Page 1 of 1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended: June 30, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________________ to _________________
Commission file number: 1-10671
THE MERIDIAN RESOURCE CORPORATION
(Exact name of registrant as specified in its charter)
TEXAS 76-0319553
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1401 ENCLAVE PARKWAY, SUITE 300, HOUSTON, TEXAS 77077
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 281-597-7000
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 and 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
Number of shares of common stock outstanding at August 9, 2002 49,945,068
Page 1 of 23
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, 2002 and 2001 3
Consolidated Balance Sheets as of June 30, 2002 (unaudited)
and December 31, 2001 4
Consolidated Statements of Cash Flows (unaudited) for the
Six Months Ended June 30, 2002 and 2001 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 20
PART II - OTHER INFORMATION
Item 1. Legal Proceedings 21
Item 6. Exhibits and Reports on Form 8-K 21
SIGNATURES 22
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,
-------- --------
2002 2001 2002 2001
---- ---- ---- ----
REVENUES:
Oil and natural gas $ 31,661 $ 45,701 $ 56,270 $ 115,035
Price risk management activities 670 -- (135) --
Interest and other 142 325 186 1,060
--------- --------- --------- ---------
32,473 46,026 56,321 116,095
--------- --------- --------- ---------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 3,013 4,408 6,102 9,220
Severance and ad valorem taxes 2,400 2,625 5,117 6,300
Depletion and depreciation 13,558 16,562 26,919 33,748
General and administrative 2,984 4,391 6,242 9,372
--------- --------- --------- ---------
21,955 27,986 44,380 58,640
--------- --------- --------- ---------
EARNINGS BEFORE INTEREST
AND INCOME TAXES 10,518 18,040 11,941 57,455
OTHER EXPENSES:
Interest expense 3,744 5,449 7,644 11,867
Taxes on income - current 100 900 100 3,200
Taxes on income - deferred 2,400 4,000 1,500 14,600
--------- --------- --------- ---------
6,244 10,349 9,244 29,667
--------- --------- --------- ---------
NET EARNINGS 4,274 7,691 2,697 27,788
DIVIDENDS ON PREFERRED STOCK 1,102 -- 1,102 429
--------- --------- --------- ---------
NET EARNINGS APPLICABLE
TO COMMON STOCKHOLDERS $ 3,172 $ 7,691 $ 1,595 $ 27,359
========= ========= ========= =========
NET EARNINGS PER SHARE:
Basic $ 0.06 $ 0.16 $ 0.03 $ 0.56
========= ========= ========= =========
Diluted $ 0.06 $ 0.15 $ 0.03 $ 0.49
========= ========= ========= =========
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES:
Basic 49,916 47,872 49,551 48,781
========= ========= ========= =========
Diluted 49,916 55,038 49,551 57,943
========= ========= ========= =========
See notes to consolidated financial statements.
3
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
(unaudited)
JUNE 30, DECEMBER 31,
2002 2001
---- ----
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 19,064 $ 14,340
Accounts receivable, less allowance for doubtful
accounts $891 [2002 and 2001] 27,751 23,875
Due from affiliates 2,437 844
Prepaid expenses and other 3,468 1,825
---------- ----------
Total current assets 52,720 40,884
---------- ----------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method
(including $30,236 [2002] and
$30,247 [2001] not subject to depletion) 1,114,625 1,085,656
Land 478 478
Equipment 9,717 9,578
---------- ----------
1,124,820 1,095,712
Accumulated depletion and depreciation 658,677 631,758
---------- ----------
466,143 463,954
---------- ----------
OTHER ASSETS 5,917 2,828
---------- ----------
$ 524,780 $ 507,666
========== ==========
See notes to consolidated financial statements.
4
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
(unaudited)
JUNE 30, DECEMBER 31,
2002 2001
---- ----
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 6,070 $ 35,952
Revenues and royalties payable 10,149 9,562
Notes payable 1,307 25,763
Accrued liabilities 10,431 15,895
Oil and natural gas hedging derivatives 135 --
Current income taxes payable 273 (27)
Current portion long-term debt 27,000 --
--------- ---------
Total current liabilities 55,365 87,145
--------- ---------
LONG-TERM DEBT 168,000 190,000
--------- ---------
9 1/2% CONVERTIBLE SUBORDINATED NOTES 20,000 20,000
--------- ---------
DEFERRED INCOME TAXES 23,800 22,300
--------- ---------
REDEEMABLE PREFERRED STOCK:
Preferred stock, $1.00 par value (1,500,000 shares authorized, 668,500
[2002] shares of Series C Redeemable Convertible Preferred Stock
issued at stated value) 66,850 --
--------- ---------
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares
authorized, 53,866,694 [2002] and [2001] issued) 555 553
Additional paid-in capital 378,410 393,280
Accumulated deficit (156,131) (157,726)
Unrealized loss on securities held for resale (185) (185)
Unamortized deferred compensation (380) (386)
--------- ---------
222,269 235,536
Less treasury stock, at cost (3,923,273 [2002] and
5,892,342 [2001] shares) 31,504 47,315
--------- ---------
Total stockholders' equity 190,765 188,221
--------- ---------
$ 524,780 $ 507,666
========= =========
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,
--------
2002 2001
---- ----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $ 2,697 $ 27,788
Adjustments to reconcile net earnings to net cash
provided by operating activities:
Depletion and depreciation 26,919 33,748
Amortization of other assets 1,092 1,030
Non-cash compensation 827 1,010
Non-cash price risk management activities 135 --
Deferred income taxes 1,500 14,600
Changes in assets and liabilities:
Accounts receivable (3,876) 7,012
Due from affiliates (1,593) (1,842)
Prepaid expenses and other (1,643) (3,770)
Accounts payable (29,882) 5,721
Revenues and royalties payable 587 2,672
Accrued liabilities and other (6,266) 5,441
--------- ---------
Net cash provided by (used in) operating activities (9,503) 93,410
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (29,656) (67,342)
Sale of property and equipment 548 29,817
--------- ---------
Net cash used in investing activities (29,108) (37,525)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Redeemable preferred stock 66,850 --
Reductions in long-term debt (20,000) (40,000)
Notes payable 544 26,848
Repurchase of stock -- (114,000)
Issuance of stock/exercise of options 122 455
Preferred dividends -- (3,129)
Additions to deferred loan costs (4,181) (508)
--------- ---------
Net cash provided by (used in) financing activities 43,335 (130,334)
--------- ---------
NET CHANGE IN CASH AND CASH EQUIVALENTS 4,724 (74,449)
Cash and cash equivalents at beginning of period 14,340 95,122
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 19,064 $ 20,673
========= =========
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, 2001, as filed with the Securities and Exchange Commission.
The financial statements included herein as of June 30, 2002, and for the three
and six month periods ended June 30, 2002 and 2001, 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
SUBORDINATED CREDIT AGREEMENT
The Company extended and amended the short-term subordinated credit agreement
with Fortis Capital Corporation for $25 million on April 5, 2002. 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 September 30, 2002, December 31, 2002, August 31,
2003 and April 30, 2004, with the remaining $5 million payable on December 31,
2004.
CREDIT FACILITY
In May 1998, the Company amended and restated its credit facility with The Chase
Manhattan Bank as Administrative Agent (the "Credit Facility") to provide for
maximum borrowings, subject to borrowing base limitations, of up to $250
million. Under the latest amendment to our Credit Facility, our lenders agreed
to maintain our borrowing base at $170 million. The Credit Facility matures on
May 31, 2003. During August 2002, the Company entered into 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
borrowing base under the Credit Agreement will be no less than $153 million with
funding expected to occur during September 2002, at which time the existing
Credit Facility will be retired. Pursuant to the terms of the Credit Agreement,
the borrowing base may increase to as high as $175 million before the September
2002 funding, subject to meeting certain conditions. As of June 30, 2002, the
Company's outstanding debt under its existing Credit Facility totaled $170
million compared to $190 million as of March 31, 2002, and December 31, 2001,
respectively, and accordingly, $17 million has been classified as current on the
Company's consolidated balance sheet as of June 30, 2002, to provide for the new
$153 million minimum borrowing base. Should the borrowing base be increased
prior to the September 2002 funding, corresponding amounts of the increase will
be reclassified to long-term on the Company's consolidated balance sheet.
9 1/2% CONVERTIBLE SUBORDINATED NOTES
During March 2002, the Company and the holders of the Notes amended the
conversion price to $5.00 per share. The conversion price is subject to
customary anti-dilution provisions. The holders of the Notes have been granted
registration rights with respect to the shares of Common Stock that would be
issued upon conversion of the Notes.
7
3. 8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK
The private placement of $66.85 million of 8.5% redeemable convertible preferred
stock was completed during May 2002. The preferred stock is convertible into
shares of the Company's Common Stock at a conversion price of $4.75 per share.
Dividends are payable semi-annually in cash. At the option of the Company,
one-third of the preferred shares can be forced to convert to Common Stock if
the closing price of the Company's Common Stock exceeds 150% of the conversion
price for 30 out of 40 consecutive trading days on the New York Stock Exchange.
Based on the above conversion criteria, the Company can elect to convert up to
one-third of the original issue provided that the conversion occurs no sooner
than twelve months from the most recent conversion. The preferred stock is
subject to redemption at the option of the Company after March 2005, and
mandatory redemption on March 31, 2009. The holders of the preferred stock have
been granted registration rights with respect to the shares of Common Stock
issued upon conversion of the preferred stock. Dividends of $1.1 million were
payable as of July 1, 2002.
4. COMMITMENTS AND CONTINGENCIES
LITIGATION
There are no material legal proceedings to which Meridian or any of its
subsidiaries or partnerships is a party or by 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.
8
5. 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,
2002 2001
---- ----
Numerator:
Net earnings applicable to common stockholders $ 3,172 $ 7,691
Plus income impact of assumed conversions:
Preferred stock dividends 1,102 --
Interest on convertible subordinated notes 309 312
Net earnings applicable to common stockholders
plus assumed conversions $ 4,583 $ 8,003
Denominator:
Denominator for basic net earnings per
share - weighted-average shares outstanding 49,916 47,872
Effect of potentially dilutive common shares:
Redeemable preferred stock N/A --
Convertible subordinated notes N/A 2,857
Employee and director stock options N/A 1,817
Warrants N/A 2,492
--------------- -------
Denominator for diluted net earnings per
share - weighted-average shares outstanding
and assumed conversions 49,916 55,038
=============== =======
Basic net earnings per share $ 0.06 $ 0.16
=============== =======
Diluted net earnings per share $ 0.06 $ 0.15
=============== =======
SIX MONTHS ENDED JUNE 30,
2002 2001
---- ----
Numerator:
Net earnings applicable to common stockholders $ 1,595 $27,359
Plus income impact of assumed conversions:
Preferred stock dividends 1,102 429
Interest on convertible subordinated notes 618 621
Net earnings applicable to common stockholders
plus assumed conversions $ 3,315 $28,409
Denominator:
Denominator for basic net earnings per
share - weighted-average shares outstanding 49,551 48,781
Effect of potentially dilutive common shares:
Convertible preferred stock -- 1,986
Redeemable preferred stock N/A --
Convertible subordinated notes N/A 2,857
Employee and director stock options N/A 1,833
Warrants N/A 2,486
--------------- -------
Denominator for diluted net earnings per
share - weighted-average shares outstanding
and assumed conversions 49,551 57,943
=============== =======
Basic net earnings per share $ 0.03 $ 0.56
=============== =======
Diluted net earnings per share $ 0.03 $ 0.49
=============== =======
9
6. ISSUANCE OF STOCK GRANTS
In December 2001, an offer was made to repurchase and terminate certain
interests in the Well Bonus Plans from current and former employees in exchange
for the issuance of Common Stock. The offering was for a total of 1,940,991
shares of our Common Stock. The Common Stock was issued on February 4, 2002, at
the last reported sales price of $3.48 per share. The effective date of this
transaction was December 31, 2001.
7. OIL AND NATURAL GAS HEDGING ACTIVITIES
During March 2002, the Company entered into derivative agreements to provide an
economic hedge of a portion of its oil and gas production volumes through the
typically volatile summer months. Through the use of costless collars the
Company hedged approximately 55% of its gas production and 27% of its oil
production, for a six-month period from April 1, 2002 through September 30,
2002, establishing average floors of $2.25 per MMBTU and $20.00 per barrel and
average ceilings of $3.98 per MMBTU and $29.18 per barrel. As of June 30, 2002,
the Company had an unrealized non-cash loss of $135,000 due to the
mark-to-market valuation of the derivative agreements. These derivatives were
not designated for special accounting under FAS 133 and the non-cash loss has
been charged to earnings.
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 and six months ended June 30, 2002 and 2001. 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, 2001 (and the notes attached
thereto), should be read in conjunction with this discussion.
GENERAL
BUSINESS ACTIVITIES. During the second quarter of 2002, Meridian's drilling
activities have been focused in the Company's East Lake Arthur Field, the
Lakeside Field, the Biloxi Marshlands project area and the Kent Bayou Field.
Additional drilling activities in these and other similar areas will comprise
our capital budget for 2002, currently set at $70 million.
Current activities include:
During March 2002, the Company commenced drilling operations on the East Lake
Arthur - Hughes #2 well in Jefferson Davis Parish, Louisiana. Hole conditions
have delayed the drilling operations by approximately ninety days. As a result,
the Company recently began sidetrack operations on the well and is currently
drilling at approximately 12,700 feet with an objective depth of approximately
19,000 feet. During the drilling of the Hughes #1 well, the Company logged an
apparent 100' of net pay in the Bol Mex 3-6 sands and detected no water levels.
The Company is the operator of the field and owns a 96% working interest and a
68% net revenue interest in the field. The Hughes #2 well is a twin offset to
the Hughes #1 well.
During April 2002, the Company began drilling the Lakeside - Lacassane #1 well
located in Cameron Parish, Louisiana. The well is currently drilling at
approximately 16,700 feet with an objective depth of approximately 17,900 feet.
The well is being drilled to test an updip location to the Lakeside - SL 15223
#1 well that discovered in excess of 100' of productive sands in the Marg Howei
and Camerina intervals and is currently producing 12 Mmcfe/d, with collective
production of over 4 Bcfe. The Company is operator of the well and has a 73%
working interest and a 42% net revenue interest.
During June 2002, the Company commenced drilling operations on the Continental
Land and Fur No. 65 well in the Kent Bayou Field in Terrebonne Parish,
Louisiana. The well is currently drilling at approximately 14,400 feet with an
objective depth of approximately 19,600 feet. The development well is being
drilled to exploit the Rob L sand that is currently productive in adjoining
acreage immediately offset to the well site. The Company is the operator and
owns a 93% working interest in the well.
On the Biloxi Marshlands project area, the Company has initiated a large-scale
proprietary 3-D seismic survey that will image approximately 500 square miles in
three phases over the next three years. The first phase of the seismic survey
commenced during the second quarter of 2002. Based on 2-D and 3-D seismic
acquired over a small portion of the acreage to date, the Company's geologists
have begun initial mapping of more than a dozen prospect leads. The Biloxi
Marshlands project focuses on relatively shallow, normal pressured horizons. As
a result, the project will blend with the Company's traditional deep plays,
providing lower costs, reduced mechanical risks and an expected high probability
of success. Fields in the immediate and surronding area have produced
approximately 750-800 Bcfe to date. The first well, the Biloxi Marsh Lands No.
1, began drilling during the second quarter of 2002. The well was drilled to a
depth of 9,294 feet and encountered 66 gross feet of gas bearing sand above a
water level with approximately 12 net feet of apparent gas pay. The quality of
the reservoir appears adequate for a completion. The Company has elected to
proceed with the running tubing, testing and completion of this well after the
drilling of additional wells in the area.
11
Other drilling operations scheduled for 2002 include both shallow and deep
exploration tests primarily in the south Louisiana and Gulf of Mexico region.
In addition, the Company has expanded its acreage and 3-D seismic inventory to
provide a continued blend of high potential low risk projects extending its
capital budget to take advantage of expected increased demand and reduced
supply of domestic oil and natural gas beginning in 2003 and beyond. In keeping
with our commitment to reduce debt and improve the Company's capital structure,
the Company has further lowered its borrowing base and outstanding debt, reduced
operating costs, general and administative overhead, and interest expenses.
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 for the
three months ended June 30, 2002, was $24.99 per barrel compared to $27.16 per
barrel for the three months ended June 30, 2001, and $20.62 per barrel for the
three months ended March 31, 2002. Our average oil price for the six months
ended June 30, 2002, was $22.80 per barrel compared to $28.12 per barrel for the
six months ended June 30, 2001. Our average natural gas price for the three
months ended June 30, 2002, was $3.69 per Mcf compared to $5.12 per Mcf for the
three months ended June 30, 2001, and $2.51 per Mcf for the three months ended
March 31, 2002. Our average natural gas price for the six months ended June 30,
2002, was $3.08 per Mcf compared to $6.53 per Mcf for the six months ended June
30, 2001. 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 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,
2001, for further discussion.
12
RESULTS OF OPERATIONS
THREE MONTHS ENDED JUNE 30, 2002 COMPARED TO THREE MONTHS ENDED JUNE 30, 2001
OPERATING REVENUES. Second quarter 2002 oil and natural gas revenues decreased
$14.0 million as compared to second quarter 2001 revenues, primarily due to a
14% decrease in production volumes and a 19% decrease in average commodity
prices, both on a natural gas equivalent basis. The decrease in production was a
result of the property sales during 2001 and natural production declines,
partially offset by new discoveries placed on line at varying times during the
second half of 2001 and the first half of 2002. Drilling of new wells expected
to offset production declines experienced delays in early 2002 for various
reasons and did not resume until the end of the first quarter of 2002.
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the three months ended June 30, 2002 and
2001:
THREE MONTHS ENDED
JUNE 30, INCREASE
2002 2001 (DECREASE)
Production Volumes:
Oil (Mbbl) 631 687 (8%)
Natural gas (MMcf) 4,304 5,285 (19%)
MMcfe 8,089 9,405 (14%)
Average Sales Prices:
Oil (per Bbl) $ 24.99 $ 27.16 (8%)
Natural gas (per Mcf) $ 3.69 $ 5.12 (28%)
MMcfe $ 3.91 $ 4.86 (19%)
Operating Revenues (000's):
Oil $15,768 $18,656 (15%)
Natural gas 15,893 27,045 (41%)
------- -------
Total Operating Revenues $31,661 $45,701 (31%)
======= =======
OPERATING EXPENSES. Oil and natural gas operating expenses decreased $1.4
million (32%) to $3.0 million for the three months ended June 30, 2002, compared
to $4.4 million for the same period in 2001. On an equivalent unit of production
basis, lease operating expenses decreased from $0.47 per MCFE for the second
quarter 2001 to $0.37 per MCFE for the 2002 period. This decrease was primarily
due to the sale of high cost, non-core properties during mid 2001 and the
reorganization of field operations in late 2001. This reorganization involved a
20% reduction in field operating personnel and increased emphasis in operating
cost reductions. In addition, the Company undertook an expanded workover program
during 2001 in order to benefit from the higher commodity prices being realized
at the time.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes decreased $0.2
million (9%) to $2.4 million for the second quarter of 2002, compared to $2.6
million during the same period in 2001. Meridian's oil and natural gas
production is primarily from southern Louisiana, and is therefore subject to
Louisiana severance tax. The severance tax rates for Louisiana are 12.5% of
gross oil revenues and $0.199 per Mcf for natural gas, an increase from $0.097
per Mcf effective in July 2001. Our decrease was primarily due to the decrease
in oil and natural gas production and the decrease in oil prices from the same
period in 2001 partially offset by the increase in the natural gas tax rate.
Effective July 2002, Louisiana gas severance tax has decreased by $.077 per Mcf
to $.122 per Mcf.
13
DEPLETION AND DEPRECIATION. Depletion and depreciation expense decreased $3.0
million (18%) during the second quarter of 2002 to $13.6 million from $16.6
million for the same period of 2001. This was primarily a result of the decrease
in production volumes during the 2002 period in comparison to 2001 and a
decrease in the depletion rate from 2001 levels.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense decreased
by $1.4 million (32%) to $3.0 million for three months ended June 30, 2002,
compared to $4.4 million during the comparable period last year. On an
equivalent unit of production basis, general and administrative expenses
decreased to $0.37 per MCFE for the second quarter of 2002 from $0.47 per MCFE
in the second quarter of 2001. This reduction is partially due to the savings
realized from staff reductions during 2001 and the purchase and termination of
certain outstanding well bonus plan interests.
INTEREST EXPENSE. Interest expense decreased $1.7 million (31%) to $3.7 million
for the second quarter of 2002 in comparison to $5.4 million for the second
quarter of 2001. The decrease is primarily a result of a decrease in the balance
outstanding for the revolving credit line and a decrease in the interest rates.
14
SIX MONTHS ENDED JUNE 30, 2002, COMPARED TO SIX MONTHS ENDED JUNE 30, 2001
OPERATING REVENUES. Oil and natural gas revenues during the six months ended
June 30, 2002, decreased $58.8 million as compared to revenues during the six
months ended June 30, 2001, due to average sales prices decreasing 40% and a
decrease in production volumes of 18%, both on a natural gas equivalent basis.
The production decrease is primarily a result of the property sales in 2001 and
natural production declines, partially offset by new wells brought on during
2001. Drilling of new wells expected to offset production declines experienced
delays in early 2002 for various reasons and did not resume until the end of the
first quarter of 2002.
The following table summarizes production volumes, average sales prices and
gross revenues for the six months ended June 30, 2002 and 2001.
SIX MONTHS ENDED
JUNE 30, INCREASE
2002 2001 (DECREASE)
Production Volumes:
Oil (Mbbl) 1,264 1,466 (14%)
Natural gas (MMcf) 8,900 11,295 (21%)
MMcfe 16,484 20,089 (18%)
Average Sales Prices:
Oil (Bbl) $ 22.80 $ 28.12 (19%)
Natural gas (Mcf) $ 3.08 $ 6.53 (53%)
MMcfe $ 3.41 $ 5.73 (40%)
Gross Revenues (000's):
Oil $ 28,822 $ 41,224 (30%)
Natural gas 27,448 73,811 (63%)
-------- --------
Total $ 56,270 $115,035 (51%)
======== ========
OPERATING EXPENSES. Oil and natural gas operating expenses decreased $3.1
million (34%) to $6.1 million for the six months ended June 30, 2002, compared
to $9.2 million for the six months ended June 30, 2001. This decrease was
primarily due to the sale of high cost, non-core properties during mid-2001 and
the reorganization of field operations during 2001. This reorganization involved
a 20% reduction in field operating personnel and increased emphasis in operating
cost reductions. In addition, the Company undertook an expanded workover program
during 2001 in order to benefit from the higher commodity prices being realized
at the time.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes decreased $1.2
million (19%) to $5.1 million for the six months ended June 30, 2002, compared
to $6.3 million for the six months ended June 30, 2001. This decrease is largely
attributable to the decrease in production and the decrease in oil revenues from
the same period in 2001 partially offset by an increase 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
$0.199 per Mcf for natural gas. The tax rate for natural gas for the first half
of 2001 was $0.097 per Mcf.
15
DEPLETION AND DEPRECIATION. Depletion and depreciation expense decreased $6.8
million (20%) to $26.9 million during the first six months of 2002 from $33.7
million for the same period last year. This decrease was primarily a result of
the 18% decrease in production on an Mcfe basis from the comparable period in
2001, and a decrease in the depletion rate from 2001 levels.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense decreased
$3.2 million (33%) to $6.2 million for the first six months of 2002 compared to
$9.4 million during the first six months of 2001. On an equivalent unit of
production basis, general and administrative expenses decreased to $0.38 per
MCFE from $0.47 for the comparable six month periods. This reduction is
partially due to the savings realized from staff reductions during 2001 and the
purchase and termination of certain outstanding well bonus plan interests at the
end of 2001.
INTEREST EXPENSE. Interest expense decreased $4.3 million (36%) to $7.6 million
during the first six months of 2002 compared to $11.9 million during the
comparable period of 2001. 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.
16
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. During the second quarter of 2002, Meridian's capital
expenditures were internally financed with cash from operations. As of June 30,
2002, we had a cash balance of $19.1 million and working capital deficit of $2.6
million, including $27 million in current portion of long-term debt. 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. We entered into an amended and restated credit facility with
The Chase Manhattan Bank as Administrative Agent (the "Credit Facility") to
provide for maximum borrowings, subject to borrowing base limitations, of up to
$250 million. Under the amendment to our Credit Facility, our lenders agreed to
maintain our borrowing base at $170 million. During August 2002, the Company
entered into 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 borrowing base under the Credit Agreement
will be no less than $153 million with funding expected to occur during
September 2002, at which time the existing Credit Facility will be retired.
Pursuant to the terms of the Credit Agreement, the borrowing base may increase
to as high as $175 million before the September 2002 funding, subject to meeting
certain conditions. As of June 30, 2002, the Company's outstanding debt under
its existing Credit Facility totaled $170 million compared to $190 million as of
March 31, 2002, and December 31, 2001, respectively, and accordingly $17 million
has been classified as current on the Company's consolidated balance sheet as of
June 30, 2002, to provide for the new $153 minimum borrowing base. Should the
borrowing base be increased prior to the September 2002 funding, corresponding
amounts of the increase would be reclassified to long-term on the Company's
consolidated balance sheet.
Under the Credit Facility, as amended, the Company may secure either (i) an
alternative base rate loan that bears interest at a rate per annum equal to the
greater of the administrative agent's prime rate, a certificate of deposit-based
rate or a federal funds-based rate plus 0.25% to 1.0% or (ii) a Eurodollar base
rate loan that bears interest, generally, at a rate per annum equal to the
London interbank offered rate ("LIBOR") plus 1.25% to 2.75%, depending on the
ratio of the aggregate outstanding loans and letters of credit to the borrowing
base. The Credit Facility also provides for commitment fees ranging from 0.3% to
0.5% per annum.
SUBORDINATED CREDIT AGREEMENT. The Company extended and amended the short-term
subordinated credit agreement with Fortis Capital Corporation for $25 million on
April 5, 2002. 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 September 30, 2002, December 31, 2002, August 31, 2003
and April 30, 2004, with the remaining $5 million payable on December 31, 2004.
9 1/2% CONVERTIBLE SUBORDINATED NOTES. During March 2002, the Company and the
holders of the Notes amended the conversion price to $5.00 per share. The
conversion price is subject to customary anti-dilution provisions. The holders
of the Notes have been granted registration rights with respect to the shares of
Common Stock that would be issued upon conversion of the Notes.
8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK. During May 2002, the Company
completed the private placement of $66.85 million of 8.5% redeemable convertible
preferred stock. The conversion price is subject to customary anti-dilution
provisions. See Note 3 of the Notes to Consolidated Financial Statements.
OIL AND NATURAL GAS HEDGING ACTIVITIES. During March 2002, the Company entered
into derivative agreements hedging a portion of its oil and gas production
volumes through the typically volatile summer months. Through the use of
costless collars the Company hedged approximately 55% of the its gas production
and 27% of its oil production, for a six month period from April 1, 2002,
through September 30, 2002, establishing average floors of $2.25 per MMBTU and
$20.00 per barrel and average ceilings of $3.98 per MMBTU and $29.18 per barrel.
These derivatives were not designated for special accounting under FAS 133 and a
$135,000 non-cash loss has been charged to earnings as of June 30, 2002.
17
CAPITAL EXPENDITURES. In the second quarter of 2002, Meridian's drilling
activities have been focused in the Company's East Lake Arthur Field, Lakeside
Field, the Biloxi Marshlands project area and the Kent Bayou Field. Additional
drilling activities in these and other similar areas will comprise our 2002
capital budget of $70 million.
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 $66.85 million of 8.5% redeemable
convertible preferred stock and dividends are payable semi-annually. Dividends
of $1.1 million were payable as of July 1, 2002.
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, anticipated results from third party disputes and
litigation, expectations regarding 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 for 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
18
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 that cannot be measured in an exact manner,
and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgement.
Reserve estimates are inherently imprecise and may be expected to change as
additional information becomes available. There are numerous uncertainties
inherent in estimating quantities and values of proved reserves and in
projecting future rates of production and timing of development expenditures,
including many factors beyond our control. Because all reserve estimates are to
some degree speculative, the quantities of oil and natural gas that 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.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is currently exposed to market risk from hedging contracts changes
and changes in interest rates. A discussion of the market risk exposure in
financial instruments follows.
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 the $20 million principal of
9 1/2% Convertible Subordinated Notes due June 18, 2005. 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 $170 million remains borrowed under the Credit Facility, we
estimate our annual interest expense will change by $1.7 million for each 100
basis point change in the applicable interest rates utilized under the Credit
Facility. Changes in interest rates would, assuming all other things being
equal, cause the fair market value of debt with a fixed interest rate, such as
the Notes, to increase or decrease, and thus increase or decrease the amount
required to refinance the debt. The fair value of the Notes is dependent on
prevailing interest rates and our current stock price as it relates to the
conversion price of $5.00 per share of our Common Stock.
HEDGING CONTRACTS
Meridian may address market risk by selecting instruments whose value
fluctuations correlate strongly with the underlying commodity being hedged. From
time to time, we may enter 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. Meridian 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, we would be
exposed to price risk. Meridian 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.
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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
There are no material legal proceedings to which Meridian or any of its
subsidiaries or partnerships is a party or by 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
The Company filed no reports on Form 8-K during the second quarter of 2002.
21
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, 2002 By: JOSEPH A. REEVES, JR.
-----------------------------------------
Joseph A. Reeves, Jr.
Chief Executive Officer
(Principal Executive Officer)
Director and Chairman of the Board
By: MICHAEL J. MAYELL
-----------------------------------
Michael J. Mayell
President and Director
By: LLOYD V. DELANO
-----------------------------------------
Lloyd V. DeLano
Senior Vice President
Chief Accounting Officer
By: JAMES H. SHONSEY
-----------------------------------------
James H. Shonsey
Executive Vice President
Chief Financial Officer
22
INFORMATIONAL ADDENDUM TO REPORT ON FORM 10-Q
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
NOT FILED PURSUANT TO THE SECURITIES EXCHANGE ACT OF 1934
The undersigned Chief Executive Officer and Chief Financial Officer of The
Meridian Resource Corporation do hereby certify as follows:
The undersigned hereby certify that this Report on Form 10-Q fully complies with
the requirements of section 13(a) or 15(d) of the Securities Exchange Act of
1934 and the information contained in this Report on Form 10-Q fairly presents,
in all material respects, the financial condition and results of operations of
The Meridian Resource Corporation.
/s/ JOSEPH A. REEVES, JR.
----------------------------------------
Name: Joseph A. Reeves, Jr.
Title: Chief Executive Officer
/s/ MICHAEL J. MAYELL
----------------------------------------
Name: Michael J. Mayell
Title: President
/s/ JAMES H. SHONSEY
----------------------------------------
Name: James H. Shonsey
Title: Chief Financial Officer
/s/ LLOYD V. DELANO
----------------------------------------
Name: Lloyd V. DeLano
Title: Chief Accounting Officer
23