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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, 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 May 10, 2002, was 20,314,148.
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ATP OIL & GAS CORPORATION
TABLE OF CONTENTS
Page
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets:
March 31, 2002 (unaudited) and December 31, 2001........... 3
Consolidated Statements of Operations: For the
three months ended March 31, 2002 and 2001 (unaudited)..... 4
Consolidated Statements of Cash Flows: For the
three months ended March 31, 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............................. 11
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK...... 17
PART II. OTHER INFORMATION............................................... 19
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Amounts)
March 31, December 31,
2002 2001
------------- --------------
(unaudited)
Assets
Current assets
Cash and cash equivalents....................................................... $ 2,714 $ 5,294
Accounts receivable (net of allowance of $1,430 and $1,423, respectively)....... 12,311 10,371
Commodity contracts and other derivatives....................................... - 1,936
Other current assets............................................................ 1,841 1,754
------------- --------------
Total current assets......................................................... 16,866 19,355
------------- --------------
Oil and gas properties
Oil and gas properties (using the successful efforts method of accounting)...... 325,209 319,506
Less: Accumulated depreciation, depletion, impairment and amortization.......... (198,249) (186,473)
------------- --------------
Oil and gas properties, net.................................................. 126,960 133,033
------------- --------------
Furniture and fixtures (net of accumulated depreciation)............................ 780 794
Deferred tax asset.................................................................. 22,655 19,228
Other assets, net................................................................... 5,204 5,154
------------- --------------
Total assets................................................................. $ 172,465 $ 177,564
============= ==============
Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accruals................................................... $ 21,476 $ 26,426
Current maturities of long-term debt............................................ 24,000 22,000
Commodity contracts and other derivatives....................................... 5,399 -
------------- --------------
Total current liabilities.................................................... 50,875 48,426
Long-term debt...................................................................... 72,175 78,111
Commodity contracts and other derivatives........................................... 2,053 671
Deferred revenue.................................................................... 1,251 1,296
Other long-term liabilities and deferred obligations................................ 7,245 4,068
------------- --------------
Total liabilities............................................................ 133,599 132,572
------------- --------------
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;
20,388,488 issued and 20,312,648 outstanding
at March 31, 2002 and at December 31, 2001................................... 20 20
Additional paid in capital...................................................... 80,721 80,478
Accumulated deficit............................................................. (40,977) (34,614)
Accumulated other comprehensive income.......................................... 13 19
Treasury stock.................................................................. (911) (911)
------------- --------------
Total shareholders' equity................................................... 38,866 44,992
------------- --------------
Total liabilities and shareholders' equity................................... $ 172,465 $ 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
March 31,
----------------------------
2002 2001
------------- -------------
Revenue
Oil and gas production......................................................... $ 18,610 $ 38,505
Gas sold - marketing........................................................... 1,180 2,938
------------- -------------
Total revenues............................................................... 19,790 41,443
------------- -------------
Costs and operating expenses
Lease operating expenses....................................................... 3,815 2,447
Gas purchased - marketing...................................................... 1,136 2,886
Geological and geophysical expenses............................................ (43) 359
General and administrative expenses............................................ 2,478 1,915
Non-cash compensation expense (general and administrative)..................... 243 1,584
Depreciation, depletion and amortization....................................... 11,860 11,032
Impairment on oil and gas properties........................................... - 8,478
------------- -------------
Total costs and operating expenses........................................... 19,489 28,701
------------- -------------
Income from operations............................................................ 301 12,742
------------- -------------
Other income (expense)
Interest income................................................................ 16 656
Interest expense............................................................... (2,666) (3,308)
Loss on derivative instruments................................................. (7,440) (20,513)
------------- --------------
Total other income (expense)................................................. (10,090) (23,165)
------------- -------------
Loss before income taxes.......................................................... (9,789) (10,423)
Income tax (expense) benefit
Current........................................................................ - (59)
Deferred....................................................................... 3,426 3,609
------------- -------------
Net loss.......................................................................... $ (6,363) $ (6,873)
============= =============
Loss per common share:
Basic and diluted.............................................................. $ (0.31) $ (0.38)
============= =============
Weighted average number of common shares, basic and diluted....................... 20,313 17,886
============= =============
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,
-----------------------------
2002 2001
------------- --------------
Cash flows from operating activities
Net loss........................................................................ $ (6,363) $ (6,873)
Adjustments to reconcile net loss to net cash
provided by operating activities -
Depreciation, depletion and amortization................................... 11,860 11,032
Impairment of oil and gas properties....................................... - 8,478
Amortization of deferred financing costs................................... 381 220
Deferred tax asset......................................................... (3,427) (3,611)
Non-cash compensation expense.............................................. 243 1,584
Other non-cash items....................................................... 58 (75)
Changes in assets and liabilities -
Accounts receivable and other ............................................... (2,027) 6,600
Net assets from risk management activities................................... 8,717 (4,968)
Accounts payable and accruals................................................ (4,950) 10,054
Other long-term assets....................................................... (391) (282)
Other long-term liabilities and deferred credits............................. 3,132 (46)
------------- --------------
Net cash provided by operating activities........................................... 7,233 22,113
------------- --------------
Cash flows from investing activities
Additions and acquisitions of oil and gas properties............................ (5,703) (48,249)
Additions to furniture and fixtures............................................. (63) (126)
------------- --------------
Net cash used in investing activities............................................... (5,766) (48,375)
------------- --------------
Cash flows from financing activities
Proceeds from initial public offering .......................................... - 78,330
Payment of offering costs ...................................................... - (893)
Payments of long-term debt...................................................... (4,000) (27,750)
Proceeds from non-recourse borrowings........................................... - 2,583
Payments of non-recourse borrowings............................................. - (9,286)
Deferred financing costs........................................................ (47) (25)
------------- --------------
Net cash provided by (used in) financing activities................................. (4,047) 42,959
------------- --------------
Increase (decrease) in cash and cash equivalents.................................... (2,580) 16,697
Cash and cash equivalents, beginning of period...................................... 5,294 18,136
------------- --------------
Cash and cash equivalents, end of period............................................ $ 2,714 $ 34,833
============= ==============
Supplemental disclosures of cash flow information:
Cash paid during the period for interest........................................ $ 1,584 $ 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. 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.
The accompanying financial statements and related notes present our
consolidated financial position as of March 31, 2002 and December 31, 2001, the
results of our operations for the three months ended March 31, 2002 and 2001 and
cash flows for the three months ended March 31, 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 months ended March 31, 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. We
will adopt the Statement effective January 1, 2003. The transition adjustment
resulting from the adoption of SFAS 143 will be reported as a cumulative effect
of a change in accounting principle. 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, results of operations or
cash flows.
In August 2001 the FASB issued SFAS No. 144 "Accounting for the Impairment
or Disposal of Long-Lived Assets" ("SFAS 144") which provides that long-lived
assets to be disposed of by sale be measured at the lower of carrying amount or
fair value less cost to sell, whether reported in continuing operations or in
discontinued operations, and broadens the reporting of discontinued operations
to include all components of an entity with operations that can be distinguished
from the rest of the entity and that will be eliminated from the ongoing
operations of the entity in a disposal transaction. SFAS 144 was effective for
fiscal years beginning after December 15, 2001. The adoption of SFAS 144 did not
have a material effect on our financial position or results of operations.
Note 3 -- Long-Term Debt
Long-term debt as of the dates indicated were as follows (in thousands):
March 31, December 31,
2002 2001
------------- -------------
Credit facility................................................................. $ 66,000 $ 70,000
Note payable, net of unamortized discount of $1,075 and $1,139, respectively.... 30,175 30,111
------------- -------------
Total debt...................................................................... 96,175 100,111
Less current maturities......................................................... (24,000) (22,000)
------------- -------------
Total long-term debt....................................................... $ 72,175 $ 78,111
============= =============
6
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 U.K. subsidiary and is
guaranteed by our wholly owned subsidiary, ATP Energy, Inc. As amended, 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 March 31, 2002, the borrowing base was $66.0 million with a $2.0 million
scheduled monthly reduction for April, May and June 2002. Future monthly
reduction amounts, if any, will be set at the next redetermination date. The
redetermination dates are on or around the first business day of each calendar
quarter at which time the lenders can increase or decrease the borrowing base
and the monthly reduction amount. On May 10, 2002, the borrowing base was
redetermined to be $64.0 million as of May 1, 2002. The next scheduled
redetermination date is on or around the first business day of July 2002. The
$24.0 million of current maturities of long-term debt assumes there is no change
in the monthly reduction amount of the borrowing base during the next twelve
months. 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 during 2002. As of March 31, 2002, all of our
borrowing base under the agreement was outstanding.
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 amended
credit facility matures in November 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.
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 during 2002. As of March 31, 2002, all of our borrowing base under
the agreement was outstanding.
As of March 31, 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.
7
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 loss per share is computed based on the following
information (in thousands, except per share amounts):
Three Months Ended
March 31,
-------------------------------
2002 2001
------------- -------------
Net loss available to common shareholders....................................... (6,363) $ (6,873)
============= =============
Weighted average shares outstanding, basic and diluted.......................... 20,313 17,886
============= =============
Net loss per share, basic and diluted........................................... $ (0.31) $ (0.38)
============= =============
Note 5 -- Stock Option Compensation
In the first quarter of 2002 and 2001, we recorded a non-cash charge to
compensation expense of approximately $0.2 million and $1.6 million,
respectively, 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.
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. Our comprehensive loss for the three
months ended March 31, 2002 and 2001 was $6.4 million and $17.0 million,
respectively. The change in accumulated other comprehensive income (loss), net
of tax, for the three months ended March 31 was as follows (in thousands):
Three Months Ended
March 31,
------------------------------
2002 2001
------------- -------------
Balance at beginning of period.................................................. $ 19 $ -
Other comprehensive income (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.................................... (6) (75)
------------- ------------
Balance at end of period........................................................ $ 13 $ (10,111)
============= =============
8
Note 7 -- Derivative Instruments and Hedging 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 as to 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. In addition to these instruments, we also manage our exposure to oil
and gas price risks by periodically entering into fixed-price delivery
contracts.
We have not attempted to qualify for the hedge provisions under SFAS 133
and have not designated our derivatives as hedging instruments. 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.
As of March 31, 2002, we had derivative and fixed-price contracts in place
for the following natural gas and oil volumes:
Average
Fixed
Period Volumes Price
------ ------- -----
Natural gas (MMBtu):
2002................................................................ 7,944,000 $ 2.92
2003................................................................ 6,080,000 3.02
Oil (Bbl):
2002................................................................ 275,000 $ 24.38
As of March 31, 2002, the fair value of the swap agreements we had entered
into was a current liability of $5.4 million and long-term liability of $2.1
million. The derivative assets and liabilities represent the difference between
contract prices and future market prices on contracted volumes of the
commodities as of March 31, 2002. The net loss on derivative instruments of $7.4
million and $20.5 million for the three months ended March 31, 2002 and 2001,
respectively, are detailed below (in thousands):
Three Months Ended
March 31,
-----------------------------
2002 2001
------------- -------------
Gain (loss) on settled contracts during the period................ $ 1,277 $ (23,254)
Gain (loss) on open derivative positions at March 31, 2002........ (8,717) 2,741
------------- -------------
Total........................................................... $ (7,440) $ (20,513)
============= =============
9
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.
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 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. 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 us alleging
formation of a contract with us and our breach of the alleged contract. The
complaint seeks compensatory damages of approximately $1.1 million. We believe
that this claim is without merit, and we intend to defend it vigorously.
We are 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.
10
ATP OIL & GAS CORPORATION AND SUBSIDIARIES
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
ATP Oil & Gas Corporation ("ATP"), 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 and by developing our
acquisitions quickly.
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
March 31,
-----------------------------
2002 2001
------------- -------------
Production:
Natural gas (MMcf)................................................ 4,476 5,151
Oil and condensate (MBbls)........................................ 427 108
------------- -------------
Total (MMcfe)................................................... 7,035 5,800
Revenues (in thousands):
Natural gas....................................................... $ 10,701 $ 35,555
Effects of risk management activities (1)......................... 1,277 (23,254)
------------- -------------
Total........................................................... $ 11,978 $ 12,301
============= =============
Oil and condensate................................................ $ 7,909 $ 2,950
Effects of risk management activities............................. - -
------------- -------------
Total........................................................... $ 7,909 $ 2,950
============= =============
Natural gas, oil and condensate................................... $ 18,610 $ 38,505
Effects of risk management activities (1)......................... 1,277 (23,254)
------------- -------------
Total........................................................... $ 19,877 $ 15,251
============= =============
Table and footnote continued on following page
11
Three Months Ended
March 31,
-----------------------------
2002 2001
------------- -------------
Average sales price per unit:
Natural gas (per Mcf)............................................. $ 2.39 $ 6.90
Effects of risk management activities (per Mcf)................... 0.29 (4.51)
------------- -------------
Total........................................................... $ 2.68 $ 2.39
============= =============
Oil and condensate (per Bbl)...................................... $ 18.54 $ 27.22
Effects of risk management activities (per Bbl)................... - -
------------- -------------
Total........................................................... $ 18.54 $ 27.22
============= =============
Natural gas, oil and condensate (per Mcfe)........................ $ 2.65 $ 6.64
Effects of risk management activities (per Mcfe).................. 0.18 (4.01)
------------- -------------
Total........................................................... $ 2.83 $ 2.63
============= =============
Expenses (per Mcfe):
Lease operating expense........................................... $ 0.54 $ 0.35
General and administrative........................................ 0.35 0.33
Depreciation, depletion and amortization.......................... 1.69 1.90
- --------------------
(1) Represents the gain (loss) on the settlement of derivatives attributable to first quarter
2002 and 2001 production of 7.0 Bcfe and 5.8 Bcfe, respectively.
Three Months Ended March 31, 2002 Compared with Three Months Ended March 31,
2001
For the three months ended March 31, 2002, we reported a net loss of $6.4
million, or $0.31 per share on total revenue of $19.8 million, as compared with
a net loss of $6.9 million, or $0.38 per share on total revenue of $41.4 million
in the first quarter of 2001. Adjusted EBITDA increased 18% in the first quarter
of 2002 to $13.7 million from $11.6 million in the first quarter of 2001.
Adjusted EBITDA means earnings before interest expense, income taxes,
depreciation, depletion and amortization, impairments on oil and gas properties,
unrealized gains and losses, non-cash compensation expense and extraordinary
items. Our Adjusted EBITDA margin increased to 65% as compared to 63% in 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. Our revenue from natural gas and oil production for
the first quarter of 2002 decreased over the same period in 2001 by
approximately 52%, from $38.5 million to $18.6 million. This decrease was
primarily due to an approximate 65% decrease in our natural gas sales price
partially offset by a 21% increase in production. The increase in production
volumes from 5.8 Bcfe to 7.0 Bcfe was attributable to new wells brought on line
subsequent to the first quarter of 2001.
Marketing Revenue. Revenues from natural gas marketing activities decreased
to $1.2 million in the first quarter of 2002 as compared to $2.9 million in the
first quarter of 2001. This decrease was due to a decrease in the sales price
per MMBtu. The average sales price per MMBtu decreased from $6.52 in the first
quarter of 2001 to $2.62 in the first quarter of 2002.
Lease Operating Expense. Lease operating expenses for the first quarter of
2002 increased to $3.8 million from $2.4 million in the first quarter of 2001.
This increase was attributable to an increase in production volumes and certain
wells which were acquired subsequent to the first quarter of 2001.
12
Gas Purchased-Marketing. Our cost of purchased gas was $1.1 million for the
first quarter of 2002 compared to $2.9 million for the first quarter of 2001.
The average cost decreased from $6.41 per MMBtu in 2001 to $2.52 per MMBtu in
2002.
General and Administrative Expense. General and administrative expense
increased to $2.5 million for the first quarter of 2002 compared to $1.9 million
for the same period in 2001. The primary reason for the increase was the result
of increased expenses related to being a public company for an entire quarter
and bank charges connected with financing arrangements.
Non-Cash Compensation Expense. In the first quarter of 2002 and 2001, we
recorded a non-cash charge to compensation expense of approximately $0.2 million
and $1.6 million, respectively, for options granted since September 1999 through
the date of our initial public offering on February 5, 2001. The total expected
expense as of the measurement date will be recognized in the periods in which
the option vests. Each option is divided into three equal portions corresponding
to the three vesting dates (April 10, 2001, February 9, 2002, and February 9,
2003), with the related compensation cost for each portion amortized
straight-line over the period to the vesting date.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense increased 8% from the first quarter 2001 amount of
$11.0 million to the first quarter 2002 amount of $11.9 million. The average
DD&A rate was $1.69 per Mcfe in the first quarter of 2002 compared to $1.90 per
Mcfe in the same quarter of 2001.
Impairment Expense. For the first quarter of 2001, we recorded an
impairment of $8.5 million due primarily to drilling an unsuccessful development
well. We recorded no impairments in the first quarter of 2002.
Other Income (Expense). In the first quarter of 2002 and 2001, we recorded
a net loss on derivative instruments of $7.4 million and $20.5 million,
respectively. The net loss in 2002 is comprised of a realized gain of $1.3
million for derivative contracts settled in the quarter and an unrealized loss
of $8.7 million representing the change in fair market value of the open
derivative positions at March 31, 2002. The net loss in 2001 is comprised of a
realized loss of $22.8 million for derivative contracts settled in the quarter
and an unrealized gain of $2.3 million representing the change in fair market
value of the open derivative positions at March 31, 2001.
Interest expense decreased to $2.7 million in the first quarter of 2002
from $3.3 million in the comparable quarter of 2001 primarily due to lower
borrowing levels in addition to a slight decrease in interest rates.
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 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
planned capital requirements through the end of 2002. 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. 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. 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 during 2002. As operator of all of our projects in
development, we have the ability to significantly control the timing of most of
our 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, which could negatively impact our
future revenues and cash flows.
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Cash Flows
Three Months Ended,
March 31,
----------------------------
2002 2001
------------- ------------
(in thousands)
Cash provided by (used in)
Operating activities................................. $ 7,233 $ 22,113
Investing activities................................. (5,766) (48,375)
Financing activities................................. (4,047) 42,959
Cash provided by operating activities in the first quarter of 2002 and 2001
was $7.2 million and $22.1 million, respectively. Cash flow from operations
decreased due to the sharp decline in oil and gas prices from the first quarter
of 2001, somewhat offset by the 21% increase in production. In addition, our
significant decrease in development activity during the first quarter of 2002
allowed us to use available cash to reduce amounts owed to third parties.
Cash used in investing activities in the first quarter of 2002 and 2001 was
$5.8 million and $48.3 million, respectively. We incurred no costs for the one
acquisition made in the first quarter of 2002 and incurred $5.2 million for
development activity on one project that was postponed in 2001. In the first
quarter of 2001, $23.1 million was used for the acquisition of eleven properties
in the Gulf of Mexico and the Southern Gas Basin of the North Sea.
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 quarter of 2001 included the proceeds from our initial
public offering in February 2001 of $78.3 million and the repayment of our prior
credit facility of $27.8 million.
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 U.K. subsidiary and is
guaranteed by our wholly owned subsidiary, ATP Energy, Inc. As amended, 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 March 31, 2002, the borrowing base was $66.0 million with a $2.0 million
scheduled monthly reduction for April, May and June 2002. On May 10, 2002, the
borrowing base was redetermined to be $64.0 million as of May 1, 2002. Future
monthly reduction amounts, if any, will be set at the next redetermination date.
The redetermination dates are on or around the first business day of each
calendar quarter at which time the lenders can increase or decrease the
borrowing base and the monthly reduction amount. The next scheduled
redetermination date is on or around the first business day of July 2002. The
$24.0 million of current maturities of long-term debt assumes there is no change
in the monthly reduction amount of the borrowing base during the next twelve
months. 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 during 2002. As of March 31, 2002, all of our
borrowing base under the agreement was outstanding.
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 amended
credit facility matures in November 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.
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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 during 2002. As of March 31, 2002, all of our borrowing base under
the agreement was outstanding.
As of March 31, 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.
Working Capital
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 a deficit of
approximately $4.6 million at March 31, 2002 as compared to a deficit of
approximately $9.0 million at December 31, 2001. The 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.
Our 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, sale of interests in selected properties and the potential sale and
lease back of certain of our platforms and pipelines. We have also explored the
possibility of the issuance of new debt or equity in both the public and private
markets. 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 development and acquisition
program. 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.
15
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 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. 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 us alleging
formation of a contract with us and our breach of the alleged contract. The
complaint seeks compensatory damages of approximately $1.1 million. We believe
that this claim is without merit, and we intend to defend it vigorously.
We are 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 FASB 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. We will adopt the Statement effective January 1, 2003. The
transition adjustment resulting from the adoption of SFAS 143 will be reported
as a cumulative effect of a change in accounting principle. 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,
results of operations or cash flows.
16
In August 2001 the FASB issued SFAS No. 144 "Accounting for the Impairment
or Disposal of Long-Lived Assets" ("SFAS 144") which provides that long-lived
assets to be disposed of by sale be measured at the lower of carrying amount or
fair value less cost to sell, whether reported in continuing operations or in
discontinued operations, and broadens the reporting of discontinued operations
to include all components of an entity with operations that can be distinguished
from the rest of the entity and that will be eliminated from the ongoing
operations of the entity in a disposal transaction. SFAS 144 was effective for
fiscal years beginning after December 15, 2001. The adoption of SFAS 144 did not
have a material effect on our financial position or results of operations.
Item 3. Quantitative and Qualitative Disclosures about Market Risks
We are exposed to various market risks, including volatility in natural gas
and oil commodity prices and interest rates. To manage such exposure, we monitor
our expectations of future commodity prices and interest rates when making
decisions with respect to risk management. 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.
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 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. 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.
As of March 31, 2002, we had derivative and fixed-price contracts in place
for the following natural gas and oil volumes:
Average
Fixed
Period Volumes Price
------ ------- -----
Natural gas (MMBtu):
2002 ............................................................... 7,944,000 $ 2.92
2003 ............................................................... 6,080,000 3.02
Oil (Bbl):
2002 ............................................................... 275,000 $ 24.38
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.
17
Forward-Looking Statements and Associated Risks
Some of the information included in this quarterly report includes
assumptions, expectations, projections, intentions or beliefs about future
events. These statements are intended as "forward-looking statements" under the
Private Securities Litigation Reform Act of 1995. We caution that assumptions,
expectations, projections, intentions and beliefs about future events may and
often do vary from actual results and the differences can be material.
All statements in this document that are not statements of historical fact
are forward looking statements. Forward looking statements include, but are not
limited to:
. projected operating or financial results;
. budgeted or projected capital expenditures;
. statements about pending or recent acquisitions, including the
anticipated closing dates;
. expectations regarding our planned expansions and the
availability of acquisition opportunities;
. statements about the expected drilling of wells and other planned
development activities;
. expectations regarding natural gas and oil markets in the United States
and the United Kingdom; and
. timing and amount of future production of natural gas and oil.
When used in this document, the words "anticipate," "estimate," "project,"
"forecast," "may," "should," and "expect" reflect forward-looking statements.
There can be no assurance that actual results will not differ materially
from those expressed or implied in such forward looking statements. Some of the
key factors which could cause actual results to vary from those expected
include:
. the timing and extent of changes in natural gas and oil prices;
. the timing of planned capital expenditures and availability of
acquisitions;
. the inherent uncertainties in estimating proved reserves and
forecasting production results;
. operational factors affecting the commencement or maintenance of
producing wells, including catastrophic weather related damage,
unscheduled outages or repairs, or unanticipated changes in drilling
equipment costs or rig availability;
. the condition of the capital markets generally, which will be affected
by interest rates, foreign currency fluctuations and general economic
conditions;
. cost and other effects of legal and administrative proceedings,
settlements, investigations and claims, including environmental
liabilities which may not be covered by indemnity or insurance; and
. other U.S. or United Kingdom regulatory or legislative developments
which affect the demand for natural gas or oil generally, increase the
environmental compliance cost for our production wells or impose
liabilities on the owners of such wells.
18
PART II. OTHER INFORMATION
Items 1, 2, 3, 4 & 5 are not applicable and have been omitted.
Item 6 - Exhibits and Reports on Form 8-K
A. Exhibits - None
B. Reports on Form 8-K - None.
19
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, 2002 By: /s/ Albert L. Reese, Jr.
--------------------------------
Albert L. Reese, Jr.
Senior Vice President and Chief
Financial Officer
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