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: June 30, 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 August 6, 2003 50,204,101
Page 1 of 38
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 Six Months Ended June 30, 2003 and 2002 3
Consolidated Balance Sheets as of June 30, 2003 (unaudited)
and December 31, 2002 4
Consolidated Statements of Cash Flows (unaudited) for the
Six Months Ended June 30, 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 14
Item 3. Quantitative and Qualitative Disclosures about Market Risk 25
Item 4. Controls and Procedures 26
PART II - OTHER INFORMATION
Item 1. Legal Proceedings 27
Item 6. Exhibits and Reports on Form 8-K 27
SIGNATURES 28
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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------------- --------------------------
REVENUES: 2003 2002 2003 2002
----------- ----------- ---------- -----------
Oil and natural gas $ 29,603 $ 31,661 $ 58,590 $ 56,270
Price risk management activities -- 670 -- (135)
Interest and other 51 142 89 186
----------- ----------- ---------- -----------
29,654 32,473 58,679 56,321
----------- ----------- ---------- -----------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 2,803 3,013 5,287 6,102
Severance and ad valorem taxes 1,548 2,400 3,367 5,117
Depletion and depreciation 15,187 13,558 29,842 26,919
Accretion expense 128 -- 256 --
General and administrative 2,972 2,984 5,782 6,242
----------- ----------- ---------- -----------
22,638 21,955 44,534 44,380
----------- ----------- ---------- -----------
EARNINGS BEFORE INTEREST AND INCOME TAXES 7,016 10,518 14,145 11,941
----------- ----------- ---------- -----------
OTHER EXPENSES:
Interest expense 3,611 3,744 6,229 7,644
----------- ----------- ---------- -----------
EARNINGS (LOSS) BEFORE INCOME TAXES 3,405 6,774 7,916 4,297
----------- ----------- ---------- -----------
INCOME TAXES
Current -- 100 -- 100
Deferred -- 2,400 -- 1,500
----------- ----------- ---------- -----------
-- 2,500 -- 1,600
----------- ----------- ---------- -----------
NET EARNINGS (LOSS) BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 3,405 4,274 7,916 2,697
Cumulative effect of change in accounting principle -- -- (1,309) --
----------- ----------- ---------- -----------
NET EARNINGS (LOSS) 3,405 4,274 6,607 2,697
Dividends on preferred stock 1,481 1,102 2,962 1,102
----------- ----------- ---------- -----------
NET EARNINGS (LOSS) APPLICABLE
TO COMMON STOCKHOLDERS $ 1,924 $ 3,172 $ 3,645 $ 1,595
=========== =========== ========== ===========
NET EARNINGS (LOSS) PER SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE
Basic and Diluted $ 0.04 $ 0.06 $ 0.10 $ 0.03
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
ACCOUNTING PRINCIPLE PER SHARE:
Basic and Diluted $ -- $ -- $ (0.03) $ --
----------- ----------- ---------- -----------
NET EARNINGS (LOSS) PER SHARE:
Basic and Diluted $ 0.04 $ 0.06 $ 0.07 $ 0.03
=========== =========== ========== ===========
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic and Diluted 50,163 49,916 50,126 49,551
=========== =========== ========== ===========
See notes to consolidated financial statements.
3
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
JUNE 30, DECEMBER 31,
2003 2002
------------ ------------
(unaudited)
ASSETS
------
CURRENT ASSETS:
Cash and cash equivalents $ 10,132 $ 7,287
Accounts receivable, less allowance
for doubtful accounts
$833 [2003 and 2002] 28,832 24,167
Due from affiliates 1,029 1,557
Prepaid expenses and other 3,464 2,221
Assets from price risk management activities 2,030 604
------------- ------------
Total current assets 45,487 35,836
------------- ------------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including
$22,581 [2003] and $18,993 [2002] not
subject to depletion) 1,197,230 1,162,436
Land 478 478
Equipment 9,964 9,913
------------- ------------
1,207,672 1,172,827
Less accumulated depletion and depreciation 791,696 761,854
------------- ------------
Total property and equipment, net 415,976 410,973
------------- ------------
OTHER ASSETS:
Assets from price risk management activities 145 292
Deferred tax asset 4,415 2,560
Other 5,568 6,579
------------- ------------
Total other assets 10,128 9,431
------------- ------------
Total assets $ 471,591 $ 456,240
============= ============
See notes to consolidated financial statements.
4
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
JUNE 30, DECEMBER 31,
2003 2002
------------ ------------
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 14,613 $ 16,842
Revenues and royalties payable 14,426 12,378
Notes payable 1,084 831
Accrued liabilities 11,370 9,958
Liabilities from price risk management activities 10,961 6,781
Current income taxes payable 931 931
Current portion long-term debt 34,000 35,250
------------ ------------
Total current liabilities 87,385 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 3,827 1,686
Abandonment costs 4,779 --
------------ ------------
8,606 1,686
REDEEMABLE PREFERRED STOCK:
Preferred stock, $1.00 par value (1,500,000 shares authorized,
726,500 [2003] and 696,900 [2002] shares of Series C
Redeemable Convertible Preferred Stock issued at stated value) 72,650 69,690
------------ ------------
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized,
53,868,343 [2003 and 2002] issued) 564 557
Additional paid-in capital 378,262 378,215
Accumulated deficit (206,093) (209,738)
Accumulated other comprehensive loss (8,383) (4,938)
Unamortized deferred compensation (311) (356)
------------ ------------
164,039 163,740
Less treasury stock, at cost (3,684,741 shares [2003] and
3,779,225 [2002] shares) 29,589 30,347
------------ ------------
Total stockholders' equity 134,450 133,393
------------ ------------
Total liabilities and stockholders' equity $ 471,591 $ 456,240
============ ============
See notes to consolidated financial statements.
5
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
(unaudited)
SIX MONTHS ENDED
JUNE 30,
----------------------------------
2003 2002
------------- -------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $ 6,607 $ 2,697
Adjustments to reconcile net earnings to net cash
provided by operating activities:
Cumulative effect of change in accounting principle 1,309 --
Depletion and depreciation 29,842 26,919
Amortization of other assets 1,137 1,092
Non-cash compensation 676 827
Non-cash price risk management activities -- 135
Accretion expense 256 --
Deferred income taxes -- 1,500
Changes in assets and liabilities:
Accounts receivable (4,665) (3,876)
Due from affiliates 528 (1,593)
Prepaid expenses and other (1,243) (1,643)
Accounts payable (2,229) (29,882)
Revenues and royalties payable 2,048 587
Accrued liabilities and other 1,153 (6,266)
------------- ------------
Net cash provided by (used in) operating activities 35,419 (9,503)
------------- ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (31,669) (29,656)
Sale of property and equipment 39 548
------------- ------------
Net cash used in investing activities (31,630) (29,108)
------------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Redeemable preferred stock -- 66,850
Reductions in long-term debt (1,250) (20,000)
Proceeds from notes payable 1,439 1,307
Reductions in notes payable (1,187) (763)
Issuance of stock/exercise of options 180 122
Preferred dividends -- --
Additions to deferred loan costs (126) (4,181)
------------- ------------
Net cash provided by (used in) financing activities (944) 43,335
------------- ------------
NET CHANGE IN CASH AND CASH EQUIVALENTS 2,845 4,724
Cash and cash equivalents at beginning of period 7,287 14,340
------------- ------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 10,132 $ 19,064
============= ============
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 June 30, 2003, and for the three
and six month periods ended June 30, 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. Certain minor
reclassifications of prior period statements have been made to conform to
current reporting practices.
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. Borrowings under the Credit
Agreement mature on August 13, 2005. The initial borrowing base under the
existing Credit Agreement was established on September 23, 2002, at $165
million, with the first borrowing base redetermination date scheduled for
November 30, 2002. The parties to the Credit Agreement 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, with quarterly redetermination thereafter.
On March 31, 2003, the Company received notice from its senior lenders that
effective April 30, 2003, the borrowing base was 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 was required to make up the
deficiency through the addition of reserves or value to its current reserve base
or pay the senior lenders the noticed deficiency within 90 days of the effective
date of April 30, 2003. On July 29, 2003, the lenders consented to an extension
until September 12, 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 or borrower, under the Credit Agreement, have the right to redetermine
the borrowing base at any time 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 under certain circumstances Preferred 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
7
default as a result of the independent auditors' report which contained a "going
concern" modification for our 2002 consolidated financial statements.
Under the 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 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, bringing the outstanding
balance to $17.5 million. 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 with the terms of this agreement.
8
3. EARNINGS PER SHARE (in thousands, except per share)
The following tables set forth the computation of basic and diluted net earnings
per share:
THREE MONTHS ENDED JUNE 30,
2003 2002
-------------- --------------
Numerator:
Net earnings applicable to common stockholders $ 1,924 $ 3,172
Plus income impact of assumed conversions:
Preferred stock dividends 1,481 1,102
Interest on convertible subordinated notes 309 309
-------------- --------------
Net earnings applicable to common stockholders
plus assumed conversions $ 3,714 $ 4,583
-------------- --------------
Denominator:
Denominator for basic net earnings per
share - weighted-average shares outstanding 50,163 49,916
Effect of potentially dilutive common shares:
Redeemable preferred stock N/A N/A
Convertible subordinated notes N/A N/A
Employee and director stock options N/A N/A
Warrants N/A N/A
-------------- --------------
Denominator for diluted net earnings per
share - weighted-average shares outstanding
and assumed conversions 50,163 49,916
============== ==============
Basic net earnings per share $ 0.04 $ 0.06
============== ==============
Diluted net earnings per share $ 0.04 $ 0.06
============== ==============
SIX MONTHS ENDED JUNE 30,
2003 2002
-------------- --------------
Numerator:
Net earnings applicable to common stockholders $ 3,645 $ 1,595
Plus income impact of assumed conversions:
Preferred stock dividends 2,962 1,102
Interest on convertible subordinated notes 618 618
-------------- --------------
Net earnings applicable to common stockholders
plus assumed conversions $ 7,225 $ 3,315
-------------- --------------
Denominator:
Denominator for basic net earnings per
share - weighted-average shares outstanding 50,126 49,551
Effect of potentially dilutive common shares:
Redeemable preferred stock N/A N/A
Convertible subordinated notes N/A N/A
Employee and director stock options N/A N/A
Warrants N/A N/A
-------------- --------------
Denominator for diluted net earnings per
share - weighted-average shares outstanding
and assumed conversions 50,126 49,551
============== ==============
Basic net earnings per share $ 0.07 $ 0.03
============== ==============
Diluted net earnings per share $ 0.07 $ 0.03
============== ==============
9
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 Statement of
Financial Accounting Standards (SFAS) No. 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 June 30, 2003, fair value of the Company's oil and natural gas
swaps is an unrealized loss of $12.6 million ($8.2 million net of tax)
recognized in other comprehensive income. Based upon June 30, 2003, oil and
natural gas commodity prices, approximately $8.9 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
$3,026,000 for the three months and $10,131,000 for the six months ended June
30, 2003, as a result of hedging transactions.
The notional amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 19% of our proved developed natural gas production and 74% of our
proved developed oil production. The fair values of the hedges are based on the
difference between the strike price and the New York Mercantile Exchange future
prices for the applicable trading months.
Weighted Average Fair Value (unrealized)
Notional Strike Price at June 30, 2003
Amount ($ per unit) (in thousands)
--------- ------------------- ----------------------
Natural Gas (mmbtu)
July 2003 - June 2005 5,820,000 $ 3.77 $ 8,754
Oil (bbls)
July 2003 - July 2005 1,451,000 $ 24.04 $ 3,859
---------------------
---------------------
$ 12,613
---------------------
10
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 three month and six month periods ended
June 30, 2003 and 2002, related to restricted stock awards totaled $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. (In thousands, except per share data.)
Three Months Ended June 30,
--------------------------------
2003 2002
-------------- -------------
Net earnings (loss) applicable to common stockholders as reported ($000) $ 1,924 $ 3,172
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) $ 1,914 $ 3,162
Basic earnings (loss) per share:
As reported $ 0.04 $ 0.06
Pro forma $ 0.04 $ 0.06
Diluted earnings (loss) per share:
As reported $ 0.04 $ 0.06
Pro forma $ 0.04 $ 0.06
Six Months Ended June 30,
--------------------------------
2003 2002
-------------- -------------
Net earnings (loss) applicable to common stockholders as reported ($000) $ 3,645 $ 1,595
Stock-based compensation expense determined
under fair value method for all awards, net of tax ($000) 20 20
Net earnings (loss) applicable to common stockholders pro forma ($000) $ 3,625 $ 1,575
Basic earnings (loss) per share:
As reported $ 0.07 $ 0.03
Pro forma $ 0.07 $ 0.03
Diluted earnings (loss) per share:
As reported $ 0.07 $ 0.03
Pro forma $ 0.07 $ 0.03
11
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 $256 thousand in the first six months of 2003.
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 June 30, Six Months Ended June 30,
------------------------------- -------------------------------
2003 2002 2003 2002
-------------- ------------- ------------ --------------
Net earnings (loss) as reported $ 3,405 $ 4,274 $ 6,607 $ 2,697
Additional accretion expense -- (117) -- (234)
Cumulative effect of accounting change -- -- 1,309 --
-------------- ------------- ------------ --------------
Pro forma net earnings (loss) $ 3,405 $ 4,157 $ 7,916 $ 2,463
Pro forma net earnings (loss) per share $ 0.04 $ 0.06 $ 0.10 $ 0.03
The following table describes the change in the Company's asset retirement
obligations for the period ended June 30, 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 256
-----------------
Asset retirement obligation at June 30, 2003 $ 4,779
7. NEW ACCOUNTING PRONOUNCEMENT
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No. 51". Interpretation No. 46 requires a company to consolidate a variable
interest entity ("VIE") if the company has variable interest that is exposed to
a majority of the entity's expected losses if they occur, receive a majority of
the entity's expected residual returns if they occur, or both. In addition, more
extensive disclosure requirements apply to the primary and other significant
variable owners of the VIE. This interpretation applies immediately to VIEs
created after January 31, 2003, and to VIEs in which an enterprise obtains an
interest after that date. It is also effective for the first fiscal year
12
or interim period beginning after June 15, 2003, to VIEs in which a company
holds a variable interest that is acquired before February 1, 2003. The guidance
regarding this interpretation is extremely complex and, although we do not
believe we have an interest in a VIE, the Company continues to assess the
impact, if any, this interpretation will have on the Company's consolidated
financial statements.
13
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 and six months ended June 30, 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 six months 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 second quarter of 2003, capital expenditures were focused primarily
in our Biloxi Marshland play. The Company continued to increase its near term
daily production rates by completing and placing on production two additional
wells, the Biloxi Marshlands No. 6-2 and No. 7-1 wells. In early August, the
Biloxi Marshlands No. 1-2 well was placed on production. With the addition of
these three new wells, the Biloxi Marshlands project area has produced at rates
as high as approximately 74 MMCF/D (44 MMCF/D net). However, this rate is
dependent on the transporting pipeline's operating pressure, which is subject to
fluctuations. Drilling operations are currently being conducted on the Company's
Biloxi Marshlands No. 18-1 well which is drilling at approximately 9,300 feet.
Other activities during the second quarter of 2003 included the acquisition of
187 square miles of 3-D seismic data adjacent to and south and east of the
recent well activity announced by the Company. It is anticipated that this new
3-D seismic data will form the basis of new project in this area.
Although the Company has identified as many as 5-7 prospective drilling
opportunities in its Biloxi Marshland project area, future wells in this area
during 2003 beyond the Biloxi Marshlands No. 18-1 well will depend on budget
availability, permitting, leasing and access issues as well as the results and
timing of completing the acquisition, processing and interpretation of the new
3-D seismic data currently being acquired.
In addition to the activities in the Biloxi Marshlands project area, the Company
has recently logged Ship Shoal prospect which was spudded in early July 2003.
Meridian owns a 43% working interest. The well tested the Lower Pleistocene
sands at approximately 13,000 feet but was found to be noncommercial and is
presently being plugged and abandoned by the operator. Net cost to Meridian was
approximately $2 million.
Two significant workover and recompletions have been completed during 2003. The
Avoca No. 47-1 well was placed back on production during May at a rate of 8
MMCFE/D. In addition, the Thibodaux No. 1 well was returned to production during
July at a rate of 19 MMCFE/D. Collectively a net addition to Meridian of
approximately 14 MMCFE/D, replacing production that was offstream during most of
the second quarter of 2003.
14
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 June 30, 2003,
was $25.19 per barrel compared to $24.99 per barrel for the three months ended
June 30, 2002, and $25.15 per barrel for the three months ended March 31, 2003.
Our average oil price for the six months ended June 30, 2003, was $25.17 per
barrel compared to $22.80 per barrel for the six months ended June 30, 2002. Our
average natural gas price (after adjustments for hedging activities) for the
three months ended June 30, 2003, was $5.39 per Mcf compared to $3.69 per Mcf
for the three months ended June 30, 2002, and $5.82 per Mcf for the three months
ended March 31, 2003. Our average natural gas price for the six months ended
June 30, 2003, was $5.59 per Mcf compared to $3.08 per Mcf for the six months
ended June 30, 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.
15
RESULTS OF OPERATIONS
THREE MONTHS ENDED JUNE 30, 2003 COMPARED TO THREE MONTHS ENDED JUNE 30, 2002
OPERATING REVENUES. Second quarter 2003 oil and natural gas revenues decreased
$2.1 million as compared to second quarter 2002 revenues, due to a 26% decrease
in production volumes caused primarily from wells either being off production
temporarily or impacted by mechanical issues. This was partially offset by a 27%
increase in average commodity prices on a natural gas equivalent basis. The
decrease in production was primarily a result of the Avoca 47-1 and Thibodaux
No. 1 wells being out of production during the quarter, two Weeks Island wells
encountering extraneous water production, which the Company is addressing with
offset wells and natural production declines, primarily in the Thornwell, Gibson
Humphries and Turtle Bayou fields. These reductions in production were partially
offset by new production from the Biloxi Marshlands project area. Additional
recoveries of production are expected from operations such as those conducted on
the Avoca 47-1 and the Thibodaux No. 1 wells. It is expected that similar
recoveries will occur as we conduct the operations in the Weeks Island field
within the next 6-10 months. However, as always, there can be no assurances that
other operations will be successful.
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the three months ended June 30, 2003 and
2002:
THREE MONTHS ENDED
JUNE 30, INCREASE
2003 2002 (DECREASE)
---- ---- ----------
Production Volumes:
Oil (Mbbl) 347 631 (45%)
Natural gas (MMcf) 3,869 4,304 (10%)
Mmcfe 5,951 8,089 (26%)
Average Sales Prices:
Oil (per Bbl) $ 25.19 $ 24.99 1%
Natural gas (per Mcf) $ 5.39 $ 3.69 46%
Mmcfe $ 4.97 $ 3.91 27%
Operating Revenues (000's):
Oil $ 8,742 $15,768 (45%)
Natural gas 20,861 15,893 31%
------- -------
Total Operating Revenues $29,603 $31,661 (7%)
OPERATING EXPENSES. Oil and natural gas operating expenses decreased $0.2
million (7%) to $2.8 million for the three months ended June 30, 2003, compared
to $3.0 million for the same period in 2002. This decrease primarily resulted
from reorganization of field operations enabling the Company to reduce labor and
other field related costs. This area of cost controls is a continuing focus of
the Company.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes decreased $0.9
million (36%) to $1.5 million for the second quarter of 2003, compared to $2.4
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 $1.6
million (12%) during the second quarter of 2003 to $15.2 million from $13.6
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.
16
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense was
reported as $3.0 million for the three month periods ended June 30, 2003 and
2002, respectively. As previously announced, during the first quarter of 2003,
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. Although the full impact of
these reductions has not been recognized because of the severance packages that
continued through this and future quarters it is anticipated that these changes
will result in future savings in costs without sacrificing the Company's
exploration efforts or opportunities. To date, it is anticipated that the
changes have reduced salaries by approximately 25%.
INTEREST EXPENSE. Interest expense decreased $0.1 million (4%) to $3.6 million
for the second quarter of 2003 in comparison to the second 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, partially offset by a recent lead bank calculation adjustment of $0.9
million to the rate used for the credit facility.
17
SIX MONTHS ENDED JUNE 30, 2003, COMPARED TO SIX MONTHS ENDED JUNE 30, 2002
OPERATING REVENUES. Oil and natural gas revenues during the six months ended
June 30, 2003, increased $2.3 million as compared to revenues during the six
months ended June 30, 2002, due to average sales prices increasing 48% partially
offset by a decrease in production volumes of 30%, both on a natural gas
equivalent basis. The production decrease is primarily a result of the Avoca
47-1 and Thibodaux No. 1 wells being out of production during a portion of the
2003 period and of natural production declines, partially offset by new wells
brought on during 2003, the full impact of which will not be fully realized
until mid-third quarter 2003.
The following table summarizes production volumes, average sales prices and
gross revenues for the six months ended June 30, 2003 and 2002.
SIX MONTHS ENDED
JUNE 30, INCREASE
2003 2002 (DECREASE)
---- ---- ----------
Production Volumes:
Oil (Mbbl) 744 1,264 (41%)
Natural gas (MMcf) 7,132 8,900 (20%)
Mmcfe 11,597 16,484 (30%)
Average Sales Prices:
Oil (Bbl) $ 25.17 $ 22.80 10%
Natural gas (Mcf) $ 5.59 $ 3.08 81%
MMcfe $ 5.05 $ 3.41 48%
Gross Revenues (000's):
Oil $ 18,727 $ 28,822 (35%)
Natural gas 39,863 27,448 45%
-------- -------
Total $ 58,590 $ 56,270 4%
OPERATING EXPENSES. Oil and natural gas operating expenses decreased $0.8
million (13%) to $5.3 million for the six months ended June 30, 2003, compared
to $6.1 million for the six months ended June 30, 2002. This decrease was
primarily due to a reorganization involving a reduction in labor costs and
increased emphasis in operating cost reductions. This area of cost controls is a
continuing focus of the Company.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes decreased $1.7
million (34%) to $3.4 million for the six months ended June 30, 2003, compared
to $5.1 million for the six months ended June 30, 2002. This decrease is largely
attributable to the decrease in production, the decrease in oil revenues from
the same period in 2002 and a decrease in the tax rate for natural gas.
Meridian's production is primarily from southern Louisiana, and, therefore, is
subject to a current tax rate of 12.5% of gross oil revenues and $0.122 per Mcf
for natural gas. The tax rate for natural gas for the first half of 2002 was
$0.199 per Mcf.
18
DEPLETION AND DEPRECIATION. Depletion and depreciation expense increased $2.9
million (11%) to $29.8 million during the first six months of 2003 from $26.9
million for the same period last year. This increase was primarily a result of
increased depletion rate from 2002 levels, partially offset by the 30% decrease
in production on an Mcfe basis from the comparable period in 2002.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense decreased
$0.4 million (7%) to $5.8 million for the first six months of 2003 compared to
$6.2 million during the first six months of 2002. This reduction is partially
due to a reduction in professional and technical services during 2003 as
compared to 2002 levels. As previously announced, during the first quarter of
2003 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. Although the
full impact of these reductions has not been recognized due to the severance
packages included, it is anticipated that these changes will result in future
savings in costs without sacrificing the Company's exploration efforts or
opportunities.
INTEREST EXPENSE. Interest expense decreased $1.4 million (19%) to $6.2 million
during the first six months of 2003 compared to $7.6 million during the
comparable period of 2002. The decrease is primarily a result of the reduction
in debt and the Federal Reserve Bank's decrease in overall interest rates which
has led to a decrease in the average interest rate on the credit facility.
19
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. During the second quarter of 2003, Meridian's capital
expenditures were internally financed with cash from operations. As of June 30,
2003, we had a cash balance of $10.1 million and a working capital deficit of
$41.9 million. This deficit was made up primarily of $34 million of current
maturities of long-term debt, and a $8.9 million net current liability
associated with 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 was 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 was 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. On July 29, 2003, the lenders consented to a 45 day extension
of the deadline until September 12, 2003, enabling additional time for all
parties to consider the various means by which the Company may achieve
compliance and remove the borrowing base deficiency. As a result of the recent
discoveries, additions to reserves and production, and anticipated additional
cash flows, it is management's intent to use excess cash flow to reduce the
total debt position without compromising its capital expenditures currently
scheduled for its growth. 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 year ended December 31, 2002. Other than the borrowing base as
calculated solely by the lender, the Company is in compliance with all financial
ratios and loan covenants. 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.
20
Under the 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 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, the agent bank, Societe Generale, noticed to the Company that it
believes there is a $26.5 million borrowing base deficiency at April 30, 2003
that was to 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 may also be subject to deferral for any borrowing base
deficiencies that may exist at that time. The total amounts noticed as due or
$34 million due under these agreements represents a significant component of our
$41.9 million working capital deficiency at June 30, 2003.
In conjunction with the amendment to the Credit Agreement of March 31, 2003, the
lenders permitted the Company to continue its capital expenditure program as
scheduled. As a result, although significant new reserves have been recently
added to the Company's reserves, the Company has paid only $2.5 million toward
the reduction of its credit facility. To this end we have obtained a 45 day
extension from our bank group to allow for a sufficient amount of time to
negotiate a modification to our credit facility. Although we can make no
assurances that we can successfully reach an agreement, we anticipate that the
modification will take the form of an amortization schedule over a specified
time period. We do not expect these monthly payments to impede our anticipated
$30 to $35 million of capital expenditures for the remainder of the year.
Further, the Company continues to discuss with third parties the infusion of
capital in the form of subordinated debt, equity or a combination of both.
Although we can make no assurances as to when or in what amounts, if any, that
third parties may agree to make any such investments on terms reasonably
satisfactory to us, if we obtain such capital, the proceeds would be used
primarily to reduce the current indebtedness of the senior credit facility as
well as to fund capital expenditures for calendar year 2003.
Although there can be no assurances, 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.
21
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 SFAS 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 second quarter of 2003, Meridian's exploration
activities have been focused primarily in the Company's Biloxi Marshlands
acreage. As a result of the low-risk nature of this play and its confirmation
with the recent drilling successes, we anticipate the drilling and 3-D seismic
activities in the Biloxi Marshlands area will comprise the majority of our 2003
capital budget. We expect to spend approximately $30 to $35 million in capital
expenditures during the last six months of the year.
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 May 2002, the
Company completed the private placement of $67 million of 8.5% redeemable
convertible preferred stock and dividends are payable semi-annually. Under the
terms of the Credit Agreement, dividend payments required during 2003 on the
preferred stock have been paid-in-kind through our issuance of additional
preferred stock.
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.
22
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.
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.
23
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 but largely dependent solely on the
discretion of its lenders.
24
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 SFAS 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.
The estimated June 30, 2003, fair value of the Company's oil and natural gas
swaps is an unrealized loss of $12.6 million ($8.2 million net of tax)
recognized in other comprehensive income. Based upon June 30, 2003, oil and
natural gas commodity prices, approximately $8.9 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.
25
Payments under these swap agreements reduced oil and natural gas revenues by
$3,026,000 for the three months and $10,131,000 for the six months ended June
30, 2003, as a result of hedging transactions.
The notional amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 19% of our proved developed natural gas production and 74% of our
proved developed oil production. The fair values of the hedges are based on the
difference between the strike price and the New York Mercantile Exchange future
prices for the applicable trading months.
Weighted Average Fair Value (unrealized)
Notional Strike Price at June 30, 2003
Amount ($ per unit) (in thousands)
----------------- ---------------------- ---------------------------
Natural Gas (mmbtu)
July 2003 - June 2005 5,820,000 $ 3.77 $ 8,754
Oil (bbls)
July 2003 - July 2005 1,451,000 $ 24.04 $ 3,859
---------------------
$ 12,613
---------------------
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 Accounting 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
Accounting 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.
26
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
31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or
Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.
31.2 Certification of President pursuant to Rule 13a-14(a) or Rule 15d-14(a)
under the Securities Exchange Act of 1934, as amended.
31.3 Certification of Chief Accounting Officer pursuant to Rule 13a-14(a) or
Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.
32.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(b) or
Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended,
and 18 U.S.C. Section 1350.
32.2 Certification of President pursuant to Rule 13a-14(b) or Rule 15d-14(b)
under the Securities Exchange Act of 1934, as amended, and 18 U.S.C.
Section 1350.
32.3 Certification of Chief Accounting Officer pursuant Rule 13a-14(b) or
Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended,
and 18 U.S.C. Section 1350.
(b) The Company filed no reports on Form 8-K during the second quarter
of 2003.
27
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: August 14, 2003 By: /s/ LLOYD V. DELANO
------------------------------
Lloyd V. DeLano
Senior Vice President
Chief Accounting Officer
28
INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
31.1 Certification of Chief Executive Officer pursuant to Rule
13a-14(a) or Rule 15d-14(a) under the Securities Exchange
Act of 1934, as amended.
31.2 Certification of President pursuant to Rule 13a-14(a) or
Rule 15d-14(a) under the Securities Exchange Act of 1934, as
amended.
31.3 Certification of Chief Accounting Officer pursuant to Rule
13a-14(a) or Rule 15d-14(a) under the Securities Exchange
Act of 1934, as amended.
32.1 Certification of Chief Executive Officer pursuant to Rule
13a-14(b) or Rule 15d-14(b) under the Securities Exchange
Act of 1934, as amended, and 18 U.S.C. Section 1350.
32.2 Certification of President pursuant to Rule 13a-14(b) or
Rule 15d-14(b) under the Securities Exchange Act of 1934, as
amended, and 18 U.S.C. Section 1350.
32.3 Certification of Chief Accounting Officer pursuant Rule
13a-14(b) or Rule 15d-14(b) under the Securities Exchange
Act of 1934, as amended, and 18 U.S.C. Section 1350.
29