UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended: March 31, 2006
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 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check
one)
Large Accelerated Filer [ ] Accelerated Filer [X] Non-Accelerated Filer [ ]
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
Number of shares of common stock outstanding at May 3, 2006: 86,926,502
Page 1 of 36
THE MERIDIAN RESOURCE CORPORATION
QUARTERLY REPORT ON FORM 10-Q
INDEX
Page
Number
------
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statements of Operations (unaudited) for the
Three Months Ended March 31, 2006 and 2005 3
Consolidated Balance Sheets as of March 31, 2006
(unaudited) and December 31, 2005 4
Consolidated Statements of Cash Flows (unaudited) for the
Three Months Ended March 31, 2006 and 2005 6
Consolidated Statements of Stockholders' Equity
(unaudited) for the Three Months Ended March 31, 2006
and 2005 7
Consolidated Statements of Comprehensive Income (Loss)
(unaudited) for the Three Months Ended March 31, 2006
and 2005 8
Notes to Consolidated Financial Statements (unaudited) 9
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 16
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 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 MARCH 31,
----------------------------
2006 2005
------- -------
REVENUES:
Oil and natural gas $57,827 $50,132
Price risk management activities (640) (292)
Interest and other 319 204
------- -------
57,506 50,044
------- -------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 4,553 4,683
Severance and ad valorem taxes 2,735 2,632
Depletion and depreciation 29,499 25,322
General and administrative 5,111 5,013
Accretion expense 301 251
Hurricane damage repairs 1,999 --
------- -------
44,198 37,901
------- -------
EARNINGS BEFORE OTHER EXPENSES & INCOME TAXES 13,308 12,143
------- -------
OTHER EXPENSE:
Interest expense 1,378 985
------- -------
EARNINGS BEFORE INCOME TAXES 11,930 11,158
------- -------
INCOME TAXES:
Current 171 590
Deferred 4,428 3,710
------- -------
4,599 4,300
------- -------
NET EARNINGS 7,331 6,858
Dividends on preferred stock -- 731
------- -------
NET EARNINGS APPLICABLE TO COMMON STOCKHOLDERS $ 7,331 $ 6,127
======= =======
NET EARNINGS PER SHARE:
Basic $ 0.08 $ 0.08
Diluted $ 0.08 $ 0.07
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic 86,850 79,271
Diluted 92,552 85,024
See notes to consolidated financial statements.
3
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
MARCH 31, DECEMBER 31,
ASSETS 2006 2005
------ ----------- ------------
(unaudited)
CURRENT ASSETS:
Cash and cash equivalents $ 35,853 $ 23,265
Restricted cash 1,243 1,234
Accounts receivable, less allowance for doubtful accounts of
$242 [2006 and 2005] 34,326 41,188
Prepaid expenses and other 750 1,294
Assets from price risk management activities 1,100 528
Deferred tax asset 383 1,150
---------- ----------
Total current assets 73,655 68,659
---------- ----------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including
$36,096 [2006] and $26,623 [2005] not subject to depletion) 1,546,623 1,512,036
Land 48 48
Equipment 6,563 6,540
---------- ----------
1,553,234 1,518,624
Less accumulated depletion and depreciation 1,062,090 1,032,595
---------- ----------
Total property and equipment, net 491,144 486,029
---------- ----------
OTHER ASSETS:
Assets from price risk management activities 45 235
Other 768 879
---------- ----------
Total other assets 813 1,114
---------- ----------
TOTAL ASSETS $ 565,612 $ 555,802
========== ==========
See notes to consolidated financial statements.
4
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
MARCH 31, DECEMBER 31,
LIABILITIES AND STOCKHOLDERS' EQUITY 2006 2005
------------------------------------ ----------- ------------
(unaudited)
CURRENT LIABILITIES:
Accounts payable $ 6,818 $ 7,595
Revenues and royalties payable 7,805 9,149
Due to affiliates 3,535 4,638
Notes payable 213 1,103
Accrued liabilities 22,737 22,272
Liabilities from price risk management activities 2,979 3,977
Asset retirement obligations 2,840 2,879
Current income taxes payable 146 108
--------- ---------
Total current liabilities 47,073 51,721
--------- ---------
LONG-TERM DEBT 75,000 75,000
--------- ---------
OTHER:
Deferred income taxes 46,485 41,967
Liabilities from price risk management activities 279 464
Asset retirement obligations 9,412 9,085
--------- ---------
56,176 51,516
--------- ---------
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized,
86,902,640 [2006] and 86,817,658 [2005] issued) 902 900
Additional paid-in capital 525,582 524,692
Accumulated deficit (138,064) (145,395)
Accumulated other comprehensive loss (710) (2,314)
Unamortized deferred compensation (347) (318)
--------- ---------
Total stockholders' equity 387,363 377,565
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 565,612 $ 555,802
========= =========
See notes to consolidated financial statements.
5
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
(unaudited)
THREE MONTHS ENDED
MARCH 31,
-------------------
2006 2005
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $ 7,331 $ 6,858
Adjustments to reconcile net earnings to net cash
provided by operating activities:
Depletion and depreciation 29,499 25,322
Amortization of other assets 111 107
Non-cash compensation 510 427
Non-cash price risk management activities 640 292
Accretion expense 301 251
Deferred income taxes 4,428 3,710
Changes in assets and liabilities:
Restricted cash (9) 460
Accounts receivable 6,862 3,547
Prepaid expenses and other 544 523
Due to affiliates (1,103) (825)
Accounts payable (777) (5,354)
Revenues and royalties payable (1,344) (1,256)
Accrued liabilities and other 1,114 (3,928)
-------- --------
Net cash provided by operating activities 48,107 30,134
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (34,629) (34,763)
Proceeds from (settlements on) sale of property -- (109)
-------- --------
Net cash used in investing activities (34,629) (34,872)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Reductions - Notes payable (890) (736)
Issuance of stock/exercise of stock options, net -- (83)
Preferred dividends -- (1,360)
Additions to deferred loan costs -- (13)
-------- --------
Net cash used in financing activities (890) (2,192)
-------- --------
NET CHANGE IN CASH AND CASH EQUIVALENTS 12,588 (6,930)
Cash and cash equivalents at beginning of period 23,265 24,297
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 35,853 $ 17,367
======== ========
INFORMATION
Non-cash financing activities:
Conversion of preferred stock $ -- $ (702)
Issuance of shares for settlement of accrued liabilities $ (271) $ (1,210)
See notes to consolidated financial statements.
6
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
THREE MONTHS ENDED MARCH 31, 2006 AND 2005
(in thousands)
(unaudited)
Common Stock Accumulated
-------------- Additional Other Unamortized
Par Paid-In Accumulated Comprehensive Deferred
Shares Value Capital (Deficit) Loss Compensation Total
------ ----- ---------- ----------- ------------- ------------ --------
Balance, December 31, 2004 79,215 $821 $490,351 $(173,244) $(1,574) $(313) $316,041
Issuance of rights to common stock -- 1 455 -- -- (456) --
Exercise of stock options 20 -- 67 -- -- -- 67
Compensation expense -- -- -- -- -- 427 427
Accum. other comprehensive income -- -- -- -- (7,473) -- (7,473)
Issuance for conversion of pref stock 163 2 700 -- -- -- 702
Expenditures assoc. w/stock offering -- -- (150) -- -- -- (150)
Issuance of shares as compensation 223 2 1,208 -- -- -- 1,210
Preferred dividends -- -- -- (731) -- -- (731)
Net earnings -- -- -- 6,858 -- -- 6,858
------ ---- -------- --------- ------- ----- --------
Balance, March 31, 2005 79,621 $826 $492,631 $(167,117) $(9,047) $(342) $316,951
====== ==== ======== ========= ======= ===== ========
Balance, December 31, 2005 86,818 $900 $524,692 $(145,395) $(2,314) $(318) $377,565
Issuance of rights to common stock -- 1 450 -- -- (451) --
Company's 401(k) plan contibutions 21 -- 88 -- -- -- 88
Stock-based compensation -- -- 82 -- -- -- 82
Compensation expense -- -- -- -- -- 422 422
Accum. other comprehensive income -- -- -- -- 1,604 -- 1,604
Issuance of shares as compensation 64 1 270 -- -- -- 271
Net earnings -- -- 7,331 -- -- 7,331
------ ---- -------- --------- ------- ----- --------
Balance, March 31, 2006 86,903 $902 $525,582 $(138,064) $ (710) $(347) $387,363
====== ==== ======== ========= ======= ===== ========
See notes to consolidated financial statements.
7
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(thousands of dollars)
(unaudited)
THREE MONTHS
ENDED MARCH 31,
----------------
2006 2005
------ -------
Net earnings applicable to common stockholders $7,331 $ 6,127
------ -------
Other comprehensive income (loss), net of tax, for
unrealized losses from hedging activities:
Unrealized holding gains (losses) arising during period (1) 845 (8,685)
Reclassification adjustments on settlement of contracts (2) 759 1,212
------ -------
1,604 (7,473)
------ -------
Total comprehensive income (loss) $8,935 $(1,346)
====== =======
(1) net of income tax (expense) benefit $ (455) $ 4,676
(2) net of income tax expense $ (409) $ (652)
See notes to consolidated financial statements.
8
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, 2005, as filed with the Securities and Exchange Commission.
The financial statements included herein as of March 31, 2006, and for the three
month periods ended March 31, 2006 and 2005, are unaudited, and in the opinion
of management, the information furnished reflects all material adjustments,
consisting of normal recurring adjustments, necessary for a fair presentation of
financial position and of the results for the interim periods presented. Certain
minor reclassifications of prior period statements have been made to conform to
current reporting practices. The results of operations for interim periods are
not necessarily indicative of results to be expected for a full year.
2. ACCRUED LIABILITIES
Below is the detail of accrued liabilities on the Company's balance sheets as of
March 31, 2006 and December 31, 2005 (thousands of dollars):
MARCH 31, DECEMBER 31,
2006 2005
--------- ------------
Capital Expenditures $14,785 $12,853
Operating expenses/taxes 3,036 2,794
Hurricane damage repairs 1,438 2,717
Compensation 1,831 1,949
Interest 527 503
Other 1,120 1,456
------- -------
TOTAL $22,737 $22,272
======= =======
3. DEBT
CREDIT FACILITY. On December 23, 2004, the Company amended its existing credit
facility to provide for a four-year $200 million senior secured credit facility
(the "Credit Facility") with Fortis Capital Corp., as administrative agent, sole
lead arranger and bookrunner; Comerica Bank as syndication agent; and Union Bank
of California as documentation agent. Bank of Nova Scotia, Allied Irish Banks
P.L.C., RZB Finance LLC and Standard Bank PLC completed the syndication group.
The initial borrowing base under the Credit Facility was $130 million and it has
been reaffirmed by the syndication group effective April 30, 2006. As of March
31, 2006, outstanding borrowings under the Credit Facility totaled $75 million.
The Credit Facility is subject to semi-annual borrowing base redeterminations on
April 30 and October 31 of each year. In addition to the scheduled semi-annual
borrowing base redeterminations, the lenders or the Company have the right to
redetermine the borrowing base at any time, provided that no party can request
more than one such redetermination between the regularly scheduled borrowing
base redeterminations. The determination of the borrowing base is subject to a
number of factors, including quantities of proved oil and gas reserves, the
bank's price assumptions and other various factors unique to each member bank.
The
9
Company's lenders can redetermine the borrowing base to a lower level than the
current borrowing base if they determine that the oil and natural gas reserves,
at the time of redetermination, are inadequate to support the borrowing base
then in effect.
Obligations under the Credit Facility are secured by pledges of outstanding
capital stock of the Company's subsidiaries and by a first priority lien on not
less than 75% (95% in the case of an event of default) of its present value of
proved oil and gas properties. In addition, the Company is required to deliver
to the lenders and maintain satisfactory title opinions covering not less than
70% of the present value of proved oil and natural gas properties. The Credit
Facility also contains other restrictive covenants, including, among other
items, maintenance of certain financial ratios, restrictions on cash dividends
on common stock and under certain circumstances preferred stock, limitations on
the redemption of preferred stock and an unqualified audit report on the
Company's consolidated financial statements, all of which the Company is in
compliance.
The Company recently notified the syndication group that a shortfall existed in
the mortgage and the title opinion requirements with respect to the reserve
information the Company was required to deliver to the syndication group on
March 15, 2006. The primary reason for the shortfall was the inclusion of new
properties drilled during 2005 included in the Company's reserve estimates,
which were not previously encumbered by mortgages. Accordingly, the syndication
group approved a 30-day waiver of the mortgage requirement and a 60-day waiver
of the title opinion requirement. The Company is in full compliance with these
requirements within the time periods allowed in the waiver.
Under the Credit Facility, the Company may secure either (i) (a) an alternative
base rate loan that bears interest at a rate per annum equal to the greater of
the administrative agent's prime rate; or (b) federal funds-based rate plus 1/2
of 1%, plus an additional 0.5% to 1.25% depending on the ratio of the aggregate
outstanding loans and letters of credit to the borrowing base 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 2.25%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. At March 31, 2006, the three-month LIBOR interest rate
was 5.0%. The Credit Facility also provides for commitment fees of 0.375%
calculated on the difference between the borrowing base and the aggregate
outstanding loans under the Credit Facility.
4. 8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK
In 2005, the Company completed the conversion of all of the remaining
outstanding shares of preferred stock to common stock, with $31.6 million of
stated value being converted into approximately 7.1 million shares of the
Company's common stock.
10
5. COMMITMENTS AND CONTINGENCIES
LITIGATION.
H. L. HAWKINS LITIGATION. In December 2004, the estate of H.L. Hawkins filed a
claim against Meridian for damages "estimated to exceed several million dollars"
for Meridian's alleged gross negligence and willful misconduct under certain
agreements concerning certain wells and property in the S.W. Holmwood and E.
Lake Charles Prospects in Calcasieu Parish in Louisiana, as a result of
Meridian's satisfying a prior adverse judgment in favor of Amoco Production
Company. Meridian has filed an answer denying Hawkins' claims and asserted a
counterclaim for attorney's fees, court costs and other expenses, and for
declaratory relief that Meridian is entitled to retain the amounts that it had
been paid by Hawkins. The Company has not provided any amount for this matter in
its financial statements at March 31, 2006.
TITLE/LEASE DISPUTES. Title and lease disputes arise due to various events that
have occurred in the various states in which the Company operates. These
disputes are usually small and could lead to the Company over- or under-stating
reserves when a final resolution to the title dispute is made.
ENVIRONMENTAL LITIGATION. Various landowners have sued Meridian (along with
numerous other oil companies) in various similar lawsuits concerning several
fields in which the Company has had operations. The lawsuits seek injunctive
relief and other relief, including unspecified amounts in both actual and
punitive damages for alleged breaches of mineral leases and alleged failure to
restore the plaintiffs' lands from alleged contamination and otherwise from the
defendants' oil and gas operations. The Company, in certain instances, has
indemnified third parties from the claims made in these lawsuits. The Company
has not provided any amount for these matters in its financial statements at
March 31, 2006.
LITIGATION INVOLVING INSURABLE ISSUES. There are no other material legal
proceedings which exceed our insurance limits to which Meridian or any of its
subsidiaries 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.
6. EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted net earnings
per share (in thousands, except per share):
THREE MONTHS
ENDED MARCH 31,
-----------------
2006 2005
------- -------
Numerator:
Net earnings applicable to common stockholders $ 7,331 $ 6,127
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 86,850 79,271
Effect of potentially dilutive common shares:
Warrants 4,975 4,536
Employee and director stock options 727 1,217
------- -------
Denominator for diluted earnings per share -
weighted-average shares outstanding
and assumed conversions 92,552 85,024
======= =======
Basic earnings per share $ 0.08 $ 0.08
======= =======
Diluted earnings per share $ 0.08 $ 0.07
======= =======
11
7. OIL AND NATURAL GAS HEDGING ACTIVITIES
The Company may address market risk by selecting instruments with value
fluctuations that correlate strongly with the underlying commodity being hedged.
From time to time, we may enter into 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 are 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
derivative contracts. These contracts allow the Company to predict with greater
certainty the effective oil and natural gas prices to be received for hedged
production. Although derivatives often fail to achieve 100% effectiveness for
accounting purposes, these derivative instruments continue to be highly
effective in achieving the risk management objectives for which they were
intended. These contracts have been designated as cash flow hedges as provided
by FAS 133 and any changes in fair value are recorded in other comprehensive
income until earnings are affected by the variability in cash flows of the
designated hedged item. Any changes in fair value resulting from the
ineffectiveness of the hedge are reported in the consolidated statement of
operations as a component of revenues. The Company recognized a loss related to
hedge ineffectiveness of $0.6 million during the three months ended March 31,
2006, and $0.3 million during the three months ended March 31, 2005.
The estimated March 31, 2006 fair value of the Company's oil and natural gas
derivatives was an unrealized loss of $1.1 million ($0.7 million net of tax)
which is recorded in Accumulated Other Comprehensive Loss on the Company's
consolidated balance sheet. Based upon March 31, 2006 oil and natural gas
commodity prices, approximately $0.9 million of the loss deferred in other
comprehensive income could potentially lower gross revenues over the next twelve
months. As of March 31, 2006, the derivative contracts expire at various dates
through July 31, 2007.
Net settlements under these contracts reduced oil and natural gas revenues by
$1,168,000 and $1,864,000 for the three months ended March 31, 2006 and 2005,
respectively, as a result of hedging transactions.
The Notional Amount is equal to the total net volumetric hedge position of the
Company during the periods presented. As of March 31, 2006, the positions
effectively hedge approximately 6% of the proved developed natural gas
production and 18% of the proved developed oil production during the respective
terms of the hedging agreements. The fair values of the hedges are based on the
difference between the strike price and the New York Mercantile Exchange future
prices for the applicable trading months.
The fair value of the Company's hedging agreements is recorded on the
consolidated balance sheet as separately identified assets or liabilities. The
estimated fair value of the hedging agreements as of March 31, 2006, is provided
below:
12
Fair Value
Notional Floor Price Ceiling Price Mar 31, 2006
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- --------------- ------------- --------------
NATURAL GAS (MMBTU)
Apr 2006 - Oct 2006 Collar 1,130,000 $ 8.00 $14.50 $ 1,034
CRUDE OIL (BBLS)
Apr 2006 - Jul 2006 Collar 59,000 $37.50 $47.50 (2,042)
Apr 2006 - Jul 2006 Collar 17,000 $40.00 $50.00 (404)
Aug 2006 - Jul 2007 Collar 168,000 $50.00 $74.00 (702)
-------
Total Crude Oil (3,148)
-------
$(2,114)
=======
See Note 10, Subsequent Events, for additional information.
8. STOCK-BASED COMPENSATION
In December 2004, the FASB issued SFAS No. 123R which is a replacement statement
to SFAS No. 123 entitled "Share-Based Payment." This statement also amends SFAS
Statement 95. This statement addresses the accounting for share-based payment
transactions in which an enterprise receives employee services in exchange for
(a) equity instruments of the enterprise or (b) liabilities that are based on
the fair value of the enterprise's equity instruments or that may be settled by
the issuance of such equity instruments. The statement eliminates the ability to
account for share-based compensation transactions using APB Opinion No. 25,
"Accounting for Stock Issued to Employees," and generally requires instead that
such transactions be accounted for using a fair-value-based method. The Company
adopted the provisions of SFAS No. 123R on January 1, 2006, using the modified
prospective method.
Compensation expense is recorded for stock option awards over the requisite
vesting periods based upon the market value on the date of the grant.
Stock-based compensation expense of approximately $82,000 was recorded in the
three months ended March 31, 2006. No stock-based compensation expense was
recorded in the three month period ended March 31, 2005.
The following is a pro-forma reconciliation of reported earnings and earnings
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).
13
THREE MONTHS ENDED
MARCH 31,
2005
------------------
Net earnings applicable to common stockholders as reported $6,127
Stock-based compensation expense determined under
fair value method for all awards, net of tax (58)
------
Net earnings applicable to common stockholders pro forma $6,069
======
Basic earnings per share:
As reported $ 0.08
Pro forma $ 0.08
Diluted earnings per share:
As reported $ 0.07
Pro forma $ 0.07
9. 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 the Company to record a liability for the fair value of
our dismantlement and abandonment costs, excluding salvage values.
The following table describes the change in the Company's asset retirement
obligations for the three months ended March 31, 2006, and for the year ended
December 31, 2005 (thousands of dollars):
Asset retirement obligation at December 31, 2004 $ 9,624
Revisions to estimates and other changes during 2005 519
Additional retirement obligations recorded in 2005 883
Settlements during 2005 (182)
Accretion expense for 2005 1,120
-------
Asset retirement obligation at December 31, 2005 11,964
Additional retirement obligations recorded in 2006 77
Revisions to estimates during 2006 (90)
Accretion expense for 2006 301
-------
Asset retirement obligation at March 31, 2006 $12,252
=======
The Company's revisions to estimates represent changes to the expected amount
and timing of payments to settle the asset retirement obligations. These changes
primarily result from obtaining new information about the timing of our
obligations to plug the natural gas and oil wells and costs to do so.
10. SUBSEQUENT EVENTS
14
During April 2006, the Company entered into a series of hedging contracts to
hedge a portion of its oil and natural gas production for 2006, 2007 and 2008.
The hedge contracts were completed in the form of costless collars. The costless
collars provide the Company with a lower floor price and an upper limit ceiling
price on the hedged volumes. The floor price represents the lowest price the
Company will receive for the hedged volumes, while the ceiling price represents
the highest price the Company will receive for the hedged volumes. The costless
collars will be settled monthly based on the daily settlement price of the NYMEX
futures contract of oil and natural gas during each respective month. The
Notional Amount is equal to the total net volumetric hedge position of the
Company during the periods presented. These hedge contracts, combined with those
discussed in note 7, effectively hedge approximately 30% of the proved developed
natural gas production, and 23% of the proved developed oil production during
the respective terms of the hedging agreements. The following table summarizes
the contracted volumes and prices for the costless collars.
15
Notional Floor Price Ceiling Price
Amount ($ per unit) ($ per unit)
---------- ------------ --------------
NATURAL GAS (MMBTU)
June 2006 - May 2007 4,800,000 $ 8.00 $10.60
CRUDE OIL (BBLS)
August 2007 - April 2008 54,000 $60.00 $82.00
May 2008 - July 2008 15,000 $60.00 $82.00
In April 2006, the Company completed negotiations for an amendment to the
current office building lease agreement that extends the current office lease
until September 30, 2011. The base rental payments will be $1.7 million in 2007
and 2008, $1.8 million in 2009, $2.0 million in 2010 and $1.6 million in 2011.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL.
The Company's business plan has been reformatted to extend and expand its
exploration portfolio beyond its conventional assets in the Louisiana and Texas
Gulf Coast regions to include the establishment of large acreage positions in
known unconventional and resource plays located within producing regions of the
lower continental United States containing longer-lived reserves. In recognition
of the maturity of the Company's traditional producing region and the paradigm
of pricing, management reformatted its business strategy retaining its position
in the Gulf Coast of south Louisiana and Texas leveraging off the higher cash
flows generated from these properties to acquire exploration opportunities with
large acreage positions, multiple repeatable wells and longer-lived reserves.
The first venture beyond its traditional boundaries began with its East Texas
Woodbine/Austin Chalk play located primarily in Polk and Tyler Counties, Texas.
OPERATIONS OVERVIEW.
EAST TEXAS PLAY Drilling activities were initiated during January 2006 with the
drilling of four successive wells beginning with the BSM number 3 well which was
drilled to a depth of approximately 14,600 feet to test multiple sand objectives
including the Austin Chalk, Upper and Middle Woodbine sand intervals. Analysis
of electric logs and cores indicated that the well contained potential pay in
the Austin Chalk section of the wellbore similar to offset wells that had been
drilled in the area. Because procedures for successful completions in the area
indicate the necessity that laterals be drilled and the wells produced
immediately upon completion, land and unit requirements forced the Company to
release the rig and the well was temporarily abandoned pending unit approval,
construction of pipeline facilities and the return of a rig to drill the
laterals. The second well, or the Katherine Leary number 1 well was likewise
drilled to approximately 14,350 feet to test the Middle Woodbine, logged and
cored with indicated pay in the Austin Chalk section of the well. The well is
awaiting completion in the Austin Chalk upon the return of the rig as with the
BSM number 3 well.
The third well, the BSM number 2 well, was drilled to approximately 14,600 feet
to test the Middle Woodbine section and, based on electric log analysis and
cores, encountered potential pay in the Upper Woodbine sand section. The well
was completed and perforated in the Upper Woodbine sand section without prior
stimulation or fracturing of the tight sand formation and tested at rates up to
1.7 Mmcf per day of natural gas and 232 barrels of water, the latter declining
during the course of the 12 hours of testing. The well was shut-in pending
construction and tie-in to the pipeline. It is anticipated that the well will be
placed on production without stimulation and observed for production with plans
to frac the well as others in the AA Wells field are typically
16
treated to enhance rate and recoveries. In addition to the Upper Woodbine pay,
electric logs and cores indicated the presence of pay in the Austin Chalk
similar to that in the offsetting wells in the nearby area.
The fourth well or the BSM number 1 well was drilled to approximately 14,500
feet to test the Upper Woodbine sand section, logged and cored and had indicated
pay in the Austin Chalk similar to that in the offset wells described above and
in the nearby wells currently producing from the Austin Chalk section. This well
is currently being prepared to be completed in the Austin Chalk by the drilling
of two laterals which are expected to take a total of approximately 65-70 days.
In the meantime, pipeline rights of way have been submitted for approval and
construction is being scheduled so that the well can be flow tested upon
completion operations.
BILOXI MARSHLAND Seabiscuit Prospect (SL 18373 well) - The well was originally
tested and put on line on March 31, 2006 at 4.5 Mmcf/d and is currently
producing at a rate of 3.9 Mmcf/d (2.6 net). Meridian owns a 92% WI and is the
operator of the well.
Gato Del Sol (SL 18307 well) - The well was originally tested in December, 2005
at 7 Mmcf/d and was put on line in February. The well is currently producing at
a rate of 4 Mmcf/d (2.8 net). Meridian owns a 92% WI and is the operator of the
well.
Hornets 6 (SL 18073 well) - The well was drilled to test the Big Hum sand
interval at approximately 12,500 feet measured depth ("MD"). The electric log
indicated that the target sand did not contain sufficient hydrocarbons to
justify a completion and the well was plugged and abandoned. Meridian owned a
92% WI and was the operator of the well.
West Cyclops (SL 18330 well) - The well was drilled to 8,650 feet MD targeting
the Deltaic sand interval, logged pay in the objective sand section insufficient
to justify a completion. The well was plugged and abandoned. Meridian owned a
92% WI and was the operator of the well.
WEEKS ISLAND FIELD In the Weeks Island area, the Company recently reached total
depth on its Goodrich-Cocke #4 well on the Son of Pink Floyd prospect. The well
encountered sloughing shale conditions during the first drilling phase which
resulted in the sidetracking of the well to move further from the salt
mineralized section. The well was drilled to test the Miocene "BF4 Sand"
objective, and recently logged 91 feet net apparent pay in the objective sand
section. The offset and down-dip wells produced approximately 1.6 million
barrels to date, and this well is approximately 65 feet high to the next highest
well in the block. The casing was set on bottom as of this date and is being
prepared to be completed within the next week, and put on-line shortly
afterwards. The Coastal rig utilized to drill this well will be moved within
Iberia Parish to drill the J.A. Smith #1 well on the "Y" Not prospect to test a
sand in the Lower Miocene formation at a depth of approximately 16,000 feet MD.
OTHER OUTSIDE OPERATED ACTIVITY
RICEVILLE AREA Henry Heirs #2 well - This well was proposed by Cimarex as an
offset to the Cimarex Henry Heirs #1 well. Meridian elected not to participate
as a working interest partner in the well, and retained a carried interest. The
well was drilled to a total depth of 12,900 feet and failed to identify
commercial hydrocarbons and is currently being plugged and abandoned.
DEEP LAKE AREA The SL 18172 #1 well on the South Deep Lake Prospect was drilled
to its target depth of 18,800 feet to test the MA-14 sands. The Company was
carried for a 6.6% WI in the entire well which was plugged and abandoned as a
dry hole, all at no cost to Meridian. PetroQuest was the operator.
17
GIBSON-HUMPHREYS FIELD The Gumbo prospect well, the Westervelt #2 well was
drilled to a target depth of 19,400 feet and encountered pay in the Rob L sand
interval. Meridian owns a 2.7% ORRI in the well by virtue of land positions and
is awaiting the well being placed on production. Denbury is the operator of the
well.
THORNWELL FIELD The Lacassane #33-4 well was drilled by Denbury, operator of the
field, and was drilled to test the Bol Perc sands. The well logged apparent pay
and was put on production in December, 2005 at approximately 7.8 Mmcf/d and 230
BCPD. The well has produced approximately 0.9 Bcf and 23,000 barrels of
condensate to date and is currently producing at approximately 5 Mmcf/d natural
gas and 100 BCPD. The Company owns a 12.3% WI.
The Abshire #33-1 well was drilled by Denbury to a total depth of 11,350 feet
and logged apparent pay in the Bol Perc sands. The operator is preparing to run
casing in the well. Meridian owns a 12.3% WI and is a non-operator.
GULF OF MEXICO, SHELF The Company recently participated in the MMS Central Gulf
of Mexico OCS Lease Sale held on March 15, 2006. It bid on two tracts and was
the apparent winner of one tract upon which it expects to cause a well to be
drilled during late 2006, depending on the availability of rig equipment. The
lease is expected to be awarded to Meridian by the MMS in the near term.
UNCONVENTIONAL/RESOURCE PLAYS
The Company has diversified its exploration effort by combining the high cash
flows of its Gulf Coast region properties with the drilling and development of
multiple unconventional and resource gas plays. Since December 2005, Meridian
has acquired strategic positions in three separate basins with working interests
ranging between 40% and 92%. Negotiations for additional positions are underway
and ongoing as an adjunct to the continued expansion and development of the Gulf
Coast asset base. Meridian currently has two barge rigs under contract for the
conventional exploration and development activities and one rig for the
completion of its current well in the East Texas Woodbine/Austin Chalk program
(BSM #1). It is anticipated that the Company will have two additional land rigs
available during the third and fourth quarters of 2006 with which it expects to
continue its operations in its East Texas field and to initiate pilot programs
on its recently acquired resource properties. The Company has initiated
discussions with rig contractors for additional rig equipment and crews
including the purchase of at least two rigs during 2006. Depending on the
success of the Woodbine/Austin Chalk play in East Texas, the Company has
sufficient acreage in that play to drill approximately 7-9 additional wells
which will keep one rig busy full time over the next two years. Additional
acreage is expected to be purchased to expand the play concept.
Since December 2005, the Company has added significant acreage positions in
three unconventional/resource plays in the Illinois Basin, the Delaware Basin
and the Palo Duro Basin. To date, the company has net acreage positions in these
basins of approximately 15,000, 22,000 and 18,000, respectively and, the Company
is working to add to those positions. Initial development of these areas is
expected to begin either late in the third quarter or early in the fourth
quarter of this year.
INDUSTRY CONDITIONS. Revenues, profitability and future growth rates of Meridian
are substantially dependent upon prevailing prices for oil and natural gas. Oil
and natural gas prices have been extremely volatile in recent years and are
affected by many factors outside of our control. Our average oil price (after
adjustments for hedging activities) for the three months ended March 31, 2006,
was $49.23 per barrel compared to $33.99 per barrel for the three months ended
March 31, 2005, and $50.14 per barrel for the three months ended December 31,
2005. Our average natural gas price (after adjustments for hedging activities)
for the three months ended March 31, 2006, was $9.20 per Mcf compared to $6.66
per Mcf for the three months ended March 31, 2005, and $11.15 per Mcf for the
three months ended December 31, 2005. Fluctuations in prevailing prices for oil
and natural gas have several important consequences to us, including affecting
the
18
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, 2005, for further discussion.
RESULTS OF OPERATIONS
THREE MONTHS ENDED MARCH 31, 2006 COMPARED TO THREE MONTHS ENDED MARCH 31, 2005
OPERATING REVENUES. First quarter 2006 oil and natural gas revenues, which
include oil and natural gas hedging activities (see Note 7 of Notes to
Consolidated Financial Statements), increased $7.7 million (15%) as compared to
first quarter 2005 revenues due to a 39% increase in average commodity prices on
a natural gas equivalent basis, partially offset by a 17% decrease in production
volumes. Oil and natural gas production volume totaled 6,432 Mmcfe for the first
quarter of 2006 compared to 7,765 Mmcfe for the comparable period of 2005. Our
average daily production decreased from 86 Mmcfe during the first quarter of
2005 to 71 Mmcfe for the first quarter of 2006. The variance in average daily
production volumes between the two periods is due in part to mechanical issues
caused by the 2005 hurricanes on the BML 1-2 well and the BML 28-1 well.
Production from these wells has been deferred until the mechanical issues can be
resolved. Additional variance differences can be attributed to new discoveries
brought on between the comparable periods, offset by natural production
declines.
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the three months ended March 31, 2006 and
2005:
THREE MONTHS
ENDED MARCH 31,
----------------- INCREASE
2006 2005 (DECREASE)
------- ------- ----------
Production Volumes:
Oil (Mbbl) 224 260 (14%)
Natural gas (MMcf) 5,087 6,203 (18%)
Mmcfe 6,432 7,765 (17%)
Average Sales Prices:
Oil (per Bbl) $ 49.23 $ 33.99 45%
Natural gas (per Mcf) $ 9.20 $ 6.66 38%
Mmcfe $ 8.99 $ 6.46 39%
Operating Revenues (000's):
Oil $11,034 $ 8,846 25%
Natural gas $46,793 $41,286 13%
------- -------
Total Operating Revenues $57,827 $50,132 15%
======= =======
19
OPERATING EXPENSES. Oil and natural gas operating expenses on an aggregate basis
decreased $0.1 million (3%) to $4.6 million during the first quarter of 2006,
compared to $4.7 million in 2005. On a unit basis, lease operating expenses
increased $0.11 per Mcfe to $0.71 per Mcfe for the first quarter of 2006 from
$0.60 per Mcfe for the first quarter of 2005. Oil and natural gas operating
expenses decreased primarily due to lower maintenance-related activities. The
increase in the per Mcfe rate was primarily attributable to the lower production
between the two corresponding periods.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes increased $0.1
million (4%) to $2.7 million for the first quarter of 2006, compared to $2.6
million during the same period in 2005 primarily because of an increase in oil
prices and a higher natural gas tax rate, partially offset by a decrease in
natural gas production. 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 $0.252 per
Mcf for natural gas, an increase from $0.208 per Mcf for the first half of 2005.
On an equivalent unit of production basis, severance and ad valorem taxes
increased to $0.43 per Mcfe from $0.34 per Mcfe for the comparable three-month
period.
DEPLETION AND DEPRECIATION. Depletion and depreciation expense increased $4.2
million (16%) during the first quarter of 2006 to $29.5 million, from $25.3
million for the same period of 2005. This was primarily the result of an
increase in the depletion rate as compared to the 2005 period, partially offset
by the decrease in oil and natural gas production. On a unit basis, depletion
and depreciation expense increased by $1.33 per Mcfe, to $4.59 per Mcfe for the
three months ended March 31, 2006, compared to $3.26 per Mcfe for the same
period in 2005, primarily due to the impact of negative reserve revisions during
2005 and the rising costs in the industry for current and projected capital
expenditures.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense increased
$0.1 million (2%) to $5.1 million compared to $5.0 million for 2005. On an
equivalent unit of production basis, general and administrative expenses
increased $0.14 per Mcfe to $0.79 per Mcfe for the first quarter of 2006
compared to $0.65 per Mcfe for the comparable 2005 period primarily due to lower
production rates between the periods. Stock-based compensation expense of
approximately $82,000 was recorded in the three months ended March 31, 2006. No
stock-based compensation expense was recorded in the three month period ended
March 31, 2005.
HURRICANE DAMAGE REPAIRS. This expense of $2.0 million is related to damages
incurred from hurricanes Katrina and Rita, primarily related to the Company's
costs in excess of insured values.
INTEREST EXPENSE. Interest expense increased $0.4 million (40%), to $1.4 million
for the first quarter of 2006 in comparison to the first quarter of 2005. The
increase is primarily a result of increased interest rates.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. During the first quarter of 2006, Meridian's capital
expenditures were internally financed with cash from operations. As of March 31,
2006, the Company had a cash balance of $35.9 million and working capital of
$26.6 million.
CASH FLOWS. Net cash provided by operating activities was $48.1 million for the
three months ended March 31, 2006, as compared to $30.1 million for the same
period in 2005. The increase of $18.0 million was primarily due to higher crude
oil and natural gas commodity prices, partially offset by lower production
volumes.
Net cash used in investing activities was $34.6 million during the three months
ended March 31, 2006, versus $34.9 million in the first three months of 2005.
20
Cash flows used in financing activities during the first three months of 2006
were $0.9 million, compared to cash used in financing activities of $2.2 million
during the first three months of 2005. This reduction in cash used in financing
activities was primarily due to reduced preferred stock dividends.
CREDIT FACILITY. On December 23, 2004, the Company amended its existing credit
facility to provide for a four-year $200 million senior secured credit facility
(the "Credit Facility") with Fortis Capital Corp., as administrative agent, sole
lead arranger and bookrunner; Comerica Bank as syndication agent; and Union Bank
of California as documentation agent. Bank of Nova Scotia, Allied Irish Banks
P.L.C., RZB Finance LLC and Standard Bankc PLC completed the syndication group.
The initial borrowing base under the Credit Facility was $130 million and it has
been reaffirmed by the syndication group effective April 30, 2006. As of March
31, 2006, outstanding borrowings under the Credit Facility totaled $75 million.
The Credit Facility is subject to semi-annual borrowing base redeterminations on
April 30 and October 31 of each year. In addition to the scheduled semi-annual
borrowing base redeterminations, the lenders or the Company, have the right to
redetermine the borrowing base at any time, provided that no party can request
more than one such redetermination between the regularly scheduled borrowing
base redeterminations. The determination of our borrowing base is subject to a
number of factors, including quantities of proved oil and gas reserves, the
bank's price assumptions and other various factors unique to each member bank.
Our lenders can redetermine the borrowing base to a lower level than the current
borrowing base if they determine that our oil and gas reserves, at the time of
redetermination, are inadequate to support the borrowing base then in effect.
Obligations under the Credit Facility are secured by pledges of outstanding
capital stock of the Company's subsidiaries and by a first priority lien on not
less than 75% (95% in the case of an event of default) of its present value of
proved oil and gas properties. In addition, the Company is required to deliver
to the lenders and maintain satisfactory title opinions covering not less than
70% of the present value of proved oil and gas properties. The Credit Facility
also contains other restrictive covenants, including, among other items,
maintenance of certain financial ratios, restrictions on cash dividends on
common stock and under certain circumstances preferred stock, limitations on the
redemption of preferred stock and an unqualified audit report on the Company's
consolidated financial statements, all of which the Company is in compliance.
The Company recently notified the syndication group that a shortfall existed in
the mortgage and the title opinion requirements with respect to the reserve
information the Company was required to deliver to the syndication group on
March 15, 2006. The primary reason for the shortfall was the inclusion of new
properties drilled during 2005 included in the Company's reserve estimates,
which were not previously encumbered by mortgages. Accordingly, the syndication
group approved a 30-day waiver of the mortgage requirement and a 60-day waiver
of the title opinion requirement. The Company is in full compliance with these
requirements within the time periods allowed in the waiver.
21
Under the Credit Facility, the Company may secure either (i) (a) an alternative
base rate loan that bears interest at a rate per annum equal to the greater of
the administrative agent's prime rate; or (b) federal funds-based rate plus 1/2
of 1%, plus an additional 0.5% to 1.25% depending on the ratio of the aggregate
outstanding loans and letters of credit to the borrowing base 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 2.25%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. At March 31, 2006, the three-month LIBOR interest rate
was 5.0%. The Credit Facility also provides for commitment fees of 0.375%
calculated on the difference between the borrowing base and the aggregate
outstanding loans under the Credit Facility.
8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK. In 2005, the Company completed the
conversion of all of the remaining outstanding shares of preferred stock to
common stock, with $31.6 million of stated value being converted into
approximately 7.1 million shares of the Company's common stock.
OIL AND NATURAL GAS HEDGING ACTIVITIES. The Company may address market risk by
selecting instruments with fluctuating values that correlate strongly with the
underlying commodity being hedged. From time to time we may enter into
derivative contracts to hedge the price risks associated with a portion of
anticipated future oil and gas production. These contracts allow the Company to
predict with greater certainty the effective oil and natural gas prices to be
received for our hedged 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.
These hedging contracts have been designated as cash flow hedges as provided by
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
operations as revenues.
CAPITAL EXPENDITURES. Total capital expenditures for this period approximated
$34.6 million. Our strategy is to blend exploration drilling activities with
high-confidence workover and development projects in order to capitalize on
periods of high commodity prices. Capital expenditures were for acreage
acquisitions, exploratory drilling, geological and geophysical, workovers, and
related capitalized general and administrative expenses. During 2006, the
Company has completed drilling operations on thirteen wells of which one well
was placed on production with six wells having logged apparent pay and six
unproductive wells.
The 2006 capital expenditures plan is currently forecast at approximately $132
million. The actual expenditures will be determined based on a variety of
factors, including prevailing prices for oil and natural gas, our expectations
as to future pricing and the level of cash flow from operations. We currently
anticipate funding the 2006 plan utilizing cash flow from operations. When
appropriate, excess cash flow from operations beyond that needed for the 2006
capital expenditures plan will be used to de-lever the Company by development of
exploration discoveries or direct payment of debt.
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 were payable semi-annually. A
semi-annual cash dividend of $1.3 million was paid in January 2005.
22
In 2005, the Company completed the conversion of all of the remaining
outstanding shares of the 8.5% Redeemable Convertible preferred stock to common
stock, with $31.6 million of stated value being converted into approximately 7.1
million shares of the Company's common 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.
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
23
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 available
data and of engineering and geological interpretation and judgment. Reserve
estimates may be 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. 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.
FULL-COST CEILING TEST. At the end of each quarter, the unamortized cost of oil
and natural gas properties, after deducting the asset retirement obligation, net
of related deferred income taxes, is limited to the sum of the estimated future
net revenues from proved properties using period-end prices, after giving effect
to cash flow hedge positions, discounted at 10%, and the lower of cost or fair
value of unproved properties adjusted for related income tax effects.
The calculation of the ceiling test and the provision for depletion and
amortization are based on estimates of proved reserves. There are numerous
uncertainties inherent in estimating quantities of proved reserves and in
projecting the future rates of production, timing, and plan of development. The
accuracy of any reserves estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment. Results of
drilling, testing, and production subsequent to the date of the estimate may
justify a revision of such estimate. Accordingly, reserve estimates are often
different from the quantities of oil and natural gas that are ultimately
recovered.
Due to the imprecision in estimating oil and natural gas revenues as well as the
potential volatility in oil and natural gas prices and their effect on the
carrying value of our proved oil and natural gas reserves, there can be no
assurance that write-downs in the future will not be required as a result of
factors that may negatively affect the present value of proved oil and natural
gas reserves and the carrying value of oil and natural gas properties, including
volatile oil and natural gas prices, downward revisions in estimated proved oil
and natural gas reserve quantities and unsuccessful drilling activities. At
March 31, 2006, we had a cushion (i.e. the excess of the ceiling over our
capitalized costs) of $50.9 million (before tax).
BORROWING BASE FOR THE CREDIT FACILITY. The Credit Agreement with Fortis Capital
Corp. as administrative agent, is presently scheduled for borrowing base
redetermination dates on a semi-annual basis with the next such redetermination
scheduled for October 31, 2006. 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.
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. 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 $75 million remains borrowed under the Credit Facility, we
estimate our annual interest expense will change by $0.75 million for each 100
basis point change in the applicable interest rates utilized under the Credit
Agreement.
HEDGING CONTRACTS
Meridian may address market risk by selecting instruments whose value
fluctuations correlate strongly with the underlying commodity being hedged. From
time to time, we may enter into derivative contracts to hedge the price risks
associated with a portion of anticipated future oil and natural gas production.
While the use of hedging arrangements limits the downside risk of adverse price
movements, it may also limit future gains from favorable movements. Under these
agreements, payments are received or made based on the differential between a
fixed and a variable product price. These agreements are settled in cash at or
prior to expiration or exchanged for physical delivery contracts. Meridian does
not obtain collateral to support the agreements, but monitors the financial
viability of counter-parties and believes its credit risk is minimal on these
transactions. In the event of nonperformance, the Company would be exposed to
price risk. Meridian has some risk of accounting loss since the price received
for the product at the actual physical delivery point may differ from the
prevailing price at the delivery point required for settlement of the hedging
transaction.
The Company has entered into certain derivative contracts as summarized in the
table below. The Notional Amount is equal to the total net volumetric hedge
position of the Company during the periods presented. As of March 31, 2006, the
positions effectively hedge approximately 6% of the proved developed natural gas
production and 18% of the proved developed oil production during the respective
terms of the contracts. The fair values of the hedges are based on the
difference between the strike price and the New York Mercantile Exchange future
prices for the applicable trading months.
Ceiling Fair Value
Notional Floor Price Price Mar 31, 2006
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ ------------ --------------
NATURAL GAS (MMBTU)
Apr 2006 - Oct 2006 Collar 1,130,000 $ 8.00 $14.50 $ 1,034
CRUDE OIL (BBLS)
Apr 2006 - Jul 2006 Collar 59,000 $37.50 $47.50 (2,042)
Apr 2006 - Jul 2006 Collar 17,000 $40.00 $50.00 (404)
Aug 2006 - Jul 2007 Collar 168,000 $50.00 $74.00 (702)
-------
Total Crude Oil (3,148)
-------
$(2,114)
=======
The above excludes hedges entered into after March 31, 2006; see Note 10,
Subsequent Events, for additional information.
25
ITEM 4. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
We conducted an evaluation 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-15(e) under the
Securities Exchange Act of 1934) as of the end of the first quarter of 2006.
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 during the first quarter of 2006 that could
significantly affect these controls.
CHANGES IN INTERNAL CONTROLS
During the three month period ended March 31, 2006, there were no changes in the
Company's internal control over financial reporting that have materially
affected or are reasonably likely to materially affect such internal control
over financial reporting.
26
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
H. L. HAWKINS LITIGATION. In December 2004, the estate of H.L. Hawkins filed a
claim against Meridian for damages "estimated to exceed several million dollars"
for Meridian's alleged gross negligence and willful misconduct under certain
agreements concerning certain wells and property in the S.W. Holmwood and E.
Lake Charles Prospects in Calcasieu Parish in Louisiana, as a result of
Meridian's satisfying a prior adverse judgment in favor of Amoco Production
Company. Meridian has filed an answer denying Hawkins' claims and asserted a
counterclaim for attorney's fees, court costs and other expenses, and for
declaratory relief that Meridian is entitled to retain the amounts that it had
been paid by Hawkins. The Company has not provided any amount for this matter in
its financial statements at March 31, 2006.
TITLE/LEASE DISPUTES. Title and lease disputes may arise due to various events
that have occurred in the various states in which the Company operates. These
disputes are usually small and could lead to the Company over- or under-stating
our reserves when a final resolution to the title dispute is made.
ENVIRONMENTAL LITIGATION. Various landowners have sued Meridian (along with
numerous other oil companies) in various similar lawsuits concerning several
fields in which the Company has had operations. The lawsuits seek injunctive
relief and other relief, including unspecified amounts in both actual and
punitive damages for alleged breaches of mineral leases and alleged failure to
restore the plaintiffs' lands from alleged contamination and otherwise from the
defendants' oil and gas operations. The Company, in certain instances, has
indemnified third parties from the claims made in these lawsuits. The Company
has not provided any amount for these matters in its financial statements at
March 31, 2006.
LITIGATION INVOLVING INSURABLE ISSUES. There are no other material legal
proceedings which exceed our insurance limits to which Meridian or any of its
subsidiaries 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 1A. RISK FACTORS.
For a discussion of the Company's risk factors, see Item 1A, "Risk Factors", in
the Company's Form 10-K for the year ended December 31, 2005.
ITEM 6. 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.
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: May 10, 2006 By: /s/ LLOYD V. DELANO
------------------------------------
Lloyd V. DeLano
Senior Vice President
Chief Accounting Officer
28
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.