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, 2007
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 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, 2007: 89,355,687
Page 1 of 32
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, 2007 and 2006 3
Consolidated Balance Sheets as of March 31, 2007
(unaudited) and December 31, 2006 4
Consolidated Statements of Cash Flows (unaudited) for the
Three Months Ended March 31, 2007 and 2006 6
Consolidated Statements of Stockholders' Equity
(unaudited) for the Three Months Ended March 31, 2007
and 2006 7
Consolidated Statements of Comprehensive Income (Loss)
(unaudited) for the Three Months Ended March 31, 2007
and 2006 8
Notes to Consolidated Financial Statements (unaudited) 9
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 17
Item 3. Quantitative and Qualitative Disclosures about Market Risk 27
Item 4. Controls and Procedures 28
PART II - OTHER INFORMATION
Item 1. Legal Proceedings 29
Item 1A. Risk Factors 29
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 29
Item 6. Exhibits 30
SIGNATURES 31
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,
-----------------
2007 2006
------- -------
REVENUES:
Oil and natural gas $40,143 $57,827
Price risk management activities 12 (640)
Interest and other 424 319
------- -------
40,579 57,506
------- -------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 7,767 4,553
Severance and ad valorem taxes 2,844 2,735
Depletion and depreciation 21,003 29,499
General and administrative 3,895 5,111
Accretion expense 553 301
Hurricane damage repairs -- 1,999
------- -------
36,062 44,198
------- -------
EARNINGS BEFORE OTHER EXPENSES & INCOME TAXES 4,517 13,308
------- -------
OTHER EXPENSE:
Interest expense 1,539 1,378
------- -------
EARNINGS BEFORE INCOME TAXES 2,978 11,930
------- -------
INCOME TAXES:
Current 138 171
Deferred 1,172 4,428
------- -------
1,310 4,599
------- -------
NET EARNINGS $ 1,668 $ 7,331
======= =======
NET EARNINGS PER SHARE:
Basic $ 0.02 $ 0.08
Diluted $ 0.02 $ 0.08
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic 89,253 86,850
Diluted 94,678 92,552
See notes to consolidated financial statements.
3
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
MARCH 31, DECEMBER 31,
2007 2006
----------- ------------
(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 19,641 $ 31,424
Restricted cash 27 1,282
Accounts receivable, less allowance for
doubtful accounts of $232 [2007 and 2006] 25,530 24,285
Due from affiliates 1,055 670
Prepaid expenses and other 1,400 3,457
Assets from price risk management activities 1,806 7,968
---------- ----------
Total current assets 49,459 69,086
---------- ----------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost
method (including $75,677 [2007] and
$54,356 [2006] not subject to depletion) 1,689,485 1,663,865
Land 48 48
Equipment 9,783 7,492
---------- ----------
1,699,316 1,671,405
Less accumulated depletion and depreciation 1,294,509 1,273,522
---------- ----------
Total property and equipment, net 404,807 397,883
---------- ----------
OTHER ASSETS:
Assets from price risk management activities 286 490
Other 325 436
---------- ----------
Total other assets 611 926
---------- ----------
TOTAL ASSETS $ 454,877 $ 467,895
========== ==========
See notes to consolidated financial statements.
4
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
MARCH 31, DECEMBER 31,
2007 2006
----------- ------------
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 5,993 $ 9,751
Revenues and royalties payable 7,084 7,933
Notes payable 279 2,754
Accrued liabilities 18,712 21,938
Liabilities from price risk management activities 958 1,024
Asset retirement obligations 5,449 4,803
Deferred income taxes payable 192 2,336
Current income taxes payable 9 --
--------- ---------
Total current liabilities 38,676 50,539
--------- ---------
LONG-TERM DEBT 75,000 75,000
--------- ---------
OTHER:
Deferred income taxes 4,455 3,364
Liabilities from price risk management activities 237 190
Asset retirement obligations 17,159 18,005
--------- ---------
21,851 21,559
--------- ---------
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares
authorized, 89,450,466 [2007] and 89,139,600
[2006] issued) 932 928
Additional paid-in capital 535,808 534,441
Accumulated deficit (217,611) (219,279)
Accumulated other comprehensive income 573 4,707
--------- ---------
319,702 320,797
Less treasury stock, at cost 150,000 [2007]
shares 352 --
--------- ---------
Total stockholders' equity 319,350 320,797
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 454,877 $ 467,895
========= =========
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,
-------------------
2007 2006
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $ 1,668 $ 7,331
Adjustments to reconcile net earnings to net cash
provided by operating activities:
Depletion and depreciation 21,003 29,499
Amortization of other assets 111 111
Non-cash compensation 644 510
Non-cash price risk management activities (12) 640
Accretion expense 553 301
Deferred income taxes 1,172 4,428
Changes in assets and liabilities:
Restricted cash 1,255 (9)
Accounts receivable (1,245) 6,862
Prepaid expenses and other 2,057 544
Due from affiliates (385) (1,103)
Accounts payable (3,758) (777)
Revenues and royalties payable (849) (1,344)
Asset retirement obligations (642) --
Other assets and liabilities (2,490) 1,114
-------- --------
Net cash provided by operating activities 19,082 48,107
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (30,568) (34,629)
Proceeds from sale of property 2,530 --
-------- --------
Net cash used in investing activities (28,038) (34,629)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Reductions - Notes payable (2,475) (890)
Repurchase of common stock (352) --
-------- --------
Net cash used in financing activities (2,827) (890)
-------- --------
NET CHANGE IN CASH AND CASH EQUIVALENTS (11,783) 12,588
Cash and cash equivalents at beginning of period 31,424 23,265
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 19,641 $ 35,853
======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Non cash - activities:
Issuance of shares as compensation $ (85) $ --
Issuance of shares for contract services $ (642) $ (271)
ARO Liability - new wells drilled $ -- $ 77
ARO Liability - changes in estimates $ (111) $ (90)
See notes to consolidated financial statements.
6
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
THREE MONTHS ENDED MARCH 31, 2007 AND 2006
(in thousands)
(unaudited)
Accumulated
Common Stock Additional Accumulated Other Unamortized Treasury Stock
----------------- Paid-In Earnings Comprehensive Deferred --------------
Shares Par Value Capital (Deficit) Income (Loss) Compensation Shares Cost Total
------ --------- ---------- ----------- ------------- ------------ ------ ----- --------
Balance, December 31, 2005 86,818 $900 $524,692 $(145,395) $(2,314) $(318) -- -- $377,565
Effect of adoption of SFAS 123R -- -- (318) -- -- 318 -- -- --
Issuance of rights to common
stock -- 1 (1) -- -- -- -- -- --
Company's 401(k) plan
contributions 21 -- 88 -- -- -- -- -- 88
Stock-based compensation -- -- 82 -- -- -- -- -- 82
Compensation expense -- -- 422 -- -- -- -- -- 422
Accum. other comprehensive
income -- -- -- -- 1,604 -- -- -- 1,604
Issuance of shares for
contract services 64 1 270 -- -- -- -- -- 271
Net earnings -- -- -- 7,331 -- -- -- -- 7,331
------ ---- -------- --------- ------- ----- --- ----- --------
Balance, March 31, 2006 86,903 $902 $525,235 $(138,064) $ (710) $ -- -- $ -- $387,363
====== ==== ======== ========= ======= ===== === ===== ========
Balance, December 31, 2006 89,140 $928 $534,441 $(219,279) $ 4,707 $ -- -- $ -- $320,797
Issuance of rights to common
stock -- 2 (2) -- -- -- -- -- --
Company's 401(k) plan
contributions 42 -- 132 -- -- -- -- -- 132
Shares repurchased (150) -- -- -- -- -- 150 (352) (352)
Stock-based compensation -
FAS123R -- -- 87 -- -- -- -- -- 87
Compensation expenses -- -- 425 -- -- -- -- -- 425
Accum. other comprehensive
income -- -- -- -- (4,134) -- -- -- (4,134)
Issuance of shares for
contract services 237 2 640 -- -- -- -- -- 642
Issuance of shares as
compensation 31 -- 85 -- -- -- -- -- 85
Net earnings -- -- -- 1,668 -- -- -- -- 1,668
------ ---- -------- --------- ------- ----- --- ----- --------
Balance, March 31, 2007 89,300 $932 $535,808 $(217,611) $ 573 $ -- 150 $(352) $319,350
====== ==== ======== ========= ======= ===== === ===== ========
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,
------------------
2007 2006
------- ------
Net earnings $ 1,668 $7,331
------- ------
Other comprehensive income (loss), net of tax, for
unrealized gains (losses) from hedging activities:
Unrealized holding gains (losses) arising during period (1) (2,931) 845
Reclassification adjustments on settlement of contracts (2) (1,203) 759
------- ------
(4,134) 1,604
------- ------
Total comprehensive income (loss) $(2,466) $8,935
======= ======
(1) Net income tax (expense) benefit $ 1,579 $ (455)
(2) Net income tax (expense) benefit $ 648 $ (409)
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, 2006, as filed with the Securities and Exchange Commission.
The financial statements included herein as of March 31, 2007, and for the three
month periods ended March 31, 2007 and 2006, 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 financial 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. RECENT ACCOUNTING PRONOUNCEMENTS
On February 15, 2007, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 159, "The Fair Value
Option for Financial Assets and Financial Liabilities - Including an Amendment
of FASB Statement No. 115 ("SFAS No. 159")". The statement permits entities to
choose to measure eligible financial instruments and certain other items at fair
market value, with the objective of improving financial reporting by giving
entities the opportunity to mitigate volatility in reported earnings caused by
measuring related assets and liabilities differently without having to apply
complex hedge accounting provisions. The Statement is effective for fiscal years
beginning after November 15, 2007. The adoption of SFAS No. 159 is not expected
to have a material impact, if any, on the Company's financial statements.
3. ACCRUED LIABILITIES
Below is the detail of accrued liabilities on the Company's balance sheets as of
March 31, 2007 and December 31, 2006 (thousands of dollars):
MARCH 31, DECEMBER 31,
2007 2006
--------- ------------
Capital expenditures $11,674 $13,851
Operating expenses/taxes 4,081 4,024
Hurricane damage repairs -- 71
Compensation 593 1,197
Interest 485 506
Other 1,879 2,289
------- -------
TOTAL $18,712 $21,938
======= =======
9
4. 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,
collectively the "Lenders". The current borrowing base under the Credit Facility
was determined to be $115 million by the syndication group effective April 30,
2007. As of March 31, 2007, 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 natural gas reserves,
the bank's price assumptions and other various factors unique to each member
bank. The 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 natural 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, limitations on the repurchase
of the Company's Common Stock and an unqualified audit report on the Company's
consolidated financial statements, all of which the Company is in compliance.
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, 2007, the three-month LIBOR interest rate
was 5.35%. 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.
5. INCOME TAXES
In July 2006, the FASB issued FASB Interpretation No. 48 ("FIN 48"), "Accounting
for Uncertainty in Income Taxes - an Interpretation of SFAS No. 109." FIN 48
clarifies the accounting for uncertainty in income taxes recognized in an
enterprise's financial statements in accordance with SFAS No. 109, Accounting
for Income Taxes. FIN 48 prescribes a recognition threshold and measurement
attribute for the financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return. FIN 48 also provides
guidance on recognition, classification, interest and penalties, accounting in
interim periods, disclosure, and transition. The Company adopted the provisions
of FIN 48 on January 1, 2007, and the adoption had no material impact on the
Company's results of operations and financial
10
condition.
6. 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, willful misconduct and breach of
fiduciary duty 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. Mr. James Bond has been added as a defendant
by Hawkins claiming Mr. Bond, when he was General Manager of Hawkins, did not
have the right to consent, could not consent or breached his fiduciary duty to
Hawkins if he did consent to all actions taken by Meridian. The Company has not
provided any amount for this matter in its financial statements at March 31,
2007.
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 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 Company's
oil and natural gas operations. The Company, in certain instances, has
indemnified third parties from the claims made in these lawsuits. In three of
the lawsuits, Shell Oil Company and SWPI LP have demanded indemnity and defense
from Meridian; Meridian has denied such demands. The Company has not provided
any amount for this matter in its financial statements at March 31, 2007.
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.
COMMITMENTS.
The Company has an agreement for the construction and purchase of one newly
built land based drilling rig in conjunction with an engineering design and
fabrication/rig contractor, for approximately $12 million. This contractor will
ultimately operate, crew and maintain the rig. Delivery of the rig is currently
expected in the third quarter of 2007 when the rig will be mobilized to the
Company's East Texas Austin Chalk play.
7. COMMON STOCK
In March 2007, the Company's Board of Directors authorized a new share
repurchase program. Under the program, the Company may repurchase in the open
market or through privately negotiated transactions up to $5 million worth of
common shares per year over the next three years. The timing, volume, and nature
of share repurchases will be at the discretion of management, depending on
market conditions, applicable securities laws, and other factors. Prior to
implementing this program, the Company was required to seek approval of the
repurchase program from the Lenders under the Credit Facility. The repurchase
program was approved by the Lenders, subject to certain restrictive covenants.
In March 2007, the Company repurchased
11
150,000 common shares at a cost of $352,000. It is the intent of the Company to
continue this program through this and future years.
12
8. 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,
-----------------
2007 2006
------- -------
Numerator:
Net earnings $ 1,668 $ 7,331
Denominator:
Denominator for basic earnings per share -
weighted-average shares outstanding 89,253 86,850
Effect of potentially dilutive common shares:
Warrants 5,425 4,975
Employee and director stock options -- 727
------- -------
Denominator for diluted earnings per share -
weighted-average shares outstanding
and assumed conversions 94,678 92,552
======= =======
Basic earnings per share $ 0.02 $ 0.08
======= =======
Diluted earnings per share $ 0.02 $ 0.08
======= =======
9. 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 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 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 SFAS No. 133 and any changes in fair value are recorded in accumulated 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 $12 thousand
gain related to hedge ineffectiveness during the three months ended March 31,
2007, and a loss of approximately $0.6 million during the three months ended
March 31, 2006.
13
The estimated March 31, 2007 fair value of the Company's oil and natural gas
derivatives resulted in an unrealized gain of $0.9 million ($0.6 million net of
tax) which is recognized in accumulated other comprehensive income. Based upon
March 31, 2007 oil and natural gas commodity prices, approximately $0.8 million
of the gain deferred in accumulated other comprehensive income could potentially
increase gross revenues over the next twelve months. These derivative agreements
expire at various dates through December 31, 2008.
Net settlements under these contracts increased (decreased) oil and natural gas
revenues by $1,850,000 and ($1,168,000) for the three months ended March 31,
2007 and 2006, respectively, as a result of hedging transactions.
The notional amount is equal to the total net volumetric hedge position of the
Company during the periods presented. As of March 31, 2007, the positions
effectively hedge approximately 41% of the estimated proved developed natural
gas production and 28% of the estimated proved developed oil production during
the respective terms of the hedging agreements. The fair values of the hedges
are based on the difference between the strike price and the New York Mercantile
Exchange future prices for the applicable trading months.
The fair value of the hedging agreements is recorded on the consolidated balance
sheet as assets or liabilities. The estimated fair value of the hedging
agreements as of March 31, 2007, is provided below:
Estimated
Fair Value
Ceiling Asset (Liability)
Notional Floor Price Price March 31, 2007
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ ------------ -----------------
NATURAL GAS (MMBTU)
Apr 2007 - May 2007 Collar 800,000 $ 8.00 $10.60 $376
Apr 2007 - Dec 2007 Collar 3,260,000 $ 7.00 $11.50 318
----
Total Natural Gas 694
----
CRUDE OIL (BBLS)
Apr 2007 - July 2007 Collar 48,000 $50.00 $74.00 (85)
Jan 2008 - Dec 2008 Collar 40,000 $55.00 $83.00 (62)
Aug 2007 - April 2008 Collar 54,000 $60.00 $82.00 (10)
May 2008 - July 2008 Collar 15,000 $60.00 $82.00 (7)
Apr 2007 - July 2007 Collar 15,000 $60.00 $96.10 14
Aug 2007 - July 2008 Collar 52,000 $65.00 $93.15 161
Aug 2007 - July 2008 Collar 40,000 $70.00 $87.40 192
----
Total Crude Oil 203
----
$897
====
See Note 12, Subsequent Events, for additional information.
14
10. STOCK-BASED COMPENSATION
STOCK OPTIONS
Effective January 1, 2006, the Company adopted the provisions of SFAS No. 123R,
"Shared-Based Payment," using the modified prospective method. SFAS 123R
replaces SFAS No. 123, "Accounting for Stock-Based Compensation" and amends SFAS
No. 95, "Statement of Cash Flows." SFAS No. 123R addresses the accounting for
share-based payment transactions in which an enterprise received 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.
SFAS No. 123R eliminates the ability to account for share-based compensation
transactions using Accounting Principles Board ("APB") Opinion No. 25,
"Accounting for Stock Issued to Employees", and generally requires instead that
such transactions be accounted for using the fair-value based method. Prior to
adoption of SFAS No. 123R, the Company followed the intrinsic value method in
accordance with APB No. 25 to account for stock options.
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 $87,000 was recorded in the
three months ended March 31, 2007 and $82,000 was recognized in the three month
period ended March 31, 2006.
11. ASSET RETIREMENT OBLIGATIONS
The Company follows SFAS No. 143, "Accounting for Asset Retirement Obligations,"
which 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. The Company records gains or losses
from settlements as an adjustment to the full cost pool. This standard requires
the Company to record a liability for the fair value of our dismantlement and
abandonment costs, excluding salvage values.
15
The following table describes the change in the Company's asset retirement
obligations for the three months ended March 31, 2007, and for the year ended
December 31, 2006 (thousands of dollars):
Asset retirement obligation at December 31, 2005 $11,964
Additional retirement obligations recorded in 2006 4,559
Settlements during 2006 (6,026)
Revisions to estimates and other changes during 2006 10,723
Accretion expense for 2006 1,588
-------
Asset retirement obligation at December 31, 2006 22,808
Additional retirement obligations recorded in 2007 --
Settlements during 2007 (642)
Revisions to estimates and other changes during 2007 (111)
Accretion expense for 2007 553
-------
Asset retirement obligation at March 31, 2007 $22,608
=======
The Company's revisions to estimates represent changes to the expected amount
and timing of payments to settle the asset retirement obligations. These changes
primarily result from obtaining new information about the timing of our
obligations to plug the natural gas and oil wells and costs to do so.
12. SUBSEQUENT EVENTS
During April 2007, the Company entered into a series of hedging contracts to
hedge a portion of its natural gas production for 2008. The hedge contracts were
completed in the form of costless collars. The costless collars provide the
Company with a lower limit floor price and an upper limit ceiling price on the
hedged volumes. The floor price represents the lowest price the Company will
receive for the hedged volumes, while the ceiling price represents the highest
price the Company will receive for the hedged volumes. The costless collars will
be settled monthly based on the NYMEX futures contract of oil and natural gas
during each respective month. The Notional Amount is equal to the total net
volumetric hedge position of the Company during the periods presented. These
hedge contracts, combined with those discussed in Note 9, effectively hedge
approximately 39% of the estimated proved developed natural gas production, and
28% of the estimated proved developed oil production during the respective terms
of the hedging agreements. The following table summarizes the contracted volumes
and prices for the costless collars.
Notional Floor Price Ceiling Price
Amount ($ per unit) ($ per unit)
--------- ------------ -------------
NATURAL GAS (MMBTU)
Jan 2008 - Dec 2008 2,230,000 $7.00 $12.15
Jan 2008 - Dec 2008 1,010,000 $7.50 $11.50
16
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL.
The Company's business plan has been modified 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 crude oil and natural gas pricing, management modified its business strategy
while retaining its position in the Gulf Coast region of south Louisiana and
Texas and leveraged off the higher cash flows generated from these properties to
acquire exploration opportunities with large acreage positions, multiple
repeatable wells and longer-lived reserves.
OPERATIONS OVERVIEW. The Company is on track and aggressively pursuing its
drilling with other growth activities whereby it has set targeted spending of
$127 million during 2007. As an integral part of these efforts, the Company has
created a balanced portfolio of projects that it believes will reduce its risk
profile, thereby improving success, and maintain its exposure to its historical
high returns of and on capital deployed while at the same time developing longer
lived reserves.
EAST TEXAS AREA
In 2006, Meridian moved East Texas activities from planning to production and
development. This play has become a primary area of focus for the Company's 2007
budget. Based on analogues in the nearby fields and the success by comparison of
the first well Meridian completed in the Austin Chalk, the Blackstone Minerals
("BSM") No. 1 well, the Company has accelerated its holdings to over 33,000
acres and executed joint ventures for the development of the play over the
course of the next three to five years. Accordingly, Meridian has committed 37%
of its capital budget to generate and participate in the drilling of at least
seven wells in the area during 2007.
The first well (BSM No. 1) was completed during October 2006 and tested at
initial rates of 27 Mmcf/d and 1,300 BOPD.
Currently, the Company has three active rigs operating in the East Texas Austin
Chalk play--one well scheduled to be tested within the next 10 to 15 days, and
one well recently spud and another beginning the lateral drilling.
The Katherine Leary No. 1 well recently reached total depth of its second
horizontal lateral. The first lateral extends approximately 5,300 feet in length
with the second extending approximately 5,600 feet for a total wellbore exposure
in the Austin Chalk of 10,900 feet. The well is currently being completed and
will be tested once the drilling rig has been removed from the surface location.
Barring any unforeseen delays, this operation will take place in the next 10 to
15 days.
A rig was moved on location at the BSM No. 2 to drill a single lateral in the
Austin Chalk formation. Since the drilling of the vertical section during 2006,
this well was previously completed as a Woodbine producer but reserves did not
prove to be economic. A window was cut into the wellbore at approximately 13,100
feet to begin the lateral. The horizontal lateral will extend to approximately
6,100 feet.
17
A second new rig was moved onto its location at the BSM No. 4 location. This
well is designed to drill vertically to approximately 13,000 feet before turning
horizontal for another single lateral test of approximately 5,000 feet in the
Austin Chalk formation. The well is currently drilling at approximately 2,500
feet.
The Company is testing the drilling of single lateral wells versus dual lateral
wells to determine the best methods to develop the field, improve drilling time,
improve ultimate recoveries of reserves and fully develop the play in a timely
manner at less initial cost. Lease acreage and unitization do play into the
locations and decisions where this concept, if successful, can be applied.
The Company and its joint venture partners currently hold approximately 33,000
gross acres in the play. The Company is aggressively working to increase its
position in this very competitive area and is in the final stages of finalizing
title and documentation of an additional 20,000 plus gross acres. With the
additional acreage, the number of possible locations increases in general terms
to approximately fifty, thereby providing the Company with enough drilling
inventory for the next several years. The Company anticipates that two rigs will
remain in the East Texas area to develop the play for the foreseeable future.
Meridian is the operator of the field on behalf of its joint venture partners
and will generally hold between 37% and 75% WI.
TEXAS GULF COAST AND OFFSHORE
In August of 2006, the Company purchased all of the Texas Gulf Coast assets of
Vintage Petroleum LLC. Meridian paid approximately $21 million in cash and
stock. While a portion of the assets were comprised of producing properties, a
primary reason for the acquisition was the near and long term upside of
exploitation and exploration assets identified on the 3-D seismic data over the
properties.
For 2007, the Company has scheduled four wells in the Nueces Bay project area.
To date, it has participated as a non-operating working interest partner (23%
WI) in three wells. Two wells have been completed and placed on production and
one is currently under evaluation and testing.
The outside operated ST 976 No. 1 well on the East White Point prospect located
in the Nueces Bay project area was fracture stimulated in one of several deep
Frio sands. The well was tested at a gross daily flow rate of approximately 3.2
million cubic feet of gas per day and 340 barrels of condensate. As previously
announced, this well was drilled to a depth of approximately 13,800 feet
measured depth ("MD") and had apparent natural gas pay in five Frio sand
intervals. Meridian owns approximately 23% working interest in this well. The
operator of this well has proposed the drilling of two additional wells in the
area.
In addition, the Company has drilled one scheduled well in Nueces Bay and is
currently conducting testing operations for completion of that well. The ST 786
No. 12 well on the Indian Point prospect located in the Nueces Bay project area
was fracture stimulated in one of two deep Anderson sand sections of the lower
Frio formation. The results of the fracture stimulation were less than expected,
therefore the Company will move up the hole to test and fracture stimulate the
upper portion of the Anderson (Frio) sand. This well was drilled to a depth of
approximately 15,150 feet MD and had apparent natural gas pay in six Frio sand
intervals. Depending on the results of this well, the Company anticipates one
additional well for this area in 2007 and could have an additional three to four
prospective locations offset to the well. The Company owns approximately 49%
working interest in this well and is the operator.
The High Island 29 prospect is located in the shallow waters of the Gulf of
Mexico near the Company's High Island 55 production platform. The primary
objective of this well is the Upper Miocene formation at a depth of
approximately 8,000 feet. Recently, the Company was the successful bidder in the
State lease sale on 720 additional acres needed to secure the prospect. The
Company has a target time frame of the second half of the year to spud the well.
18
The Brazos 388-S prospect is also located in the shallow waters of the Gulf of
Mexico. The primary objective of the well is the Siph-D sand formation at a
depth of approximately 13,000 feet. The Company currently holds a 100% working
interest in the prospect and has a targeted drilling time frame for the second
half of the year to spud the well.
MID-CONTINENT
As part of the Company's plan to diversify its asset portfolio, the Company
acquired acreage (approximately 22,000 acres) offsetting a producing field in
the Mid-Continent region of north central Oklahoma. Since acquiring its position
to exploit this Hunton/Woodford de-watering play, the Company has drilled four
wells including one saltwater disposal well.
As previously announced, the Company completed the drilling of its first two gas
wells, the Enterprise No. 7-1 and the Constellation No. 8-1. They were completed
in the Hunton formation at a depth of approximately 7,500 feet. As expected,
initial production from the two wells is primarily water with small amounts of
natural gas which is expected to gradually increase to commercial quantities of
natural gas with less water over the coming months. Additionally, in the same
play, the Company drilled and completed the Constellation No. 8-2 and is
preparing it for production.
The Company operates the field and owns approximately 80% working interest. This
play is on the Company's list of primary focus areas for growth and has plans to
drill a minimum of fourteen wells here during 2007.
SOUTH LOUISIANA AND OFFSHORE
This mainstay focus area of the Company holds significant potential for
increased reserves and production during 2007. South Louisiana remains a core
area for Meridian where the Company has built a large knowledge and information
base that it believes holds significant value for the development of future
projects. Although the Company is expanding beyond our traditional footprint of
South Louisiana, it has not pulled out of this area, and continues to generate
and participate in opportunities that target larger reserves.
Currently, in offshore Louisiana, the Company is negotiating for a rig to move
onto its West Cameron 332 block location which is expected to happen in the next
few weeks. The targeted formation is the Upper Miocene sand at a depth of
approximately 13,800 feet. Meridian owns 17% working interest before casing
point and 37% working interest after casing point and will be the operator.
The previously announced E. W. Brown No. 1 well was completed and tested in the
Hackberry formation. The electric logs indicated approximately 32 gross feet of
apparent pay in the targeted sands. The well was tested at a gross daily flow
rate of approximately 3.6 million cubic feet of natural gas per day and 240
barrels of condensate. However, characteristics of the well test raised
questions regarding the economics of a completion relative to the potential size
of the reservoir. The Company is considering a fracture stimulation to test this
well's limits of recovery and is currently evaluating the future utility of the
well relative to the costs of completing the construction of production
facilities and pipeline.
19
DEEP ARCHTOP
The Company is continuing to develop its Deep Archtop prospect for drilling. It
recently increased its current leasehold position to approximately 5,000 acres
on the prospect by being the successful unopposed bidder in a recent State of
Louisiana lease sale.
The project is designed to test a Jurassic Cotton Valley four-way closure in the
Biloxi Marshlands area of St. Bernard Parish Louisiana. This 30,000-foot
prospect has over 14,400 acres of closure, imaged by 3-D seismic. The Company
will spend the coming year in pre-drill work, followed by 300-plus days to drill
the well which is estimated to cost $60 million. The shallow marshlands water
location provides the potential for significant savings in drilling the test
well and post development infrastructure. Similarly sized offshore projects
typically cost much more and require longer periods of time to construct the
necessary pipelines and production facilities. Meridian owns production
facilities and pipelines in the immediate area. Meridian intends to retain and
pay its share of approximately 20% working interest to the casing point in this
well.
The spud date for the well is difficult to predict at this time as there are
numerous variables that can affect the timing of the well. However, the Company
has set a target date of mid-year 2008.
UNCONVENTIONAL RESOURCE PLAYS
The Company's push for diversity and growth continue to develop in the Delaware
Basin, Illinois Basin and Palo Duro Basin.
In the Delaware Basin, the Company and its joint venture partner are currently
evaluating drilling locations. The group owns approximately 85,000 acres in the
area and anticipates that it will drill a minimum of two wells during 2007.
In the New Albany Shale Play in the Illinois Basin, the Company continues to
acquire leases and currently owns an approximate 30,000-acre lease position.
Drilling plans for the initial wells in the area are being evaluated. The
Company's working interest in the play is 92% with Meridian as operator.
In the Palo Duro Basin Play, the Company owns approximately 35,000 gross acres.
Several operators in the basin are in various stages of testing optimal drilling
and completion techniques for wells in the area. An operator has recently
reported drilling and completing a successful well that is immediately adjacent
to a portion of the Company's acreage. The Company is currently evaluating the
development of the basin and its plans for the play.
OTHER CONDITIONS
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, 2007,
was $50.30 per barrel compared to $49.23 per barrel for the three months ended
March 31, 2006, and $53.06 per barrel for the three months ended December 31,
2006. Our average natural gas price (after adjustments for hedging activities)
for the three months ended March 31, 2007, was $7.34 per Mcf compared to $9.20
per Mcf for the three months ended March 31, 2006, and $7.19 per Mcf for the
three months ended December 31, 2006. 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
20
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, 2006, for further discussion.
RESULTS OF OPERATIONS
THREE MONTHS ENDED MARCH 31, 2007 COMPARED TO THREE MONTHS ENDED MARCH 31, 2006
OPERATING REVENUES. First quarter 2007 oil and natural gas revenues, which
include oil and natural gas hedging activities (see Note 9 of Notes to
Consolidated Financial Statements), decreased $17.7 million (31%) as compared to
first quarter 2006 revenues due to a 15% decrease in average commodity prices on
a natural gas equivalent basis, and an 18% decrease in production volumes
partially offset in part by the Company's hedging program. Oil and natural gas
production volumes totaled 5,257 Mmcfe for the first quarter of 2007 compared to
6,432 Mmcfe for the comparable period of 2006. Our average daily production
decreased from 71 Mmcfe during the first quarter of 2006 to 58 Mmcfe for the
first quarter of 2007.
First quarter 2006 production was generally higher as a result of returning to
full production, 100% of the wells that were previously shut in due to the
Katrina and Rita hurricanes. In addition to the natural declines of existing
production that occurred between the periods, the Company experienced
intermediate production declines because of delays in the replacement of its
production due to the unavailability of rigs and equipment in the Company's East
Texas Austin Chalk development program during the first three quarters of 2006.
These delays prevented the Company from timely drilling the laterals in each of
four wells drilled to the Austin Chalk and delayed the addition of replacement
of normal production declines during 2006 and the first quarter of 2007.
Since the third quarter of 2006, the Company has taken an aggressive approach to
increase its acreage position and drilling activities in this prolific play and
has contracted for the purchase of one rig and a twelve-month lease of an
additional rig that will better insure an uninterrupted drilling and completion
schedule and the replacement of production and reserves. Three rigs are
currently operating in the area, with plans to drill at least seven total wells
in the immediate area during 2007 and to maintain at least two rigs working in
this play for the foreseeable future. It is anticipated that the second
completed well, the Katherine Leary No. 1, will be ready to be tested and placed
on production within the next 10-15 days after the rig is released and the
production pipeline is connected. Although oil and natural gas prices for the
industry in general have experienced a marked decline since the first quarter of
2006, the Company's effective hedging strategy continues to partially insulate
it against the total impact of such price declines.
21
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the three months ended March 31, 2007 and
2006:
THREE MONTHS
ENDED MARCH 31,
----------------- INCREASE
2007 2006 (DECREASE)
------- ------- ----------
Production Volumes:
Oil (Mbbl) 249 224 11%
Natural gas (MMcf) 3,764 5,087 (26%)
Mmcfe 5,257 6,432 (18%)
Average Sales Prices:
Oil (per Bbl) $ 50.30 $ 49.23 2%
Natural gas (per Mcf) $ 7.34 $ 9.20 (20%)
Mmcfe $ 7.64 $ 8.99 (15%)
Operating Revenues (000's):
Oil $12,519 $11,034 13%
Natural gas $27,624 $46,793 (41%)
------- -------
Total Operating Revenues $40,143 $57,827 (31%)
======= =======
OPERATING EXPENSES. Oil and natural gas operating expenses on an aggregate basis
increased $3.2 million (71%) to $7.8 million during the first quarter of 2007,
compared to $4.6 million in the first quarter of 2006. On a unit basis, lease
operating expenses increased $0.77 per Mcfe to $1.48 per Mcfe for the first
quarter of 2007 from $0.71 per Mcfe for the first quarter of 2006. Oil and
natural gas operating expenses increased primarily due to significantly higher
insurance costs, industry wide increases in service costs and increased
maintenance-related activities. For the year beginning in May 2006 through April
2007 premiums increased over 450% from the prior premium year. During the first
quarter of 2007 insurance premiums increased by $1.4 million and represented 44%
of the difference in lease operating expenses between the quarters. The
remaining $1.8 million increase in operating expenses was associated with the
addition of producing wells and one-time costs related to production and
facilities including compression, storage and repairs. Although the company's
insurance costs rose for the period from May 2006 through April 2007, we
anticipate those costs to moderate during 2007. We continue to insure our assets
with improved coverage as a safeguard against losses for the Company in the
event of another hurricane. The increase in the per Mcfe rate was additionally
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 $2.8 million for the first quarter of 2007, compared to $2.7
million during the same period in 2006 primarily because of an increase in oil
volumes and 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 $0.373
per Mcf for natural gas, an increase from $0.252 per Mcf for the first half of
2006. On an equivalent unit of production basis, severance and ad valorem taxes
increased to $0.54 per Mcfe from $0.43 per Mcfe for the comparable three-month
period.
22
DEPLETION AND DEPRECIATION. Depletion and depreciation expense decreased $8.5
million (29%) during the first quarter of 2007 to $21.0 million, from $29.5
million for the same period of 2006. This was primarily the result of a decrease
in the depletion rate as compared to the 2006 period and the decrease in oil and
natural gas production. On a unit basis, depletion and depreciation expense
decreased by $0.60 per Mcfe, to $3.99 per Mcfe for the three months ended March
31, 2007, compared to $4.59 per Mcfe for the same period in 2006. The rate
decrease between the periods was due to the impact of the impairment of
long-lived assets recognized during the third quarter of 2006.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense decreased
$1.2 million (24%) to $3.9 million compared to $5.1 million for 2006. The
decrease between the periods was due to lower accounting, legal and other
professional fees. On an equivalent unit of production basis, general and
administrative expenses decreased $0.05 per Mcfe to $0.74 per Mcfe for the first
quarter of 2007 compared to $0.79 per Mcfe for the comparable 2006 period
primarily due to lower production rates between the periods. Stock-based
compensation expense of approximately $87,000 was recognized in the three months
ended March 31, 2007 compared to $82,000 for the three month period ended March
31, 2006.
HURRICANE DAMAGE REPAIRS. This reduction was due to no additional costs related
to repairs during the first quarter of 2007.
INTEREST EXPENSE. Interest expense increased $0.2 million (12%), to $1.6 million
for the first quarter of 2007 in comparison to the first quarter of 2006. The
increase is primarily a result of increased interest rates.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. During the first quarter of 2007, Meridian's capital
expenditures were internally financed with cash flow from operations and cash on
hand. As of March 31, 2007, the Company had a cash balance of $19.6 million and
working capital of $10.8 million.
CASH FLOWS. Net cash provided by operating activities was $19.1 million for the
three months ended March 31, 2007, as compared to $48.1 million for the same
period in 2006. The decrease of $29.0 million was primarily due to lower crude
oil and natural gas commodity prices and lower production volumes.
Net cash used in investing activities was $28.0 million during the three months
ended March 31, 2007, versus $34.6 million in the first three months of 2006.
Cash flows used in financing activities during the first three months of 2007
were $2.8 million, compared to cash used in financing activities of $0.9 million
during the first three months of 2006. This increase in cash used in financing
activities was primarily due to the reduction in notes payable issued in
connection with the Company's annual insurance renewal.
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 borrowing base under the Credit Facility was redetermined to be $115 million
by the syndication group effective April 30, 2007. As of March 31, 2007,
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
23
determination of our borrowing base is subject to a number of factors, including
quantities of proved oil and natural 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 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.
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, 2007, the three-month LIBOR interest rate
was 5.35%. 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.
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 natural 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 were
approximately $30.6 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.
24
The 2007 capital expenditures plan is currently forecast at approximately $127
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 2007 plan utilizing cash flow from operations and cash on
hand. When appropriate, excess cash flow from operations beyond that needed for
the 2007 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.
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
25
of a significant event for which we are not adequately insured could cause our
actual results to differ from those reflected in our forward-looking statements.
DRILLING RISKS. Our decision to purchase, explore, develop or otherwise exploit
a prospect or property will depend in part on the evaluation of data obtained
through geophysical and geological analysis, production data and engineering
studies, which are inherently imprecise. Therefore, we cannot assure you that
all of our drilling activities will be successful or that we will not drill
uneconomical wells. The occurrence of unexpected drilling results could cause
the actual results to differ from those reflected in our forward-looking
statements.
UNCERTAINTIES IN ESTIMATING RESERVES AND FUTURE NET CASH FLOWS. Reserve
engineering is a subjective process of estimating the recovery from underground
accumulations of oil and natural gas we cannot measure in an exact manner, and
the accuracy of any reserve estimate is a function of the quality of 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, 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, 2007, we had a cushion (i.e. the excess of the ceiling over our
capitalized costs) of approximately $110 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, 2007. 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.
26
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 on
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, 2007, the
positions effectively hedge approximately 41% of the estimated proved developed
natural gas production and 28% of the estimated 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.
27
Estimated
Fair Value
Asset (Liability)
Notional Floor Price Ceiling Price March 31, 2007
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ ------------- -----------------
NATURAL GAS (MMBTU)
Apr 2007 - May 2007 Collar 800,000 $8.00 $10.60 $376
Apr 2007 - Dec 2007 Collar 3,260,000 $7.00 $11.50 318
----
Total Natural Gas 694
----
CRUDE OIL (BBLS)
Apr 2007 - July 2007 Collar 48,000 $50.00 $74.00 (85)
Jan 2008 - Dec 2008 Collar 40,000 $55.00 $83.00 (62)
Aug 2007 - April 2008 Collar 54,000 $60.00 $82.00 (10)
Apr 2008 - July 2008 Collar 15,000 $60.00 $82.00 (7)
Apr 2007 - July 2007 Collar 15,000 $60.00 $96.10 14
Aug 2007 - July 2008 Collar 52,000 $65.00 $93.15 161
Aug 2007 - July 2008 Collar 40,000 $70.00 $87.40 192
----
Total Crude Oil 203
----
$897
====
The above excludes hedges entered into after March 31, 2007; see Note 12,
Subsequent Events, of the Notes to Consolidated Financial Statements for
additional information.
ITEM 4. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
We conducted an evaluation under the supervision of and with the participation
of Meridian's management, including our Chief Executive Officer, President 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 2007.
Based upon that evaluation, our Chief Executive Officer, President 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 2007 that
could significantly affect these controls.
CHANGES IN INTERNAL CONTROLS
During the three month period ended March 31, 2007, 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.
28
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, willful misconduct and breach of
fiduciary duty 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. Mr. James Bond has been added as a defendant
by Hawkins claiming Mr. Bond, when he was General Manager of Hawkins, did not
have the right to consent, could not consent or breached his fiduciary duty to
Hawkins if he did consent to all actions taken by Meridian. The Company has not
provided any amount for this matter in its financial statements at March 31,
2007.
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 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 Company's
oil and natural gas operations. The Company, in certain instances, has
indemnified third parties from the claims made in these lawsuits. In three of
the lawsuits, Shell Oil Company and SWPI LP have demanded indemnity and defense
from Meridian; Meridian has denied such demands. The Company has not provided
any amount for this matter in its financial statements at March 31, 2007.
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, 2006. There have been no
changes to these risk factors during the quarter ended March 31, 2007.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Following is a summary of our repurchase activity, for the three-month period
ending March 31, 2007:
ISSUER PURCHASES OF EQUITY SECURITIES
TOTAL
NUMBER OF TOTAL NUMBER OF SHARES APPROXIMATE DOLLAR VALUE
SHARES AVERAGE PRICE PURCHASED AS PART OF A OF SHARES THAT MAY YET BE
PERIOD PURCHASED PAID PER SHARE PUBLICLY ANNOUNCED PLAN (A) PURCHASED UNDER THE PLAN DURING 2007
------ --------- -------------- --------------------------- ------------------------------------
January 2007 --
February 2007 --
March 2007 150,000 $2.35 150,000 $4,648,000
------- ----- ------- ----------
Total 150,000 $2.35 150,000 $4,648,000
======= ===== ======= ==========
29
(a) In March 2007, our Board of Directors authorized the repurchase in the open
market or through privately negotiated transactions up to $5 million worth of
common shares per year over the next three years. The timing, volume, and nature
of share repurchases will be at the discretion of management, depending on
market conditions, applicable securities laws, and other factors. In March 2007,
the Company repurchased 150,000 common shares in the open market at an aggregate
cost of $352,000. Such shares are reflected in the accompanying Consolidated
Balance Sheet as "treasury stock." See Note 7 of the Notes to Consolidated
Financial Statements. It is our intent to continue this program through this and
future years.
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.
30
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, 2007 By: /s/ LLOYD V. DELANO
------------------------------------
Lloyd V. DeLano
Senior Vice President
Chief Accounting Officer
31
EXHIBIT INDEX
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.
32