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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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 May 10, 2001, was 20,285,714.
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ATP OIL & GAS CORPORATION
TABLE OF CONTENTS
PAGE
----
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets:
March 31, 2001 and December 31, 2000................. 3
Consolidated Statements of Operations:
For the three months ended March 31, 2001 and 2000... 4
Consolidated Statements of Cash Flows:
For the three months ended March 31, 2001 and 2000... 5
Notes to Consolidated Financial Statements................ 6
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.................. 10
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK................................................. 15
PART II. OTHER INFORMATION....................................... 17
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
MARCH 31, DECEMBER 31,
2001 2000
--------- -----------
(unaudited)
ASSETS
Current assets
Cash and cash equivalents.................................................... $ 34,833 $ 18,136
Accounts receivable (net of allowance of $707 and $443, respectively)........ 24,008 32,542
Deferred tax asset........................................................... 5,404 --
Commodity contracts and other derivatives.................................... 181 --
Other current assets......................................................... 4,531 2,597
--------- ---------
Total current assets....................................................... 68,957 53,275
--------- ---------
Oil and gas properties
Oil and gas properties (using the successful efforts method of accounting)... 257,934 209,548
Less: Accumulated depreciation, depletion, impairment and amortization....... (130,423) (110,823)
--------- ---------
Oil and gas properties, net................................................ 127,511 98,725
--------- ---------
Furniture and fixtures (net of accumulated depreciation)...................... 566 487
Deferred tax asset............................................................ 11,263 7,652
Other assets.................................................................. 1,319 1,854
--------- ---------
Total assets............................................................... $ 209,616 $ 161,993
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT)
Current liabilities
Accounts payable and accruals................................................ $ 59,853 $ 49,799
Commodity contracts and other derivatives.................................... 17,901 7,248
Other deferred obligations................................................... 63 63
--------- ---------
Total current liabilities.................................................. 77,817 57,110
Long-term debt................................................................ -- 27,750
Non-recourse borrowings....................................................... 82,076 88,779
Deferred revenue.............................................................. 1,435 1,481
Other long-term liabilities and deferred obligations.......................... 52 52
--------- ---------
Total liabilities.......................................................... 161,380 175,172
--------- ---------
Shareholders' equity (deficit)
Preferred stock: $0.001 par value, authorized 10,000,000 shares
at March 31, 2001 and December 31, 2000; none issued and
outstanding at March 31, 2001 and December 31, 2000........................
Common stock: $0.001 par value, authorized 100,000,000 shares
at March 31, 2001 and December 31, 2000; 20,285,714 shares and
14,285,714 shares issued and outstanding at March 31, 2001
and December 31, 2000, respectively........................................ 20 14
Additional paid in capital................................................... 78,430 38
Accumulated deficit.......................................................... (20,103) (13,231)
Accumulated other comprehensive loss......................................... (10,111) --
--------- ---------
Total shareholders' equity (deficit)....................................... 48,236 (13,179)
--------- ---------
Total liabilities and shareholders' equity (deficit)....................... $ 209,616 $ 161,993
========= =========
See accompanying notes to consolidated financial statements.
3
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, Except Per Share Amounts)
(UNAUDITED)
Three Months Ended
March 31,
--------------------
2001 2000
--------- -------
Revenue
Oil and gas production....................................... $ 38,505 $13,895
Gas sold - marketing......................................... 2,938 1,232
-------- -------
Total revenues.............................................. 41,443 15,127
-------- -------
Costs and operating expenses
Lease operating expenses..................................... 2,806 2,940
Gas purchased - marketing.................................... 2,886 1,181
General and administrative expenses.......................... 1,915 1,594
Non-cash compensation expense................................ 1,584 -
Depreciation, depletion and amortization..................... 11,032 5,967
Impairment on oil and gas properties......................... 8,478 -
-------- -------
Total costs and operating expenses.......................... 28,701 11,682
-------- -------
Net income from operations.................................... 12,742 3,445
-------- -------
Other income (expense)
Interest income.............................................. 656 186
Interest expense............................................. (3,308) (2,047)
Loss on derivative instruments............................... (20,513) -
-------- -------
Total other income (expense)................................ (23,165) (1,861)
-------- -------
Net income (loss) before income taxes......................... (10,423) 1,584
Income tax (expense) benefit
Current...................................................... (59) -
Deferred..................................................... 3,609 (555)
-------- -------
Net income (loss)............................................. $ (6,873) $ 1,029
======== =======
Income (loss) per common share:
Basic and diluted............................................ $(0.38) $0.07
======== =======
Weighted average number of common shares, basic and diluted... 17,886 14,286
======== =======
See accompanying notes to consolidated financial statements.
4
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
---------------------
2001 2000
--------- --------
Cash flows from operating activities
Net income (loss)........................................ $ (6,873) $ 1,029
Adjustments to reconcile net income (loss) to net cash
provided by operating activities -
Depreciation, depletion and amortization............. 11,032 5,967
Impairment of oil and gas properties................. 8,478 -
Amortization of deferred financing costs............. 220 27
Deferred tax asset................................... (3,611) 555
Non-cash compensation expense........................ 1,584 -
Other non-cash items................................. (75) 424
Changes in assets and liabilities -
Accounts receivable and other.......................... 6,600 (5,239)
Restricted cash........................................ - 353
Net assets from risk management activities............. (4,968) -
Accounts payable and accruals.......................... 10,054 11,139
Other long-term assets................................. (282) -
Other long-term liabilities and deferred credits....... (46) (10)
-------- --------
Net cash provided by operating activities................. 22,113 14,245
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions and acquisitions of oil and gas properties..... (48,249) (26,765)
Additions to furniture and fixtures...................... (126) (43)
-------- --------
Net cash used in investing activities..................... (48,375) (26,808)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from initial public offering.................... 78,330 -
Payment of offering costs................................ (893) -
Payments of short-term debt.............................. - (1,500)
Payments of long-term debt............................... (27,750) -
Proceeds from non-recourse borrowings.................... 2,583 7,189
Payments of non-recourse borrowings...................... (9,286) (2,607)
Deferred financing costs................................. (25) (3)
-------- --------
Net cash provided by financing activities................. 42,959 3,079
-------- --------
Increase (decrease) in cash and cash equivalents.......... 16,697 (9,484)
Cash and cash equivalents, beginning of period............ 18,136 17,779
-------- --------
Cash and cash equivalents, end of period.................. $ 34,833 $ 8,295
======== ========
Supplemental disclosures of cash flow information:
Cash paid during the period for interest................. $ 909 $ 655
======== ========
Cash paid during the period for taxes.................... $ - $ -
======== ========
See accompanying notes to 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 March 31, 2001 and December 31, 2000, the
results of our operations for the three months ended March 31, 2001 and 2000 and
cash flows for the three months ended March 31, 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 months ended March 31, 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 in the period of change, and
subsequently recognized in earnings when the offsetting hedged transaction
occurs. We primarily use derivatives to hedge the price of natural gas and have
elected not to account for our hedging activities under the hedge accounting
provisions allowed in the standard. This election will result in increased
earnings volatility associated with commodity price fluctuations, as all of our
derivative financial instruments are accounted for on a mark-to-market basis
beginning January 1, 2001. Gains and losses on all derivative instruments
related to accumulated other comprehensive income and adjustments to carrying
amounts on production 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 quarter of 2001, losses of $37.3 million ($24.2 million after
tax) were reclassified from accumulated other comprehensive loss to
6
earnings. The fair value of all outstanding derivatives decreased $16.7 million
from the adoption date of January 1, 2001 to March 31, 2001. As of March 31,
2001, the fair market value of our derivatives consisted of a $0.2 million asset
and a $17.9 million liability. The after-tax loss of $10.0 million recorded in
other comprehensive loss will be reclassified to earnings during 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.
NOTE 3 -- ACQUISITION OF OIL & GAS PROPERTIES
Gulf of Mexico. In February 2001 and March 2001, we acquired three and six
properties, respectively, in the Gulf of Mexico region. Eight of the above
properties were producing when acquired, with additional development operations
planned during 2001.
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 March 2001 we acquired two of the three
properties covered by the October 2000 letter of intent. Neither of the
properties were producing when we acquired them. The third property remains
under the letter of intent.
The total acquisition costs for the above properties were approximately $23.1
million.
NOTE 4 -- LONG-TERM DEBT AND NON-RECOURSE BORROWINGS
Our long-term debt and non-recourse borrowings as of March 31, 2001 and
December 31, 2000 were as follows (in thousands):
MARCH 31, DECEMBER 31,
2001 2000
--------- ------------
Credit facility........... $ -- $27,750
======= =======
Non-recourse borrowings... $82,076 $88,779
======= =======
In March 2001, we repaid our existing credit facility. At December 31, 2000,
we were in compliance with all terms of the credit agreement, other than the
covenant to maintain a current ratio of no less than 1.0 to 1.0, for which we
obtained a waiver from the lender.
We entered into our current development program credit agreement in April
1999. Loans outstanding under the agreement are secured only by the properties
financed and are non-recourse to us, meaning that, if we default in making loan
payments, the lender can seek repayment only from the properties.
The lender receives 90% of the monthly net revenues (after payment of
operating costs) from the pledged properties. For the first quarter of 2001, we
made payments to the lender of $9.3 million, including interest, under the
facility. The lender has a lifetime overriding royalty interest rights in each
of the 14 properties included in the collateral base for the development program
credit agreement. Ten of the 14 properties are subject to a 6.25% overriding
royalty interest which begins when the full amount of outstanding under the
credit agreement is repaid. The royalty interest is limited to the estimated
proved reserves attributable to the properties at the time the properties were
added to the collateral base less production after such date. Three of
7
these ten properties also are subject to a 3.125% overriding royalty on certain
specified levels of production above the proved reserves subject to the 6.25%
interest. The lender is not entitled to any of these interests unless the full
amount owed under the credit agreement has been repaid or the properties are
removed from the collateral base. Four of the fourteen properties included in
the collateral base are subject to a 6.25% overriding royalty interest in all
future production when the full amount outstanding under the credit agreement is
repaid if the amounts outstanding under the credit agreement are not repaid in
full prior to May 1, 2001.
On April 30, 2001, we repaid the full amount borrowed under the 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.
NOTE 5 -- 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 earnings per share in a loss
year, 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
MARCH 31,
-------------------
2001 2000
------- -------
Net income (loss) available to common shareholders... $(6,873) $ 1,029
======= =======
Weighted average shares outstanding.................. 17,886 14,286
======= =======
Net income (loss) per share, basic and diluted....... $ (0.38) $ 0.07
======= =======
NOTE 6 -- COMPREHENSIVE LOSS
Comprehensive loss consists of net loss, as reflected on the consolidated
statement of operations, and other gains and losses affecting stockholders'
equity that are excluded from net loss. We recorded other comprehensive loss for
the first time in the first quarter of 2001. Total comprehensive loss for the
three months ended March 31, 2001 is as follows (in thousands):
Net loss.................................................................. $ (6,873)
Other comprehensive loss, net of tax:
Cumulative effect of change in accounting principle - January 1, 2001... (34,252)
Reclassification adjustment for settled contracts....................... 24,216
Foreign currency translation adjustment................................. (75)
--------
Other comprehensive loss............................................... (10,111)
--------
Comprehensive loss........................................................ $(16,984)
========
There were no items in other comprehensive loss during 2000.
8
NOTE 7 -- STOCK OPTION COMPENSATION
In the first quarter of 2001, we recorded a non-cash charge to compensation
expense of approximately $1.6 million for options granted since September 1999
through the date of our initial public offering on February 5, 2001. The expense
was based on the difference between the exercise price of the options and the
fair market value of our stock as determined by the initial public offering
price of $14.00. 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.
NOTE 8 -- SUBSEQUENT EVENTS
Credit Agreement
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, at which time the borrowing base was $65.0 million. The amount available
for borrowing under the facility is limited to the loan value, as determined by
the bank, of certain 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 either 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.
9
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
MARCH 31,
-------------------
2001 2000
-------- -------
Production:
Natural gas (MMcf)................................ 5,151 4,615
Oil and condensate (MBbls)........................ 108 53
-------- -------
Total (Mmcfe).................................... 5,800 4,932
Revenues (in thousands):
Natural gas....................................... $ 35,555 $12,187
Effects of risk management activities(1).......... (23,254) 331
-------- -------
Total............................................ $ 12,301 $12,518
======== =======
Oil and condensate................................ $ 2,950 $ 1,533
Effects of risk management activities............. - (156)
-------- -------
Total............................................ $ 2,950 $ 1,377
======== =======
Natural gas, oil and condensate................... $ 38,505 $13,720
Effects of risk management activities(1).......... (23,254) 175
-------- -------
Total............................................ $ 15,251 $13,895
======== =======
- ------------
(1) For 2001, represents the net loss on the settlement of derivatives
attributable to first quarter 2001 production of 5,800 Mmcfe.
10
THREE MONTHS ENDED
MARCH 31,
-------------------
2001 2000
-------- -------
Average sales price per unit:
Natural gas (per Mcf)............................. $ 6.90 $ 2.64
Effects of risk management activities (per Mcf)... (4.51) 0.07
-------- -------
Total............................................ $ 2.39 $ 2.71
======== =======
Oil and condensate (per Bbl)...................... $ 27.22 $ 28.92
Effects of risk management activities (per Bbl)... - (2.94)
-------- -------
Total............................................ $ 27.22 $ 25.98
======== =======
Natural gas, oil and condensate per Mcfe........... $ 6.64 $ 2.78
Effects of risk management activities per Mcfe..... (4.01) 0.04
-------- -------
Total per Mcfe.................................... $ 2.63 $ 2.82
======== =======
Expenses (per Mcfe):
Lease operating expense........................... $ 0.48 $ 0.60
General and administrative........................ 0.33 0.32
Depreciation, depletion and amortization.......... 1.90 1.21
Three Months Ended March 31, 2001 Compared with Three Months Ended March 31,
2000
For the three months ended March 31, 2001, we reported a net loss of $6.9
million, or $0.38 per basic and diluted share on total revenue of $41.4 million,
as compared with net income of $1.0 million, or $0.07 per basic and diluted
share on total revenue of $15.1 million in the first quarter of 2000. Adjusted
EBITDA increased 21% in the first quarter of 2001 to $11.6 million from $9.6
million in the first 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 and non-cash
compensation expense. Our Adjusted EBITDA margin remained constant at 63%
compared to the prior quarter. 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. Our Adjusted EBITDA calculation 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 first quarter of 2001
increased over the same period in 2000 by approximately 181%, from $13.7 million
to $38.5 million. This increase was primarily due to an approximate 161% in
natural gas prices as well as an 18% increase in production. The increase in
production volumes from 4.9 Bcfe to 5.8 Bcfe was attributable to new wells
brought on line during the past year. Risk management activities would have
reduced oil and natural gas revenues by $23.3 million, or $4.01 per Mcfe, in the
first quarter of 2001 and increased oil and natural gas revenues by $0.2
million, or $0.04 per Mcfe, in the first quarter of 2000.
Marketing Revenue. Revenues from natural gas marketing activities increased to
$2.9 million in the first quarter of 2001 as compared to $1.2 million in the
first quarter of 2000. This increase was due to an increase in the sales price
per MMBtu. The average sales price per MMBtu increased from $2.71 in the first
quarter of 2000 to $6.52 in the first quarter of 2001.
Lease Operating Expense. Our lease operating expenses for the first quarter of
2001 decreased to $2.8 million from $2.9 million in the first quarter of 2000.
This decrease was primarily the result of lower workover spending in the first
quarter of 2001 ($0.6 million) compared to the first quarter of 2000 ($1.2
million), partially offset by an increase in geological and geophysical
expenses.
11
Gas Purchased-Marketing. Our cost of purchased gas was $2.9 million for the
first quarter of 2001 compared to $1.2 million for the first quarter of 2000.
The average cost increased from $2.60 per MMbtu in 2000 to $6.41 per MMbtu in
2001.
General and Administrative Expense. General and administrative expense
increased to $1.9 million for the first quarter of 2001 compared to $1.6 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 the first quarter of 2000 to the first quarter of 2001.
Non-cash Compensation Expense. In the first quarter of 2001, we recorded a
non-cash charge to compensation expense of approximately $1.6 million for
options granted since September 1999 through the date of our initial public
offering on February 5, 2001. The expense was based on the difference between
the exercise price of the options and the fair market value of our stock as
determined by the initial public offering price of $14.00. 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 85% from the first quarter 2000 amount of $6.0
million to the first quarter 2001 amount of $11.0 million.
Impairment Expense. As of March 31, 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 $8.5 million in the first quarter of 2001.
These impairments were primarily the result of drilling an unsuccessful
development well and a reduction in expected future undiscounted cash flows on
the other property due to lower natural gas prices at March 31, 2001.
Other Income (Expense). In 2001, we recorded a loss on derivative instruments
of $20.5 million comprised of a net realized loss of $22.8 million and an
unrealized gain of $2.3 million. The net realized loss of $22.8 million
represents derivative contracts settled in the first quarter of 2001, while the
offsetting gain represents the change in the fair market value of the open
derivative positions at March 31, 2001. Prior to the adoption of SFAS 133,
realized gains or losses were recorded as a component of revenue.
Interest expense for the first quarter of 2001 increased $1.3 million to $3.3
million from the comparable quarter in 2000 primarily due to higher borrowing
levels in addition to a slight increase in interest rates. We capitalized nil
and $0.7 million of interest for the three months ended March 31, 2001 and 2000,
respectively.
LIQUIDITY AND CAPITAL RESOURCES
2001 Acquisitions
Gulf of Mexico. In February 2001 and March 2001, we acquired three and six
properties, respectively, in the Gulf of Mexico region. Eight of the above
properties were producing when acquired, with additional development operations
planned during 2001.
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 March 2001 we acquired two of the three
properties covered by the October 2000 letter of intent. Neither of the
properties were producing when we acquired them. The third property remains
under the letter of intent.
The total acquisition costs for the above properties was approximately $23.1
million.
12
General
We have financed our acquisition and development activity through a
combination of project-based development and bank borrowings as well as cash
from operations. We believe that 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 sustaining capital expenditures for the foreseeable
future.
We believe that our capital resources are adequate to meet the requirements of
our business. However, future cash flows are subject to a number of variables
including the level of production and oil and gas prices. We cannot assure you
that operations and other capital resources will provide cash in sufficient
amounts to maintain planned levels of capital expenditures.
At March 31, 2001, we had a working capital deficit of $8.9 million. Excluding
the effects of the adoption of SFAS 133, which is represented as an asset of
$0.2 million and a liability of $17.9 million on the consolidated balance sheet,
we would have had a working capital surplus of $8.9 million.
Cash Flows
THREE MONTHS ENDED,
MARCH 31,
-------------------
2001 2000
-------- -------
Cash provided by (used in)
Operating activities....... $ 22.1 $ 14.2
Investing activities....... (48.4) (26.8)
Financing activities....... 43.0 3.1
Cash provided by operating activities in the first quarter of 2001 primarily
reflects increased oil and gas production volumes and price realizations,
partially offset by net cash used in price risk management activities.
Cash used in investing activities totaled $48.4 million in the first quarter
of 2001 as compared to $26.8 million in the same period of 2000. The 2001
amount includes expenditures of $23.1 million used for the acquisition of eleven
properties in the Gulf of Mexico and U.K. Southern Gas Basin areas.
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 facility of $27.8 million and payments net of
interest of $6.7 million on our non-recourse borrowing facility.
Credit Agreements
Bank Credit Agreement. As of March 31, 2001, we had repaid our former
revolving credit facility. In April 2001, we entered into a new $100.0 million
senior-secured revolving credit facility, at which time the borrowing base was
$65.0 million. The amount available for borrowing under the facility is limited
to the loan value, as determined by the bank, of certain 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 either 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.
13
Development Program Credit Agreement. We entered into our current development
program credit agreement in April 1999. Loans outstanding under the agreement
are secured only by the properties financed and are non-recourse to us, meaning
that, if we default in making loan payments, the lender can seek repayment only
from the properties.
The lender receives 90% of the monthly net revenues (after payment of
operating costs) from the pledged properties. For the first quarter of 2001, we
made payments to the lender of $9.3 million, including interest, under the
facility. The lender has a lifetime overriding royalty interest rights in each
of the 14 properties included in the collateral base for the development program
credit agreement. Ten of the 14 properties are subject to a 6.25% overriding
royalty interest which begins when the full amount of outstanding under the
credit agreement is repaid. The royalty interest is limited to the estimated
proved reserves attributable to the properties at the time the properties were
added to the collateral base less production after such date. Three of these ten
properties also are subject to a 3.125% overriding royalty on certain specified
levels of production above the proved reserves subject to the 6.25% interest.
The lender is not entitled to any of these interests unless the full amount owed
under the credit agreement has been repaid or the properties are removed from
the collateral base. Four of the fourteen properties included in the collateral
base are subject to a 6.25% overriding royalty interest in all future production
when the full amount outstanding under the credit agreement is repaid if the
amounts outstanding under the credit agreement are not repaid in full prior to
May 1, 2001.
On April 30, 2001, we repaid the full amount borrowed under the 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.
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 in the period of change, and
subsequently recognized in earnings when the offsetting hedged transaction
occurs. We primarily use derivatives to hedge the price of natural gas and have
elected not to account for our hedging activities under the hedge accounting
provisions allowed in the standard. This election will result in increased
earnings volatility associated with commodity price fluctuations, as all of our
derivative financial instruments are accounted for on a mark-to-market basis
beginning January 1, 2001. Gains and losses on all derivative instruments
related to accumulated other comprehensive income and adjustments to carrying
amounts on production 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 quarter of 2001, losses of $37.3 million ($24.2 million after
tax) were reclassified from accumulated other comprehensive loss to earnings.
The fair value of all outstanding derivatives decreased $16.7 million from the
adoption date of January 1, 2001 to March 31, 2001. As of March 31, 2001, the
fair market value of our derivatives consisted of a $0.2 million asset and a
$17.9 million liability. The after-tax loss of $10.0 million recorded in other
comprehensive loss will be reclassified to earnings during the year ended
December 31, 2001 as the transactions are settled.
14
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. Substantially all of our derivative
contracts are entered into with major financial 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 March 31, 2001, we had the following financial hedges on natural gas in
place:
SWAPS COLLARS
------------------- -------------------------
AVERAGE AVERAGE AVERAGE AVERAGE
MMBTU/DAY $/MMBTU MMBTU/DAY $/MMBTU
--------- ------- --------- -------------
Period:
Second quarter 2001... 29,000 $2.83 3,300 $5.10 to 6.15
Third quarter 2001.... 28,400 2.84 3,300 5.10 to 6.15
Fourth quarter 2001... 9,400 2.87 1,100 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
April 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.
15
FORWARD-LOOKING STATEMENTS AND ASSOCIATED RISKS
Some of the information included in this quarterly report include 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.
16
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 Credit Agreement, dated as of April 27, 2001, among ATP Oil & Gas
Corporation and BNP Paribas, as Agent, and the Lenders Signatory
thereto.
B. Reports on Form 8-K - None.
17
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: May 15, 2001 By: /s/ ALBERT L. REESE, JR.
------------------------
Albert L. Reese, Jr.
Senior Vice President and Chief
Financial Officer
18