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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: March 31, 2003
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
incorporation or organization) Identification No.)
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 [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ]
Number of shares of common stock outstanding at May 8, 2003 50,162,304
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 Ended March 31, 2003 and 2002 3
Consolidated Balance Sheets as of March 31, 2003 (unaudited)
and December 31, 2002 4
Consolidated Statements of Cash Flows (unaudited) for the
Three Months Ended March 31, 2003 and 2002 6
Notes to Consolidated Financial Statements (unaudited) 7
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 11
Item 3. Quantitative and Qualitative Disclosures about Market Risk 18
Item 4. Controls and Procedures 19
PART II - OTHER INFORMATION
Item 1. Legal Proceedings 20
Item 6. Exhibits and Reports on Form 8-K 20
SIGNATURES 21
2
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands of dollars, except per share information)
(unaudited)
THREE MONTHS ENDED
MARCH 31,
2003 2002
---- ----
REVENUES:
Oil and natural gas $ 28,987 $ 24,609
Price risk management activities ----- (805)
Interest and other 38 44
----------- -----------
29,025 23,848
----------- -----------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 2,484 3,089
Severance and ad valorem taxes 1,819 2,717
Depletion and depreciation 14,655 13,361
Accretian expense 128 --
General and administrative 2,810 3,258
----------- -----------
21,896 22,425
----------- -----------
EARNINGS BEFORE INTEREST
AND INCOME TAXES 7,129 1,423
OTHER EXPENSES:
Interest expense 2,618 3,900
Taxes on income - deferred -- (900)
----------- -----------
2,618 3,000
----------- -----------
NET EARNINGS (LOSS) BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 4,511 (1,577)
Cumulative effect of change in accounting principle (1,309) --
----------- -----------
NET EARNINGS (LOSS) 3,202 (1,577)
Dividends on preferred stock 1,481 --
----------- -----------
NET EARNINGS (LOSS) APPLICABLE TO COMMON STOCKHOLDERS $ 1,721 $ (1,577)
=========== ===========
NET EARNINGS (LOSS) PER SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE:
Basic and Diluted $ 0.06 $ (0.03)
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE PER SHARE:
Basic and Diluted $ (0.03) $ --
----------- -----------
NET EARNINGS (LOSS) PER SHARE:
Basic and Diluted $ 0.03 $ (0.03)
=========== ===========
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic and Diluted 50,090 49,182
=========== ===========
See notes to consolidated financial statements.
3
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
MARCH 31, DECEMBER 31,
2003 2002
---- ----
(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 7,214 $ 7,287
Accounts receivable, less allowance for doubtful accounts
$833 [2003 and 2002] 31,142 24,167
Due from affiliates 1,632 1,557
Prepaid expenses and other 2,071 2,221
Assets from price risk management activities 1,059 604
------------ ------------
Total current assets 43,118 35,836
------------ ------------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including
$19,982 [2003] and $18,993 [2002] not
subject to depletion) 1,181,593 1,162,436
Land 478 478
Equipment 9,921 9,913
1,191,992 1,172,827
Less accumulated depletion and depreciation 776,508 761,854
------------ ------------
Total property and equipment, net 415,484 410,973
------------ ------------
OTHER ASSETS:
Assets from price risk management activities 95 292
Deferred tax asset 3,678 2,560
Other 6,011 6,579
------------ ------------
Total other assets 9,784 9,431
------------ ------------
Total assets $ 468,386 $ 456,240
============ ============
See notes to consolidated financial statements.
4
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
MARCH 31, DECEMBER 31,
2003 2002
---- ----
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 20,409 $ 16,842
Revenues and royalties payable 12,559 12,378
Notes payable 82 831
Accrued liabilities 12,491 9,958
Liabilities from price risk management activities 8,231 6,781
Current income taxes payable 931 931
Current portion long-term debt 34,000 35,250
------------- -------------
Total current liabilities 88,703 82,971
------------- -------------
LONG-TERM DEBT 148,500 148,500
------------- -------------
9 1/2% CONVERTIBLE SUBORDINATED NOTES 20,000 20,000
------------- -------------
OTHER:
Liabilities from price risk management activities 3,433 1,686
Abandonment costs 4,651 --
------------- -------------
8,084 1,686
------------- -------------
REDEEMABLE PREFERRED STOCK:
Preferred stock, $1.00 par value (1,500,000 shares authorized,
696,900 shares of Series C Redeemable Convertible
Preferred Stock issued at stated value) 69,690 69,690
------------- -------------
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized,
53,868,343 [2003 and 2002] issued) 560 557
Additional paid-in capital 377,919 378,215
Accumulated deficit (208,017) (209,738)
Accumulated other comprehensive loss (7,017) (4,938)
Unamortized deferred compensation (277) (356)
------------- -------------
163,168 163,740
Less treasury stock, at cost (3,706,039 shares [2003] and
3,779,225 [2002] shares) 29,759 30,347
------------- -------------
Total stockholders' equity 133,409 133,393
------------- -------------
Total liabilities and stockholders' equity $ 468,386 $ 456,240
============= =============
See notes to consolidated financial statements.
5
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
(unaudited)
THREE MONTHS ENDED
MARCH 31,
2003 2002
---- ----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss) $ 3,202 $ (1,577)
Adjustments to reconcile net earnings (loss) to net cash
provided by operating activities:
Cumulative effect of change in accounting principle 1,309 --
Depletion and depreciation 14,654 13,361
Amortization of other assets 568 520
Non-cash compensation 413 409
Non-cash price risk management activities -- 805
Accretion expense 128 --
Deferred income taxes -- (900)
Changes in assets and liabilities:
Accounts receivable (6,975) 3,036
Due from affiliates (75) (1,508)
Prepaid expenses and other 150 223
Accounts payable 3,567 143
Revenues and royalties payable 181 (202)
Accrued liabilities and other 795 (5,829)
-------------- --------------
Net cash provided by operating activities 17,917 8,481
-------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (16,085) (11,485)
Sale of property and equipment 135 119
-------------- --------------
Net cash used in investing activities (15,950) (11,366)
-------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Reductions in long-term debt (1,250) --
Notes payable (749) (508)
Issuance of stock/exercise of options (41) --
Additions to deferred loan costs -- (1,370)
-------------- --------------
Net cash used in financing activities (2,040) (1,878)
-------------- --------------
NET CHANGE IN CASH AND CASH EQUIVALENTS (73) (4,763)
Cash and cash equivalents at beginning of period 7,287 14,340
-------------- --------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 7,214 $ 9,577
============== ==============
See notes to consolidated financial statements.
6
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, 2002, as filed with the Securities and Exchange Commission.
The financial statements included herein as of March 31, 2003, and for the three
month periods ended March 31, 2003 and 2002, 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.
2. DEBT
CREDIT FACILITY. During August 2002, the Company replaced its Chase Manhattan
Bank Credit Facility with a new three-year $175 million underwritten senior
secured credit agreement (the "Credit Agreement") with Societe Generale, as
administrative agent, lead arranger and book runner, and Fortis Capital Corp.,
as co-lead arranger and documentation agent. The current borrowing base under
the existing Credit Agreement was established on September 23, 2002, at $165
million, with the borrowing base redetermination date scheduled for November 30,
2002. The parties to the Credit Agreement have entered into an amendment of the
Agreement, effective March 31, 2003, to eliminate the November 30, 2002,
redetermination date and to reschedule the borrowing base redetermination date
for April 30, 2003, and quarterly redetermination thereafter.
On March 31, 2003, the Company received notice from its senior lenders that
effective April 30, 2003, the borrowing base will be established at $138.5
million. Accordingly, the Company has reflected the difference of $26.5 million
as a current maturity of its long-term debt and is required to make up the
deficiency through the addition of reserves or value to its current reserve base
or pay the senior lenders this deficiency within 90 days of the effective date
of April 30, 2003. Though no assurances can be made that sufficient funds will
be available to pay this deficiency, management believes that it can satisfy
this deficiency through a combination of the addition of reserves, third-party
financing, property sales and cash flow.
In addition to the scheduled quarterly borrowing base redeterminations, the
lenders and the Credit Agreement 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 Agreement are secured by pledges of
outstanding capital stock of the Company's subsidiaries and a mortgage on the
Company's oil and natural gas properties of at least 90% of its present value of
proved properties. The Credit Agreement contains various restrictive covenants
including, among other items, maintenance of certain financial ratios and
restrictions on cash dividends on Common Stock and an unqualified audit report
on the Company's consolidated financial statements beginning with those as of
and for the year ended December 31, 2002. The Company has received from the
senior lenders a waiver of the covenant that would have triggered an event of
default as a result of the independent auditors' report which contained a "going
concern" modification for our 2002 consolidated financial statements. Borrowings
under the Credit Agreement mature on August 13, 2005.
Under the new Credit Agreement, 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 plus an additional 0.5% to
1.5% depending on the ratio of the aggregate outstanding loans and letters of
credit to the borrowing base; or a federal funds-based rate plus 1/2 of 1% or
(ii) a Eurodollar base rate loan that bears interest, generally, at a rate per
annum equal to the London interbank offered rate ("LIBOR") plus 1.5% to 2.5%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. The Credit Agreement also provides for commitment fees
ranging from 0.375% to 0.5% per annum.
SUBORDINATED CREDIT AGREEMENT. The Company extended and amended a short-term
subordinated credit agreement with Fortis Capital Corporation for $25 million
on April 5, 2002, with a maturity date of December 31, 2004. The notes are
unsecured and contain customary events of default, but do not contain any
maintenance or other restrictive covenants. The interest rate is the London
interbank offered rate ("LIBOR") plus 4.5% through December 31, 2002, LIBOR
plus 5.5% from January 1, 2003, through August 31, 2003, and LIBOR plus 6.5%
from September 1, 2003, through December 31, 2004. Note payments of $5 million
each are due on August 31, 2003 and April 30, 2004, with the remaining $5
million payable on December 31, 2004. Note payments totaling $1.25 million were
paid in January 2003. An additional $2.5 million that is currently due has been
deferred in conjunction with the March 31, 2003, amendment to the Credit
Agreement. No amounts are payable under this subordinated debt until any and
all borrowing base deficiencies under the Credit Agreement are satisfied. The
Company is in compliance under this agreement.
3. 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 MARCH 31,
2003 2002
---- ----
Numerator:
Net earnings (loss) applicable to common stockholders $ 1,721 $ (1,577)
Plus income impact of assumed conversions:
Preferred stock dividends 1,481 --
Interest on convertible subordinated notes 309 309
-------------- ------------
Net earnings (loss) applicable to common stockholders
plus assumed conversions $ 3,511 $ (1,268)
-------------- ------------
Denominator:
Denominator for basic net earnings (loss) per
share - weighted-average shares outstanding 50,090 49,182
Effect of potentially dilutive common shares:
Redeemable convertible preferred stock N/A --
Convertible subordinated notes N/A N/A
Employee and director stock options -- N/A
Warrants N/A N/A
-------------- ------------
Denominator for diluted net earnings (loss) per
share - weighted-average shares outstanding
and assumed conversions 50,090 49,182
============== ============
Basic net earnings (loss) per share $ 0.03 $ (0.03)
==============
============== ============
Diluted net earnings (loss) per share $ 0.03 $ (0.03)
============== ============
7
4. OIL AND NATURAL GAS HEDGING ACTIVITIES
The Company may address market risk by selecting instruments whose value
fluctuations correlate strongly with the underlying commodity being hedged. The
Company enters into swaps and other derivative contracts to hedge the price
risks associated with a portion of anticipated future oil and gas production.
These swaps allow the Company to predict with greater certainty the effective
oil and natural gas prices to be received for our hedged production. Although
derivatives often fail to achieve 100% effectiveness for accounting purposes,
our derivative instruments continue to be highly effective in achieving the risk
management objectives for which they were intended. While the use of hedging
arrangements limits the downside risk of adverse price movements, it may also
limit future gains from favorable movements. Under these agreements, payments
are received or made based on the differential between a fixed and a variable
product price. These agreements are settled in cash at or prior to expiration or
exchanged for physical delivery contracts. The Company does not obtain
collateral to support the agreements, but monitors the financial viability of
counter-parties and believes its credit risk is minimal on these transactions.
In the event of nonperformance, the Company would be exposed to price risk. The
Company has some risk of accounting loss since the price received for the
product at the actual physical delivery point may differ from the prevailing
price at the delivery point required for settlement of the hedging transaction.
These swaps have been designated as cash flow hedges as provided by FAS 133 and
any changes in fair value of the cash flow hedge resulting from ineffectiveness
of the hedge is reported in the consolidated statement of operation as revenues.
The estimated March 31, 2003, fair value of the Company's oil and natural gas
swaps is an unrealized loss of $10.5 million ($6.8 million net of tax)
recognized in other comprehensive income. Based upon March 31, 2003, oil and
natural gas commodity prices, approximately $7.2 million of the loss deferred in
other comprehensive income is expected to lower gross revenues over the next
twelve months when the revenues are generated. The swap agreements expire at
various dates through July 31, 2005.
Payments under these swap agreements reduced oil and natural gas revenues by
$7,105,000 for the three months ended March 31, 2003, as a result of hedging
transactions.
The Notional Amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 44% of our proved developed natural gas production and 70% of our
proved developed oil production. The fair values of the hedges are based on the
difference between the strike price and the New York Mercantile Exchange future
prices for the applicable trading months.
Weighted Average Fair Value (unrealized)
Notional Strike Price at March 31, 2003
Amount ($ per unit) (in thousands)
----------------- ---------------------- ---------------------------
Natural Gas (mmbtu)
April 2003 - June 2005 7,130,000 $ 3.78 $ 7,590
Oil (bbls)
April 2003 - July 2005 1,721,000 $ 24.22 $ 2,920
---------------------------
$ 10,510
---------------------------
8
5. STOCK-BASED COMPENSATION
SFAS 123, "Accounting for Stock-Based Compensation," as amended by SFAS 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure,"
established accounting and disclosure requirements using a fair value-based
method of accounting for stock-based employee compensation plans. As provided
for under SFAS 123, there has been no amount of compensation expense recognized
for the Company's stock option plans. The Company accounts for stock-based
compensation using the intrinsic value method prescribed in Accounting
Principles Board Opinion 25, "Accounting for Stock Issued to Employees."
Compensation expense is recorded for restricted stock awards over the requisite
vesting periods based upon the market value on the date of the grant. The
compensation expense incurred in the quarters ended March 31, 2003 and 2002,
related to restricted stock awards totaling $10 thousand for each quarter,
respectively.
The following is a reconciliation of reported earnings (loss) and earnings
(loss) per share as if the Company used the fair value method of accounting for
stock-based compensation. Fair value is calculated using the Black-Scholes
option pricing model.
Three Months Ended March 31,
2003 2002
---- ----
Net earnings (loss) applicable to common stockholders as reported ($000) $ 1,721 $ (1,577)
Stock-based compensation expense determined
under fair value method for all awards, net of tax ($000) 10 10
Net earnings (loss) applicable to common stockholders pro forma ($000) $ 1,711 $ (1,587)
Basic earnings (loss) per share:
As reported $ 0.03 $ (0.03)
Pro forma $ 0.03 $ (0.03)
Diluted earnings (loss) per share:
As reported $ 0.03 $ (0.03)
Pro forma $ 0.03 $ (0.03)
6. ASSET RETIREMENT OBLIGATIONS
On January 1, 2003, the Company adopted SFAS 143, "Accounting for Asset
Retirement Obligations." This statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement
obligations of tangible long-lived assets in the period in which it is incurred.
The fair value of asset retirement obligation liabilities has been calculated
using an expected present value technique. Fair value, to the extent possible,
should include a market risk premium for unforeseeable circumstances. No market
risk premium was included in the Company's asset retirement obligations fair
value estimate since a reasonable estimate could not be made. When the liability
is initially recorded, the entity increases the carrying amount of the related
long-lived asset. Over time, accretion of the liability is recognized each
period, and the capitalized cost is amortized over the useful life of the
related asset. Upon settlement of the liability, an entity either settles the
obligation for its recorded amount or incurs a gain or loss upon settlement.
This standard requires us to record a liability for the fair value of our
dismantlement and abandonment costs, excluding salvage values.
Upon adoption, the Company recorded transition amounts for liabilities related
to our wells, and the associated costs to be capitalized. A liability of $4.5
million was recorded to long-term liabilities and a net asset of $3.2 million
was recorded to oil and natural gas properties on January 1, 2003. This resulted
in a cumulative effect of an accounting change of ($1.3) million. Accretion
expenses subsequent to the adoption of this accounting statement decreased net
earnings $0.1 million in the first quarter of 2003.
9
The pro forma effects of the application of SFAS 143 as if the statement had
been adopted on January 1, 2002, is presented below (thousands of dollars except
per share information):
Three Months Ended March 31,
2003 2002
---- ----
Net earnings (loss) as reported $ 3,202 $ (1,577)
Additional accretion expense -- (117)
Cumulative effect of accounting change 1,309 --
------------ -------------
Pro forma net earnings (loss) $ 4,511 $ (1,694)
Pro forma net earnings (loss) per share $ 0.09 $ (0.03)
The following table describes the change in the Company's asset retirement
obligations for the period ended March 31, 2003, and the pro forma amounts for
2002 (thousands of dollars):
Asset retirement obligation at January 1, 2002 $ 4,053
Accretion expense 470
-------------
Asset retirement obligation at December 31, 2002 $ 4,523
Accretion expense 128
-------------
Asset retirement obligation at March 31, 2003 $ 4,651
10
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following is a discussion of Meridian's financial operations for the three
months ended March 31, 2003 and 2002. The notes to the Company's consolidated
financial statements included in this report, as well as our Annual Report on
Form 10-K for the year ended December 31, 2002 (and the notes attached thereto),
should be read in conjunction with this discussion.
GENERAL
BUSINESS ACTIVITIES. During the first quarter of 2003, Meridian's exploration
activities have been focused primarily in the Company's Biloxi Marshlands
acreage. We anticipate drilling and 3-D seismic activities in the Biloxi
Marshlands acreage will comprise the majority of our capital budget for 2003.
During the first quarter of 2003, capital expenditures were focused primarily in
our Biloxi Marshland play. We addressed three fronts; namely, to increase the
Company's near term daily production rates by completing the pipeline and
production facilities for the Biloxi Marshlands discovery well, the Biloxi
Marshlands 6-1 well, the identification of other drill sites in the immediate
area and the acquisition of leasehold and state water bottoms acreage for
current and future drilling operations.
The construction of the pipeline and production facilities was completed on
March 14, 2003 and the Biloxi Marshlands No. 6-1 well placed on production on
March 15, 2003 at approximately 12 MMCFE/D. This well is currently producing at
a steady rate 11.5 MMCFE/D. The facilities were designed for a production
capacity of 60 MMCFE/D based on anticipated additional drilling in the immediate
area.
In addition to the facilities at Biloxi, utilizing our proprietary 3-D seismic
which we acquired during 2002, we were successful in acquiring state lease
acreage for coverage of anticipated units to be formed as additional wells are
drilled in the area. Because our data is proprietary to Meridian, we were able
to identify specific potential drill site acreage and successfully win the bids
acquiring all of the acreage positions which we targeted during both the March
Louisiana state lease sale and recently the May Louisiana state lease sale.
Further, as additional drill sites have been identified under our proprietary
3-D and the state water bottom acreage acquired to protect our land positions,
we have initiated drilling additional wells in the immediate area. The first
well is the Biloxi Marshlands No. 6-2 well which was spud on May 3, 2003 and
reached total depth on May 14, 2003. Logging operations will commence
immediately with results announced thereafter. If successful, this well can be
placed on production within ten days because the production facilities recently
completed are immediately adjacent to the well's surface location.
Having already identified additional drilling opportunities in the adjacent area
over which we have acquired the acreage under lease, the Biloxi Marshlands No.
7-1 well has been accelerated and is currently scheduled to be drilled
immediately utilizing the same rig. This will save rig move-out and move-in
mobilization costs, take advantage of the accelerated drilling time line
experienced with the Biloxi Marshlands No. 6-2 well and, if successful, will
accelerate production rate increases and take advantage of current high natural
gas prices.
Other activities in the first quarter in the Biloxi Marshlands play included the
planning, permitting and negotiating of a 3-D seismic acquisition contract to
acquire a minimum of an additional 105 square miles of 3-D seismic data to the
south and east of the current 3-D seismic coverage owned by Meridian its area of
interest. Depending on weather conditions during the summer months in this
region, we may acquire an additional amount of 3-D data under the current
contract.
Based on current plans, the Company has scheduled a total of five (5) and
possibly six (6) wells for the Biloxi Marshlands play for calendar year 2003.
Any additional wells will depend on budget availability, and the results and
timing of completing the acquisition, processing and interpretation of the new
3-D seismic data currently being acquired.
Meridian operates the Biloxi Marshlands acreage and owns a 93% working interest
(66% net revenue interest) in the project area.
In addition to the activities in the Biloxi Marshlands play, the Company is
currently scheduled to drill its Ship Shoal prospect beginning during the late
second quarter or early third quarter, depending on rig availability and move-in
timing. Meridian developed the play and owns a 43% working interest. The well
will test the Lower Pleistocene sands at approximately 13,000 feet and
should be drilled and logged by the end of the August or early September
depending on start date and operations. It is expected that the well will be
drilled under a turnkey contract. Although, if successful, reserves will be
added in calendar year 2003, it is anticipated that the well will not be on
production until 2004 inasmuch as it is in over 250 feet of water and production
facilities will have to be constructed.
Other prospects scheduled for the second quarter are in the Company's Riceville
area. The Pathfinder prospect has been planned for a June spud date and will the
test the Lower Miocene sands at approximately 12,500 feet. Again, depending on
spud date and drilling operations, the drilling is expected to be completed
during the end of the second quarter or beginning of the third quarter.
Workover and completions activities scheduled for the second quarter include the
Avoca No. 47-1 well which was producing approximately 8 MMCFE/D and is expected
to be back on production by the end of May. In addition, the Thibodaux No. 1
well is scheduled for late May or as soon as equipment is available. This is a
high pressured well and is located over water. As a result, equipment to handle
the workover operations is an issue to insure safe operations.
Lastly, the Hughes No. 2 well is awaiting completion operations to commence
which are expected to begin on or about June 15, 2003. Plans have been
established to re-enter the open hole section, clean out the bore hole to total
depth, set a production liner and perforate the Bol Mex 5 series of sands
encountered and logged during February 2003. Meridian is the operator of the
well and owns an approximate 94% working interest and a 70% net revenue interest
in the well. The well will be on production immediately after completion
operations are concluded inasmuch as production facilities are in place and
awaiting tie-in.
At current commodity prices, if successful, production from the above mentioned
wells could result in substantial increases to the Company's cash flow from
operations for 2003 and following.
INDUSTRY CONDITIONS. Revenues, profitability and future growth rates of Meridian
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 our control. Our average oil price (after
adjustments for hedging activities) for the three months ended March 31, 2003,
was $25.15 per barrel compared to $20.62 per barrel for the three months ended
March 31, 2002, and $27.23 per barrel for the three months ended December 31,
2002. Our average natural gas price (after adjustments for hedging activities)
for the three months ended March 31, 2003, was $5.82 per Mcf compared to $2.51
per Mcf for the three months ended March 31, 2002, and $4.08 per Mcf for the
three months ended December 31, 2002. Fluctuations in prevailing prices for oil
and natural gas have several important consequences to us, including affecting
the level of cash flow received from our producing properties, the timing of
exploration of certain prospects and our access to capital markets, which could
impact our revenues, profitability and ability to maintain or increase our
exploration and development program.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES. The Company's discussion and
analysis of its financial condition and results of operation are based upon
consolidated financial statements, which have been prepared in accordance with
accounting principles generally accepted and adopted in the United States. The
preparation of these financial statements requires the Company to make estimates
and judgments that affect the reported amounts of assets, liabilities, revenues
and expenses. See the Company's Annual Report on Form 10-K for the year ended
December 31, 2002, for further discussion.
11
RESULTS OF OPERATIONS
THREE MONTHS ENDED MARCH 31, 2003 COMPARED TO THREE MONTHS ENDED MARCH 31, 2002
OPERATING REVENUES. First quarter 2003 oil and natural gas revenues increased
$4.4 million as compared to first quarter 2002 revenues, primarily due to a 75%
increase in average commodity prices partially offset by a 33% decrease in
production volumes, both on a natural gas equivalent basis. The decrease in
production was primarily a result of natural production declines, partially
offset by new discoveries placed on line at varying times during 2002.
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the three months ended March 31, 2003 and
2002:
THREE MONTHS ENDED
MARCH 31, INCREASE
2003 2002 (DECREASE)
---- ---- ----------
Production Volumes:
Oil (Mbbl) 397 633 (37%)
Natural gas (MMcf) 3,263 4,596 (29%)
MMcfe 5,646 8,395 (33%)
Average Sales Prices:
Oil (per Bbl) $ 25.15 $ 20.62 22%
Natural gas (per Mcf) $ 5.82 $ 2.51 132%
MMcfe $ 5.13 $ 2.93 75%
Operating Revenues (000's):
Oil $ 9,985 $13,054 (24%)
Natural gas 19,002 11,555 64%
------- -------
Total Operating Revenues $28,987 $24,609 18%
OPERATING EXPENSES. Oil and natural gas operating expenses decreased $0.6
million (20%) to $2.5 million for the three months ended March 31, 2003,
compared to $3.1 million for the same period in 2002. This decrease primarily
resulted from reorganization of field operations enabling the Company to
significantly reduce labor and other field related costs.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes decreased $0.9
million (33%) to $1.8 million for the first quarter of 2003, compared to $2.7
million during the same period in 2002. Meridian's oil and natural gas
production is primarily from Louisiana, and is therefore subject to Louisiana
severance tax. The severance tax rates for Louisiana are 12.5% of gross oil
revenues and $0.122 per Mcf for natural gas, a decrease from $0.199 per Mcf
effective in July 2002. Our decrease was primarily due to the decrease in oil
and natural gas production and the decrease in the natural gas tax rate,
partially offset by the increase in oil prices.
DEPLETION AND DEPRECIATION. Depletion and depreciation expense increased $1.3
million (10%) during the first quarter of 2003 to $14.7 million from $13.4
million for the same period of 2002. This was primarily a result of an increased
depletion rate for 2003 over 2002, partially offset by the decrease in
production volumes in 2003 from 2002 levels.
12
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense decreased
by $0.5 million (14%) to $2.8 million for three months ended March 31, 2003,
compared to $3.3 million during the comparable period last year. This reduction
is primarily due to a reduction in professional and technical services in 2003
as compared to 2002 levels. As previously announced, during the first quarter,
the Company initiated reductions in staff to reflect its change in exploration
strategy to lower risk, higher probability projects maintaining its focus in its
niche region of south Louisiana and southeast Texas. It is anticipated that
these changes will result in continued savings in costs without sacrificing the
Company's exploration efforts or opportunities.
INTEREST EXPENSE. Interest expense decreased $1.3 million (33%) to $2.6 million
for the first quarter of 2003 in comparison to the first quarter of 2002. The
decrease is primarily a result of the reduction in the balance outstanding for
the revolving credit lines and a decrease in the interest rates from the prior
year.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. During the first quarter of 2003, Meridian's capital
expenditures were internally financed with cash from operations. As of March 31,
2003, we had a cash balance of $7.2 million and a working capital deficit of
$45.6 million, including $34 million of current maturities of long-term debt,
and a $7.2 million deficit in price risk management activities. Our strategy is
to grow the Company prudently, taking advantage of the strong asset base built
over the years to add reserves through the drill bit while maintaining a
disciplined approach to costs. Where appropriate, we will allocate excess cash
above capital expenditures to reduce leverage.
CREDIT FACILITY. During August 2002, the Company replaced its Chase Manhattan
Bank Credit Facility with a new three-year $175 million underwritten senior
secured credit agreement (the "Credit Agreement") with Societe Generale, as
administrative agent, lead arranger and book runner, and Fortis Capital Corp.,
as co-lead arranger and documentation agent. The current borrowing base under
the existing Credit Agreement was established on September 23, 2002, at $165
million, with the borrowing base redetermination date scheduled for November 30,
2002. The parties to the Credit Agreement have entered into an amendment of the
Agreement, effective March 31, 2003, to eliminate the November 30, 2002,
redetermination date and to reschedule the borrowing base redetermination date
for April 30, 2003, and quarterly redetermination thereafter.
On March 31, 2003, the Company received notice from its senior lenders that
effective April 30, 2003, the borrowing base will be established at $138.5
million. Accordingly, the Company has reflected the difference of $26.5 million
as a current maturity of its long-term debt and is required to make up the
deficiency through the addition of reserves or value to its current reserve base
or pay the senior lenders this deficiency within 90 days of the effective date
of April 30, 2003. Though no assurances can be made that sufficient funds will
be available to pay this deficiency, management believes that it can satisfy
this deficiency through a combination of the addition of reserves, third-party
financing, property sales and cash flow.
In addition to the scheduled quarterly borrowing base redeterminations, the
lenders under the Credit Agreement 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 Agreement are secured by pledges of
outstanding capital stock of the Company's subsidiaries and a mortgage on the
Company's oil and natural gas properties of at least 90% of its present value of
proved properties. The Credit Agreement contains various restrictive covenants,
including, among other items, maintenance of certain financial ratios and
restrictions on cash dividends on Common Stock and an unqualified audit report
on the Company's consolidated financial statements beginning with those as of
and for the ended December 31, 2002. The Company has received from the senior
lenders a waiver of the covenant that would have triggered an event of default
as a result of the independent auditors' report which contained a "going
concern" modification for our 2002 consolidated financial statements. Borrowings
under the Credit Agreement mature on August 13, 2005.
13
Under the new Credit Agreement, 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 plus an additional 0.5% to 1.5% depending
on the ratio of the aggregate outstanding loans and letters of credit to the
borrowing base; or a federal funds-based rate plus 1/2 of 1% or (ii) a
Eurodollar base rate loan that bears interest, generally, at a rate per annum
equal to the London interbank offered rate ("LIBOR") plus 1.5% to 2.5%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. The Credit Agreement also provides for commitment fees
ranging from 0.375% to 0.5% per annum.
SUBORDINATED CREDIT AGREEMENT. The Company extended and amended a short-term
subordinated credit agreement with Fortis Capital Corporation for $25 million on
April 5, 2002, with a maturity date of December 31, 2004. The notes are
unsecured and contain customary events of default, but do not contain any
maintenance or other restrictive covenants. The interest rate is the London
interbank offered rate ("LIBOR") plus 4.5% through December 31, 2002, LIBOR plus
5.5% from January 1, 2003, through August 31, 2003, and LIBOR plus 6.5% from
September 1, 2003, through December 31, 2004. Note payments of $5 million each
are due on August 31, 2003 and April 30, 2004, with the remaining $5 million
payable on December 31, 2004. Note payments totaling $1.25 million were paid in
January 2003. An additional $2.5 million that is currently due has been deferred
in conjunction with the March 31, 2003, amendment to the Credit Agreement. No
amounts are payable under this subordinated debt until any and all borrowing
base deficiencies under the Credit Agreement are satisfied. The Company is in
compliance under this agreement.
CAPITAL RESOURCES AND LIQUIDITY As noted in our discussion of the Credit
Facility, there is a $26.5 million borrowing base deficiency at April 30, 2003
that must be satisfied by either sufficient additions to our proved reserves or
repayment on or before July 29, 2003, to avoid an event of default. An event of
default which is not cured results in the entire debt outstanding becoming due
and payable, unless it is waived by the senior lenders or the Credit Agreement
is otherwise amended. Also, repayment of $2.5 million, after our $1.25 million
January 2003 payment, under our subordinated debt agreement is due but is
deferred pending satisfaction of the borrowing base deficiency under the amended
Credit Agreement. The $5 million subordinated debt repayment that will become
due in August 2003 is also subject to deferral for any borrowing base
deficiencies that may exist at that time. The $34 million due in 2003 under
these agreements represents a significant component of our $45.6 million working
capital deficiency at March 31, 2003.
Based upon our expected level of production and considering a reduced level of
capital spending plan of $15 to $20 million, we project that our available cash
flow from operations is not expected to be sufficient to fund the April 30, 2003
borrowing base deficiency and amounts due or to become due in 2003 under our
subordinated debt agreement.
In an effort to address the liquidity issue and the broader issue of aligning
our capital structure with our long-term business strategy, the Company is
pursuing several plans that it believes will remedy the current borrowing base
deficiency of $26.5 million.
First, it should be noted that, as of December 31, 2002, the Company's proved
developed reserves have a present value based on SEC regulations that include
prices in effect at year-end and a 10% discount rate, of approximately $460
million or approximately three times its total senior credit facility.
Based on current cash flow projections and the Company's specific knowledge of
its drilling prospects and historical performance in the areas of anticipated
activity, potential opportunities for non-strategic property sales and/or third
party capital funding, it is management's judgment and belief that its business
plan will provide the Company with the means to meet the required coverage for
the new borrowing base by a combination of newly discovered reserves, proceeds
from strategic sales of non-essential properties, where appropriate, and/or the
infusion of third party capital in the form of sub-debt, all on or before July
29, 2003.
14
Currently, the Company has scheduled three and possibly four exploration wells
that can be drilled and logged prior to July 29, 2003, barring mechanical or
other issues out of the Company's control, such as permitting issues, weather or
equipment availability. The Company believes that these wells together have the
potential of adding reserves sufficient to remedy the borrowing base deficiency.
In addition, the Company has identified certain properties which are not
essential to its future growth and which it is in the process of marketing on a
limited basis. These include reserves of up to 100 BCFE and production of
approximately 50 mmcfe/d having an SEC PV10 value of over $281 million. It is
believed that a sale of all or a sufficient portion of these properties can be
achieved on or before July 29, 2003.
Further, the Company is in discussions with third parties regarding the infusion
of capital of up to $45-50 million in the form of subordinated debt. These
discussions are subject to certain due diligence verification of the reserves,
financial reported data and title examination as well as approval by the senior
lenders. If successful, the proceeds will be used to reduce the current
indebtedness of the senior credit facility as well as to fund capital
expenditures for calendar year 2003. Assuming positive results on both the due
diligence and of the terms and conditions of the facility by the senior lenders,
it is anticipated that this transaction could close on or before July 29, 2003.
There can be no assurances, however, additions to reserves, sufficient proceeds
from the sale of non-strategic oil and natural gas properties and new
subordinated debt or similar financing arrangements may be generated in
sufficient time to satisfy our funding obligations under both the Credit
Agreement and the subordinated debt agreement to permit an orderly reduction and
restructuring of our debt capital.
OIL AND NATURAL GAS HEDGING ACTIVITIES. The Company may address market risk by
selecting instruments whose value fluctuations correlate strongly with the
underlying commodity being hedged. The Company enters into swaps and other
derivative contracts to hedge the price risks associated with a portion of
anticipated future oil and gas production. These swaps allow the Company to
predict with greater certainty the effective oil and natural gas prices to be
received for our hedged production. Although derivatives often fail to achieve
100% effectiveness for accounting purposes, our derivative instruments continue
to be highly effective in achieving the risk management objectives for which
they were intended. While the use of hedging arrangements limits the downside
risk of adverse price movements, it may also limit future gains from favorable
movements. Under these agreements, payments are received or made based on the
differential between a fixed and a variable product price. These agreements are
settled in cash at or prior to expiration or exchanged for physical delivery
contracts. The Company does not obtain collateral to support the agreements, but
monitors the financial viability of counter-parties and believes its credit risk
is minimal on these transactions. In the event of nonperformance, the Company
would be exposed to price risk. The Company has some risk of accounting loss
since the price received for the product at the actual physical delivery point
may differ from the prevailing price at the delivery point required for
settlement of the hedging transaction.
These swaps have been designated as cash flow hedges as provided by FAS 133 and
any changes in fair value of the cash flow hedge resulting from ineffectiveness
of the hedge is reported in the consolidated statement of operations as
revenues.
CAPITAL EXPENDITURES. In the first quarter of 2003, Meridian's exploration
activities have been focused primarily in the Company's Biloxi Marshlands area.
We anticipate drilling and 3-D seismic activities in the Biloxi Marshlands
acreage will comprise the majority of our 2003 capital budget.
DIVIDENDS. It is our policy to retain existing cash for reinvestment in our
business, and therefore, we do not anticipate that dividends will be paid with
respect to the Common Stock in the foreseeable future. During
15
May 2002, the Company completed the private placement of $67 million of 8.5%
redeemable convertible preferred stock and dividends are payable semi-annually.
FORWARD-LOOKING INFORMATION
From time to time, we may make certain statements that contain "forward-looking"
information as defined in the Private Securities Litigation Reform Act of 1995
and that involve 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 and plans to sell properties, anticipated results from
third party disputes and litigation, expectations regarding future financing and
compliance with our 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 our filings with the Securities and
Exchange Commission under the Securities Act of 1933, as amended, and the
Securities Exchange Act of 1934, as amended.
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 prices we receive for our oil
and natural gas production and the level of such production are subject to wide
fluctuations and depend on numerous factors that we do 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 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 our forward-looking
statements.
Operating Risks. The occurrence of a significant event against which we are not
fully insured could have a material adverse effect on our financial position and
results of operations. Our 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, 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. In addition, we are subject
to other operating and production 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.
Although we maintain insurance coverage considered to be customary in the
industry, we are not fully insured against certain of these risks either because
such insurance is not available or because of high premium costs. We cannot
predict if or when any such risks could affect our operations. The occurrence of
a significant event for which we are not adequately insured could cause our
actual results to differ from those reflected in our forward-looking statements.
Drilling Risks. Our 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, we cannot assure you that
all of our drilling activities will be successful or that we will not drill
uneconomical wells. The occurrence of unexpected drilling results could cause
the actual results to differ from those reflected in our forward-looking
statements.
16
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 we cannot measure in an exact manner, and
the accuracy of any reserve estimate is a function of the quality of those
accumulations of data and of engineering and geological interpretation and
judgment. 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 we 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 our existing reserve estimates could cause the actual results to
differ from those reflected in our forward-looking statements.
Borrowing base for the Credit Facility. The Credit Agreement with Societe
Generale and Fortis Capital Corp. is presently scheduled for borrowing base
redetermination dates on a quarterly basis beginning April 30, 2003. The
borrowing base is redetermined on numerous factors including current reserve
estimates, reserves that have recently been added, current commodity prices,
current production rates and estimated future net cash flows. These factors have
associated risks with each of them. Significant reductions or increases in the
borrowing base will be determined by these factors, which, to a significant
extent, are not under the Company's control.
17
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.
INTEREST RATES
We are subject to interest rate risk on our long-term fixed interest rate debt
and variable interest rate borrowings. Our long-term borrowings primarily
consist of borrowings under the Credit Facility and principal due December 31,
2004 under our Subordinated Credit Agreement. Since interest charged borrowings
under the Credit Facility floats 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 $182.5 million remains borrowed under the Credit Facility
and the Subordinated Credit Agreement, we estimate our annual interest expense
will change by $1.825 million for each 100 basis point change in the applicable
interest rates utilized. 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 our current stock price as it relates
to the conversion price of $5.00 per share of our Common Stock.
HEDGING CONTRACTS
The Company may address market risk by selecting instruments whose value
fluctuations correlate strongly with the underlying commodity being hedged. The
Company enters into swaps and other derivative contracts to hedge the price
risks associated with a portion of anticipated future oil and gas production.
While the use of hedging arrangements limits the downside risk of adverse price
movements, it may also limit future gains from favorable movements. Under these
agreements, payments are received or made based on the differential between a
fixed and a variable product price. These agreements are settled in cash at or
prior to expiration or exchanged for physical delivery contracts. The Company
does not obtain collateral to support the agreements, but monitors the financial
viability of counter-parties and believes its credit risk is minimal on these
transactions. In the event of nonperformance, the Company would be exposed to
price risk. The Company has some risk of accounting loss since the price
received for the product at the actual physical delivery point may differ from
the prevailing price at the delivery point required for settlement of the
hedging transaction.
The Company's results of operations and operating cash flows are impacted by
changes in market prices for oil and natural gas. To mitigate a portion of the
exposure to adverse market changes, the Company has entered into various swap
agreements. These swaps allow the Company to predict with greater certainty the
effective oil and natural gas prices to be received for our hedged production.
Although derivatives often fail to achieve 100% effectiveness for accounting
purposes, our derivative instruments continue to be highly effective in
achieving the risk management objectives for which they were intended.
These swaps have been designated as cash flow hedges as provided by FAS 133 and
any changes in fair value of the cash flow hedge resulting from ineffectiveness
of the hedge is reported in the consolidated statement of operations as
revenues.
18
The estimated March 31, 2003, fair value of the Company's oil and natural gas
swaps is an unrealized loss of $10.5 million ($6.8 million net of tax)
recognized in other comprehensive income. Based upon March 31, 2003, oil and
natural gas commodity prices, approximately $7.2 million of the loss deferred in
other comprehensive income is expected to lower gross revenues over the next
twelve months when the revenues are generated. The swap agreements expire at
various dates through July 31, 2005.
Payments under these swap agreements reduced oil and natural gas revenues by
$7,105,000 for the three months ended March 31, 2003, as a result of hedging
transactions.
The Notional Amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 44% of our proved developed natural gas production and 70% of our
proved developed oil production. The fair values of the hedges are based on the
difference between the strike price and the New York Mercantile Exchange future
prices for the applicable trading months.
Weighted Average Fair Value (unrealized)
Notional Strike Price at March 31, 2003
Amount ($ per unit) (in thousands)
----------------- ---------------------- ---------------------------
Natural Gas (mmbtu)
April 2003 - June 2005 7,130,000 $ 3.78 $ 7,590
Oil (bbls)
April 2003 - July 2005 1,721,000 $ 24.22 $ 2,920
------------------
$ 10,510
------------------
ITEM 4. CONTROLS AND PROCEDURES
Within the 90-day period prior to the filing of this report, an evaluation was
conducted under the supervision and with the participation of Meridian's
management, including our Chief Executive Officer and Chief Financial Officer,
of the effectiveness of the design and operation of our disclosure controls and
procedures (as defined in Rule 13a-14(c) under the Securities Exchange Act of
1934). Based upon that evaluation, our Chief Executive Officer and Chief
Financial Officer concluded that the design and operation of our disclosure
controls and procedures are effective. There have been no significant changes in
our internal controls or in other factors that could significantly affect these
controls subsequent to the date of our evaluation.
19
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
On October 29, 2002, Veritas DGC Land Inc. ("Veritas Land") filed a complaint
against Meridian. The dispute concerns a contract for seismic services for
Meridian's Biloxi Marshlands project in St. Bernard Parish, Louisiana.
Purporting to invoke force majeure, Veritas Land, together with Veritas DGC Inc.
(collectively, "Veritas"), unilaterally terminated the parties' contract. The
main dispute is whether Veritas had breached the parties' contract before the
alleged force majeure events and/or when it terminated the contract; Meridian
has not made any payments to Veritas under the parties' contract. Veritas'
complaint seeks breach-of-contract damages of approximately $6.8 million
together with interest, costs and attorneys' fees.
On December 23, 2002, Meridian filed an answer denying the relief sought by
Veritas and asserting a counterclaim against Veritas (1) declaring that (i)
Meridian is not in breach of the parties' seismic contract, (ii) Meridian owes
no amounts to Veritas under the parties' seismic contract or otherwise, (iii)
Veritas materially breached the parties' contract, and (iv) Veritas Land is
solidarily liable to Meridian for all liability of Veritas DGC Inc., and (2)
seeking an award to Meridian of all attorneys' fees, court costs and other
expenses, amounts and damages incurred or suffered (or to be incurred or
suffered) by Meridian. On January 27, 2003, Veritas Land filed an answer to
Meridian's counterclaim, generally denying the counterclaim and asserting
various affirmative defenses thereto. Veritas DGC Inc. has not yet answered the
counterclaim.
No scheduling order has yet been issued. The parties have not yet issued
discovery to each other. Meridian intends to vigorously defend the claims
against it and to vigorously prosecute its counterclaim.
There are no other material legal proceedings to which Meridian or any of its
subsidiaries or partnerships is a party or to which any of its property is
subject, other than ordinary and routine litigation incidental to the business
of producing and exploring for crude oil and natural gas.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
99.1 Certification of Chief Executive Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
99.2 Certification of President pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
99.3 Certification of Chief Accounting Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
(b) The Company filed no reports on Form 8-K during the first quarter
of 2003.
20
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
(Registrant)
Date: May 15, 2003 By: LLOYD V. DELANO
------------------------------------
Lloyd V. DeLano
Senior Vice President
Chief Accounting Officer
21
CERTIFICATIONS
I, Joseph A. Reeves, Jr., certify that:
1. I have reviewed this quarterly report on Form 10-Q of The Meridian
Resource Corporation;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
22
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: May 15, 2003
/s/ Joseph A. Reeves, Jr.
-------------------------------------
Joseph A. Reeves, Jr.
Chief Executive Officer
23
CERTIFICATIONS
I, Michael J. Mayell, certify that:
1. I have reviewed this quarterly report on Form 10-Q of The Meridian
Resource Corporation;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
24
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: May 15, 2003
/s/ Michael J. Mayell
---------------------------------------
Michael J. Mayell
President
25
CERTIFICATIONS
I, Lloyd V. DeLano, certify that:
1. I have reviewed this quarterly report on Form 10-Q of The Meridian
Resource Corporation;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
26
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: May 15, 2003
/s/ Lloyd V. DeLano
-------------------------------------
Lloyd V. DeLano
Chief Accounting Officer
27
INDEX TO EXHIBIT
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
99.1 Certification of Chief Executive Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
99.2 Certification of President pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
99.3 Certification of Chief Accounting Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.