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 June 30, 2002
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 July 31, 2002, there were 26,336,532 shares of the Registrant's
Common Stock, par value $.01 per share, outstanding.
TABLE OF CONTENTS
Page
PART I - FINANCIAL INFORMATION ----
Item 1. Financial Statements:
Condensed Consolidated Balance Sheet
as of June 30, 2002 and December 31, 2001.................. 1
Condensed Consolidated Statement of Operations
for the Three and Six Months Ended June 30, 2002 and 2001.... 2
Condensed Consolidated Statement of Cash Flows
for the Six Months Ended June 30, 2002 and 2001.............. 3
Notes to Condensed Consolidated Financial Statements.......... 4
Independent Public Accountants' Review Report................. 7
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations.......................... 8
Item 3. Quantitative and Qualitative Disclosures About Market Risk.... 13
PART II - OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders........... 14
Item 5. Other Information............................................. 14
Item 6. Exhibits and Reports on Form 8-K.............................. 14
Signature..................................................... 15
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET
(In thousands)
JUNE 30, DECEMBER 31,
ASSETS 2002 2001
------ ------------------ ----------------
(Unaudited)
CURRENT ASSETS:
Cash and cash equivalents........................................ $24,446 $13,155
Accounts receivable.............................................. 63,015 46,987
Put contracts.................................................... 6,392 26,207
Other current assets............................................. 8,310 1,832
------------------ ----------------
TOTAL CURRENT ASSETS....................................... 102,163 88,181
Oil and gas properties, net:
Proved....................................................... 902,402 880,534
Unevaluated.................................................. 116,668 113,372
Building and land, net........................................... 5,294 5,352
Fixed assets, net................................................ 5,593 4,883
Other assets, net................................................ 9,867 9,461
------------------ ----------------
TOTAL ASSETS............................................... $1,141,987 $1,101,783
================== ================
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
CURRENT LIABILITIES:
Accounts payable to vendors...................................... $58,587 $69,197
Undistributed oil and gas proceeds............................... 33,834 23,741
Deferred taxes................................................... - 5,312
Fair value of swap contract...................................... 4,815 2,194
Other current liabilities........................................ 5,780 5,834
------------------ ----------------
TOTAL CURRENT LIABILITIES.................................. 103,016 106,278
Long-term debt................................................... 445,000 426,000
Production payments.............................................. 1,181 4,323
Deferred taxes................................................... 42,884 30,244
Fair value of swap contract...................................... 3,000 3,619
Other long-term liabilities...................................... 2,117 1,294
------------------ ----------------
TOTAL LIABILITIES.......................................... 597,198 571,758
------------------ ----------------
Common stock..................................................... 263 262
Additional paid-in capital....................................... 453,157 449,111
Retained earnings................................................ 97,364 75,213
Treasury stock................................................... (1,706) (2,057)
Other comprehensive income (loss)................................ (4,289) 7,496
------------------ ----------------
TOTAL STOCKHOLDERS' EQUITY................................. 544,789 530,025
------------------ ----------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY................. $1,141,987 $1,101,783
================== ================
The accompanying notes are an integral part of this balance sheet.
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per share amounts)
(Unaudited)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------------- -------------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
REVENUES:
Oil and gas production............................. $100,438 $106,011 $180,968 $249,005
Other revenues..................................... 642 718 1,520 1,725
------------ ------------ ------------ ------------
TOTAL REVENUES.............................. 101,080 106,729 182,488 250,730
------------ ------------ ------------ ------------
EXPENSES:
Normal lease operating expenses.................... 15,760 12,266 30,373 22,948
Major maintenance expenses......................... 4,673 1,259 5,962 2,606
Production taxes................................... 1,029 1,657 2,099 3,519
Depreciation, depletion and amortization........... 42,166 41,888 82,915 78,524
Interest........................................... 6,032 743 11,486 1,818
Salaries, general and administrative expenses...... 3,150 3,196 6,550 5,920
Incentive compensation plan........................ 192 - 380 523
Non-cash derivative expenses....................... 3,486 879 8,507 1,334
Merger expenses.................................... - 108 - 25,631
------------ ------------ ------------ ------------
TOTAL EXPENSES.............................. 76,488 61,996 148,272 142,823
------------ ------------ ------------ ------------
NET INCOME BEFORE INCOME TAXES....................... 24,592 44,733 34,216 107,907
------------ ------------ ------------ ------------
PROVISION FOR INCOME TAXES:
Current............................................ - (2,226) - 500
Deferred........................................... 8,608 17,891 11,976 39,080
------------ ------------ ------------ ------------
TOTAL INCOME TAXES.......................... 8,608 15,665 11,976 39,580
------------ ------------ ------------ ------------
NET INCOME........................................... $15,984 $29,068 $22,240 $68,327
============ =========== ============ ============
EARNINGS PER COMMON SHARE:
Basic earnings per share ......................... $0.61 $1.11 $0.85 $2.62
============ =========== ============ ============
Diluted earnings per share........................ $0.60 $1.10 $0.84 $2.58
============ =========== ============ ============
Average shares outstanding........................ 26,339 26,085 26,301 26,033
============ =========== ============ ============
Average shares outstanding assuming dilution...... 26,554 26,456 26,499 26,449
============ =========== ============ ============
The accompanying notes are an integral part of this statement.
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
(Unaudited)
SIX MONTHS ENDED
JUNE 30,
--------------------------------------
2002 2001
---------------- ----------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income.................................................... $22,240 $68,327
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization................ 82,915 78,524
Provision for deferred income taxes..................... 11,976 39,080
Non-cash effect of production payments.................. (3,021) (3,096)
Non-cash derivative expenses............................ 8,507 1,334
Other non-cash expenses................................. 314 815
---------------- ----------------
122,931 184,984
(Increase) decrease in accounts receivable.............. (16,028) 9,919
Increase in other current assets........................ (4,073) (300)
Increase in other accrued liabilities................... 10,039 8,298
Investment in put contracts............................. (4,822) (6,466)
Other................................................... (18) (394)
---------------- ----------------
NET CASH PROVIDED BY OPERATING ACTIVITIES....................... 108,029 196,041
---------------- ----------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in oil and gas properties......................... (117,605) (193,929)
Building and fixed asset additions........................... (1,501) (403)
Sale of unevaluated properties............................... - 1,366
---------------- ----------------
NET CASH USED IN INVESTING ACTIVITIES........................... (119,106) (192,966)
---------------- ----------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from bank borrowings................................ 22,000 5,000
Repayment of bank debt....................................... (3,000) (53,000)
Deferred financing costs..................................... (217) -
Issuance (repurchase) of treasury stock...................... 351 (200)
Proceeds from the exercise of stock options.................. 3,234 4,435
---------------- ----------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES............. 22,368 (43,765)
---------------- ----------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............ 11,291 (40,690)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD.................. 13,155 78,557
---------------- ----------------
CASH AND CASH EQUIVALENTS, END OF PERIOD........................ $24,446 $37,867
================ ================
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)...................... $11,307 $1,738
Income taxes.............................................. - 500
The accompanying notes are an integral part of this statement.
STONE ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - INTERIM FINANCIAL STATEMENTS
The condensed consolidated financial statements of Stone Energy Corporation
as of June 30, 2002 and for the three- and six-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
periods. 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 Annual Report on Form 10-K for the year
ended December 31, 2001. The results of operations for the three- and six-month
periods ended June 30, 2002 are not necessarily indicative of future financial
results. Certain prior period amounts have been reclassified to conform to
current period presentation.
NOTE 2 - EARNINGS PER SHARE
Basic net income per share of common stock was calculated by dividing net
income applicable to common stock by the weighted-average number of common
shares outstanding during the period. Diluted net income per share of common
stock was calculated by dividing net income applicable to common stock by the
weighted-average number of common shares outstanding during the period plus the
weighted-average number of dilutive stock options granted to outside directors
and employees. There were approximately 215,000 and 371,000 dilutive shares for
the second quarters of 2002 and 2001, respectively, and 198,000 and 416,000
dilutive shares for the first six months of 2002 and 2001, respectively.
Options considered antidilutive because the exercise price of the option
exceeded the average price of our common stock for the applicable period totaled
approximately 781,000 and 625,000 shares in the second quarters of 2002 and
2001, respectively, and 952,000 and 551,000 shares in the first six months of
2002 and 2001, respectively.
NOTE 3 - HEDGING ACTIVITIES
We adopted Statement of Financial Accounting Standard (SFAS) No. 133,
"Accounting for Derivative Instruments and Hedging Activities," effective
January 1, 2001. Under SFAS No. 133, as amended, the nature of a derivative
instrument must be evaluated to determine if it qualifies for hedge accounting
treatment. If the instrument qualifies for hedge accounting treatment, it is
recorded as either an asset or liability measured at fair value and subsequent
changes in the derivative's fair value are recognized in equity through other
comprehensive income, to the extent the hedge is considered effective.
Instruments not qualifying for hedge accounting treatment are recorded in the
balance sheet at fair value and changes in fair value are recognized in
earnings.
We enter into hedging transactions to secure a commodity price for a
portion of future production that is acceptable at the time of the transaction.
The primary objective of these activities is to reduce our exposure to the
possibility of declining oil and natural 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: a fixed price swap and puts.
Under SFAS No. 133, our current oil and natural gas put contracts are
considered effective cash flow hedges and therefore, changes in fair value of
the puts are reflected in other comprehensive income. Put contracts are not
costless; they 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 price. Oil contracts typically
settle using the average daily closing prices for a calendar month. Natural gas
contracts typically settle using the average closing prices of near month NYMEX
futures contracts for the three days prior to the settlement date. 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
market prices we receive for our production.
In addition to put contracts, we utilize a fixed price swap to hedge a
portion of our future natural gas production. A fixed price swap provides for
monthly payments by us or to us based on the difference between the strike price
and the agreed-upon average of NYMEX prices. Our natural gas swap contract is
with a subsidiary of Enron Corp. Due to Enron's financial difficulties, there is
no assurance that we will receive full or partial payment of any amounts that
may become owed to us under this contract. Accordingly, this swap no longer
qualifies as an effective hedge under SFAS No. 133. As a result, the change in
fair value each period is recorded through earnings and amounts previously
recorded in other comprehensive income are amortized through earnings over the
remaining life of the swap. At June 30, 2002, other comprehensive income
included $3.4 million related to the ineffective natural gas swap that remains
to be amortized.
During the second quarters of 2002 and 2001, we recognized non-cash
expenses of $3.5 million and $0.9 million, respectively, related to commodity
derivatives, the majority of which represents amortized cost associated with put
contracts that settled during the respective periods. Also included in non-cash
derivative expense for the three months ended June 30, 2002 is a $0.6 million
charge from amortization of other comprehensive income and a $0.4 million gain
related to the change in fair value of the natural gas swap. At June 30, 2002,
the unsettled put contracts were recorded as assets totaling $6.4 million and
the unsettled natural gas swap was recorded as a liability totaling $7.8
million.
Our hedge positions for the period July 1, 2002 through December 31, 2003
are summarized as follows. Currently, we have no open hedge positions subsequent
to December 31, 2003.
PUTS
----------------------------------------------------------------------------------------------
GAS OIL
--------------------------------------------- ---------------------------------------------
VOLUME COST VOLUME AVERAGE COST
(BBTUS) FLOOR (MILLIONS) (MBBLS) FLOOR (MILLIONS)
------------ ------------ ------------- ------------ ------------- ------------
2002............... 11,040 $3.50 $2.6 2,852 $24.77 $5.2
FIXED PRICE GAS SWAP
-------------------------------
VOLUME
(BBTUS) PRICE
------------- --------------
2002..................... 1,840 $2.15
2003..................... 3,650 2.15
During the second quarters of 2002 and 2001, we realized net decreases in
oil and gas revenues related to hedging transactions of ($0.4) million and
($4.4) million, respectively. For the first six months of 2002 and 2001, oil and
gas revenues included net increases (decreases) of $6.1 million and ($13.1)
million, respectively, related to hedging transactions.
NOTE 4 - LONG-TERM DEBT
Long-term debt consisted of the following:
June 30, December 31,
2002 2001
----------------- ------------------
(Unaudited)
(In millions)
8 1/4% Senior Subordinated Notes due 2011........... $200 $200
8 3/4% Senior Subordinated Notes due 2007........... 100 100
Bank debt........................................... 145 126
----------------- ------------------
Total long-term debt................................ $445 $426
================= ==================
On December 5, 2001, we issued $200.0 million principal amount of 8 1/4%
Senior Subordinated Notes due 2011. The Notes were sold at par value and we
received net proceeds of $195.5 million. At June 30, 2002, $0.7 million and $2.6
million had been accrued in connection with the interest payments on the 8 1/4%
Senior Subordinated Notes and the 8 3/4% Senior Subordinated Notes,
respectively.
Borrowings outstanding at June 30, 2002 under our bank credit facility
totaled $145.0 million, and letters of credit totaling $7.3 million have been
issued under the facility. The borrowing base under the credit facility was
increased to $300.0 million during June 2002. At June 30, 2002, we had $147.7
million of borrowings available under the credit facility and the weighted
average interest rate under the credit facility was approximately 3.3%. The
credit facility matures on December 20, 2004. The borrowing base limitation is
re-determined periodically and is based on a borrowing amount established by the
bank group resulting from an evaluation of the value of our proved oil and gas
reserves.
NOTE 5 - COMPREHENSIVE INCOME
Comprehensive income consisted of the following:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------------ -----------------------------
2002 2001 2002 2001
------------ -------------- ------------ ------------
(In thousands)
(Unaudited)
Net income............................................. $15,984 $29,068 $22,240 $68,327
Other comprehensive income (loss), net of tax effect:
Cumulative effect of accounting change
for derivatives................................. - - - (26,114)
Net change in fair value of derivatives........... (2,187) 18,394 (12,541) 24,377
Amortization of other comprehensive income from
the swap........................................ 366 - 756 -
------------ -------------- ------------ ------------
Total other comprehensive income (loss)......... (1,821) 18,394 (11,785) (1,737)
------------ -------------- ------------ ------------
Comprehensive income................................... $14,163 $47,462 $10,455 $66,590
============ ============== ============ ============
NOTE 6 - COMMITMENTS
On July 29, 2002, we entered into a $28.0 million work commitment for at
least five wells over a two-year period on the Pinedale Anticline in the Green
River Basin in Wyoming. After the initial $28.0 million investment and the
drilling of five wells, we will have earned a 50% working interest in the
project area. We expect to spud the first commitment well(s) during the third
quarter of 2002, with the remaining wells to be drilled within the terms of the
agreement.
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) and subsidiary as of June 30,
2002, and the related condensed consolidated statement of operations for the
three-month and six-month periods ended June 30, 2002, and the related condensed
consolidated statement of cash flows for the six-month period ended June 30,
2002. These financial statements are the responsibility of the Company's
management. The condensed consolidated statement of operations for the
three-month and six-month periods ended June 30, 2001, and the related condensed
consolidated statement of cash flows for the six-month period ended June 30,
2001 of Stone Energy Corporation were reviewed by other accountants whose report
(dated July 31, 2001) stated that they were not aware of any material
modifications that should be made to those statements for them to be in
conformity with accounting principles generally accepted in the United States.
We conducted our review 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,
which will be performed for the full year with the objective of expressing an
opinion regarding the financial statements taken as a whole. Accordingly, we do
not express such an opinion.
Based on our review, we are not aware of any material modifications that
should be made to the accompanying financial statements at June 30, 2002, and
for the three-month and six-month periods then ended for them to be in
conformity with accounting principles generally accepted in the United States.
/s/ Ernst & Young LLP
New Orleans, Louisiana
July 29, 2002
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
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 of 1933 and Section 21E of the Securities
Exchange Act of 1934. The words "plan," "expect," "project," "estimate,"
"assume," "believe," "anticipate," "intend," "budget," "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.
OVERVIEW
Stone Energy Corporation is a Gulf Coast Basin-focused independent oil and
gas company engaged in the acquisition and subsequent exploration, development,
production and operation of oil and gas properties.
Our business strategy, which has remained consistent since 1990, is to
increase production, cash flow and reserves through the acquisition,
exploitation and development of mature oil and gas properties. Currently, our
property base consists of 92 active properties, 56 in the Gulf Coast Basin and
36 in the Rocky Mountains, and 33 primary term leases in the Gulf of Mexico. We
serve as operator on 55 of our active 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.
This report on Form 10-Q should be read in conjunction with our Annual
Report on Form 10-K for the year ended December 31, 2001. The Form 10-K includes
a discussion of risk factors to which reference is also made.
RESULTS OF OPERATIONS
The following table sets forth certain operating information with respect
to our oil and gas operations.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------------ ---------------------------
2002 2001 2002 2001
------------ ------------ ----------- -----------
PRODUCTION:
Oil (MBbls)...................................... 1,618 1,039 3,235 2,049
Gas (MMcf)....................................... 17,948 17,954 34,825 34,979
Oil and gas (MMcfe).............................. 27,656 24,188 54,235 47,273
SALES DATA (IN THOUSANDS) (a):
Oil.............................................. $40,608 $27,586 $74,539 $57,174
Gas ............................................. 59,830 78,425 106,429 191,831
------------ ------------ ----------- -----------
Total oil and gas sales.......................... $100,438 $106,011 $180,968 $249,005
AVERAGE SALES PRICES (a):
Oil (per Bbl).................................... $25.10 $26.55 $23.04 $27.90
Gas (per Mcf) ................................... 3.33 4.37 3.06 5.48
Oil and gas (per Mcfe)........................... 3.63 4.38 3.34 5.27
EXPENSES (PER MCFE):
Normal lease operating expenses (b).............. $0.57 $0.51 $0.56 $0.49
Salaries, general and administrative expenses.... 0.11 0.13 0.12 0.13
DD&A expense on oil and gas properties........... 1.50 1.71 1.51 1.64
(a) Includes the cash effects of hedging
(b) Excludes major maintenance expenses
NET INCOME. For the second quarter of 2002, we reported net income totaling
$16.0 million, or $0.60 per share, compared to net income reported for the
second quarter of 2001 of $29.1 million, or $1.10 per share. Net income for the
first six months of 2002 and 2001 totaled $22.2 million, or $0.84 per share, and
$68.3 million, or $2.58 per share, respectively.
OIL AND GAS REVENUES. During the second quarter of 2002, oil and gas
revenues totaled $100.4 million, compared to $106.0 million for the second
quarter of 2001. Year-to-date 2002 oil and gas revenues totaled $181.0 million
compared to $249.0 million during the comparable 2001 period. The decline in
2002 revenues was primarily due to lower average realized oil and natural gas
prices, offset in part by increased oil production volumes.
PRICES. Prices realized during the second quarter of 2002 averaged $25.10
per Bbl of oil and $3.33 per Mcf of natural gas. This represents a 17% decrease,
on an Mcfe basis, over second quarter 2001 average realized prices of $26.55 per
Bbl of oil and $4.37 per Mcf of natural gas. Average realized prices during the
first half of 2002 were $23.04 per Bbl of oil and $3.06 per Mcf of natural gas
compared to $27.90 per Bbl of oil and $5.48 per Mcf of natural gas realized
during the first half of 2001. All unit pricing amounts include the cash effects
of hedging.
During the second quarter of 2002, hedging transactions reduced the average
price we received for natural gas by $0.03 per Mcf compared to a net decrease of
$0.25 per Mcf for the second quarter of 2001. Hedging transactions for natural
gas during the first half of 2002 increased the average price we received for
gas by $0.16 per Mcf compared to a net decrease of $0.39 per Mcf for the
comparable 2001 period. Hedging transactions during the first half of 2002
increased the average price realized for oil by $0.24 per Bbl.
PRODUCTION. Natural gas production during the second quarters of 2002 and
2001 remained constant at approximately 18.0 Bcf, while oil production during
the second quarter of 2002 increased 56% to approximately 1.6 million barrels
compared to 1.0 million barrels produced during the second quarter of 2001. On a
gas equivalent basis, production volumes for the second quarter of 2002
increased 14% to 27.7 Bcfe compared to second quarter 2001 production of 24.2
Bcfe. Year-to-date 2002 production totaled 3.2 million barrels of oil and 34.8
Bcf of gas while six-month 2001 production totaled 2.0 million barrels of oil
and 35.0 Bcf of gas. The increase in production was primarily due to the
December 2001 acquisition of eight producing properties.
EXPENSES. Normal lease operating expenses during the second quarter of 2002
totaled $15.8 million, or $0.57 per Mcfe, compared to $12.3 million, or $0.51
per Mcfe, for the comparable quarter in 2001. For the first six months of 2002,
normal lease operating expenses totaled $30.4 million, or $0.56 per Mcfe,
compared to $22.9 million, or $0.49 per Mcfe, during the comparable period of
2001. The December 2001 acquisition of eight producing properties increased the
number of producing wells and the volume of oil production from 2001 levels. The
combination of these factors contributed to the increase in normal lease
operating expenses during 2002.
Major maintenance expenses, which represent major repair and workover
operations, totaled $4.7 million during the second quarter of 2002 compared to
$1.3 million in the second quarter of 2001. A majority of the increase in these
expenses is attributable to workover operations on wells in the Vermilion 46,
Vermilion 131 and Eugene Island 243 fields.
Depreciation, depletion and amortization (DD&A) expense on oil and gas
properties for the second quarter of 2002 totaled $41.5 million, or $1.50 per
Mcfe, compared to $41.5 million, or $1.71 per Mcfe, for the second quarter of
2001. Year-to-date 2002 DD&A expense on oil and gas properties totaled $81.7
million, or $1.51 per Mcfe, compared to $77.7 million, or $1.64 per Mcfe, for
the comparable period in 2001. The lower per unit DD&A expense for 2002 resulted
from higher production rates and the impact of the lower costs associated with
reserve acquisitions in the fourth quarter of 2001.
We financed fourth quarter 2001 acquisitions with $200.0 million principal
amount of 8 1/4% Senior Subordinated Notes due 2011 and borrowings under the
bank credit facility. As a result, interest expense, net of amounts capitalized,
for the second quarter of 2002 was $6.0 million, compared to $0.7 million during
the second quarter of 2001. For the six months ended June 30, 2002, interest
expense, net of amounts capitalized, totaled $11.5 million compared to $1.8
million during the comparable period in 2001.
Salaries, general and administrative expenses for the second quarter of
2002 totaled $3.2 million, or $0.11 per Mcfe, compared to $3.2 million, or $0.13
per Mcfe, during the second quarter of 2001. For the six months ended June 30,
2002, salaries, general and administrative expenses totaled $6.6 million, or
$0.12 per Mcfe, compared to $5.9 million, or $0.13 per Mcfe, during the
comparable period of 2001. The higher salaries and general and administrative
expenses were primarily due to the increase in the number of employees required
to manage a larger property base as a result of merger and acquisition activity
during 2001.
NEW ACCOUNTING STANDARDS
In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other
Intangible Assets." SFAS No. 141 prohibits the use of the pooling-of-interest
method of accounting for all business combinations initiated after June 30,
2001. SFAS No. 142 requires that goodwill not be amortized in any circumstances
and also requires goodwill to be tested annually for impairment or when events
or circumstances occur between annual tests indicating that goodwill for a
reporting unit might be impaired. SFAS No. 142 establishes a new method of
testing goodwill for impairment based on a fair value concept and is effective
for fiscal years beginning after December 15, 2001. The adoption of SFAS Nos.
141 and 142 is not expected to have a material impact on our financial
statements because we do not have any goodwill recorded.
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
amortization. An assessment of the impact of SFAS 143 on our financial condition
and results of operations has yet to be completed. We expect that the adoption
of SFAS 143 will result in increases in the capitalized costs of our oil and gas
properties and in the recognition of additional liabilities related to asset
retirement obligations.
In April 2002, the FASB issued SFAS No. 145, "Recision of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." This statement is effective for fiscal years beginning after
December 15, 2002. SFAS No. 145 will affect income statement classification of
gains and losses from extinguishment of debt and require certain other technical
corrections. Based on current operations, we do not anticipate that SFAS No. 145
will have a material effect on our financial position, results of operations or
liquidity.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities," which supersedes Emerging Issues
Task Force Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)." SFAS No. 146 requires the recognition of
liabilities for costs associated with an exit or disposal activity when those
liabilities are incurred rather than at the date of an entity's commitment to an
exit or disposal activity. This statement is effective for exit and disposal
activities that are initiated after December 31, 2002. Based on current
operations, we do not anticipate that SFAS No. 146 will have a material effect
on our financial position, results of operations or liquidity.
HEDGING ACTIVITIES
We adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," effective January 1, 2001. Under SFAS No. 133, as amended, the
nature of a derivative instrument must be evaluated to determine if it qualifies
for hedge accounting treatment. If the instrument qualifies for hedge accounting
treatment, it is recorded as either an asset or liability measured at fair value
and subsequent changes in the derivative's fair value are recognized in equity
through other comprehensive income, to the extent the hedge is considered
effective. Instruments not qualifying for hedge accounting treatment are
recorded in the balance sheet at fair value and changes in fair value are
recognized in earnings.
Our natural gas swap contract is with a subsidiary of Enron Corp. Due to
Enron's financial difficulties, there is no assurance that we will receive full
or partial payment of any amounts that may become owed to us under this
contract. Accordingly, this swap no longer qualifies as an effective hedge under
SFAS No. 133. As a result, the change in fair value for each period is recorded
through earnings and amounts previously recorded in other comprehensive income
are amortized through earnings over the remaining life of the swap. At June 30,
2002, other comprehensive income included $3.4 million related to the
ineffective natural gas swap that remains to be amortized.
During the second quarters of 2002 and 2001, we recognized $3.5 million and
$0.9 million, respectively, of non-cash derivative expense, the majority of
which represents amortized cost associated with put contracts that settled
during the respective periods. At June 30, 2002, the unsettled put contracts
were recorded as assets totaling $6.4 million and the unsettled gas swap was
recorded as a liability totaling $7.8 million. All changes in fair values of the
puts were recorded in equity through other comprehensive income.
On April 3, 2002, we entered into additional oil put contracts with three
separate counter-parties totaling 12,000 barrels of oil per day at a price of
$25.00 per Bbl. These contracts began May 1, 2002 and extend through December
31, 2002. The cost of these contracts totaling $4.8 million is charged to
earnings as the contracts settle. These contracts qualify as effective hedges
under SFAS No. 133.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW. Net cash flow from operations excluding working capital changes
for the second quarter and first six months of 2002 was $68.9 million, or $2.59
per share, and $122.9 million, or $4.64 per share, respectively, compared to
$88.3 million, or $3.34 per share, and $185.0 million, or $6.99 per share,
reported for the respective periods of 2001.
CAPITAL EXPENDITURES. Capital expenditures during the second quarter of
2002 totaled $51.5 million and included $2.6 million of capitalized salaries,
general and administrative expenses and incentive compensation expenses and $2.1
million of capitalized interest. Capital expenditures for the first half of 2002
totaled $106.9 million including $5.1 million of capitalized salaries, general
and administrative expenses and incentive compensation expenses and $4.2 million
of capitalized interest. These investments were financed by cash flow from
operations, working capital and borrowings under the bank credit facility.
BUDGETED CAPITAL EXPENDITURES. Our current estimated 2002 capital
expenditures budget of approximately $210.0 million is allocated 90% to Gulf
Coast Basin operations and 10% to Rocky Mountain activities. On July 29, 2002,
we entered into a $28.0 million work commitment for at least five wells over a
two-year period on the Pinedale Anticline in Wyoming. After the initial $28.0
million investment and the drilling of five wells, we will have earned a 50%
working interest in the project area. We expect to spud the first commitment
well(s) during the third quarter of 2002, with the remaining wells to be drilled
within the terms of the agreement. The Pinedale Anticline is a developing gas
field in the Green River Basin in Wyoming.
Based upon our outlook on oil and gas prices and production rates, we
expect cash flow from operations to be sufficient to fund the remaining 2002
capital expenditures budget. 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.
PRODUCTION MARKETING RISK. The publicly disclosed deteriorating financial
conditions and recently reduced credit ratings of certain purchasers of
production increase the possibility that we may not receive payment for a
portion of our future production. We have attempted to diversify our sales and
obtain credit protections such as letters of credit, guarantees and prepayments
from certain of our purchasers. We are unable to predict, however, what impact
the financial difficulties of certain purchasers may have on our future results
of operations and liquidity.
BANK CREDIT FACILITY. During August 2002, we repaid $9.0 million of
borrowings outstanding under our bank credit facility. As of August 12, 2002, we
had a borrowing base under the credit facility of $300.0 million with
availability of $156.7 million in borrowings. The credit facility matures on
December 20, 2004. The borrowing base under the credit facility, which is
re-determined periodically, is based on an amount established by the bank group
resulting from an evaluation of the value of our proved oil and gas reserves.
ENVIRONMENTAL
Compliance with applicable Federal, state and local environmental and
safety regulations has not required any significant capital expenditures or
materially affected our business or earnings. We believe we are in substantial
compliance with environmental and safety regulations and foresee no material
expenditures in the future; however, we are unable to predict the impact that
compliance with future regulations may have on our capital expenditures,
earnings and competitive position.
DEFINED TERMS
Oil and condensate are stated in barrels ("Bbl") or thousand barrels
("MBbl"). Natural gas is stated herein in billion cubic feet ("Bcf"), million
cubic feet ("MMcf") or thousand cubic feet ("Mcf"). Oil and condensate are
converted to gas at a ratio of one barrel of liquids per six Mcf of gas. Bcfe,
MMcfe, and Mcfe represent one billion cubic feet, one million cubic feet and one
thousand cubic feet of gas equivalent, respectively. BBtu represents one billion
British Thermal Units. An active property is an oil and gas property with
existing production. A primary term lease is an oil and gas property with no
existing production, in which we have a specific time frame to establish
production without losing the rights to explore the property.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY PRICE RISK
Our major market risk exposure continues to be the pricing applicable to
our oil and gas production. Our revenues, profitability and future rate of
growth depend substantially upon the market prices of oil and natural gas, which
fluctuate widely. Oil and natural gas price declines and volatility could
adversely affect our revenues, cash flows and profitability. Price volatility is
expected to continue. In order to manage our exposure to oil and natural gas
price declines, we occasionally enter into oil and natural gas price hedging
arrangements to secure a price for a portion of our expected future production.
We do not enter into hedging transactions for trading purposes.
Our hedging policy provides that not more than one-half of our estimated
production quantities can be hedged without the consent of the Board of
Directors. In April 2002, we entered into additional oil put contracts, which
were approved by our Board of Directors, to secure what we believe to be an
attractive floor price for a portion of our oil production for the remainder of
2002. See Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations - Hedging Activities for a detailed discussion of
hedges in place to manage our exposure to oil and natural gas price declines.
INTEREST RATE RISK
At June 30, 2002, we had long-term debt outstanding of $445.0 million. Of
this amount, $300.0 million, or 67%, bears interest at fixed rates averaging
8.4%. The remaining $145.0 million of debt outstanding at June 30, 2002 bears
interest at a floating rate. At June 30, 2002, the weighted average interest
rate under our floating-rate debt was 3.3%. Because the majority of our
long-term debt at June 30, 2002 was at fixed rates, we consider our interest
rate exposure at such date to be minimal. At June 30, 2002, we had no open
interest rate hedge positions to reduce our exposure to changes in interest
rates.
Since the filing of our Annual Report on Form 10-K, there have been no
material changes in reported market risk as it relates to interest rates and
commodity prices.
PART II - OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the annual meeting of stockholders held on May 16, 2002, three Class III
Directors, Robert A. Bernhard, Joe R. Klutts and James H. Stone, were elected to
serve as Directors until the 2005 annual meeting of stockholders. Robert A.
Bernhard received the vote of 16,191,430 shares with the vote of 7,206,070
shares withheld; Joe R. Klutts received the vote of 22,781,592 shares with the
vote of 615,908 shares withheld; and James H. Stone received the vote of
22,909,705 shares with the vote of 487,795 shares withheld. No other Director
was standing for election. Peter K. Barker, D. Peter Canty, Raymond B. Gary and
David R. Voelker are Class I Directors whose terms expire at the 2003 annual
meeting of stockholders. B.J. Duplantis, John P. Laborde and Richard A.
Pattarozzi are Class II Directors whose terms expire at the 2004 annual meeting
of stockholders.
The Board of Directors withdrew the proposal for the stockholders to ratify
the appointment of Arthur Andersen LLP as our independent auditors for the year
2002.
ITEM 5. OTHER INFORMATION
On June 26, 2002, the Board of Directors, upon recommendation of the Audit
Committee, resolved to discharge Arthur Andersen LLP to act as Stone's
independent public accountant. Also, the Board of Directors approved the
appointment of Ernst & Young LLP to serve as Stone's independent public
accountant for the fiscal year ending December 31, 2002.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
*15.1- Letter from Ernst & Young LLP dated August 14, 2002
regarding unaudited interim financial information.
99.1 - Letter of Arthur Andersen LLP, dated June 26, 2002,
regarding change in certifying accountant (incorporated
by reference to Exhibit 16.1 to the Registrant's
Current Report on Form 8-K dated June 26, 2002 (File
No. 001-12074)).
* Filed herewith
(b) We filed the following reports on Form 8-K during the three
months ended June 30, 2002:
Date of Event Reported Item Reported
---------------------- -------------
June 26, 2002 Item 4 and 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: August 14, 2002 By: /s/James H. Prince
----------------------------
James H. Prince
Senior Vice President, Chief Financial
Officer and Treasurer
(On behalf of Registrant and as
Principal Financial Officer)