UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended September 30, 2001
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the transition period from to
Commission file number 1-12074
STONE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 72-1235413
(State or other jurisdiction (I.R.S. employer
of incorporation or organization) identification no.)
625 E. Kaliste Saloom Road 70508
Lafayette, Louisiana (Zip code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (337) 237-0410
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 ___
As of November 9, 2001, there were 26,189,270 shares of the Registrant's
Common Stock, par value $.01 per share, outstanding.
TABLE OF CONTENTS
Page
PART I
Item 1. Financial Statements:
Condensed Consolidated Balance Sheet
as of September 30, 2001 and December 31, 2000.................. 1
Condensed Consolidated Statement of Operations
for the Three and Nine Months Ended September 30, 2001 and 2000. 2
Condensed Consolidated Statement of Cash Flows
for the Nine Months Ended September 30, 2001 and 2000........... 3
Notes to Condensed Consolidated Financial Statements.............. 4
Auditors' Review Report........................................... 8
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................. 9
PART II
Item 6. Exhibits and Reports on Form 8-K.................................. 13
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET
(In thousands)
September 30, December 31,
ASSETS 2001 2000
------------------ ----------------
(Unaudited)
Current assets:
Cash and cash equivalents.................................... $20,077 $78,557
Marketable securities, at market............................. - 300
Accounts receivable.......................................... 53,306 95,722
Put contracts................................................ 27,047 1,847
Other current assets......................................... 3,051 2,916
------------------ ----------------
Total current assets....................................... 103,481 179,342
Oil and gas properties, net:
Proved....................................................... 593,268 691,883
Unevaluated.................................................. 67,600 55,691
Building and land, net........................................... 5,377 4,914
Fixed assets, net................................................ 5,058 4,441
Put contracts.................................................... 5,541 3,152
Other assets, net................................................ 2,943 4,681
------------------ ----------------
Total assets............................................... $783,268 $944,104
================== ================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.............................................. $104,657 $116,281
Fair value of swap contracts.................................. 1,664 -
Other current liabilities..................................... 2,528 9,996
------------------ ----------------
Total current liabilities.................................. 108,849 126,277
Long-term debt................................................... 100,000 148,000
Production payments.............................................. 5,917 10,906
Deferred tax liability........................................... 34,417 68,926
Fair value of swap contracts..................................... 4,489 -
Other long-term liabilities...................................... 1,284 2,418
------------------ ----------------
Total liabilities.......................................... 254,956 356,527
------------------ ----------------
Common stock..................................................... 262 260
Additional paid in capital....................................... 447,027 440,729
Retained earnings................................................ 69,847 146,588
Other comprehensive income....................................... 11,176 -
------------------ ----------------
Total stockholders' equity................................. 528,312 587,577
------------------ ----------------
Total liabilities and stockholders' equity................. $783,268 $944,104
================== ================
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per share amounts)
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------- -------------------------------
2001 2000 2001 2000
--------------- ------------ ------------- ------------
Revenues
Oil and gas production........................ $82,366 $108,536 $331,371 $261,846
Other income.................................. 716 1,011 2,441 2,872
--------------- ------------ ------------- ------------
Total revenues......................... 83,082 109,547 333,812 264,718
--------------- ------------ ------------- ------------
Expenses
Normal lease operating expenses............... 12,543 10,754 35,491 29,644
Major maintenance expenses.................... 1,765 2,831 4,371 5,046
Production taxes.............................. 1,736 2,047 5,255 5,668
Depreciation, depletion and amortization...... 47,537 30,589 126,061 83,454
Write-down of oil and gas properties.......... 237,741 - 237,741 -
Interest...................................... 771 2,164 2,589 6,989
Salaries, general and administrative.......... 3,194 3,146 9,114 9,057
Incentive compensation plan................... - 504 523 1,092
Hedge premium expense......................... 889 - 2,223 -
Merger expenses............................... 88 - 25,719 -
--------------- ------------ ------------- ------------
Total expenses......................... 306,264 52,035 449,087 140,950
--------------- ------------ ------------- ------------
Net income (loss) before income taxes........... (223,182) 57,512 (115,275) 123,768
--------------- ------------ ------------- ------------
Income tax provision (benefit):
Current....................................... - 205 500 272
Deferred...................................... (78,114) 19,925 (39,034) 43,047
--------------- ------------ ------------- ------------
(78,114) 20,130 (38,534) 43,319
--------------- ------------ ------------- ------------
Net income (loss)............................... ($145,068) $37,382 ($76,741) $80,449
=============== ============ ============= ============
Earnings per common share:
Basic earnings (loss) per share ............. ($5.54) $1.45 ($2.94) $3.12
=============== ============ ============= ============
Diluted earnings (loss) per share............ ($5.54) $1.42 ($2.94) $3.06
=============== ============ ============= ============
Average shares outstanding................... 26,184 25,839 26,084 25,772
=============== ============ ============= ============
Average shares outstanding assuming
dilution.................................. 26,184 26,388 26,084 26,277
=============== ============ ============= ============
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
(Unaudited)
Nine Months Ended
September 30,
--------------------------------------
2001 2000
---------------- ----------------
Cash flows from operating activities:
Net income (loss)............................................. ($76,741) $80,449
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
DD&A.................................................... 126,061 83,454
Write-down of oil and gas properties.................... 237,741 -
Provision (benefit) for deferred income taxes........... (39,034) 43,047
Non-cash effect of production payments.................. (4,691) (4,279)
Amortization of hedge premiums.......................... 2,223 -
Other non-cash expenses................................. 912 922
---------------- ----------------
246,471 203,593
Decrease in marketable securities..................... 300 34,606
(Increase) decrease in accounts receivable............ 42,416 (29,088)
(Increase) decrease in other current assets........... (526) 1,021
Increase (decrease) in other accrued liabilities...... (10,152) 10,755
Investment in put contracts........................... (6,466) -
Other................................................. (1,251) 214
---------------- ----------------
Net cash provided by operating activities....................... 270,792 221,101
---------------- ----------------
Cash flows from investing activities:
Investment in oil and gas properties....................... (286,518) (187,284)
Building additions and renovations......................... (562) (1,007)
Sale of unevaluated properties............................. 1,366 3,790
Increase in other assets .................................. (159) (1,571)
---------------- ----------------
Net cash used in investing activities........................... (285,873) (186,072)
---------------- ----------------
Cash flows from financing activities:
Proceeds from borrowings..................................... 5,000 59,000
Repayment of debt............................................ (53,000) (45,000)
Deferred financing costs..................................... - (200)
Purchase of treasury stock................................... (200) (649)
Proceeds from the exercise of stock options.................. 4,801 3,067
---------------- ----------------
Net cash provided by (used in) financing activities............. (43,399) 16,218
---------------- ----------------
Net increase (decrease) in cash and cash equivalents............ (58,480) 51,247
Cash and cash equivalents, beginning of period.................. 78,557 17,651
---------------- ----------------
Cash and cash equivalents, end of period........................ $20,077 $68,898
================ ================
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)...................... $4,715 $8,640
Income taxes.............................................. 500 272
STONE ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - INTERIM FINANCIAL STATEMENTS
The condensed consolidated financial statements of Stone Energy Corporation
at September 30, 2001 and for the three- and nine-month periods then ended are
unaudited and reflect all adjustments (consisting only of normal recurring
adjustments) which are, in the opinion of management, necessary for a fair
presentation of the financial position and operating results for the interim
period. The condensed consolidated financial statements should be read in
conjunction with the consolidated financial statements and notes thereto,
together with management's discussion and analysis of financial condition and
results of operations, contained in our Current Report on Form 8-K filed on
September 20, 2001. The results of operations for the three- and nine-month
periods ended September 30, 2001 are not necessarily indicative of future
financial results. Certain prior period amounts have been reclassified to
conform to current period presentation.
In accordance with the pooling of interests method of accounting for a
merger transaction, all results were combined to give effect to the merger of
Stone and Basin Exploration, Inc. Prior to the merger, Basin accounted for
depreciation, depletion and amortization (DD&A) of oil and gas properties using
the units of production method. In connection with the restatement of our
financial statements on a pooling-of-interests basis, Basin's historical
provision for DD&A was restated to conform to the future gross revenue method
used by Stone. This restatement included related adjustments to Basin's
historical reduction in carrying value of oil and gas properties recorded at the
end of 1998 and their historical provision for income taxes. All periods
presented reflect the effects of these adjustments. In addition, we reclassified
certain amounts in Basin's historical financial statements to conform to Stone's
presentation.
NOTE 2 - EARNINGS PER SHARE
In periods of net losses, basic and dilutive net income per share of common
stock are calculated by dividing net income applicable to common stock by the
weighted-average number of common shares outstanding during the period. In
addition, the weighted-average number of options granted to outside directors
and employees that are traditionally considered dilutive are added to
anti-dilutive shares for those periods.
Since we reported net losses for the three- and nine-month periods ended
September 30, 2001, there were no dilutive shares for those periods and
antidilutive shares totaled approximately 1,053,000 and 962,000 shares,
respectively.
Dilutive shares for the third quarter and first nine months of 2000 totaled
approximately 549,000 and 505,000 shares, respectively. Antidilutive shares for
the these periods only included options whose exercise price exceeded the
average price of our stock and totaled approximately 391,000 and 286,000 shares,
respectively.
NOTE 3 - CEILING TEST WRITE-DOWN
The Securities and Exchange Commission requires companies to calculate a
comparison of net capitalized costs of proved oil and gas properties to the
discounted present value of future cash flows from the related reserves. The
calculation is made using commodity prices held flat for the life of the
reserves. If capitalized costs exceed discounted cash flows, the assets are
required to be written down to the value of the discounted cash flows. We have
historically used commodity prices on the last day of the quarter for reserve
valuation purposes including the calculation of the ceiling test. As a result of
the low natural gas price on September 30, 2001, we recorded a $237.7 million
non-cash write-down of our oil and gas properties during the third quarter of
2001.
Throughout September 2001, natural gas prices declined and closed on
September 30, 2001 at $1.83 per MMBtu. The price volatility of today's natural
gas market makes it difficult to determine the appropriate pricing for valuation
as illustrated by the price change between September 30, 2001 and October 31,
2001. The September 30, 2001 natural gas price, which was used in calculating
the ceiling test write-down that we recorded in third quarter of 2001, is
significantly different from the closing price of natural gas on October 31,
2001 of $3.29 per MMBtu. If our discounted cash flows were valued using October
31, 2001 prices, no ceiling test write-down would have occurred. While use of
the lower quarter-end natural gas price did result in an oil and gas property
write-down, it did not result in the loss of any proved reserves.
NOTE 4 - HEDGING ACTIVITIES
We enter into hedging transactions to secure a price for a portion of
future production that is acceptable at the time at which the transaction is
entered into. The primary objective of these activities is to reduce our
exposure to the possibility of declining oil and gas prices during the term of
the hedge. We do not enter into hedging transactions for trading purposes. We
currently utilize two forms of hedging contracts: fixed price swaps and puts.
Fixed price swaps typically provide for monthly payments by us if NYMEX
prices rise above the fixed swap price or to us if prices fall below the fixed
swap price.
Put contracts are purchased at a rate per unit of hedged production that
fluctuates with the commodity futures market. The historical cost of the put
contracts represents our maximum cash exposure. We are not obligated to make any
further payments under the put contracts regardless of future commodity price
fluctuations. Under put contracts, monthly payments are made to us if NYMEX
prices fall below the agreed upon floor price, while allowing us to fully
participate in commodity prices above that floor.
Since over 90% of our production has historically been derived from the
Gulf Coast Basin, we believe that fluctuations in NYMEX prices will closely
match changes in the market price we receive for our production. Oil contracts
typically settle using the average of the daily closing prices for a calendar
month. Natural gas contracts typically settle using the average closing prices
of near month NYMEX futures contracts for three days prior to the settlement
date.
The following table shows our hedging position as of October 1, 2001.
Puts
----------------------------------------------------------
Gas Oil
--------------------------- ---------------------------
Volume Volume
(BBtus) Floor (Bbls) Floor
----------- ----------- ------------ -----------
2001............. 7,360 $3.50 322,000 $25.00
2002............. 21,900 3.50 1,277,500 24.00
Fixed Price Gas Swaps
------------------------------------------
Volume (BBtus) Price
------------------- ------------------
2001............. 1,840 $2.33
2002............. 3,650 2.15
2003............. 3,650 2.15
During the third quarters of 2001 and 2000, we realized net increases
(decreases) in oil and gas revenues related to hedging transactions of $2.6
million and ($14.1) million, respectively. Nine-month 2001 and 2000 oil and gas
revenues included net decreases of ($10.5) million and ($26.3) million,
respectively.
During the third quarter and first nine months of 2001, we recognized $0.9
million and $2.2 million of hedge premium expenses, which represents
amortization of the historical cost associated with oil and gas put contracts
that settled during the respective periods of 2001. At September 30, 2001, the
unsettled put contracts were recorded as assets totaling $32.6 million and the
unsettled gas swaps were recorded as liabilities totaling $6.2 million. All
changes in fair values of the puts and swaps were recorded net of taxes in
equity through other comprehensive income (See Note 7).
NOTE 5 - LONG-TERM DEBT
At September 30, 2001, the borrowing base under our current credit facility
was $200 million with outstanding letters of credit totaling $7.3 million and no
outstanding borrowings. We are currently negotiating a new bank credit facility
that will, among other things, increase our credit facility from $200 million to
$400 million. We expect to finance a portion of the Conoco property acquisition
(See Note 9) with borrowings under this credit facility.
NOTE 6 - PRODUCTION PAYMENTS
In 1999, we acquired a 51% working interest in the Lafitte Field by
executing an agreement that included a dollar-denominated production payment to
be satisfied through the sale of production from the purchased property. Based
on the quarterly revaluation of this transaction, at September 30, 2001, the
production payment associated with this purchase totaled $1.4 million.
In July 1999, we acquired an additional working interest in East Cameron
Block 64 and a 100% working interest in West Cameron Block 176 in exchange for a
volumetric production payment. This agreement requires that 7.3 MMcf of gas per
day be delivered to the seller from South Pelto Block 23 until 8 Bcf of gas have
been distributed. We amortize the volumetric production payment as specified
deliveries of gas are made to the seller and recognize non-cash revenue in the
form of gas production revenues. At September 30, 2001, the volumetric
production payment was $4.5 million, and we recognized $1.5 million and $4.5
million as gas revenues during each of the three- and nine-month 2001 and 2000
periods, respectively.
NOTE 7 - COMPREHENSIVE INCOME
Prior to the adoption of SFAS No. 133, the only component of comprehensive
income on our balance sheet was net income. Effective January 1, 2001, we
adopted SFAS No. 133 which created other components of comprehensive income as
presented in the table below.
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ------------------------------
2001 2000 2001 2000
------------- ------------- ------------ -------------
(in thousands)
Net income (loss).......................................... ($145,068) $37,382 ($76,741) $80,449
Other comprehensive income (loss), net of tax effect:
Cumulative effect of accounting change
for derivatives..................................... - - (26,114) -
Net change in fair value of derivatives............... 12,913 - 37,290 -
------------- ------------- ------------- -------------
Total other comprehensive income.................... 12,913 - 11,176 -
------------- ------------- ------------- -------------
Comprehensive income (loss)................................ ($132,155) $37,382 ($65,565) $80,449
============= ============= ============= =============
NOTE 8 - NEW ACCOUNTING STANDARD
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations," effective for fiscal years beginning after June 15,
2002. This statement will require us to record the fair value of liabilities
related to future asset retirement obligations in the period the obligation is
incurred. We expect to adopt SFAS No. 143 on January 1, 2003. Upon adoption, we
will be required to recognize cumulative transition amounts for existing asset
retirement obligation liabilities, asset retirement costs and accumulated
depreciation. We have not yet determined the transition amounts.
NOTE 9 - ACQUISITION OF CONOCO PROPERTIES
During October 2001, we entered into asset and stock purchase agreements to
acquire up to $300 million of oil and gas properties located in the Gulf of
Mexico from Conoco, Inc. A substantial portion of the offered price is
attributable to properties that are subject to elections by third party working
interest owners to exercise their preferential rights. We plan to finance the
acquisition through a combination of borrowings under our credit facility and
other long-term debt instruments. We expect to close the transaction by December
31, 2001.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE STOCKHOLDERS OF
STONE ENERGY CORPORATION:
We have reviewed the accompanying condensed consolidated balance sheet of
Stone Energy Corporation (a Delaware corporation) as of September 30, 2001, and
the related condensed consolidated statements of operations for the three-month
and nine-month periods ended September 30, 2001 and 2000, and the condensed
consolidated statements of cash flows for the nine-month periods ended September
30, 2001 and 2000. These financial statements are the responsibility of the
Company's management.
We conducted our reviews in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical procedures to
financial data and making inquiries of persons responsible for financial and
accounting matters. It is substantially less in scope than an audit conducted in
accordance with auditing standards generally accepted in the United States, the
objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our reviews, we are not aware of any material modifications that
should be made to the financial statements referred to above for them to be in
conformity with accounting principles generally accepted in the United States.
We have previously audited, in accordance with auditing standards generally
accepted in the United States, the balance sheet of Stone Energy Corporation as
of December 31, 2000, included in the Company's Form 8-K dated September 20,
2001, (not presented herein), and, in our report therein dated February 23,
2001, we expressed an unqualified opinion on that statement. In our opinion, the
information set forth in the accompanying condensed consolidated balance sheet
as of December 31, 2000, is fairly stated, in all material respects, in relation
to the balance sheet from which it has been derived.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana
October 30, 2001
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Throughout this document we make statements that are classified as
"forward-looking". Please refer to the "Forward-Looking Statements" section on
page 12 of this document for an explanation of these types of assertions. We use
the terms "Stone", "Stone Energy", "Company", "we", "us" and "our" to refer to
Stone Energy Corporation. Results for all periods reflect the combination of
Stone and Basin.
OVERVIEW
Stone Energy Corporation is an independent oil and gas company engaged in
the acquisition, exploration, development and operation of oil and gas
properties in the Gulf Coast Basin and Rocky Mountains.
Our business strategy is to increase production, cash flow and reserves
through the acquisition and development of mature properties. Currently, our
property base consists of 80 productive properties, 48 in the Gulf Coast Basin
and 32 in the Rocky Mountains, and 40 Gulf Coast Basin primary term leases. We
serve as operator on 52 of our producing properties, which enables us to better
control the timing and cost of rejuvenation activities. We believe that there
will continue to be opportunities to acquire properties in the Gulf Coast Basin
due to the increased focus by major and large independent companies on projects
away from the onshore and shallow water shelf regions of the Gulf of Mexico.
BASIS OF PRESENTATION
In accordance with the pooling of interests method of accounting for a
merger transaction, all results were combined to give effect to the merger of
Stone and Basin Exploration, Inc. Prior to the merger, Basin accounted for
depreciation, depletion and amortization (DD&A) of oil and gas properties using
the units of production method. In connection with the restatement of our
financial statements on a pooling-of-interests basis, Basin's historical
provision for DD&A was restated to conform to the future gross revenue method
used by Stone. This restatement included related adjustments to Basin's
historical reduction in carrying value of oil and gas properties recorded at the
end of 1998 and their historical provision for income taxes. All periods
presented reflect the effects of these adjustments. In addition, we reclassified
certain amounts in Basin's historical financial statements to conform to Stone's
presentation.
RESULTS OF OPERATIONS
The following table sets forth certain operating information with
respect to our oil and gas operations.
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------- ---------------------------
2001 2000 2001 2000
------------ ----------- ----------- -----------
PRODUCTION:
Oil (MBbls)............................................... 1,027 1,125 3,075 3,273
Gas (MMcf):
Produced excluding volumetric production payment........ 17,066 19,164 50,725 51,691
Volumetric production payment........................... 672 667 1,993 2,000
------------ ----------- ----------- -----------
Total gas volumes produced............................. 17,738 19,831 52,718 53,691
Oil and gas (MMcfe):
Produced excluding volumetric production payment........ 23,228 25,914 69,175 71,329
Volumetric production payment........................... 672 667 1,993 2,000
------------ ----------- ----------- -----------
Total oil and gas volumes produced..................... 23,900 26,581 71,168 73,329
SALES DATA (IN THOUSANDS) (a):
Oil....................................................... $27,108 $31,838 $84,282 $84,718
Gas:
Gas sales excluding volumetric production payment...... 53,764 75,204 242,607 172,646
Volumetric production payment.......................... 1,494 1,494 4,482 4,482
------------ ----------- ----------- -----------
Total gas sales........................................ 55,258 76,698 247,089 177,128
AVERAGE SALES PRICES (a):
Oil (per Bbl)............................................. $26.40 $28.30 $27.41 $25.88
Gas (per Mcf):
Price excluding volumetric production payment.......... 3.15 3.92 4.78 3.34
Volumetric production payment.......................... 2.24 2.24 2.24 2.24
Net average price...................................... 3.12 3.87 4.69 3.30
Oil and gas (per Mcfe):
Price excluding volumetric production payment.......... 3.48 4.13 4.73 3.61
Volumetric production payment.......................... 2.24 2.24 2.24 2.24
Net average price ..................................... 3.45 4.08 4.66 3.57
EXPENSES (per Mcfe):
Normal lease operating expenses (b)....................... $0.52 $0.40 $0.50 $0.40
Salaries, general and administrative...................... 0.13 0.12 0.13 0.12
DD&A on oil and gas properties............................ 1.97 1.14 1.75 1.12
(a) Includes the effects of hedging
(b) Excludes major maintenance expenses
NET INCOME. For the third quarter of 2001, we reported a net loss totaling
$145.1 million, or $5.54 per share, compared to net income reported for the
third quarter of 2000 of $37.4 million, or $1.42 per share. Net income (loss)
for the first nine months of 2001 and 2000 totaled ($76.7) million and $80.4
million, or ($2.94) and $3.06 per share, respectively.
Included in third quarter and nine-month 2001 results was a non-cash
write-down of oil and gas properties totaling $237.7 million or $154.5 million
after taxes. In addition, during the third quarter of 2001, non-recurring merger
expenses totaled $0.1 million, bringing total 2001 merger expenses from the
Basin transaction to $25.7 million, or $18.5 million after taxes. Excluding
merger expenses and the non-cash write-down, net income for the three- and
nine-months ended September 30, 2001 totaled $9.5 million, or $0.36 per share,
and $96.3 million, or $3.64 per share, respectively.
The Securities and Exchange Commission requires companies to calculate a
comparison of net capitalized costs of proved oil and gas properties to the
discounted present value of future cash flows from the related reserves. The
calculation is made using commodity prices held flat for the life of the
reserves. If capitalized costs exceed discounted cash flows, the assets are
required to be written down to the value of the discounted cash flows. We have
historically used commodity prices on the last day of the quarter for reserve
valuation purposes including the calculation of the ceiling test.
Throughout September 2001, natural gas prices declined and closed on
September 30, 2001 at $1.83 per MMBtu. The price volatility of today's natural
gas market makes it difficult to determine the appropriate pricing for valuation
as illustrated by the price change between September 30, 2001 and October 31,
2001. The September 30, 2001 natural gas price, which was used in calculating
the ceiling test write-down that we recorded in third quarter of 2001, is
significantly different from the closing price of natural gas on October 31,
2001 of $3.29 per MMBtu. If our discounted cash flows were valued using October
31, 2001 prices, no ceiling test write-down would have occurred. While use of
the lower quarter-end natural gas price did result in an oil and gas property
write-down, it did not result in the loss of any proved reserves.
OIL AND GAS REVENUES. As a result of lower realized prices and reduced
production volumes, oil and gas revenues for the third quarter of 2001 declined
to $82.4 million, compared to $108.5 million for the third quarter of 2000.
Year-to-date oil and gas revenues increased to $331.4 million compared to $261.8
million during the comparable 2000 period.
PRICES. Prices realized during the third quarter of 2001 averaged $26.40
per barrel of oil and $3.12 per Mcf of gas. This represents a 15% decrease, on a
thousand cubic feet of gas equivalent (Mcfe) basis, from third quarter 2000
average realized prices of $28.30 per barrel of oil and $3.87 per Mcf of gas.
Average realized prices during the first nine months of 2001 were $27.41 per
barrel of oil and $4.69 per Mcf of gas compared to $25.88 per barrel of oil and
$3.30 per Mcf of gas realized during the first nine months of 2000. All unit
pricing amounts include the effects of hedging.
PRODUCTION. Natural gas production during the third quarter of 2001
decreased to approximately 17.7 billion cubic feet compared to third quarter
2000 gas production of 19.8 billion cubic feet, while oil production during the
third quarter of 2001 totaled approximately 1 million barrels compared to 1.1
million barrels of oil produced during the third quarter of 2000. On a gas
equivalent basis, production volumes for the third quarter of 2001 declined to
23.9 Bcfe compared to third quarter 2000 production of 26.6 Bcfe. Year-to-date
2001 production totaled 3.1 million barrels of oil and 52.7 billion cubic feet
of gas while year-to-date 2000 production totaled 3.3 million barrels of oil and
53.7 billion cubic feet of gas.
During the third quarter of 2000, we recorded the highest oil and gas
production volumes in our history. On an Mcfe basis, production volumes for the
third quarter of 2001 declined 10% from third quarter 2000 volumes. The decline
in our 2001 production rate has been the result of normal production declines.
Typically, we are able to offset these declines by bringing new wells on
production soon after drilling operations have been completed. During 2001
however, we have drilled multiple successful wells that we were unable to
immediately place on production due to the need for substantial production
facilities. We expect to have the facilities in place and the wells on full
production by January 2002, at which point we expect a 16% increase in our
production over our estimated average rate for 2001 of 255 MMcfe per day.
EXPENSES. Normal operating costs during the third quarter of 2001 totaled
$12.5 million, compared to $10.8 million for the comparable quarter in 2000. The
increase in operating costs was due primarily to industry-wide increases in the
costs of oil field products and services.
Depreciation, depletion and amortization (DD&A) expense on oil and gas
properties for the third quarter of 2001 totaled $47.1 million or $1.97 per
Mcfe, compared to $30.2 million or $1.14 per Mcfe for the third quarter of 2000.
Third quarter 2001 DD&A expense was negatively impacted by significantly lower
quarter-end natural gas prices. Year-to-date 2001 DD&A expense on oil and gas
properties totaled $124.8 million, or $1.75 per Mcfe, compared to $82.2 million,
or $1.12 per Mcfe, for the comparable period in 2000.
General and administrative expenses for the third quarter of 2001 totaled
$3.2 million, or $0.13 per Mcfe, compared to $3.1 million, or $0.12 per Mcfe,
for the third quarter of 2000.
As a result of the repayment of all bank debt in February 2001 and the
increase in capitalized interest on unevaluated properties, interest expense for
the third quarter of 2001 decreased to $0.8 million from $2.2 million for the
comparable 2000 period.
Our estimated effective tax rate is 35%. However, we estimated that
approximately $5.2 million of merger-related expenses were not tax deductible.
The exclusion of these expenses had a 2% impact on the effective tax rate for
the first nine months of 2001.
HEDGING ACTIVITIES
During the third quarter of 2001, hedging transactions increased the
average price we received for gas by $0.15 per Mcf compared to net decreases of
$3.34 per barrel and $0.54 per Mcf for the third quarter of 2000. Hedging
transactions for the first nine months of 2001 reduced the average price we
received for gas by $0.21 per Mcf compared to net decreases of $3.64 per barrel
and $0.28 per Mcf for the comparable 2000 period.
During the third quarter and first nine months of 2001, we recognized $0.9
million and $2.2 million of hedge premium expenses, which represents
amortization of the historical cost associated with oil and gas put contracts
that settled during the respective periods of 2001. At September 30, 2001, the
unsettled put contracts were recorded as assets totaling $32.6 million and the
unsettled gas swaps were recorded as liabilities totaling $6.2 million. All
changes in fair values of the puts and swaps were recorded in equity through
other comprehensive income.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW. Net cash flow from operations before working capital changes for
the third quarter and first nine months of 2001 was $61.5 million, or $2.35 per
share, and $246.5 million, or $9.45 per share, compared to $86.8 million and
$203.6 million, or $3.29 and $7.75 per share, reported for the respective
periods of 2000. Excluding the effect of non-recurring merger expenses, net cash
flow from operations for the third quarter of 2001 was $61.5 million and for the
first nine months of 2001 was $265 million.
CAPITAL EXPENDITURES. Capital expenditures excluding acquisition costs
during the third quarter of 2001 totaled $82.7 million, including $2.2 million
of capitalized salaries, general and administrative expenses and $1.6 million of
capitalized interest. Capital expenditures excluding acquisition costs for the
first nine months of 2001 totaled $264.3 million, including $7.8 million of
capitalized salaries, general and administrative expenses and $4.8 million of
capitalized interest. Oil and gas property acquisition costs totaled $1 million
and $12.8 million during the three- and nine-month periods ended September 30,
2001. These investments were financed by cash flow from operations and working
capital.
BUDGETED CAPITAL EXPENDITURES. Our 2001 capital expenditures budget,
excluding acquisitions, capitalized salaries, general and administrative costs
and interest, is currently $290 million. As of November 1, 2001, we spudded 66
of the 70 gross wells planned for 2001. Of the 70 wells, 50 are in the onshore
and shallow water offshore regions of the Gulf Coast Basin and 20 are in the
Rocky Mountains.
Based upon our outlook of oil and gas prices and production rates, we
believe that our cash on hand and cash flow from operations will be sufficient
to fund the remainder of our 2001 capital expenditures budget. Currently, we
estimate that our daily production rate will average 255 MMcfe for 2001. If oil
and gas prices or production rates fall below our current expectations, we
believe that the available borrowings under our bank credit facility will be
sufficient to fund the capital expenditures in excess of operating cash flow.
Although we do not budget acquisitions, we continue to evaluate properties
and transaction alternatives to add to our existing property base. On October
10, 2001, we announced that we had entered into asset and stock purchase
agreements to acquire up to $300 million of oil and gas properties located in
the Gulf of Mexico from Conoco, Inc. A substantial portion of the offered price
is attributable to properties that are subject to elections by third party
working interest owners to exercise their preferential rights. We expect to
close the transaction by December 31, 2001.
We expect to finance the Conoco property acquisition through a combination
of borrowings under our credit facility and other long-term debt instruments.
Our borrowing base is currently $200 million with outstanding letters of credit
totaling $7.3 million and no outstanding borrowings. We are currently
negotiating a new bank credit facility that will, among other things, increase
our credit facility from $200 million to $400 million.
FORWARD-LOOKING STATEMENTS. This Form 10-Q and the information incorporated
by reference contain statements that constitute "forward-looking statements"
within the meaning of Section 27A of the Securities Act and Section 21E of the
Securities Exchange Act. The words "expect", "project", "estimate", "believe",
"anticipate", "intend", "budget", "plan", "forecast", "predict" and other
similar expressions are intended to identify forward-looking statements. These
statements appear in a number of places and include statements regarding our
plans, beliefs or current expectations, including the plans, beliefs and
expectations of our officers and directors.
When considering any forward-looking statement, you should keep in mind the
risk factors that could cause our actual results to differ materially from those
contained in any forward-looking statement. Important factors that could cause
actual results to differ materially from those in the forward-looking statements
herein include the timing and extent of changes in commodity prices for oil and
gas, operating risks and other risk factors as described in our Annual Report on
Form 10-K as filed with the Securities and Exchange Commission. Furthermore, the
assumptions that support our forward-looking statements are based upon
information that is currently available and is subject to change. We
specifically disclaim all responsibility to publicly update any information
contained in a forward-looking statement or any forward-looking statement in its
entirety and therefore disclaim any resulting liability for potentially related
damages. All forward-looking statements attributable to Stone Energy Corporation
are expressly qualified in their entirety by this cautionary statement.
PART II
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
*15.1 - Letter from Arthur Andersen LLP dated November 9,
2001, regarding unaudited interim financial information.
* Filed herewith
(b) We filed the following reports on Form 8-K during the three months ended
September 30, 2001:
Date of Event Reported Item Reported
---------------------- -------------
September 20, 2001 Items 5, 7
SIGNATURE
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 thereunto duly authorized.
STONE ENERGY CORPORATION
Date: November 9, 2001 By: /s/James H. Prince
------------------------------
James H. Prince
Vice President, Chief Financial
Officer and Treasurer
(On behalf of Registrant and as
Principal Financial Officer)