over the period to
the vesting date.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion and
amortization expense decreased 4% from $14.0 million in the third quarter 2000
to $13.4 million in the third quarter 2001 due to impairments taken in previous
quarters.
Impairment Expense. As of September 30, 2001, the future undiscounted cash
flows were less than their individual net book value on two of our properties.
As a result, we recorded impairments of $3.7 million in the third quarter of
2001. These impairments were primarily the result of reductions in expected
future undiscounted cash flows on each property due to reserve adjustments at
September 30, 2001. For the third quarter of 2000, we recorded an impairment of
$0.8 million related to one property as a result of a reduction in recoverable
reserves.
Other Income (Expense). In the third quarter of 2001, we recorded a loss on
derivative instruments of $3.3 million comprised of a realized gain of $2.0
million and an unrealized loss of $5.3 million. The realized gain represents
derivative contracts settled in the third quarter of 2001, while the offsetting
loss represents the change in the fair market value of the open derivative
positions at September 30, 2001. Prior to the adoption of SFAS 133, realized
gains or losses were recorded as a component of revenue.
Interest expense for the third quarter of 2001 decreased to $2.1 million from
$3.3 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
September 30, 2001 or 2000.
Nine Months Ended September 30, 2001 Compared with Nine Months Ended September
30, 2000
For the nine months ended September 30, 2001, we reported a net loss of $10.2
million, or $0.52 per basic and diluted share, on total revenue of $93.4
million, as compared with a net loss of $6.0 million, or $0.42 per basic and
diluted share, on total revenue of $75.1 million (excluding hedging effects) in
the first nine months of 2000. Adjusted EBITDA in the first nine months of 2001
was $44.2 million compared with $41.7 million in the first nine months of 2000.
Our Adjusted EBITDA margin was 66% in the first nine months of 2001 and 69% in
the comparable period in 2000.
13
Oil and Gas Revenue. Excluding the effects of risk management activities, our
revenue from natural gas and oil production for the first nine months of 2001
increased approximately 24% over the same period in 2000, from $70.0 million to
$87.1 million. This increase was primarily due to an approximate 33% increase
in natural gas prices, partially offset by a 2% decrease in production. The
decrease in production volumes from 18.9 Bcfe to 18.5 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 $26.7
million, or $1.44 per Mcfe in the first nine months of 2001 compared with $14.9
million, or $0.79 per Mcfe in the first nine months of 2000.
Marketing Revenue. Revenues from natural gas marketing activities increased to
$6.3 million in the first nine months of 2001 as compared to $5.0 million in the
first nine months of 2000. This increase was due to an increase in the sales
price per MMBtu. The average sales price per MMBtu increased from $3.67 in the
first nine months of 2000 to $4.60 in the first nine months of 2001.
Lease Operating Expense. Our lease operating expenses for the first nine
months of 2001 increased to $9.7 million from $8.4 million in the first nine
months of 2000. This increase was primarily the result of an increased number
of properties.
Gas Purchased-Marketing. Our cost of purchased gas was $6.1 million for the
first nine months of 2001 compared to $4.9 million for the first nine months of
2000. The average cost increased from $3.54 per MMBtu in 2000 to $4.49 per
MMBtu in 2001.
Geological and Geophysical Expense. In the first nine months of 2001, we
recorded $1.2 million of costs related to the acquisition of 3-D seismic data
purchased for development purposes on our properties located in the Gulf of
Mexico ($0.5 million) and U.K. ($0.7 million).
General and Administrative Expense. General and administrative expense
increased to $6.7 million for the first nine months of 2001 compared to $4.0
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 31 at the end of the first nine months of 2000 to 44 at
the end of first nine months of 2001. In addition, our U.K. office was opened
in the third quarter of 2000.
Non-cash Compensation Expense. In the first nine months of 2001, we recorded a
non-cash charge to compensation expense of approximately $2.9 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 total expected
expense as of the measurement date will be recognized in the periods in which
the option vests. Each option is divided into three equal portions corresponding
to the three vesting dates (April 10, 2001, February 9, 2002, and February 9,
2003), with the related compensation cost for each portion amortized straight-
line over the period to the vesting date.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion and
amortization expense increased 25% from $30.7 million in the first nine months
of 2000 to $38.5 million in the first nine months of 2001.
Impairment Expense. As of September 30, 2001, the future undiscounted cash
flows were less than their individual net book value on six of our properties.
As a result, we recorded impairments of $17.8 million in the first nine months
of 2001. These impairments were primarily the result of drilling a non-
commercial development well at our Main Pass 282 property ($8.3 million) and a
reduction in expected future undiscounted cash flows on the other properties due
to reserve adjustments. For the first nine months of 2000, we recorded an
impairment of $7.0 million related to one property as a result of a reduction in
recoverable reserves.
14
Other Income (Expense). In the first nine months of 2001, we recorded a loss
on derivative instruments of $17.5 million comprised of a realized loss of $26.3
million and an unrealized gain of $8.8 million. The realized loss represents
derivative contracts settled in the first nine months of 2001, while the
offsetting gain represents the change in the fair market value of the open
derivative positions at September 30, 2001. Prior to the adoption of SFAS 133,
realized gains or losses were recorded as a component of revenue.
Interest expense decreased $1.3 million from $8.4 million in the first nine
months of 2000 to $7.1 million in the first nine months of 2001. We capitalized
none and $0.7 million of interest for the nine months ended September 30, 2001
and 2000, respectively.
Income Tax Benefit - Deferred. Income tax benefit of $3.9 million was
recognized for the nine months ended September 30, 2001 compared to an income
tax benefit of $3.2 million for the nine months ended September 30, 2000. The
effective income tax rates were approximately 29% and 35% for the first nine
months of 2001 and 2000, respectively. The difference in the income tax rate is
the result of permanent tax differences related to our U.K. subsidiary.
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
Nine Months Ended,
September 30,
------------------
2001 2000
------- ------
(in millions)
Cash provided by (used in)
Operating activities....... $ 62.1 $ 35.3
Investing activities....... (108.8) (50.8)
Financing activities....... 38.1 16.8
Cash provided by operating activities in the first nine months of 2001
primarily reflects increased price realizations, partially offset by net cash
used in price risk management activities.
Cash used in investing activities totaled $108.8 million in the first nine
months of 2001 as compared to $50.8 million in the same period of 2000. The
2001 amount includes expenditures on oil and gas properties of $108.4 million,
of which $25.2 million was used for the acquisition of 17 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 $77.6 million was used for development. Comparable
expenditures for acquisition and development in 2000 were $2.6 million and $48.0
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
proceeds of $65.0 million from our new credit facility and $30.0 million from a
promissory note (see Credit Agreements). Financing activities also included the
repayment of our prior credit facilities of $119.9 million and $15.0 million of
our current facility and promissory note.
15
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 September 30, 2001 was $50.0 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.
On November 5, 2001 we amended our existing credit facility and increased our
borrowing base from $50.0 million to $70.0 million, thereby increasing our
liquidity and flexibility. The margin on the bank base rate was increased to
0.25%, 0.50%, 0.75% or 1.00% depending on the amount outstanding under the
credit agreement. The margin on a Eurodollar loan was also increased to 2.25%,
2.50%, 2.875% or 3.125% depending on the amount outstanding under the credit
agreement. The amended facility matures in November 2003.
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 third 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. If the note is paid at maturity, the
maximum payment premium of 16.5% is required. The repayment premium is being
amortized to interest expense straight-line, over the term of the note which
approximates the effective interest method. The resulting liability is included
in other long-term liabilities on the consolidated balance sheet. In July 2001,
we received proceeds of $30.0 million in consideration for the issuance of the
note. The discount of $1.3 million is being amortized to interest expense using
the effective interest method. The amount available for borrowing under the note
is limited to the loan value of oil and gas properties pledged under the note,
as determined by the purchaser. The borrowing base is scheduled for
redetermination at least once every six months. If our outstanding balance
exceeds the borrowing base at any time, we are required to repay such excess
within 10 days subject to the provisions of the agreement.
Working Capital
Our working capital position has improved since September 30, 2001 as a result
of the renegotiation of our existing credit facility, cash flow from operations
and a reduction of expenditures related to the curtailment of current
development activity. The borrowing base under the $100.0 million credit
facility was increased from $50.0 million as of September 30, 2001 to $70.0
million on November 5, 2001. As a result of recent increases in our oil and gas
reserves and production levels, we expect that the borrowing base will be
increased from its current level at the
16
next scheduled borrowing base review on or about January 1, 2002, further
improving our working capital position. In response to our working capital
deficit of $32.4 million as of September 30, 2001, and lower gas prices
prevailing in the third quarter and softening development costs which we expect
will continue into 2002, we have significantly reduced our planned development
activities in the third and fourth quarters of 2001 and postponed activity until
2002. We are currently in negotiations with several lenders and potential
investors to provide significant additional private capital. Although there can
be no assurance we will be successful in negotiating these transactions, we
believe these transactions, combined with our current credit facility and cash
flow from operating activities will provide us with additional flexibility and
liquidity, including liquidity to meet our future development plans. If we are
not successful in closing these transactions, our ability to develop and produce
our oil and gas properties will be negatively impacted.
Commitments and Contingencies
On August 28, 2001, we signed an agreement to acquire an offshore block in the
Outer Continental Shelf of the Gulf of Mexico. Principal assets to be acquired
included interests in proved oil and gas reserves and associated wells,
platforms and facilities. The agreement, as amended, contemplated a closing date
of October 31, 2001. However, due to certain circumstances including events
which transpired on September 11, 2001, we were unable to obtain necessary
financing and consummate the transaction by that date. We are currently in
discussions with the seller to complete the transaction and are seeking to
obtain the necessary financing. If we are unable to consummate this acquisition,
we may be required to pay additional amounts which would reduce earnings in the
period such obligation is incurred. Any such reduction could be material to our
financial position, results of operations and cash flows in such period. See
Note 10 in the notes to the consolidated financial statements located elsewhere
in this report for further information.
In August 2001, Burlington Resources Inc. filed suit against us alleging
formation of a contract with us and our breach of the alleged contract. The
complaint seeks compensatory damages of approximately $1.1 million. We believe
that this claim is without merit, and we intend to defend it vigorously.
We are, in the ordinary course of business, a claimant and/or defendant in
various legal proceedings. Management does not believe that the outcome of
these legal proceedings, individually, and in the aggregate will have a
materially adverse effect on our financial condition, results of operations or
cash flows.
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 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 nine months of 2001, losses of $50.7 million ($33.0 million
after tax) were reclassified from accumulated other comprehensive loss to
earnings. The remaining after-tax loss of $1.3 million recorded in other
comprehensive loss will be reclassified to earnings during the last three 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 September 30, 2001, the fair market
value of our derivatives consisted of a $2.7 million current asset and a $0.5
million long-term liability.
17
Recent Accounting Pronouncements
In 2001, the FASB approved SFAS No. 141 "Business Combinations" ("SFAS
141"), No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142") No. 143
"Accounting for Asset Retirement Obligations" ("SFAS 143") and No. 144
"Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144").
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.
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.
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.
SFAS 144 provides that long-lived assets to be disposed of by sale be measured
at the lower of carrying amount or fair value less cost to sell, whether
reported in continuing operations or in discontinued operations, and broadens
the reporting of discontinued operations to include all components of an entity
with operations that can be distinguished from the rest of the entity and that
will be eliminated from the ongoing operations of the entity in a disposal
transaction. SFAS 144 is effective for fiscal years beginning after December 15,
2001.
SFAS 141 and SFAS 142 will not apply to us unless we enter into a future
business combination. We are currently assessing the impact of SFAS 143 and SFAS
144 on our financial condition and 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 redetermination 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 may 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.
18
As of September 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:
Fourth quarter 2001...... 16,100 2.92 3,100 5.10 to 6.15
2002..................... 10,000 3.00 - -
January - October 2003... 10,000 3.00 - -
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 October
2001, we received NYMEX settlement plus $0.15 with a ceiling price of
$3.50 per MMBtu on 10,000 MMBtu per day.
In October 2001, we entered into additional natural gas swaps beginning
November 1, 2001 and terminating at varying future dates. The volumes contracted
are 5,000 and 10,000 MMBtu per day at prices ranging from $2.83 to $3.07.
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.
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;
. statements regarding financing which may be obtained in the future;
. 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.
19
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;
. timing and availability of adequate financing upon acceptable terms;
. 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.
20
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
We are, in the ordinary course of business, a claimant and/or defendant in
various legal proceedings. Management does not believe that the outcome of
these legal proceedings, individually, and in the aggregate will have a
materially adverse effect on our financial condition, results of operations or
cash flows. See Note 10 in the notes to our consolidated financial statements
located elsewhere in this report.
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.
ITEMS 3, 4 & 5 ARE NOT APPLICABLE AND HAVE BEEN OMITTED.
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
A. Exhibits
10.1 Fourth Amendment to Credit Agreement dated October 1, 2001, among ATP
Oil & Gas Corporation and BNP Paribas, as Agent, and the Lenders
Signatory thereto.
10.2 Fifth Amendment to Credit Agreement dated November 5, 2001, among ATP
Oil & Gas Corporation and BNP Paribas, as Agent, and the Lenders
Signatory thereto.
B. Reports on Form 8-K - None.
21
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: November 14, 2001 By: /s/ Albert L. Reese, Jr.
----------------------------------
Albert L. Reese, Jr.
Senior Vice President and Chief
Financial Officer
22