1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 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, 1999
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: 1-10671
THE MERIDIAN RESOURCE CORPORATION
(Exact name of registrant as specified in its charter)
TEXAS 76-0319553
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1401 ENCLAVE PARKWAY, SUITE 300, HOUSTON, TEXAS 77077
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 281-597-7000
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 and 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
--- ---
Number of shares of common stock outstanding at November 4, 1999 46,184,893
Page 1 of 28
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THE MERIDIAN RESOURCE CORPORATION
QUARTERLY REPORT ON FORM 10-Q
INDEX
Page
Number
------
PART I -- FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statements of Operations (unaudited) for the
Three Months and Nine Months Ended September 30, 1999
and 1998 3
Consolidated Balance Sheets as of September 30, 1999 (unaudited)
and December 31, 1998 4
Consolidated Statements of Cash Flows (unaudited) for the
Nine Months Ended September 30, 1999 and 1998 6
Notes to Consolidated Financial Statements (unaudited) 7
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 12
Item 3. Quantitative and Qualitative Disclosures about Market Risk 25
PART II -- OTHER INFORMATION
Item 1. Legal Proceedings 26
Item 6. Exhibits and Reports on Form 8-K 27
SIGNATURE 28
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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands of dollars, except per share)
(unaudited)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
1999 1998 1999 1998
--------- --------- --------- ---------
REVENUES:
Oil and natural gas $ 38,678 $ 23,076 $ 92,587 $ 46,349
Interest and other 269 162 635 527
--------- --------- --------- ---------
38,947 23,238 93,222 46,876
--------- --------- --------- ---------
COSTS AND EXPENSES:
Oil and natural gas operating 3,880 5,540 12,096 8,866
Severance and ad valorem taxes 3,267 1,371 8,248 2,206
Depletion and depreciation 13,665 15,285 39,080 27,824
General and administrative 4,129 2,511 10,033 6,626
Interest 6,121 3,702 16,729 8,725
Impairment of long-lived assets -- -- -- 196,126
Litigation expenses and loss provision (454) -- (454) --
--------- --------- --------- ---------
30,608 28,409 85,732 250,373
--------- --------- --------- ---------
EARNINGS (LOSS) BEFORE
INCOME TAXES 8,339 (5,171) 7,490 (203,497)
TAXES ON INCOME 600 -- 600 (22,000)
--------- --------- --------- ---------
NET EARNINGS (LOSS) 7,739 (5,171) 6,890 (181,497)
--------- --------- --------- ---------
DIVIDEND REQUIREMENT ON
PREFERRED STOCK 1,350 1,350 4,050 1,350
--------- --------- --------- ---------
NET EARNINGS (LOSS) APPLICABLE
TO COMMON STOCKHOLDERS $ 6,389 ($ 6,521) $ 2,840 ($182,847)
========= ========= ========= =========
NET EARNINGS (LOSS) PER SHARE:
Basic $ 0.14 ($ 0.14) $ 0.06 ($ 4.85)
========= ========= ========= =========
Diluted $ 0.13 ($ 0.14) $ 0.06 ($ 4.85)
========= ========= ========= =========
See notes to consolidated financial statements.
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THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
SEPTEMBER 30, DECEMBER 31,
1999 1998
------------- ------------
(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 6,928 $ 9,478
Accounts receivable 33,553 32,558
Due from (to) affiliates (224) 4,848
Prepaid expenses and other 3,121 1,394
--------- ---------
Total current assets 43,378 48,278
--------- ---------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method
(including $73,379,000 [1999] and
$100,015,000 [1998] not subject to depletion) 887,691 820,322
Land 478 478
Equipment 8,554 6,775
--------- ---------
896,723 827,575
Accumulated depletion and depreciation (475,158) (436,120)
--------- ---------
421,565 391,455
--------- ---------
OTHER ASSETS 5,041 5,442
--------- ---------
$ 469,984 $ 445,175
========= =========
See notes to consolidated financial statements.
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THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
SEPTEMBER 30, DECEMBER 31,
1999 1998
------------- ------------
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 24,334 $ 19,138
Revenues and royalties payable 3,412 6,500
Accrued liabilities 17,994 24,440
Notes payable 320 --
Current maturities of long-term debt -- 84
--------- ---------
Total current liabilities 46,060 50,162
--------- ---------
LONG-TERM DEBT 250,000 240,000
--------- ---------
9 1/2% CONVERTIBLE SUBORDINATED NOTES 20,000 --
--------- ---------
LITIGATION LIABILITIES -- 6,205
--------- ---------
STOCKHOLDERS' EQUITY:
Preferred stock, $1.00 par value (25,000,000 shares
authorized, 3,982,906 [1999 and
1998] shares of Series A Cumulative
Convertible Preferred Stock issued at stated value) 135,000 135,000
Common stock, $0.01 par value (200,000,000 shares
authorized, 46,184,893 [1999] and
45,817,319 [1998] issued) 468 461
Additional paid-in capital 272,802 270,477
Accumulated deficit (253,974) (256,814)
Unamortized deferred compensation (372) (293)
--------- ---------
153,924 148,831
Treasury stock, at cost (0 [1999] and
1,275 [1998] shares) -- (23)
--------- ---------
Total stockholders' equity 153,924 148,808
--------- ---------
$ 469,984 $ 445,175
========= =========
See notes to consolidated financial statements.
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THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
(unaudited)
NINE MONTHS ENDED,
SEPTEMBER 30,
1999 1998
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss) $ 6,890 ($181,497)
Adjustments to reconcile net earnings (loss) to net cash
provided by operating activities:
Depletion and depreciation 39,080 27,824
Amortization of other assets 816 138
Non-cash compensation 1,217 1,407
Impairment of long-lived assets -- 196,126
Deferred income taxes -- (22,000)
Changes in assets and liabilities excluding effects of
acquisition of oil and gas properties:
Accounts receivable (995) (14,186)
Due from affiliates 5,072 (466)
Prepaid expenses and other (1,727) 259
Accounts payable 5,196 25,163
Revenues and royalties payable (3,088) (2,528)
Notes payable 320 --
Accrued liabilities and other (13,804) 2,269
--------- ---------
Net cash provided by operating activities 38,977 32,509
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (73,035) (92,106)
Acquisition of oil and natural gas properties (5,860) (37,078)
Proceeds from sale of oil and natural gas properties 9,747 2,100
--------- ---------
Net cash used in investing activities (69,148) (127,084)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt 40,000 91,895
Reductions in long-term debt (10,084) (116)
Proceeds from issuance of common stock 2,355 1,293
Preferred stock dividends accrued (4,050) (1,350)
Deferred loan costs (600) (1,516)
--------- ---------
Net cash provided by financing activities 27,621 90,206
--------- ---------
NET CHANGE IN CASH AND CASH EQUIVALENTS (2,550) (4,369)
Cash and cash equivalents at beginning of period 9,478 8,083
--------- ---------
CASH AND CASH EQUIVALENTS
AT END OF PERIOD $ 6,928 $ 3,714
========= =========
See notes to consolidated financial statements.
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THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. BASIS OF PRESENTATION
The consolidated financial statements reflect the accounts of The Meridian
Resource Corporation and its subsidiaries (the "Company") after elimination of
all significant intercompany transactions and balances. The financial statements
should be read in conjunction with the consolidated financial statements and
notes thereto included in the Company's Annual Report on Form 10-K for the year
ended December 31, 1998, as filed with the Securities and Exchange Commission.
The financial statements included herein as of September 30, 1999, and for the
three and nine month periods ended September 30, 1999 and 1998, are unaudited,
and, in the opinion of management, the information furnished reflects all
material adjustments, consisting of normal recurring adjustments, necessary for
a fair statement of the results for the interim periods presented. Certain minor
reclassifications of prior period statements have been made to conform to
current reporting practices.
2. IMPAIRMENT OF LONG-LIVED ASSETS
No impairment of long-lived assets was recognized during the first nine months
of 1999 due to improved commodity prices and significant reserve additions made
during the period. During the first nine months of 1998, the Company recognized
$196.1 million in non-cash write-downs of its oil and natural gas properties
under the full cost method of accounting, primarily as a result of declines in
both oil and natural gas prices which significantly lowered the present value of
proved oil and natural gas reserves as of September 30, 1998.
3. LONG-TERM DEBT
In May 1998, the Company amended and restated its credit facility with The Chase
Manhattan Bank as Administrative Agent (the "Credit Facility") to provide for
maximum borrowings, subject to borrowing base limitations, of up to $250
million. In November 1998, the Company amended the Credit Facility to increase
the then-existing borrowing base from $200 million to $250 million. The
borrowing base, currently set at $250 million, is scheduled to be redetermined
on March 31, 2000. In addition to the regularly scheduled semi-annual borrowing
base redeterminations, the lenders under the Credit Facility have the right to
redetermine the borrowing base at any time once during each calendar year and
the Company has the right to obtain a redetermination by the banks of the
borrowing base once during each calendar year. Borrowings under the Credit
Facility are secured by pledges of the outstanding capital stock of the
Company's material subsidiaries and a mortgage of all of the Company's offshore
oil and natural gas properties and several onshore oil and natural gas
properties. The Credit Facility contains various restrictive covenants,
including, among other things, maintenance of certain financial ratios and
restrictions on cash dividends on the Common Stock.
Borrowings under the Credit Facility mature on May 22, 2003.
Under the Credit Facility, as amended, the Company may secure either (i) an
alternative base rate loan that bears interest at a rate per annum equal to the
greater of the administrative agent's prime rate, a certificate of deposit based
rate or a federal funds based rate plus 0.25% to 1.0%; or (ii) a Eurodollar base
rate loan that bears interest, generally, at a rate per annum equal to the
London interbank offered rate plus 1.25% to 2.5%,
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depending on the Company's ratio of the aggregate outstanding loans and letters
of credit to the borrowing base. The Credit Facility also provides for
commitment fees ranging from .3% to .5% per annum. At September 30, 1999, the
Company had outstanding borrowings of $250 million under the Credit Facility.
4. 9 1/2% CONVERTIBLE SUBORDINATED NOTES
During June 1999, the Company completed private placements of an aggregate of
$20 million of its 9 1/2% Convertible Subordinated Notes due June 18, 2005 (the
"Notes"). The Notes are unsecured and contain customary events of default, but
do not contain any maintenance or other restrictive covenants. Interest is
payable on a quarterly basis.
The Notes are convertible at any time by the holders of the Notes into shares of
the Company's common stock, $.01 par value ("Common Stock"), utilizing a
conversion price of $7.00 per share (the "Conversion Price"). The Conversion
Price is subject to customary anti-dilution provisions. The holders of the Notes
have been granted registration rights with respect to the shares of Common Stock
that are issued upon conversion of the Notes or issuance of the warrants
discussed below.
The Notes may be prepaid by the Company at any time without penalty or premium;
however, in the event the Company redeems or prepays the Notes on or before June
21, 2001, the Company will issue to the holders of the Notes warrants to
purchase that number of shares of Common Stock into which such Notes would have
been convertible on the date of prepayment. Such warrants will have exercise
prices equal to the Conversion Price in effect on the date of issuance and will
expire on June 21, 2001, regardless of the date such warrants are issued.
5. COMMITMENTS AND CONTINGENCIES
LITIGATION
In November 1998, Enron Capital & Trade Resources Corp. ("Enron") filed an
action in the District Court of Harris County, Texas, 11th Judicial District,
Texas against the Company and certain Shell affiliates alleging causes of action
against the Company and Shell for trespass and tortious interference with
contract and seeking declaratory and injunctive relief. Enron asserts that the
Company's drilling and operation of certain Louisiana oil and gas wells has and
will trespass upon Enron's Louisiana property interests and tortiously interfere
with a Participation Agreement dated June 12, 1996 between Enron and Shell (the
"Participation Agreement"). Enron asserts further that it is being denied its
right to participate in certain drilling projects allegedly included under the
Participation Agreement, including interests in wells drilled in the Weeks
Island Field in Louisiana.
The properties covered by the Participation Agreement are owned by the Company,
with record title in the Company's subsidiary, Louisiana Onshore Properties
Inc., which was acquired from Shell in the Shell Transactions. Subject to
certain agreed upon limitations, Enron, Shell and the Company have consented to
submit this dispute to arbitration.
The Company is vigorously defending against Enron's claims and has reserved all
of its rights for reimbursement against Shell if Enron's claims are successful.
The Company believes that it is entitled to operate the referenced Louisiana
properties and that Enron is not entitled to any of the Company's interest in
wells that have been drilled in the Weeks Island Field. However, in the event of
an adverse determination resulting in a monetary judgement or property losses as
a result of Enron's claims with respect to the Weeks Island Field, the Company
believes that it is entitled to indemnification or reimbursement from Shell
under
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the agreements governing the Shell Transactions and have other rights and
actions under common law and state and federal securities laws, and in this
regard, the Company has filed suit against Shell to preserve these claims. The
Company has agreed to release Shell and its affiliates from any claims against
Shell that it may have with respect to the Weeks Island Field in exchange for
Shell's complete and unequivocal indemnity to the Company for any award,
judgement, declaration of title or settlement by Enron resulting from Enron's
claims relating to all wells and reserves located in the Weeks Island Field. As
a result of Shell's indemnity agreement, the Company currently does not believe
the dispute with Enron will have a material adverse effect on its financial
condition or results of operations.
Recently, the Company, Shell and Enron have entered into a Letter of Intent
whereby the parties have tentatively agreed to resolve all claims and disputes,
pending the execution of a Formal Settlement Agreement.
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6. EARNINGS PER SHARE
(in thousands, except per share)
The following tables set forth the computation of basic and diluted net earnings
(loss) per share:
THREE MONTHS ENDED SEPTEMBER 30,
--------------------------------
1999 1998
-------- --------
Numerator:
Net earnings (loss) $ 7,739 $ (5,171)
Less: Preferred dividend requirement 1,350 1,350
-------- --------
Net earnings (loss) used in per share calculation $ 6,389 $ (6,521)
Denominator:
Denominator for basic net earnings (loss) per
share - weighted-average shares outstanding 46,044 45,818
Effect of potentially dilutive common shares:
Convertible preferred stock 12,837 --
Employee and director stock options 830 N/A
Warrants 1,530 N/A
-------- --------
Denominator for diluted net earnings (loss) per
share - weighted average shares outstanding
and assumed conversions 61,241 45,818
======== ========
Basic net earnings (loss) per share $ 0.14 $ (0.14)
======== ========
Diluted net earnings (loss) per share $ 0.13 $ (0.14)
======== ========
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
1999 1998
--------- ---------
Numerator:
Net earnings (loss) $ 6,890 $(181,497)
Less: Preferred dividend requirement 4,050 1,350
--------- ---------
Net earnings (loss) used in per share calculation $ 2,840 $(182,847)
Denominator:
Denominator for basic net earnings (loss) per
share - weighted-average shares outstanding 45,909 37,736
Effect of potentially dilutive common shares:
Employee and director stock options 658 N/A
Warrants 1,397 N/A
--------- ---------
Denominator for diluted net earnings (loss) per
share - weighted average shares outstanding
and assumed conversions 47,964 37,736
========= =========
Basic net earnings (loss) per share $ 0.06 $ (4.85)
========= =========
Diluted net earnings (loss) per share $ 0.06 $ (4.85)
========= =========
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On June 30, 1998, the Company acquired (the "LOPI Transaction") Louisiana
Onshore Properties, Inc., an indirect subsidiary of Shell Oil Company ("Shell")
pursuant to a merger of a wholly-owned subsidiary with LOPI. In conjunction with
the other consideration paid to Shell, the Company issued a new convertible
preferred stock that is convertible into 12,837,428 shares of Common Stock. In
the event Shell elects to sell any shares of Common Stock issued upon conversion
of the Preferred Stock (the "Make-Whole Shares"), as more fully described in the
Agreement and Plan of Merger dated March 27, 1998, and included in the Company's
proxy statement dated June 10, 1998, the Company has agreed to pay Shell the
amount, if any, that the consideration received by Shell is less than $10.52 per
share. Such payment may be made in cash or Common Stock, or a combination
thereof, at the Company's election. It is the Company's policy to settle this
type of transaction with a cash payment. Based upon current oil and natural gas
prices and assuming such oil and natural gas prices continue, the Company
believes sufficient cash resources from operating activities will be generated
during the year 2000 to pay any make-whole obligations owed to Shell in cash
rather than issue Common Stock, and believes it would make any such payments in
cash assuming it is able to obtain the requisite waivers under the Credit
Facility. Therefore, the Make-Whole Shares have been removed from the earnings
per share calculations included in the financial statements.
7. RELATED PARTY TRANSACTIONS
Texas Oil Distribution and Development, Inc. ("TODD") and Sydson Energy, Inc.
("Sydson"), entities controlled by Joseph A. Reeves, Jr. and Michael J. Mayell,
respectively, have each invested 1.5% in all wells in which the Company has
participated. Effective July 15, 1999, the Company, with the approval of the
Board of Directors, acquired the Kings Bayou interests held by TODD, Sydson and
Messrs. Reeves and Mayell. Proceeds of $1.9 million to each of TODD and Sydson
and $1.3 million to each of Messrs. Reeves and Mayell due from the acquisition
were applied directly to current and/or future costs and expenses related to
TODD and Sydson's working interest rather than paid in cash.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following is a discussion of the Company's financial operations for the
three and nine months ended September 30, 1999 and 1998. The notes to the
Company's consolidated financial statements included in this report, as well as
the Company's Annual Report on Form 10-K for the year ended December 31, 1998
(and the notes attached thereto), should be read in conjunction with this
discussion.
GENERAL
DRILLING ACTIVITIES. Since the purchase of substantially all of Shell Oil
Company's properties in south Louisiana on June 30, 1998, the Company has
drilled and successfully completed 24 of 36 wells (67%), with five additional
wells in various stages of drilling or completion. This drilling activity
resulted in a unit development cost less than $0.53 per thousand cubic feet of
(Mcfe) gas equivalent (based on drilling and completion costs and the Company's
internal reserve estimates). The Company began the period of June 30, 1998,
through September 30, 1999, with approximately 281 billion cubic feet of natural
gas equivalent (Bcfe) reserves, produced approximately 61.8 Bcfe, added gross
reserves, net of sales and revisions, of approximately 135 Bcfe (48%), and ended
the September 30, 1999, period with approximately 354 Bcfe (61% natural gas) for
a net increase of 73 Bcfe (26%), resulting in a replacement of reserves of
approximately 218% for the period.
The Company's drilling activities have been focused in the Weeks Island Field,
North Turtle Bayou/Ramos Field, Thornwell Field, Riceville/West Gueydan Field,
South Deep Lake and Barataria Bay. In addition to current drilling activities at
North Turtle Bayou/Ramos, Weeks Island and Thornwell, the Company plans to
conduct drilling operations during the fourth quarter 1999 in the Kings Bayou
Field, South Timbalier Block 139, and the Turtle Bayou area, with capital
spending approximating $16 million during this period.
NORTH TURTLE BAYOU/RAMOS FIELD, ASSUMPTION PARISH, LOUISIANA
Thibodaux No. 3 Well: The Company has successfully drilled, logged and
placed on production as of November 9, 1999, the C. M. Thibodaux No. 3
well, a development well offsetting the discovery well, the C. M.
Thibodaux No. 1 well, in the North Turtle Bayou/Ramos Field which was
returned to production on August 26, 1999, and is currently 16.5
million cubic feet of gas equivalent per day (MMcfe/d). The No. 3 well
was drilled as a replacement well for the C. M. Thibodaux No. 2 well
which encountered well control problems during late June 1999 and was
subsequently plugged and abandoned.
The No. 3 well was drilled to a depth of 18,402 feet, encountering over
180 feet of pay in two separate Operc-aged sands below 17,500 feet. The
initial completion has been made in the Operc "B" sand, which logged
approximately 129 gross and net feet of pay from 17,685 feet to 17,814
feet.
The Company tested the No. 3 well at a stabilized rate of 14.3 million
cubic feet of gas per day (MMcf/d) plus 298 barrels of condensate per
day (BCPD) and no water, at a flowing tubing pressure of 11,466 pounds
per square inch (psi) on a 17/64-inch choke. Bottom hole shut-in
pressure was calculated at approximately 12,440 psi. Based on current
measurement and depending on reservoir characteristics, the Company
expects to produce the well at an initial rate of approximately 12
MMcf/d plus associated condensate expected to approximate an additional
250 BCPD. These rates will add to production from the C. M. Thibodaux
No. 1 well bringing gross field production to approximately 30 MMcfe/d
(14 MMcfe/d net).
A 12-inch flow line has been installed by the Company in the area for
this and future wells production, which should allow for production
capacity at the facility of up to 100 MMcf/d of gas and 10,000 BCPD.
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The Company is the operator of the prospect and participated in the
Thibodaux No. 1 well and the Thibodaux No. 3 well for approximately 71%
of the Working Interest.
Norman Breaux No. 1 Well: The Norman Breaux No. 1 well is an east
offset to the Thibodaux Unit in a separate fault block and unit. An
electric log was run to a depth of 18,497, indicating apparent oil and
natural gas productive sands in the Operc "A" and "B" zones which were
encountered between 17,500 feet and 17,750 feet. A 5 1/2 inch liner was
set to 18,497 feet to protect these sands, with plans to drill to a
target depth of 19,500 feet to test the prospective Cris. "A" sand.
Drilling has resumed with the well currently drilling below 19,000
feet. The Company's Working Interest in the Breaux No. 1 well is
approximately 91%.
It is anticipated that additional wells will be drilled targeting
additional Operc sands in this project area in the near future.
WEEKS ISLAND FIELD, IBERIA PARISH, LOUISIANA
Weeks Island State Unit A-24 Well: The Company continues to develop
this very prolific salt dome where the Company made a discovery that
has developed into a significant part of the Company's new reserves
immediately after acquiring the field from Shell Oil in June 1998. Five
producing wells have been drilled by the Company to date, with the
WISUA-24 well being the latest to be brought on production during
August 1999. Current production for this shallow test development well
is 275 barrels of oil per day, which brings the total field production
to approximately 13,000 BOEPD, an increase from the 7,200 BOEPD when
the Company took over operations from Shell. The Company has identified
approximately 15 new projects within this field which are scheduled to
begin drilling under the year 2000 capital budget. As operator of the
majority of the field production, the Company owns a 97% Working
Interest in the "U" sand Unit and between 55% and 75% working interest
in most of the remaining prospective area.
Myles Salt No. 1 Well: The Myles Salt No. 1 Well is currently drilling
below 9,500 feet with a target depth of approximately 12,500 feet.
Stone Energy is the operator and owns a 25% Working Interest with the
Company owning a 75% Working Interest. The well has both exploratory
and developmental targets.
The State Lease 500 No. 1 Well: The State Lease 500 No. 1 well is
drilling below surface casing at approximately 3,700 feet with a
target depth of 12,000 feet.
ROCKEFELLER/SOUTH DEEP LAKE, CAMERON PARISH, LOUISIANA
Rockefeller No. 1 Well: The SL 16067 (Rockefeller) No. 1 well was
drilled to a total depth of 20,000 feet during April 1999. Because of
the extraordinary downhole pressure environment in this directional
well bore and the need to protect potentially productive sands, the
Company elected to set production casing prior to conducting an
electric log over the entire section of the open hole. Cased-hole logs
were conducted which indicated 185 feet of apparently productive sands
between 18,370 and 18,766 feet. Production testing of the middle sands
between 18,508 feet and 18,550 feet rendered up to 13.5 Mmcfe/d gas and
approximately 200-250 barrels of water per million cubic feet of gas.
To accommodate the salt- water production, a salt-water disposal well
was drilled and completed during June 1999. Subsequent production
testing was conducted which resulted in the decision to perforate the
upper sand package between 18,372 feet and 18,398 feet. The well was
thereafter placed on production at approximately 5 Mmcfe/d with some
apparent restrictions in the gas flow and is currently being monitored
to ascertain what, if any, operations should be conducted to increase
the gas rate from the upper sand. It is anticipated that these
operations will be commenced in the next 30-60 days. The Company holds
a 47% Working Interest in this field and is the operator.
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RICEVILLE/WEST GUEYDAN FIELD, VERMILION PARISH, LOUISIANA
Burnie Benoit No. 1 Well: This is the second well in this exploitation
project area which was developed by the Company after the June 1998
Shell purchase. The well was drilled to a total depth of 16,020 feet
and logged productive sands between 14,700 feet and 14,750 feet. The
well was placed on production during June 1999 after testing 5.3 MMcfd
and 396 BOPD on a 12/64ths choke at 8,145 psi. The Company holds a
25.125% Working Interest. The Company anticipates additional
development and exploratory prospects in this project area, primarily
for the deeper Myogip sands.
SOUTH THORNWELL FIELD, JEFFERSON DAVIS PARISH, LOUISIANA
Potter 33 No. 2 Well: The Potter 33 No. 2 well was drilled to a total
depth of 11,872 feet, completed and tested at rates of 18.312 million
cubic feet of gas per day (MMcf/d) plus 540 barrels of condensate per
day (BCPD) and no water. Flowing tubing pressure was 7,042 psi on a
20/64th-inch choke from perforations between 11,756 feet and 11,772
feet in the Marg Idio (Oligocene) sand. The producing horizon contains
80 feet of gross and net pay. The well was placed on production on
November 10, 1999, at the initial rates of 12.8 MMcf/d and 440 BCPD.
The Company holds a 30% Working Interest and is the operator of the
field production.
The addition of the Potter 33 No. 2 well, brings total production in
the South Thornwell Field to 36 MMcf/d and 1050 BCPD from three
wells--the Guidry 21 No.1 well (30.33% Working Interest) completed
November 6, 1998, the Lacassine 33 No. 1 well (23.15% Working
Interest), completed March 2, 1999 and the Potter 33 No. 2 well (30.33%
Working Interest). A fourth location, the Potter No. 33 No. 1 well is
currently drilling below 11,000 feet with a target depth of 12,000
feet.
SATURDAY ISLAND/MYSTERY ISLAND FIELD, JEFFERSON PARISH, LOUISIANA
The SL 15858 No. 1 Well: The first well in this new discovery field,
the SL 15858 No. 1 (30% Working Interest), was completed on January 25,
1999, and is currently producing at a rate of 2.9 MMcf/d plus 968 BOPD
for a total of 8.7 Mmcfe/d.
LL&E Fee No. 1 Well: The LL&E Fee No. 1 well (21% Working Interest) was
tested during August 1999 and produced flow rates of 9.8 MMcf/d and 69
BCPD from the lowest of three productive intervals containing
approximately 73 feet of net oil and gas pay in the interval between
10,070 feet and 11,111 feet. The well is the second test for the
Company, based on the Barataria Bay 3-D seismic shoot completed in
1998.
WEST CAMERON BLOCK 76, OFFSHORE, LOUISIANA
West Cameron Block 76, Well B-4: During the first quarter of 1999, the
Company participated in the West Cameron 76 well No. B-4, a discovery
well in the Gulf of Mexico, which encountered over 200 feet of
productive Miocene sand below 14,700 feet measured depth. The well went
into production in June 1999 at rates of 17.1 Mmcfd and 94 BCPD.
West Cameron Block 76, Well B-5: The B-5 well, a development well,
encountered more than 217 net feet of productive Marg. A. sand between
16,525 feet and 17,165 feet measured depth. The well was brought on
production during October 1999, at rates of 20.4 MMcf/d with 151 BCPD.
The Company holds a 2.625% Working Interest in the field.
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CHOCOLATE BAYOU FIELD, BRAZORIA COUNTY, TEXAS
TMRX I. P. Farms No. 3-X Well: The No. 3-X well was recompleted in the
12,700 foot Andrau sand in a new fault block at the Company's Chocolate
Bayou Field, south of Houston near Alvin, Texas. Production tests on
the I.P. Farms No. 3-X well resulted in flow rates of 3.2 MMcfd and 96
BOPD at 5,100 psi FTP on an 8/64th-inch choke. This is the Company's
second Andrau completion in the field. The prolific Andrau sand has
produced over 600 BCF of gas in other fault blocks in the field. The
Company holds a 47% Working Interest and is the operator.
The Company continues to focus its operating activities in the South
Louisiana/Southeast Texas Gulf Coast Region. The Company has developed an asset
base that enables it to explore and exploit its low risk drilling projects with
its cash flow. The Company's efforts to reduce its lifting costs have been
highly successful and along with its goal to reduce the Company's debt will
remain an integral part of management's business plan.
INDUSTRY CONDITIONS. Revenues, profitability and future rate of growth of the
Company are substantially dependent upon prevailing prices for oil and natural
gas. Oil and natural gas prices have been extremely volatile in recent years and
are affected by many factors outside of the Company's control. In this regard,
the Company's average oil and natural gas prices, which decreased substantially
throughout 1998 and into the first quarter of 1999, increased during the third
quarter of 1999. The Company's average oil price for the three months ended
September 30, 1999, was $20.21 per barrel compared to $15.87 per barrel for the
three months ended June 30, 1999, and $12.84 per barrel for the three months
ended September 30, 1998. Our average oil price for the nine months ended
September 30, 1999, was $16.00 per barrel compared to $13.02 per barrel for the
nine months ended September 30, 1998. Our average natural gas price for the
three months ended September 30, 1999, was $2.80 per MCF compared to $2.28 per
MCF for the three months ended June 30, 1999, and $1.99 for the three months
ended September 30, 1998. Our average natural gas price for the nine months
ended September 30, 1999, was $2.28 per MCF compared to $2.16 per MCF for the
nine months ended September 30, 1998. Any significant reduction in prices the
Company receives for oil and gas production from levels experienced during the
third quarter of 1999 could result in decreased cash flow received from the
Company's producing properties, and a delay in the timing of exploration
activities, which will adversely affect the Company's revenues, profitability
and the Company's ability to maintain or increase its exploration and
development program.
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RESULTS OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 1999 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 1998
OPERATING REVENUES. Third quarter 1999 oil and natural gas revenues increased
$15.6 million as compared to third quarter 1998 revenues, primarily due to
production volumes increasing 10% and average commodity prices increasing 52%,
both on a natural gas equivalent basis. The production increase is a direct
result of new wells being placed on production during the last twelve months.
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the three months ended September 30, 1999
and 1998:
1999
THREE MONTHS ENDED 1999 PERCENTAGE
SEPTEMBER 30, INCREASE INCREASE
1999 1998 (DECREASE) (DECREASE)
-------- -------- ---------- ----------
Production Volumes:
Oil (Mbbl) 1,165 771 394 51%
Natural gas (Mmcf) 5,412 6,620 (1,208) (18%)
MMCFE 12,402 11,246 1,156 10%
Average Sales Prices:
Oil (per Bbl) $ 20.21 $ 12.84 $ 7.37 57%
Natural gas (per Mcf) $ 2.80 $ 1.99 $ 0.81 41%
MMCFE $ 3.12 $ 2.05 $ 1.07 52%
Operating Revenues (000's):
Oil $ 23,542 $ 9,897 $ 13,645 138%
Natural gas 15,136 13,179 1,957 15%
-------- -------- --------
Total Operating Revenues $ 38,678 $ 23,076 $ 15,602 68%
======== ======== ========
OPERATING EXPENSES. Oil and natural gas operating expenses decreased $1.6
million to $3.9 million for the three months ended September 30, 1999, compared
to $5.5 million for the same period in 1998. This decrease was primarily due to
the Company's continued cost reduction efforts on all of its operated
properties. On an MCFE basis, operating expenses have decreased in the three
months ended September 30, 1999, to $0.31 from $0.49 for the three months ended
September 30, 1998. Operating costs on an MCFE basis have decreased to $0.31 in
the third quarter of 1999, from $0.33 in the second quarter of 1999. These
decreases are primarily the result of the program that the Company implemented
to reduce the operating costs associated with the Shell Properties.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes increased $1.9
million to $3.3 million for the third quarter of 1999, compared to $1.4 million
during the same period in 1998. This increase is largely attributable to an
increase in onshore production (which is subject to severance taxes) and higher
oil and natural gas prices.
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INTEREST AND OTHER INCOME. Interest and other income during the third quarter
of 1999 increased $0.1 million from the comparable period in 1998 reflecting
larger cash balances associated with the Company operating more properties.
DEPLETION AND DEPRECIATION. Depletion and depreciation expense decreased $1.6
million during the third quarter of 1999 to $13.7 million from $15.3 million for
the same period of 1998. This decrease was primarily a result of the decrease in
the depletion rate for the 1999 period in comparison to the rate for 1998,
partially offset by an increase in production volumes. The decrease in the
depletion rate was primarily due to the write-down of oil and gas properties in
1998. On an MCFE basis there was a decrease of $0.26 per MCFE to $1.10 per MCFE
for the quarter ended September 30, 1999, from $1.36 per MCFE during the
comparable time period in 1998.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense increased
by $1.6 million to $4.1 million for three months ended September 30, 1999,
compared to $2.5 million during the comparable period last year. This increase
was primarily a result of increases in salaries and wages due to increased
number of employees associated with the growth of the Company's asset base and
producing properties and to costs associated with the relocation of the
corporate headquarters. On a unit of production basis, general and
administrative expense has increased to $0.33 per MCFE for the three months
ended September 30, 1999, from $0.22 per MCFE during the comparable period of
1998.
INTEREST EXPENSE. Interest expense increased $2.9 million to $6.1 million during
the third quarter of 1999 compared to $3.7 million in the comparable period in
1998. The increase is a result of additional borrowings to fund exploration
activities of approximately $10 million under our credit facility and the
issuance of the Subordinated Notes during June 1999.
IMPAIRMENT OF LONG-LIVED ASSETS. Due to the improvement in commodity prices and
significant reserve additions during the first nine months of 1999, it was not
necessary to record an impairment of long-lived assets during the third quarter
of 1999.
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NINE MONTHS ENDED SEPTEMBER 30, 1999 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
1998
OPERATING REVENUES. Oil and natural gas revenues during the nine months ended
September 30, 1999, increased $46.2 million as compared to revenues during the
nine months ended September 30, 1998, primarily due to production volumes
increasing by 74% on a natural gas equivalent basis. This production increase
was a direct result of the inclusion of results from the Shell Properties for
the first nine months of 1999 compared to only three months of 1998, as well as
new wells being placed on production during the last twelve months. Oil and
natural gas prices, on a natural gas equivalent basis, increased 15% during the
first nine months of 1999 compared to the same period in 1998.
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the nine months ended September 30, 1999
and 1998:
NINE MONTHS ENDED 1999
SEPTEMBER 30, 1999 PERCENTAGE
----------------- INCREASE INCREASE
1999 1998 (DECREASE) (DECREASE)
-------- -------- ---------- ----------
Production Volumes:
Oil (Mbbl) 3,329 1,225 2,104 171%
Natural gas (Mmcf) 17,249 14,051 3,198 23%
MMCFE 37,223 21,401 15,822 74%
Average Sales Prices:
Oil (per Bbl) $ 16.00 $ 13.02 $ 2.98 23%
Natural gas (per Mcf) $ 2.28 $ 2.16 $ 0.12 6%
MMCFE $ 2.49 $ 2.17 $ 0.32 15%
Operating Revenues (000's):
Oil $ 53,256 $ 15,867 $ 37,389 236%
Natural gas 39,331 30,398 8,933 29%
Pipeline -- 84 (84) (100%)
-------- -------- --------
Total Operating Revenues $ 92,587 $ 46,349 $ 46,238 100%
======== ======== ========
OPERATING EXPENSES. Oil and natural gas operating expenses increased $3.2
million to $12.1 million for the nine months ended September 30, 1999, compared
to $8.9 million for the nine months ended September 30, 1998. This increase was
primarily due to added operating expenses related to the inclusion of costs and
expenses from the Shell Properties as well as new wells brought on production in
the last twelve months. On an MCFE basis, operating expenses were $0.32 per MCFE
for the first nine months of 1999 compared to $0.41 per MCFE for the comparable
period last year. This reduction was due to the Company's efforts to reduce
operating costs on the Shell Properties.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes increased $6.0
million to $8.2 million for the nine months ended September 30, 1999, compared
to $2.2 million for the nine months ended September 30, 1998. This increase is
largely attributable to the additional onshore production and higher oil and
natural gas prices.
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INTEREST AND OTHER INCOME. Interest and other income was $0.6 million and $0.5
million for the nine month periods ended September 30, 1999 and 1998,
respectively.
DEPLETION AND DEPRECIATION. Depletion and depreciation expense increased $11.3
million to $39.1 million during the first nine months of 1999 from $27.8 from
the same period last year. This increase was primarily a result of the 74%
increase in production on an MCFE basis over the comparable period in 1998.
Although depletion and depreciation expense increased in the aggregate, on an
MCFE basis there was a decrease of $0.20 per MCFE to $1.05 per MCFE for the nine
months ended September 30, 1999 from $1.30 per MCFE during the first nine months
of 1998. The decrease in the depletion rate was primarily due to an increase in
reserves of approximately 20% over the prior period and to the write-down of oil
and gas properties during 1998.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense increased
by $3.4 million to $10.0 million for the first nine months of 1999 compared to
$6.6 million during the first nine months of 1998. This increase was primarily a
result of increases in salaries and wages and related employee costs associated
with the expanded property base and exploration and production activities.
General and administrative expense, on a unit of production basis, has decreased
9% to $0.26 per MCFE for the nine months ended September 30, 1999 from $0.31 per
MCFE during the comparable period or 1998.
INTEREST EXPENSE. Interest expense increased $8.0 million to $16.7 million
during the first nine months of 1999 compared to $8.7 million during the
comparable period of 1998. The increase is a result of additional borrowings
under the credit facility and the issuance of the Subordinated Notes.
IMPAIRMENT OF LONG-LIVED ASSETS. The Company did not record an impairment of
long-lived assets during the first nine months of 1999 since there were
significant reserve additions during the period as well as improved commodity
prices. During the first nine months of 1998, the Company recognized $196.1
million in non-cash write-downs of its oil and natural gas properties under the
full cost method of accounting.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. During the third quarter of 1999, the Company's liquidity needs
were met from cash from operations, additional borrowings under the credit
facility and the proceeds of $20 million from the 9 1/2% Convertible
Subordinated Notes issued in June 1999. As of September 30, 1999, the Company
had a cash balance of $6.9 million and a working capital deficit of $2.7
million. The decrease in the cash balance and the increase in the working
capital deficit from levels existing at June 30, 1999, primarily reflects the
capital expenditures related to the Company's increasing exploration and
development activities.
CREDIT FACILITY. The Company entered into an amended and restated credit
facility with The Chase Manhattan Bank as Administrative Agent (the "Credit
Facility") to provide for maximum borrowings, subject to borrowing base
limitations, of up to $250 million. The borrowing base was reaffirmed on August
23, 1999, and is currently set at $250 million, with a scheduled redetermination
on March 31, 2000. In addition to regularly scheduled semi-annual borrowing base
redeterminations, the lenders under the Credit Facility have the right to
redetermine the borrowing base at any time once during each calendar year and
the Company has the right to obtain a redetermination by the banks of the
borrowing base once during each calendar year. Borrowings under the Credit
Facility are secured by pledges of the outstanding capital stock of the
Company's subsidiaries and a mortgage of the offshore oil and natural gas
properties and several onshore oil and natural gas properties. Borrowings under
the Credit Facility mature on May 22, 2003.
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The Credit Facility includes various restrictive covenants including an interest
coverage ratio of 3.0 to 1.0, a minimum net worth requirement of approximately
$82 million, and a total debt leverage ratio (based upon total indebtedness to
12-month trailing pro forma EBITDA) of 3.50 to 1.00 at September 30, 1999 and
3.25 to 1.00 at December 31, 1999 and thereafter. Assuming that the Company
continues to be successful in the development and exploration program during the
next 12 months, management believes that the Company will be able to comply with
the Credit Facility covenants primarily due to the increase in production
scheduled to begin in the near-term at two of the most recent discoveries in
addition to the positive effects of higher oil and gas prices; however, any
declines in oil and gas commodity prices or unanticipated declines or delays in
production may adversely affect the ability to comply with the Credit Facility
covenants.
Under the Credit Facility, as amended, the Company may secure either (i) an
alternative base rate loan that bears interest at a rate per annum equal to the
greater of the administrative agent's prime rate, a certificate of deposit based
rate or a federal funds based rate plus 0.25% to 1.0% or (ii) a Eurodollar base
rate loan that bears interest, generally, at a rate per annum equal to the
London interbank offered rate plus 1.25% to 2.5%, depending on the ratio of the
aggregate outstanding loans and letters of credit to the borrowing base. The
Credit Facility also provides for commitment fees ranging from .3% to .5% per
annum.
SHORT-TERM CREDIT FACILITY. The Company has entered into a short-term line of
credit for $5 million on an as offered basis. This credit line will expire on
February 5, 2000. It is renewable by mutual agreement of the parties. The full
amount is available to be drawn.
9 1/2% CONVERTIBLE SUBORDINATED NOTES. During June 1999, the Company completed
private placements of an aggregate of $20 million of its 9 1/2% Convertible
Subordinated Notes due June 18, 2005 (the "Notes"). The Notes are unsecured and
contain customary events of default, but do not contain any maintenance or other
restrictive covenants. Interest is payable on a quarterly basis.
The Notes are convertible at any time by the holders of the Notes into shares of
the Company's common stock, $.01 par value ("Common Stock"), utilizing a
conversion price of $7.00 per share (the "Conversion Price"). The Conversion
Price is subject to customary anti-dilution provisions. The holders of the Notes
have been granted registration rights with respect to the shares of Common Stock
that are issued upon conversion of the Notes or issuance of the warrants
discussed below.
The Company may prepay the Notes at any time without penalty or premium;
however, in the event the Company redeems or prepays the Notes on or before June
21, 2001, the Company will issue to the holders of the Notes warrants to
purchase that number of shares of Common Stock into which such Notes would have
been convertible on the date of prepayment. Such warrants will have exercise
prices equal to the Conversion Price in effect on the date of issuance and will
expire on June 21, 2001, regardless of the date such warrants are issued.
CAPITAL EXPENDITURES. Capital expenditures, less the reinvestment of proceeds
from the sale of properties during the nine months ended September 30, 1999,
consisted of $69.1 million for property and equipment additions related to
exploration and development of various prospects (including leases), seismic
data acquisitions, and drilling and completion costs. Management expects capital
expenditures for the remainder of 1999 to be funded from cash flows from
producing properties. The Company expects its capital budget for the remainder
of 1999 to focus on lower risk development projects, concentrating on the
Company's Weeks Island, North Turtle Bayou/Ramos, Thornwell, Kings Bayou, East
Cameron Block 332 and South Timbalier Block 139 producing fields. Management
anticipates that based on the current product price and production forecast,
internal cash flow and borrowings under the Credit Facility should fully fund
the remainder of the 1999 capital expenditure program. The level of capital
expenditures for the 2000
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exploration and development program has not been finally determined and will
depend upon a variety of factors, including prevailing prices for oil and gas
and our expectations as to future pricing and the level of cash flow from
operations and the Company's other commitments. The Company currently
anticipates funding the 2000 exploration and development program utilizing cash
flow from operations, however, it will continue to review the options to finance
a portion of the future exploration programs with additional third party
financing.
C. M. THIBODAUX NO. 2. During late June, the C. M. Thibodaux No. 2 well
experienced uncontrolled gas flows and a fire for a short period, which was
capped with a diverting well head. A replacement well, the C. M. Thibodaux No.
3, has been completed and placed on production. The Company currently believes
that it has adequate insurance coverage to minimize any economic losses and
other damages arising out of these events.
DIVIDENDS. It is Company policy to retain its existing cash for reinvestment in
its business, and therefore, does not anticipate that dividends will be paid
with respect to the Common Stock in the foreseeable future. The Preferred Stock
issued upon closing of the LOPI Transaction accrues an annual cash dividend of
4% of its stated value with the dividend ceasing to accrue incrementally on
one-third of the shares of Preferred Stock on June 30, 2001, 2002 and 2003 so
that no dividends will accrue on any shares of Preferred Stock after June 30,
2003. Dividends on the Preferred Stock aggregating $4.05 million were accrued
for the first nine months of 1999, of which $1.35 million had been paid as of
September 30, 1999.
STOCK RIGHTS AND RESTRICTIONS AGREEMENT. In light of the large ownership
position issued to SLOPI in the LOPI Transaction and in recognition of both the
Company's and SLOPI's desire that the Company function as an independent oil and
gas company, the Company entered into a Stock Rights and Restrictions Agreement
with SLOPI that define and limit SLOPI's and the Company's respective rights and
obligations. These agreements will limit SLOPI's and its affiliates' control
while protecting their interests in the context of certain extraordinary
transactions by (i) allowing SLOPI to maintain representation on our Board of
Directors, (ii) restricting SLOPI's and its affiliates' ability to effect
certain business combinations with the Company or to propose certain business
combinations with the Company, (iii) restricting the ability of SLOPI and its
affiliates to sell certain portions of their shares of Common Stock and
Preferred Stock, subject to certain exceptions designed to permit them to sell
such shares over time and to sell such shares in the event of certain business
combinations involving the Company, (iv) limiting SLOPI's and its affiliates'
discretionary voting rights to 23% of the total voting shares, except with
respect to certain extraordinary events and in situations in which the price of
the Common Stock for a period of time has been less than $5.50 per share or the
Company is in material breach of its obligations under the agreements governing
the LOPI Transaction, (v) permitting SLOPI and its affiliates to purchase
additional amounts of our securities in order to maintain a 21% beneficial
ownership interest in our Common Stock or securities convertible into our Common
Stock, (vi) extending certain statutory and corporate restrictions on business
combinations applicable to SLOPI and its affiliates and (vii) obligating the
Company, at its option, to issue a currently indeterminable number of additional
shares of Common Stock in the future or pay cash in satisfaction of a make-whole
provision contained in the Stock Rights and Restrictions Agreement in the event
SLOPI receives less than approximately $10.52 per share on the sale of any
Common Stock that is issuable upon conversion of the Preferred Stock. SLOPI
currently is restricted from selling shares of Common Stock owned by it
(including shares of common stock issued to it upon conversion of the Preferred
Stock) until July 1, 2000. Beginning on July 1, 2000, SLOPI may sell 25% of the
Common Stock owned by it and may sell an incremental 25% of the Common Stock
owned by it each year until June 30, 2003, at which time it is free to sell any
Common Stock owned by it. Although SLOPI's ability to sell all of the Common
Stock issued to it upon conversion of the Preferred Stock is limited until July
1, 2003, in the event SLOPI could sell all Common Stock issued on conversion of
the Preferred Stock at the market prices existing on September 30, 1999, the
make-whole obligation would be approximately $74 million, which the Company may
satisfy at
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our option in cash or Common Stock. Based upon current oil and natural gas
prices and assuming such oil and natural gas prices continue, the Company
believes sufficient cash resources from operating activities will be generated
during the year 2000 to pay any make-whole obligations owed to Shell in cash
rather than issue Common Stock, and believes it would make any such payments in
cash assuming it is able to obtain the requisite waivers under the Credit
Facility. This obligation could significantly dilute all holders of our Common
Stock other than Shell, or significantly reduce the Company's ability to raise
additional funds for exploration and development and the levels of its capital
expenditures.
YEAR 2000
The Company is currently conducting a company-wide Year 2000 readiness program
("Y2K Program"). The Y2K Program is addressing the issue of computer programs
and embedded computer chips being unable to distinguish between the year 1900
and the year 2000. Therefore, some computer hardware and software will need to
be modified prior to the year 2000 to remain functional. It is believed that the
Company's internal accounting and operating systems are substantially Year 2000
compliant.
The Company's Y2K Program is divided into three major categories: (i) internal
information and accounting ("IT") systems, (ii) non-"IT" equipment and systems
and (iii) third-party suppliers and customers. The general stages of review with
respect to each of the categories are (a) identifying and assessing items or
systems that are not Year 2000 compliant, (b) assessing costs and expenses
associated with the various alternatives for remedying items and systems that
are not Year 2000 compliant and (c) repairing or replacing items that are
determined not to be Year 2000 compliant.
The Company has completed the review of its IT equipment and systems and
currently believes that the internal information and accounting systems are Year
2000 compliant, except for certain field software that is currently not believed
to be material to its operations. The Company has tested an alternative solution
for making such field software Year 2000 compliant.
The Company has completed the review of its non-IT equipment and systems. The
Company believes such equipment and systems will not present any material Year
2000 issues. At present, the Company has not identified any non-IT equipment and
systems that are not Year 2000 compliant that cannot be remedied or replaced at
minimal cost.
The Company is in the process of assessing its third party Year 2000 issues
during the remainder of 1999. The third party review initially consists of
written inquiries to third party suppliers, subcontractors and customers
requesting information and representations from such third parties as to their
readiness for the Year 2000. The Company is in the process of circulating these
responses and, based upon such responses, will determine the necessity for
requesting additional information as appropriate. The Company believes it has
alternative suppliers and product customers to mitigate material exposure if
certain of its current suppliers and customers are determined not to be Year
2000 ready.
Management believes that it has taken reasonable steps in developing its Y2K
Program. Notwithstanding these actions, there can be no assurance that all of
the Company's Year 2000 issues or those of its key suppliers, subcontractors or
customers will be resolved or addressed satisfactorily before the Year 2000
commences. If the key suppliers, subcontractors, customers and other third
parties fail to address their Year 2000 issues, and there are no alternatives
available to the Company, then the usual channels of supply and distribution
could be disrupted, in which event it could experience a material adverse impact
on its business, results of operations or financial position. In addition,
although it is believed the internal planning efforts are adequate to address
its internal Year 2000 concerns, there can be no assurances that the Company
will
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not experience unanticipated negative consequences and material costs caused by
undetected errors or defects in the technology used in its internal systems,
which could have material adverse effect on its business, results of operations
or financial condition. The Company currently is unable to estimate the most
reasonably likely worst-case effects of the arrival of the year 2000 and
currently does not have a contingency plan in place for any such unanticipated
negative effects.
It is anticipated that the total costs related to the Year 2000 issue will not
exceed $250,000, the majority of which will be incurred by the Company in 1999.
To date, there have been no material deferments of other IT projects resulting
from the work taking place on the Company's Y2K Program.
FORWARD-LOOKING INFORMATION
From time-to-time, the Company may make certain statements that contain
"forward-looking" information as defined in the Private Securities Litigation
Reform Act of 1995 and that involves risk and uncertainty. These forward-looking
statements may include, but are not limited to exploration and seismic
acquisition plans, anticipated results from current and future exploration
prospects future capital expenditure plans, anticipated results from third party
disputes and litigation, expectations regarding compliance with its credit
facility, the anticipated results of wells based on logging data and production
tests, future sales of production, earnings, margins, production levels and
costs, market trends in the oil and natural gas industry and the exploration and
development sector thereof, environmental and other expenditures and various
business trends. Forward-looking statements may be made by management orally or
in writing including, but not limited to, the Management's Discussion and
Analysis of Financial Condition and Results of Operations section and other
sections of the Company's filings with the Securities and Exchange Commission
under the Securities Act of 1933 and the Securities Exchange Act of 1934.
Actual results and trends in the future may differ materially depending on a
variety of factors including, but not limited to the following:
Changes in the price of oil and natural gas. The price the Company receives for
its oil and natural gas production and the level of such production are subject
to wide fluctuations and depend on numerous factors that it does not control,
including seasonality, worldwide economic conditions, the condition of the
United States economy (particularly the manufacturing sector), foreign imports,
political conditions in other oil-producing and natural-gas-producing countries,
the actions of the Organization of Petroleum Exporting Countries and domestic
government regulation, legislation and policies. Material declines in the prices
received for oil and natural gas could make the actual results differ from those
reflected in the Company's forward-looking statements.
Operating Risks. The occurrence of a significant event for which the Company is
not fully insured against could have a material adverse effect on its financial
position and results of operations. Company operations are subject to all of the
risks normally incident to the exploration for and the production of oil and
natural gas, including uncontrollable flows of oil, natural gas, brine or well
fluids into the environment (including groundwater and shoreline contamination),
blowouts, cratering, mechanical difficulties, fires, explosions, unusual or
unexpected formation pressures, pollution and environmental hazards, and other
operating and productions risks such as title problems, weather conditions,
compliance with government permitting requirements, shortages of or delays in
obtaining equipment, reductions in product prices, limitations in the market for
products, litigation and disputes in the ordinary course of business, each of
which could result in damage to or destruction of oil and natural gas wells,
production facilities or other property, or injury to persons. Although the
Company maintains insurance coverage considered to be customary in the industry,
it is not fully insured against certain of these risks either because such
insurance is not available or because
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of high premium costs. The Company cannot predict if or when any such risks
could affect it. The occurrence of a significant event for which the Company is
not adequately insured could cause its actual results to differ from those
reflected in our forward-looking statements.
Drilling Risks. The Company's decision to purchase, explore, develop or
otherwise exploit a prospect or property will depend in part on the evaluation
of data obtained through geophysical and geological analysis, production data
and engineering studies, which are inherently imprecise. Therefore, the Company
cannot be assured that all of its drilling activities will be successful or that
it will not drill uneconomical wells. The occurrence of unexpected drilling
results could cause the actual results to differ from those reflected in the
Company's forward-looking statements.
Uncertainties in Estimating Reserves and Future Net Cash Flows. Reserve
engineering is a subjective process of estimating the recovery from underground
accumulations of oil and natural gas that cannot be measured in an exact manner,
and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgement.
Reserve estimates are inherently imprecise and may be expected to change as
additional information becomes available. There are numerous uncertainties
inherent in estimating quantities and values of proved reserves and in
projecting future rates of production and timing of development expenditures,
including many factors beyond our control. Because all reserve estimates are to
some degree speculative, the quantities of oil and natural gas that the Company
ultimately recover, production and operating costs, the amount and timing of
future development expenditures and future oil and natural gas sales prices may
differ from those assumed in these estimates. Significant downward revisions to
it's existing reserve estimates could cause the actual results to differ from
those reflected in the Company's forward-looking statements.
Year 2000. The risks related to the year 2000, and the dates on which the
Company believes the Y2K Program will be completed, are based on management's
best estimates, which were derived utilizing numerous assumptions of future
events, including the continued availability of certain resources, third-party
modification plans and other factors. However, there can be no guarantee that
these estimates will be achieved, or that there will not be a delay in, or
increased costs associated with, the implementation of the Company's Y2K
Program. Specific factors that might cause differences between the estimates and
actual results include, but are not limited to, the availability and cost of
personnel trained in these areas, the ability to locate and correct all relevant
computer codes, timely responses to and corrections by third parties and
suppliers, the ability to implement interfaces between the new systems and the
systems not being replaced, and similar uncertainties. Due to the general
uncertainty inherent in the Year 2000 problem, resulting in part from the
uncertainty of the Year 2000 readiness of third parties and the interconnection
of global businesses, the Company cannot ensure the ability to timely and cost
effectively resolve problems associated with the Year 2000 issue that may affect
it's operations and business or expose it to third-party liability.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is currently exposed to market risk from hedging contracts changes
and changes in interest rates. A discussion of the market risk exposure in
financial instruments follows.
HEDGING CONTRACTS
Effective July 16, 1999, the Company entered into certain hedging contracts as
summarized in the table below. The Notional Amount is equal to the total net
volumetric hedge position of the Company during the periods. The positions
effectively hedge approximately 60% of the Company's current oil production. The
fair values of the hedge are based on the difference between the strike price
and the New York Mercantile Exchange future prices for the applicable trading
months of 1999 and 2000.
Weighted Average Fair Value at
Notional Strike Price September 30, 1999
Amount ($ per unit) (in thousands)
----------- ----------------------- ------------------
Oil (thousands of barrels): Floor Ceiling
------- ---------
October 1999 - June 2000 1,918 $16.00 $24.00 $0
INTEREST RATES
The Company is subject to interest rate risk on its long-term fixed interest
rate debt and variable interest rate borrowings. The Company's long-term
borrowings primarily consist of borrowings under the Credit Facility and the $20
million principal of 9 1/2% Convertible Subordinated Notes due June 15, 2005.
Since borrowings under the Credit Facility float with prevailing interest rates
(except for the applicable interest period for Eurodollar loans), the carrying
value of borrowings under the Credit Facility should approximate the fair market
value of such debt. Changes in interest rates, however, will change the cost of
borrowing. Assuming $250 million remains borrowed under the Credit Facility, the
Company estimates its annual interest expense will change by $2.5 million for
each 100 basis point change in the applicable interest rates utilized under the
Credit Facility. Changes in interest rates would, assuming all other things
being equal, cause the fair market value of debt with a fixed interest rate,
such as the Notes, to increase or decrease, and thus increase or decrease the
amount required to refinance the debt. The fair value of the Notes is dependent
on prevailing interest rates and the Company's current stock price as it relates
to the conversion price of $7.00 per share of its Common Stock.
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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
C. M. THIBODAUX NO. 2
During late June 1999, the Company's C. M. Thibodaux No. 2 well experienced
uncontrolled gas flows and a fire for a short period, which was capped with a
diverting well head. A replacement well, the C. M. Thibodaux No. 3, has been
completed and placed on production. The Company has determined that no material
reserves have been lost. A class action lawsuit has been filed in the 15th
Judicial District Court, Parish of St. Mary, Louisiana No. 104,204 "D", against
various of the Company's operating subsidiaries as well as other third parties
involved with the Company in drilling the well alleging various economic and
environmental damage was caused by the negligence of the Company's operating
subsidiaries and the other third party defendants. At this time, this lawsuit
has not been served on the Company's subsidiaries or any of the other third
party defendants. The Company does not believe that its actions were negligent
with respect to the operation of the C. M. Thibodaux No. 2 or that there is any
evidence of economic or environmental damage. The Company therefore intends to
vigorously defend this lawsuit if it is pursued by the plaintiffs. In the event
of an adverse determination, however, the Company believes that is has adequate
insurance coverage to minimize any economic losses and other damages arising out
of these events; and therefore, does not believe that these matters surrounding
the C. M. Thibodaux No. 2 will have a material adverse effect on its financial
condition or results of operation.
ENRON DISPUTE
In November 1998, Enron Capital & Trade Resources Corp. ("Enron") filed an
action in the District Court of Harris County, Texas, 11th Judicial District,
Texas against the Company and certain Shell affiliates alleging causes of action
against the Company and Shell for trespass and tortious interference with
contract and seeking declaratory and injunctive relief. Enron asserts that the
Company's drilling and operation of certain Louisiana oil and gas wells has and
will trespass upon Enron's Louisiana property interests and tortiously interfere
with a Participation Agreement dated June 12, 1996 between Enron and Shell (the
"Participation Agreement"). Enron asserts further that it is being denied its
right to participate in certain drilling projects allegedly included under the
Participation Agreement, including interests in wells drilled in the Weeks
Island Field.
The properties covered by the Participation Agreement are owned by the Company,
with record title in the Company's subsidiary, Louisiana Onshore Properties
Inc., which was acquired from Shell in the Shell Transactions. Subject to
certain agreed upon limitations, Enron, Shell and the Company have consented to
submit this dispute to arbitration.
The Company is vigorously defending against Enron's claims and has reserved all
of its rights for reimbursement against Shell if Enron's claims are successful.
The Company believes that its is entitled to operate the referenced Louisiana
properties and that Enron is not entitled to any of the Company's interest in
wells that have been drilled in the Weeks Island Field. However, in the event of
an adverse determination resulting in a monetary judgement or property losses as
a result of Enron's claims with respect to the Weeks Island Field, the Company
believes that it is entitled to indemnification or reimbursement from Shell
under the agreements governing the Shell Transactions and have other rights and
actions under common law and state and federal securities laws, and in this
regard, the Company has filed suit against Shell to preserve these claims. The
Company has agreed to release Shell and its affiliates from any claims against
Shell that it may with respect to the Weeks Island Field in exchange for Shell's
complete and unequivocal indemnity to the
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Company for any award, judgement, declaration of title or settlement by Enron
resulting from Enron's claims relating to all wells and reserves located in the
Weeks Island Field. As a result of Shell's indemnity agreement, the Company
currently does not believe the dispute with Enron will have a material adverse
effect on its financial condition or results of operations.
Recently, the Company, Shell and Enron have entered into a Letter of Intent
whereby the parties have tentatively agreed to resolve all claims and disputes,
pending the execution of a Formal Settlement Agreement.
AMOCO LITIGATION
The Company previously filed an appeal relating to the decision of the federal
district court in the Amoco litigation that was previously described in the
Company's Annual Report on Form 10-K for the year ended December 31, 1998. In
connection with this appeal, the court entered a judgment aggregating against
all parties including the Company. During the third quarter of 1999, the Company
paid $5.8 million in final settlement of this litigation.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits.
27.1 Financial Data Schedule.
(b) The Company filed no reports on Form 8-K during the third quarter of
1999.
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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.
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
(Registrant)
Date: November 12, 1999 By: /s/ P. RICHARD GESSINGER
-----------------------------
P. Richard Gessinger
Executive Vice President and
Chief Financial Officer
By: /s/ LLOYD V. DELANO
----------------------------
Lloyd V. DeLano
Vice President
Chief Accounting Officer
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INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
27.1 Financial Data Schedule.