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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2002
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number: 000-32261
ATP OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)
Texas 76-0362774
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
4600 Post Oak Place, Suite 200
Houston, Texas 77027
(Address of principal executive offices)
(Zip Code)
(713) 622-3311
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [_]
The number of shares outstanding of Registrant's common stock, par value $0.001,
as of August 12, 2002, was 20,316,267.
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ATP OIL & GAS CORPORATION
TABLE OF CONTENTS
Page
----
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets:
June 30, 2002 (unaudited) and December 31, 2001 ........................ 3
Consolidated Statements of Operations:
For the three and six months ended June 30, 2002 and 2001 (unaudited) 4
Consolidated Statements of Cash Flows:
For the six months ended June 30, 2002 and 2001 (unaudited) ............ 5
Notes to Consolidated Financial Statements (unaudited) ......................... 6
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS ......................................... 12
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK .................... 20
PART II. OTHER INFORMATION ............................................................ 22
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Amounts)
June 30, December 31,
2002 2001
------------ --------------
(unaudited)
Assets
Current assets
Cash and cash equivalents ................................................ $ 5,703 $ 5,294
Accounts receivable (net of allowance of $1,430 and $1,423, respectively) 13,988 10,371
Commodity contracts and other derivatives ................................ -- 1,936
Other current assets ..................................................... 3,584 1,754
--------- ---------
Total current assets .................................................. 23,275 19,355
--------- ---------
Oil and gas properties
Oil and gas properties (using the successful efforts method of accounting) 331,199 319,506
Less: Accumulated depreciation, depletion, impairment and amortization ... (211,205) (186,473)
--------- ---------
Oil and gas properties, net ........................................... 119,994 133,033
--------- ---------
Furniture and fixtures (net of accumulated depreciation) ..................... 735 794
Deferred tax asset ........................................................... 20,947 19,228
Other assets, net ............................................................ 3,421 5,154
--------- ---------
Total assets .......................................................... $ 168,372 $ 177,564
========= =========
Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accruals ............................................ $ 20,063 $ 26,426
Current maturities of long-term debt ..................................... 18,000 22,000
Commodity contracts and other derivatives ................................ 5,128 --
--------- ---------
Total current liabilities ............................................. 43,191 48,426
Long-term debt ............................................................... 72,242 78,111
Commodity contracts and other derivatives .................................... 1,773 671
Deferred revenue ............................................................. 1,204 1,296
Other long-term liabilities and deferred obligations ......................... 7,698 4,068
--------- ---------
Total liabilities ..................................................... 126,108 132,572
--------- ---------
Shareholders' equity
Preferred stock: $0.001 par value, 10,000,000 shares authorized;
none issued ........................................................... -- --
Common stock: $0.001 par value, 100,000,000 shares authorized;
20,390,107 issued and 20,314,267 outstanding at June 30, 2002;
20,388,488 issued and 20,312,648 outstanding at December 31, 2001 ..... 20 20
Additional paid in capital ............................................... 80,967 80,478
Accumulated deficit ...................................................... (37,806) (34,614)
Accumulated other comprehensive income (loss) ............................ (6) 19
Treasury stock ........................................................... (911) (911)
--------- ---------
Total shareholders' equity ............................................ 42,264 44,992
--------- ---------
Total liabilities and shareholders' equity ............................ $ 168,372 $ 177,564
========= =========
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 Six Months Ended
June 30, June 30,
----------------------------- ----------------------------
2002 2001 2002 2001
------------- ------------- ------------- -------------
Revenue:
Oil and gas production ....................... $ 27,742 $ 29,005 $ 46,352 $ 67,510
Gas sold - marketing ......................... 1,569 2,030 2,749 4,968
------------- ------------- ------------- -------------
Total revenues ............................. 29,311 31,035 49,101 72,478
------------- ------------- ------------- -------------
Costs and operating expenses:
Lease operating expenses ..................... 3,542 4,807 7,357 7,253
Gas purchased - marketing .................... 1,524 1,981 2,660 4,867
Geological and geophysical expenses .......... 54 112 11 472
General and administrative expenses .......... 2,556 2,135 5,034 4,050
Non-cash compensation expense
(general and administrative) ............... 244 882 487 2,466
Depreciation, depletion and amortization ..... 13,030 14,072 24,890 25,104
Impairment on oil and gas properties ......... - 5,705 - 14,183
------------- ------------- ------------- -------------
Total costs and operating expenses ......... 20,950 29,694 40,439 58,395
------------- ------------- ------------- -------------
Income from operations .......................... 8,361 1,341 8,662 14,083
------------- ------------- ------------- -------------
Other income (expense):
Interest income .............................. 10 137 26 793
Interest expense ............................. (2,614) (1,713) (5,280) (5,021)
Gain (loss) on derivative instruments ........ (879) 6,351 (8,319) (14,162)
------------- ------------- ------------- -------------
Total other income (expense) ............... (3,483) 4,775 (13,573) (18,390)
------------- ------------- ------------- -------------
Income (loss) before income taxes and
extraordinary item ........................... 4,878 6,116 (4,911) (4,307)
Income tax (expense) benefit:
Current ...................................... - 59 - -
Deferred ..................................... (1,707) (2,362) 1,719 1,247
------------- ------------- ------------- -------------
Income (loss) before extraordinary item ......... 3,171 3,813 (3,192) (3,060)
Extraordinary item, net of tax .................. - (602) - (602)
------------- ------------- ------------- -------------
Net income (loss) ............................... $ 3,171 $ 3,211 $ (3,192) $ (3,662)
============= ============= ============= =============
Basic and diluted earnings (loss) per
common share:
Income (loss) before extraordinary item .... $ 0.16 $ 0.19 $ (0.16) $ (0.16)
Extraordinary item, net of tax ............. - (0.03) - (0.03)
------------- ------------ ------------- -------------
Net income (loss) per common share ......... $ 0.16 $ 0.16 $ (0.16) $ (0.19)
============= ============ ============= =============
Weighted average number of common shares:
Basic ........................................ 20,314 20,287 20,314 19,093
============= ============= ============= =============
Diluted ...................................... 20,456 20,705 20,314 19,093
============= ============= ============= =============
See accompanying notes to consolidated financial statements.
4
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
Six Months Ended
June 30,
-----------------------------
2002 2001
------------- --------------
Cash flows from operating activities
Net loss ...................................................................... $ (3,192) $ (3,662)
Adjustments to reconcile net loss to net cash
provided by operating activities -
Depreciation, depletion and amortization ................................. 24,890 25,104
Impairment of oil and gas properties ..................................... - 14,183
Amortization of deferred financing costs ................................. 768 308
Extraordinary item ....................................................... - 926
Net (assets) liabilities from risk management activities ................. 8,166 (16,774)
Deferred taxes ........................................................... (1,719) (1,572)
Non-cash compensation expense ............................................ 487 2,466
Other non-cash items ..................................................... 154 (64)
Changes in assets and liabilities -
Accounts receivable and other .............................................. (3,988) 13,178
Accounts payable and accruals .............................................. (6,363) 20,070
Other long-term assets ..................................................... (388) (282)
Other long-term liabilities and deferred credits ........................... 3,538 (105)
-------- --------
Net cash provided by operating activities ......................................... 22,353 53,776
-------- --------
Cash flows from investing activities
Additions and acquisitions of oil and gas properties .......................... (11,693) (81,933)
Additions to furniture and fixtures ........................................... (95) (288)
-------- --------
Net cash used in investing activities ............................................. (11,788) (82,221)
-------- --------
Cash flows from financing activities
Proceeds from initial public offering ......................................... - 78,330
Payment of offering costs ..................................................... - (893)
Proceeds from long-term debt .................................................. - 65,000
Payments of long-term debt .................................................... (10,000) (32,750)
Proceeds from non-recourse borrowings ......................................... - 3,359
Payments of non-recourse borrowings ........................................... - (92,138)
Deferred financing costs ...................................................... (158) (1,777)
Treasury stock purchases ...................................................... - (911)
Other ......................................................................... 2 165
-------- --------
Net cash provided by (used in) financing activities ............................... (10,156) 18,385
-------- --------
Increase (decrease) in cash and cash equivalents .................................. 409 (10,060)
Cash and cash equivalents, beginning of period .................................... 5,294 18,136
-------- --------
Cash and cash equivalents, end of period .......................................... $ 5,703 $ 8,076
======== ========
Supplemental disclosures of cash flow information:
Cash paid during the period for interest ...................................... $ 3,343 $ 909
======== ========
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 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 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.
The accompanying financial statements and related notes present our
consolidated financial position as of June 30, 2002 and December 31, 2001, the
results of our operations for the three and six months ended June 30, 2002 and
2001 and cash flows for the six months ended June 30, 2002 and 2001. The
financial statements have been prepared in accordance with the instructions to
interim reporting as prescribed by the Securities and Exchange Commission
("SEC"). All adjustments, consisting only of normal recurring adjustments, that
in the opinion of management were necessary for a fair statement of the results
for the interim periods, have been reflected. All significant intercompany
transactions have been eliminated. Certain reclassifications have been made to
prior period amounts to conform to current period presentation. The results of
operations for the three and six months ended June 30, 2002 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 2001 Annual Report on
Form 10-K.
Note 2 -- Accounting Pronouncements
In June 2001 the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 143 "Accounting for
Asset Retirement Obligations" ("SFAS 143"). 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. The
statement is effective for fiscal years beginning after June 15, 2002. We will
adopt the statement for our fiscal year beginning 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. We are currently
assessing the impact of SFAS 143 and therefore, at this time, cannot reasonably
estimate the effect of this statement on our consolidated financial position or
results of operations.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statement
Nos. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" ("SFAS 145"). SFAS 145 requires that gains and losses from
extinguishment of debt be classified as extraordinary items only if they meet
the criteria in Accounting Principles Board Opinion No. 30 ("Opinion No. 30").
Applying the provisions of Opinion No. 30 will distinguish transactions that are
part of an entity's recurring operations from those that are unusual and
infrequent that meet the criteria for classification as an extraordinary item.
The statement is effective for fiscal years beginning after May 15, 2002. We
will adopt the provisions of SFAS 145 for our fiscal year beginning January 1,
2003. The adoption of the provisions of SFAS 145 is not expected to affect our
future financial position or liquidity. When we adopt the provisions of SFAS
145, gains or losses from the early extinguishment of debt recognized in our
consolidated statements of operations for prior years will be reclassified to
other revenues or other expense and included in the determination of the income
(loss) from continuing operations of those periods.
6
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" ("SFAS 146"). SFAS 146 addresses
financial accounting and reporting for costs associated with exit or disposal
activities and nullified Emerging Issues Task Force Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring". SFAS 146
requires that a liability for a cost associated with an exit or disposal
activity be recognized when the liability is incurred. SFAS 146 also establishes
that fair value is the objective for initial measurement of the liability. The
provisions of this statement are effective for exit or disposal activities that
are initiated after December 31, 2002. We will adopt the provisions of SFAS 146
on January 1, 2003 and are currently assessing the impact of the statement on
our financial position and results of operations, if any.
Note 3 -- Long-Term Debt
Long-term debt as of the dates indicated was as follows (in thousands):
June 30, December 31,
2002 2001
----------- -----------
Credit facility ....................................... $ 60,000 $ 70,000
Note payable, net of unamortized discount of $1,008 and
$1,139, respectively ................................ 30,242 30,111
--------- ---------
Total debt ............................................ 90,242 100,111
Less current maturities ............................... (18,000) (22,000)
--------- ---------
Total long-term debt ............................. $ 72,242 $ 78,111
========= =========
We have a $100.0 million senior-secured revolving credit facility which is
secured by substantially all of our U.S. oil and gas properties, as well as by
approximately two-thirds of the capital stock of our foreign subsidiaries and is
guaranteed by our wholly owned subsidiary, ATP Energy, Inc. 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. At June 30,
2002, the borrowing base was $60.0 million, all of which was outstanding. During
July 2002, we made a $2.0 million principal payment in accordance with the
scheduled reduction. On July 31, 2002, the agreement was amended and restated
and the borrowing base was increased to $62.0 million with a $2.0 million
borrowing base reduction scheduled to commence on September 1, 2002, instead of
the previously scheduled August 27, 2002. The redetermination dates are
scheduled during the first month of each calendar quarter at which time the
lenders can increase or decrease the borrowing base and the monthly reduction
amount. The $18.0 million of current maturities of long-term debt is based upon
the borrowing base and monthly reduction amounts which were established on July
31, 2002. 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%. A material reduction in the
borrowing base or a material increase in the monthly reduction amount by the
lender would have a material negative impact on our cash flows and our ability
to fund future operations.
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 0.25%, 0.50%, 0.75% or 1.00% 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 2.25%, 2.50%, 2.875%, or 3.125%
depending on the amount outstanding under the credit facility. The July 31, 2002
amended credit facility extended the maturity from November 2003 to May 2004.
Our credit facility contains conditions and restrictive provisions, among other
things, (1) limiting 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.
7
Effective June 29, 2001, we issued a note payable 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 U.S. 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 expected 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 purchaser has the
right to make a redetermination of the borrowing base at least once every six
months. We have not been notified of any change in the borrowing base in 2002.
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. A material reduction in the borrowing base by the lender would have a
material negative impact on our cash flows and our ability to fund future
obligations. As of June 30, 2002, all of our borrowing base under the agreement
was outstanding.
As of June 30, 2002, we were in compliance with all of the financial
covenants of our credit facility and note payable agreements. We anticipate that
we will be in compliance with all of the covenants for both agreements for the
remainder of the year.
Note 4 -- 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 Six Months Ended
June 30, June 30,
------------------------ ------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
Net income (loss) ................................... $ 3,171 $ 3,211 $ (3,192) $ (3,662)
=========== =========== =========== ===========
Weighted average shares outstanding - basic ......... 20,314 20,287 20,314 19,093
Effect of dilutive securities - stock options ....... 142 418 - -
----------- ----------- ----------- -----------
Weighted average shares outstanding - diluted ....... 20,456 20,705 20,314 19,093
=========== =========== =========== ===========
Net income (loss) per share - basic and diluted ..... $ 0.16 $ 0.16 $ (0.16) $ (0.19)
=========== =========== =========== ===========
8
Note 5 -- Comprehensive Income
Comprehensive income consists of net income, as reflected on the
consolidated statement of operations, and other gains and losses affecting
shareholders' equity that are excluded from net income. The change in
accumulated other comprehensive income (loss), net of tax, for the three and six
months ended June 30, 2002 and 2001 is as follows (in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
Balance at beginning of period ....................... $ 13 $ (10,111) $ 19 $ -
Cumulative effect of change in accounting
principle - January 1, 2001 ....................... - - - (34,252)
Reclassification adjustment for settled contracts .... 4,765 - 28,981
Foreign currency translation adjustment .............. (19) 11 (25) (64)
------ --------- ------ ---------
Balance at end of period ............................. $ (6) $ (5,335) $ (6) $ (5,335)
====== ========== ====== =========
Total comprehensive income for the three months ended June 30, 2002 was
$3.2 million and total comprehensive loss for the six months ended June 30, 2002
was $3.2 million. Total comprehensive income for the three months ended June 30,
2001 was $8.0 million and total comprehensive loss for the six months ended
June 30, 2001 was $9.0 million.
Note 6 -- Stock Option Compensation
In the first half of 2002, 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. In the first half of 2001, we
recorded a non-cash compensation expense of $2.0 million for the above options
and an additional non-cash compensation expense of $0.5 million related to
certain options granted prior to September 1999 and exercised in the first half
of 2001. The additional $0.5 million expense was recorded as a result of the
manner in which those shares were exercised.
Note 7 -- Derivative Instruments and Price Risk Management Activities
On January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"), as amended, and recorded a
cumulative transition loss of $34.3 million, net of tax, to accumulated other
comprehensive income to account for the effect of the change in accounting
principle. The standard requires that all derivatives be recorded on the balance
sheet at fair value and establishes criteria for documentation and measurement
of hedging activities.
We regularly use derivative instruments with respect to a portion of our
oil and gas production to manage our exposure to price volatility. These
instruments, which are generally placed with counter parties which we believe to
be of high credit quality, may take the form of futures contracts, swaps or
options.
At June 30, 2002, we had not attempted to qualify our derivatives for the
hedge accounting provisions under SFAS 133. Accordingly, we have accounted for
the changes in market value of these derivatives through current earnings. Gains
and losses on all derivative instruments are included in other income (expense)
on the consolidated financial statements.
9
As of June 30, 2002, we had derivative contracts in place for the following
natural gas and oil volumes:
Average
Fixed
Period Volumes Price
------ ------- -------
Natural gas (MMBtu):
Remainder of 2002 ................ 4,418,000 $ 2.92
2003 ............................ 6,080,000 3.02
Oil (Bbl):
Remainder of 2002 ................ 123,000 $ 24.07
2003 ............................ 182,500 24.10
As of June 30, 2002, the fair value of the derivative instruments we had
entered into was a current liability of $5.1 million and long-term liability of
$1.8 million. The derivative assets and liabilities represent the difference
between contract prices and future market prices on contracted volumes of the
commodities as of June 30, 2002. The net gain or loss on derivative instruments
is detailed below for the periods indicated (in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
Loss on settled contracts during the period .............. $ (1,430) $ (3,294) $ (153) $ (26,548)
Gain (loss) on open derivative positions at June 30 ...... 551 9,645 (8,166) 12,386
----------- ----------- ----------- -----------
Total ................................................. $ (879) $ 6,351 $ (8,319) $ (14,162)
=========== =========== =========== ===========
In addition to these derivative instruments, we also manage our exposure to
oil and gas price risks by periodically entering into fixed-price delivery
contracts. As of June 30, 2002, we had fixed-price contracts in place for the
following natural gas and oil volumes:
Average
Fixed
Period Volumes Price
------ --------- -----------
Natural gas (MMBtu):
Remainder of 2002 ..................... 1,688,000 $ 3.58
2003 ................................. 4,226,000 3.82
Oil (Bbl):
Remainder of 2002 ..................... 92,000 $ 25.25
Note 8 -- Commitments and Contingencies
On August 28, 2001 ATP entered into a written agreement to acquire a
property in the Gulf of Mexico during September 2001. On October 9, 2001 the
agreement was amended to ultimately extend the closing date until October 31,
2001 in exchange for payments made by ATP totaling $3.0 million. This amendment
also contained an arrangement whereby if ATP did not close on the property, and
if sellers sold the property to a third party with a sale that met specific
contract requirements, ATP would be required to execute a six month note for
payment of the differential. Since ATP did not obtain the financing for the
acquisition by October 31, 2001, the transaction did not close by that date;
however, the parties' intensive work toward closing continued beyond that date
without interruption.
10
While working on the closing for the property with ATP, the sellers sold the
property to a third party without informing ATP until after the closing had
taken place. ATP filed an action in the District Court of Harris County, Texas
against the sellers, generally alleging improper sale of the offshore property
to a third party and breach of contract, and seeking unspecified damages from
the sellers. The case is encaptioned ATP Oil & Gas Corporation vs. Legacy
Resources Co., L.P. et al, No. 2001-63224 in the 269th Judicial District Court
of Harris County, Texas. At the same time the sellers notified ATP of their sale
to a third party, the sellers had a demand made upon ATP for execution of a six
month note for the amount of an alleged differential of approximately $12.3
million plus interest at 16%. Substantiation of the amount and validity of the
demand could not be ascertained based on the content of the demand received. ATP
contested the entire demand. The litigation is in its very early stages with
written discovery propounded by ATP, but no answers received, and no depositions
taken. The judge has abated the litigation, until arbitration pursuant to the
underlying agreements between the sellers and ATP is completed. The arbitration
is presently scheduled for mid to late February of 2003. Since the legal and
arbitration proceedings have just begun, and a prediction of the outcome would
be premature and uncertain, we have not accrued any amount related to this
matter. And while we are seeking recovery of the amounts previously paid and
discussed above, the $3.0 million was charged to earnings in 2001 along with
certain other costs related to this matter. ATP intends to vigorously defend
against the sellers' claims and forcefully pursue its own claims in this matter.
In August 2001, Burlington Resources Inc. filed suit against ATP alleging
formation of a contract with ATP 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 also, 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.
11
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"), a Texas corporation, was formed on
August 8, 1991 and is 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 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, developing the properties
in a relatively short period of time and by operating the properties
efficiently.
Critical Accounting Policies
Our discussion and analysis of our financial condition and results of
operations are based on consolidated financial statements which have been
prepared in accordance with generally accepted accounting principles in the
United States. The preparation of these financial statements requires us to make
estimates and judgments that affect the reported amounts or assets, liabilities,
revenues and expenses. We believe that certain accounting policies affect our
more significant judgments and estimates used in the preparation of our
consolidated financial statements. Our 2001 Annual Report on Form 10-K includes
a discussion of our critical accounting policies.
Results of Operations
Currently, our derivative instruments are not designated as hedging
instruments under the provisions of Financial Accounting Standards Board
("FASB") Statement of Financial Accounting Standard ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"), as
amended, and any gains or losses from these activities are included in other
income (expense). The following table sets forth selected financial and
operating information for our natural gas and oil operations inclusive of the
effects of risk management activities:
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- --------------------
2002 2001 2002 2001
-------- -------- -------- --------
Production:
Natural gas (MMcf) ...................... 5,552 5,634 10,028 10,786
Oil and condensate (MBbls) .............. 385 94 812 203
-------- -------- -------- --------
Total (Mmcfe) ......................... 7,864 6,201 14,899 12,001
Revenues (in thousands):
Natural gas ............................. $ 18,561 $ 26,571 $ 29,262 $ 62,125
Effects of risk management activities (1) (1,305) (3,294) (28) (26,548)
-------- -------- -------- --------
Total ................................. $ 17,256 $ 23,277 $ 29,234 $ 35,577
======== ======== ======== ========
Oil and condensate ...................... $ 9,181 $ 2,434 $ 17,090 $ 5,385
Effects of risk management activities (1) (125) -- (125) --
-------- -------- -------- --------
Total ................................. $ 9,056 $ 2,434 $ 16,965 $ 5,385
======== ======== ======== ========
Natural gas, oil and condensate ......... $ 27,742 $ 29,005 $ 46,352 $ 67,510
Effects of risk management activities (1) (1,430) (3,294) (153) (26,548)
-------- -------- -------- --------
Total ................................. $ 26,312 $ 25,711 $ 46,199 $ 40,962
======== ======== ======== ========
Table and footnote continued on following page
12
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
Average sales price per unit:
Natural gas (per Mcf) ............................... $ 3.34 $ 4.72 $ 2.92 $ 5.76
Effects of risk management activities (per Mcf) ..... (0.24) (0.59) - (2.46)
------ ------ ------ ------
Total ............................................. $ 3.10 $ 4.13 $ 2.92 $ 3.30
====== ====== ====== ======
Oil and condensate (per Bbl) ........................ $23.83 $25.75 $21.05 $26.56
Effects of risk management activities (per Bbl) ..... (0.32) - (0.15) -
------ ------ ------ ------
Total ............................................. $23.51 $25.75 $20.90 $26.56
====== ====== ====== ======
Natural gas, oil and condensate (per Mcfe) .......... $ 3.53 $ 4.68 $ 3.11 $ 5.62
Effects of risk management activities (per Mcfe) .... (0.18) (0.53) (0.01) (2.21)
------ ------ ------ ------
Total ............................................. $ 3.35 $ 4.15 $ 3.10 $ 3.41
====== ====== ====== ======
Expenses (per Mcfe):
Lease operating expense ............................. $ 0.45 $ 0.78 $ 0.49 $ 0.60
General and administrative .......................... 0.33 0.34 0.34 0.34
Depreciation, depletion and amortization ............ 1.66 2.27 1.67 2.09
- ------------
(1) Represents the loss on the settlement of derivatives attributable to second
quarter 2002 and 2001 production of 7.9 Bcfe and 6.2 Bcfe, respectively,
and first half 2002 and 2001 production of 14.9 Bcfe and 12.0 Bcfe,
respectively.
Three Months Ended June 30, 2002 Compared with Three Months Ended June 30, 2001
For the three months ended June 30, 2002, we reported net income of $3.2
million, or $0.16 per share on total revenue of $29.3 million, as compared with
net income of $3.2 million, or $0.16 per share on total revenue of $31.0 million
in the second quarter of 2001.
Oil and Gas Revenue. Our revenue from natural gas and oil production for
the second quarter of 2002 decreased from the same period in 2001 by
approximately 4%, from $29.0 million to $27.7 million. This decrease was
primarily due to an approximate 19% decrease in our sales price per Mcfe
partially offset by a 27% increase in production. The increase in production
volumes from 6.2 Bcfe to 7.9 Bcfe was attributable to development activities on
three properties which were completed subsequent to June 30, 2001.
Marketing Revenue. Revenues from natural gas marketing activities decreased
to $1.6 million in the second quarter of 2002 as compared to $2.0 million in the
second quarter of 2001. This decrease was due to a decrease in the sales price
per MMBtu. The average sales price per MMBtu decreased from $4.46 in the second
quarter of 2001 to $3.45 in the second quarter of 2002.
Lease Operating Expense. Lease operating expenses for the second quarter of
2002 decreased to $3.5 million from $4.8 million in the second quarter of 2001.
This decrease was attributable to costs of $1.5 million incurred on workover
activities on three of our properties in the second quarter of 2001. No
workovers were performed in the second quarter of 2002. In addition, recurring
lease operating expense decreased on a per Mcfe basis as a result of
restructuring existing contracts and cost structures resulting in significant
costs savings in the current quarter.
Gas Purchased-Marketing. Our cost of purchased gas was $1.5 million for the
second quarter of 2002 compared to $2.0 million for the second quarter of 2001.
The average cost decreased from $4.36 per MMBtu in 2001 to $3.35 per MMBtu in
2002.
General and Administrative Expense. General and administrative expense
increased to $2.6 million for the second quarter of 2002 compared to $2.1
million for the same period in 2001. The primary reason for the increase was the
result of increased activities in our U.K. office.
13
Non-Cash Compensation Expense. In the second quarter of 2002, we recorded a
non-cash charge to compensation expense of approximately $0.2 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. In the second quarter of 2001, we recorded a non-cash
compensation expense of $0.4 million for the above options and an additional
non-cash compensation expense of $0.5 million related to certain options granted
prior to September 1999 and exercised in the second quarter of 2001. The
additional $0.5 million expense was recorded as a result of the manner in which
those shares were exercised.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense decreased 7% from the second quarter 2001 amount of
$14.1 million to the second quarter 2002 amount of $13.0 million. The average
DD&A rate was $1.66 per Mcfe in the second quarter of 2002 compared to $2.27 per
Mcfe in the same quarter of 2001 as a result of impairments recorded in the
prior year.
Impairment Expense. We recorded no impairments in the second quarter of
2002. For the second quarter of 2001, we recorded impairments of $5.7 million
due primarily to reductions in expected future cash flows on four properties due
to lower natural gas prices at June 30, 2001.
Other Income (Expense). In the second quarter of 2002, we recorded a loss
on derivative instruments of $0.9 million. The net loss in the second quarter of
2002 is comprised of a realized loss of $1.4 million for derivative contracts
settled in the quarter and an unrealized gain of $0.5 million representing the
change in fair market value of the open derivative positions at June 30, 2002.
In the second quarter of 2001, we recorded a gain on derivative instruments of
$6.4 million. The net gain in the second quarter of 2001 was comprised of a
realized loss of $3.3 million for derivative contracts settled in the quarter
and an unrealized gain of $9.7 million representing the change in fair market
value of the open derivative positions at June 30, 2001.
Interest expense increased to $2.6 million in the second quarter of 2002
from $1.7 million in the comparable quarter of 2001 primarily due to higher
borrowing levels and increased amortization resulting from higher debt financing
costs.
Six Months Ended June 30, 2002 Compared with Six Months Ended June 30, 2001
For the six months ended June 30, 2002, we reported a net loss of $3.2
million, or $0.16 per share, on total revenue of $49.1 million, as compared with
a net loss of $3.7 million, or $0.19 per share, on total revenue of $72.5
million in the first half of 2001.
Oil and Gas Revenue. Our revenue from natural gas and oil production for
the first half of 2002 decreased approximately 31% from the same period in 2001,
from $67.5 million to $46.4 million. This decrease was primarily due to an
approximate 9% decrease in our sales price per Mcfe, partially offset by a 24%
increase in production. The increase in production volumes from 12.0 Bcfe to
14.9 Bcfe was primarily attributable to development activities which were
completed subsequent to June 30, 2001.
Marketing Revenue. Revenues from natural gas marketing activities decreased
to $2.7 million in the first half of 2002 as compared to $4.9 million in the
first half of 2001. This decrease was due to a decrease in the sales price per
MMBtu. The average sales price per MMBtu decreased from $5.49 in the first half
of 2001 to $3.04 in the first half of 2002.
14
Lease Operating Expense. Lease operating expense for the first half of 2002
decreased on a Mcfe basis as compared to the first half of 2001 primarily due to
the restructuring of existing contracts and cost structures resulting in
significant costs savings in the first half of 2002.
Gas Purchased-Marketing. Our cost of purchased gas was $2.7 million for the
first half of 2002 compared to $4.9 million for the first half of 2001. The
average cost decreased from $5.38 per MMBtu in 2001 to $2.94 per MMBtu in 2002.
General and Administrative Expense. General and administrative expense
increased to $5.0 million for the first half of 2002 compared to $4.0 million
for the same period in 2001. The increase was primary due to higher compensation
related costs, increased activities in our U.K. office, public company fees and
bank charges connected with financing arrangements.
Non-cash Compensation Expense. In the first half of 2002, 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. In the first half of 2001, we recorded a non-cash compensation
expense of $2.0 million for the above options and an additional non-cash
compensation expense of $0.5 million related to certain options granted prior to
September 1999 and exercised in the first half of 2001. The additional $0.5
million expense was recorded as a result of the manner in which those shares
were exercised.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense decreased slightly from the first half 2001 amount of
$25.1 million to the first half 2002 amount of $24.9 million. The average DD&A
rate was $1.67 per Mcfe in the first half of 2002 compared to $2.09 per Mcfe in
the same half of 2001 as a result of impairments recorded in the prior year.
Impairment Expense. We recorded no impairments in the second half of 2002.
As of June 30, 2001, the future undiscounted cash flows were less than their
individual net book value on five of our properties. As a result, we recorded
impairments of $14.2 million in the first six months of 2001. These impairments
were primarily the result of drilling a non-commercial development well and a
reduction in expected future cash flows on the other properties due to lower
natural gas prices at June 30, 2001.
Other Income (Expense). In the first half of 2002, we recorded a loss on
derivative instruments of $8.3 million. The net loss in 2002 is comprised of a
realized loss of $0.1 million for derivative contracts settled in the period and
an unrealized loss of $8.2 million representing the change in fair market value
of the open derivative positions at June 30, 2002. In the first half of 2001, we
recorded a loss on derivative instruments of $14.2 million. The net loss in 2001
was comprised of a realized loss of $26.2 million for derivative contracts
settled in the period and an unrealized gain of $12.0 million representing the
change in fair market value of the open derivative positions at June 30, 2001.
Interest expense increased to $5.3 million in the first half of 2002 from
$5.0 million in the comparable half of 2001 primarily due to higher borrowing
levels.
15
Liquidity and Capital Resources
We have financed our acquisition and development activities through a
combination of project-based development arrangements, bank borrowings and
proceeds from our February 2001 IPO, as well as cash from operations. We intend
to finance our near-term development projects in the Gulf of Mexico and U.K.
through available cash flows and the potential sell down of interests in the
development projects. As operator of all of our projects in development, we have
the ability to significantly control the timing of most of our capital
expenditures. We believe the cash flows from operating activities combined with
our ability to control the timing of substantially all of our future development
and acquisition requirements will provide us with the flexibility and liquidity
to meet our future planned capital requirements.
However, future cash flows are subject to a number of variables including
increased available borrowings and the level of production and oil and natural
gas prices. Future borrowings under credit facilities are subject to variables
including the lenders' practices and policies, changes in the prices of oil and
natural gas and changes in our oil and gas reserves. A material reduction in the
borrowing base or an increase in the monthly reduction amount by our lenders
would have a material negative impact on our cash flows and our ability to fund
future obligations. 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. In periods of reduced availability of funds
from either cash flows or credit sources we have delayed planned capital
expenditures and will continue to do so when necessary. While the delay
decreases the amount of capital expenditures in the current period, it could
negatively impact our future revenues and cash flows.
Cash Flows
Six Months Ended,
June 30,
----------------------------
2002 2001
------------- ------------
(in thousands)
Cash provided by (used in)
Operating activities ............. $ 22,353 $ 53,776
Investing activities ............. (11,788) (82,221)
Financing activities ............. (10,156) 18,385
Cash provided by operating activities in the first half of 2002 and 2001
was $22.4 million and $53.8 million, respectively. Cash flow from operations
decreased primarily due to the decline in oil and gas prices from the first half
of 2001, somewhat offset by the 24% increase in production. In addition, our
significant decrease in development activity during the first half of 2002
allowed us to use available cash to reduce amounts owed to third parties.
Cash used in investing activities in the first half of 2002 and 2001 was
$11.8 million and $82.2 million, respectively. We incurred no costs for two
acquisitions made in the first half of 2002 and incurred $11.7 million for
capital expenditures, of which $9.4 million was incurred for development
activity on two projects. In the first half of 2001, capital expenditures for
acquisition and development activities were $29.5 million and $52.4 million,
respectively.
Cash used in financing activities in the first quarter of 2002 represents
principal payments on our credit facility. Cash provided from financing
activities in the first half of 2001 included the proceeds from our initial
public offering in February 2001 of $78.3 million, repayment of prior credit
facilities of $119.9 million and proceeds of $65.0 million from our then new
credit facility.
Credit Facilities
We have a $100.0 million senior-secured revolving credit facility which is
secured by substantially all of our U.S. oil and gas properties, as well as by
approximately two-thirds of the capital stock of our foreign subsidiaries and is
guaranteed by our wholly owned subsidiary, ATP Energy, Inc. 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. At June 30,
2002, the borrowing base was $60.0 million, all of which was
16
outstanding. During July 2002, we made a $2.0 million principal payment in
accordance with the scheduled reduction. On July 31, 2002, the agreement was
amended and restated and the borrowing base was increased to $62.0 million with
a $2.0 million borrowing base reduction scheduled to commence on September 1,
2002, instead of the previously scheduled August 27, 2002. The redetermination
dates are scheduled during the first month of each calendar quarter at which
time the lenders can increase or decrease the borrowing base and the monthly
reduction amount. The $18.0 million of current maturities of long-term debt is
based upon the borrowing base and monthly reduction amounts which were
established on July 31, 2002. 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%. A material
reduction in the borrowing base or a material increase in the monthly reduction
amount by the lender would have a material negative impact on our cash flows and
our ability to fund future operations.
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 0.25%, 0.50%, 0.75% or 1.00% 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 2.25%, 2.50%, 2.875%, or 3.125%
depending on the amount outstanding under the credit facility. The July 31, 2002
amended credit facility extended the maturity from November 2003 to May 2004.
Our credit facility contains conditions and restrictive provisions, among other
things, (1) limiting 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.
Note Payable
Effective June 29, 2001, we issued a note payable 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 U.S. 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 expected 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 purchaser has the
right to make a redetermination of the borrowing base at least once every six
months. We have not been notified of any change in the borrowing base in 2002.
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. A material reduction in the borrowing base by the lender would have a
material negative impact on our cash flows and our ability to fund future
obligations. As of June 30, 2002, all of our borrowing base under the agreement
was outstanding.
As of June 30, 2002, we were in compliance with all of the financial
covenants of our credit facility and note payable agreements. We anticipate that
we will be in compliance with all financial covenants for both agreements for
the remainder of the year.
17
Working Capital
At June 30, 2002, we had a working capital deficit of $19.9 million, an
improvement over our working capital deficit of $29.1 million at December 31,
2001. In compliance with the definition of working capital in our credit
facilities, which excludes current maturities of long-term debt and the current
portion of future commodity contracts and other derivatives, we had working
capital of approximately $3.2 million at June 30, 2002 as compared to a deficit
of approximately $9.0 million at December 31, 2001. The significant improvement
in our working capital is the result of the reduction of our current liabilities
through cash flows from operations and the reduction of expenditures related to
current development activity. We believe the cash flows from operating
activities combined with our ability to control the timing of substantially all
of our future development and acquisition requirements will provide us with the
flexibility and liquidity to meet our future planned capital requirements.
Our current year planned development, acquisition and debt reduction
programs are projected to be funded by available cash flow from our 2002
operations. We believe the cash flows from operating activities combined with
our ability to control the timing of substantially all of our future development
and acquisition requirements will provide us with the flexibility and liquidity
to meet our future capital requirements. In addition to these measures, we are
currently in discussions with potential investors to provide additional capital.
These discussions involve increases to our current credit facilities, new credit
facilities and the sale of interests in selected properties. We have also
explored the possibility of the issuance of new debt or equity. Completion of
any of these potential financings will expand our capabilities to further reduce
our outstanding indebtedness, increase our working capital and expand or
accelerate our 2002 and future development and acquisition programs. There can
be no assurance however, that we will be successful in negotiating any of these
transactions or that the form of the transaction will be acceptable to both the
potential investor and our management or our board of directors.
Commitments and Contingencies
On August 28, 2001 ATP entered into a written agreement to acquire a
property in the Gulf of Mexico during September 2001. On October 9, 2001 the
agreement was amended to ultimately extend the closing date until October 31,
2001 in exchange for payments made by ATP totaling $3.0 million. This amendment
also contained an arrangement whereby if ATP did not close on the property, and
if sellers sold the property to a third party with a sale that met specific
contract requirements, ATP would be required to execute a six month note for
payment of the differential. Since ATP did not obtain the financing for the
acquisition by October 31, 2001, the transaction did not close by that date;
however, the parties' intensive work toward closing continued beyond that date
without interruption.
While working on the closing for the property with ATP, the sellers sold the
property to a third party without informing ATP until after the closing had
taken place. ATP filed an action in the District Court of Harris County, Texas
against the sellers, generally alleging improper sale of the offshore property
to a third party and breach of contract, and seeking unspecified damages from
the sellers. The case is encaptioned ATP Oil & Gas Corporation vs. Legacy
Resources Co., L.P. et al, No. 2001-63224 in the 269th Judicial District Court
of Harris County, Texas. At the same time the sellers notified ATP of their sale
to a third party, the sellers had a demand made upon ATP for execution of a six
month note for the amount of an alleged differential of approximately $12.3
million plus interest at 16%. Substantiation of the amount and validity of the
demand could not be ascertained based on the content of the demand received. ATP
contested the entire demand. The litigation is in its very early stages with
written discovery propounded by ATP, but no answers received, and no depositions
taken. The judge has abated the litigation, until arbitration pursuant to the
underlying agreements between the sellers and ATP is completed. The arbitration
is presently scheduled for mid to late February of 2003. Since the legal and
arbitration proceedings have just begun, and a prediction of the outcome would
be premature and uncertain, we have not accrued any amount related to this
matter. And while we are seeking recovery of the amounts previously paid and
discussed above, the $3.0 million was charged to earnings in 2001 along with
certain other costs related to this matter. ATP intends to vigorously defend
against the sellers' claims and forcefully pursue its own claims in this matter.
18
In August 2001, Burlington Resources Inc. filed suit against ATP alleging
formation of a contract with ATP 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 also, 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.
Accounting Pronouncements
In June 2001 the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 143 "Accounting for
Asset Retirement Obligations" ("SFAS 143"). 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. The
statement is effective for fiscal years beginning after June 15, 2002. We will
adopt the statement for our fiscal year beginning 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. We are currently
assessing the impact of SFAS 143 and therefore, at this time, cannot reasonably
estimate the effect of this statement on our consolidated financial position or
results of operations.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statement
Nos. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" ("SFAS 145"). SFAS 145 requires that gains and losses from
extinguishment of debt be classified as extraordinary items only if they meet
the criteria in Accounting Principles Board Opinion No. 30 ("Opinion No. 30").
Applying the provisions of Opinion No. 30 will distinguish transactions that are
part of an entity's recurring operations from those that are unusual and
infrequent that meet the criteria for classification as an extraordinary item.
The statement is effective for fiscal years beginning after May 15, 2002. We
will adopt the provisions of SFAS 145 for our fiscal year beginning January 1,
2003. The adoption of the provisions of SFAS 145 is not expected to affect our
future financial position or liquidity. When we adopt the provisions of SFAS
145, gains or losses from the early extinguishment of debt recognized in our
consolidated statements of operations for prior years will be reclassified to
other revenues or other expense and included in the determination of the income
(loss) from continuing operations of those periods.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" ("SFAS 146"). SFAS 146 addresses
financial accounting and reporting for costs associated with exit or disposal
activities and nullified Emerging Issues Task Force Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring". SFAS 146
requires that a liability for a cost associated with an exit or disposal
activity be recognized when the liability is incurred. SFAS 146 also establishes
that fair value is the objective for initial measurement of the liability. The
provisions of this statement are effective for exit or disposal activities that
are initiated after December 31, 2002. We will adopt the provisions of SFAS 146
on January 1, 2003 and are currently assessing the impact of the statement on
our financial position and results of operations, if any.
19
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 counter parties which we believe to be of high
credit quality and the risk of credit loss is considered insignificant. We have
never experienced a loss on a derivative contract due to the inability of the
counter party to fulfill their portion of the contract.
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 flows, we periodically enter into 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. In addition to these arrangements, we also manage our exposure
to oil and gas price risks by periodically entering into fixed-price delivery
contracts. (See Note 7 to our Consolidated Financial Statements for a discussion
of activities involving derivative financial instruments during 2002.) Our
internal hedging policy provides that we examine the economic effect of entering
into a commodity contract with respect to the properties that we acquire. We
generally acquire properties at prices that are below the management's estimated
value of the estimated proved reserves at the then current natural gas and oil
prices. We will enter into short term hedging arrangements if (1) 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 or (2) if
deemed necessary by the terms of our existing credit agreements.
To calculate the potential effect of the derivative and fixed-price
contracts on future income (loss) before taxes, we applied the NYMEX oil and gas
strip prices as of June 30, 2002 to the quantity of our oil and gas production
covered by those contracts as of that date. The following table shows the
estimated potential effects of the derivative and fixed-price contracts on
future income (loss) before taxes (in thousands):
Estimated Increase (Decrease)
In Income (Loss)
Before Taxes Due To
-----------------------------
10% 10%
Decrease Increase
in Prices in Prices
--------- ---------
Instrument
- ---------
Natural gas swaps................................ $3,827 $(3,827)
Oil swaps........................................ 774 (774)
Natural gas fixed price contracts................ 2,235 (2,235)
Oil fixed price contracts........................ 242 (242)
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.
Foreign Currency Risk. The net assets, net earnings and cash flows from our
wholly owned subsidiary in the U.K. are based on the U.S. dollar equivalent of
such amounts measured in the applicable functional currency. These foreign
operations have the potential to impact our financial position due to
fluctuations in the local currency arising from the process of re-measuring the
local functional currency in the U.S. dollar. We have not utilized derivatives
or other financial instruments to hedge the risk associated with the movement in
foreign currencies.
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:
o projected operating or financial results;
o budgeted or projected capital expenditures;
o statements about pending or recent acquisitions, including the
anticipated closing dates;
o expectations regarding our planned expansions and the availability of
acquisition opportunities;
o statements about the expected drilling of wells and other planned
development activities;
o expectations regarding natural gas and oil markets in the United
States and the United Kingdom; and
o 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:
o the timing and extent of changes in natural gas and oil prices;
o the timing of planned capital expenditures and availability of
acquisitions;
o the inherent uncertainties in estimating proved reserves and
forecasting production results;
o 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;
o the condition of the capital markets generally, which will be affected
by interest rates, foreign currency fluctuations and general economic
conditions;
o 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
o 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
Items 1, 2, 3, & 5 are not applicable and have been omitted.
Item 4 - Submission of Matters to a Vote of Security Holders
The following items were presented for approval to stockholders of record on
April 30, 2002 at the Company's annual meeting of stockholders which was held on
June 14, 2002 in Houston, Texas:
(i) Election of Directors:
Abstained or
For Against Withheld
---------- ------- -------------
Chris A. Brisack ....................................... 20,180,275 - 21,857
Walter Wendlandt ....................................... 20,178,125 - 24,007
(ii) Ratification of KPMG LLP, independent certified public
accountants, as auditors of the Company's financial
statements for 2002. .................................. 20,182,462 15,570 4,100
Of the 20,314,267 shares of common stock outstanding on June 14, 2002,
20,202,132 were voted.
All matters received the required number of votes for approval.
Item 6 - Exhibits and Reports on Form 8-K
A. Exhibits - None
10.1 Amended and Restated Credit Agreement dated July 31, 2002, among ATP
Oil & Gas Corporation, Union Bank of California, N.A., as Agent,
Guaranty Bank, FSB, as Co-Agent and the Lenders Signatory thereto.
99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
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: August 13, 2002 By: /s/ Albert L. Reese, Jr.
---------------------------------------
Albert L. Reese, Jr.
Senior Vice President and Chief
Financial Officer
22