UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2005
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 of incorporation) (I.R.S. Employer
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
Securities registered pursuant to Section 12(b) of the Act:
(Title of each class) (Name of each exchange
Common Stock, $0.01 par value on which registered)
Rights to Purchase Preferred Shares New York Stock Exchange
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
----------
Indicate by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act. Yes [ ] No [X]
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes [ ] No [X]
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
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Page 1 of 87
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ X ]
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]
Aggregate market value of shares of common stock held by
non-affiliates of the Registrant at June 30, 2005 $410,169,664
Number of shares of common stock outstanding at March 1, 2006: 86,838,554
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Form (Items 10, 11, 12, 13 and 14)
is incorporated by reference from the registrant's Proxy Statement to be filed
on or before May 1, 2006.
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THE MERIDIAN RESOURCE CORPORATION
INDEX TO FORM 10-K
Page
----
PART I
Item 1. Business 4
Item 1A. Risk Factors 14
Item 1B. Unresolved Staff Comments 19
Item 2. Properties 19
Item 3. Legal Proceedings 19
Item 4. Submission of Matters to a Vote of Security Holders 20
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities 21
Item 6. Selected Financial Data 22
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 23
Item 7.A. Quantitative and Qualitative Disclosures about Market Risk 36
Item 8. Financial Statements and Supplementary Data 39
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 71
Item 9.A. Controls and Procedures 71
PART III
Item 10. Directors and Executive Officers of the Registrant 72
Item 11. Executive Compensation 72
Item 12. Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters 72
Item 13. Certain Relationships and Related Transactions 72
Item 14. Principal Accountant Fees and Services 72
PART IV
Item 15. Exhibits and Financial Statement Schedules 73
Signatures 77
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PART I
ITEM 1. BUSINESS
GENERAL
The Meridian Resource Corporation ("Meridian" or the "Company") is an
independent oil and natural gas company that explores for, acquires and develops
oil and natural gas properties utilizing 3-D seismic technology. Our operations
have historically focused on the onshore oil and gas regions in south Louisiana,
the Texas Gulf Coast and offshore in the Gulf of Mexico. As of December 31,
2005, we had proved reserves of 111 Bcfe with a present value of future net cash
flows before income taxes of approximately $681 million ($557 million after
tax). Seventy-two percent (72%) of our proved reserves were natural gas and
approximately seventy-five percent (75%) were classified as proved developed. We
own interests in 19 fields and 104 wells, and we operate approximately 90% of
our total production.
We have historically generated the majority of our exploration projects. We
believe that we are among the leaders in the industry in the application of 3-D
seismic technology and have participated in the discovery of more than 800 Bcfe
of new reserves since 1992. We also believe we have a competitive advantage in
the areas where we operate because of our large inventory of lease acreage,
seismic data coverage and experienced geotechnical, land and operational staff.
Our people, high cash flows, strategic acreage positions and database of 2-D and
3-D seismic data provide us with a significant presence in the core Gulf Coast
area and beyond, enabling us to exploit multiple exploratory and development
prospects in multiple basins. The Company's goal is to balance its current
capital expenditures such that it can add reserves and production from
longer-lived reserves to equate up to 50% of total production and reserves.
The key elements of our strategy are as follows:
- Generate reserve additions through exploration, exploitation, development
and acquisition of a risk balanced portfolio of high potential projects;
- Supplement and balance our geographic focus in the mature south Louisiana
and south Texas Gulf Coast core producing areas, with newly-developed
resource play opportunities that can generate substantial reserve additions
and increase the average reserve life for the Company;
- Apply the latest technology to a rigorous process in the generation and
development of lower-risk exploration prospects, utilizing 3-D seismic and
other technological advances to maximize our probability of success,
optimize well locations and reduce our finding costs;
- Maximize percentage ownership in each drilling prospect relative to the
probability of success, increasing the impact of discoveries on shareholder
value; and
- Maintain operational control to manage quality, costs and timing of our
drilling and production activities.
We currently have interests in leases and options to lease acreage in
approximately 163,000 gross acres in Louisiana, Texas and the Gulf of Mexico,
including approximately 35,000 net acres located in unconventional gas regions.
We also have rights or access to approximately 8,000 square miles of 3-D seismic
data, which we believe to be one of the largest positions held by a company of
our size operating in our core areas of operation.
Meridian was incorporated in Texas in 1990, with headquarters located at 1401
Enclave Parkway, Suite 300, Houston, Texas 77077. The Company's common stock is
traded on the New York Stock Exchange under the
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ticker symbol "TMR." You can locate additional information, including the
Company's filings with the Securities and Exchange Commission ("SEC"), on the
internet at www.tmrc.com and www.sec.gov.
EXPLORATION STRATEGY
Meridian has traditionally focused its exploration strategy in areas where large
accumulations of oil and natural gas have been found and where we believe
substantial new oil and natural gas reserve additions can be achieved. Our
exploration programs have been extensively filtered by the use of 3-D seismic
technology, including the latest, state-of-the-art interpretation techniques to
mitigate risks and look for indications of hydrocarbons where standard methods
have not identified similar opportunities. We also attempt to match our
exploration risks with expected results by retaining working interests in the
range between 50% and 100% in the Company's onshore wells. Our working interests
may vary in certain prospects, depending on participation structure, the ability
to offset potential assessed risk, capital availability and other factors. As a
result of our disciplined method of combining both sub-surface geology and 3-D
seismic technology in our exploration, plus our attention to all technical
aspects, we believe that we are able to develop a more accurate definition of
the risk profile of exploration prospects and plays than was previously
available using traditional exploration techniques. We therefore believe that
our reliance on technology will increase our probability of success and reduce
our dry-hole costs compared to alternatives that do not place the same emphasis
on technical detail.
Our business strategy further includes the pursuit and development of a balanced
exploration inventory, geologically and geographically, including deeper
higher-risk, yet larger potential prospects, along with shallower, lower-risk
plays with large acreage positions that are supported by seismically-driven
hydrocarbon indicators. Together, these allow for repeatable, multiple-well
extensions.
In addition, we have extended our exploration inventory (and therefore our
strategy) to include multiple unconventional (tight gas) and resource
(shale-styled) plays. As with our conventional exploration efforts, we believe
that we will have a competitive advantage in our expanded areas of exploration
because of our approach to each - retaining the best of experienced technical
teams, who understand not only the exploration aspects, but also the crucial
methods and techniques best suited for drilling and completion activities in
each area. As we proceed, we will continue to better control our positions by
acquiring large acreage positions and controlling our costs. We believe that our
continued, methodical application of the latest technology to the development of
exploration concepts, as well as to drilling and completion procedures in these
new and expanded areas of exploration, will provide the Company continued
success in the future development of new oil and gas reserves.
We believe that this expansion will further improve the probability of success,
reduce dry-hole costs and allow us to capitalize on the current high cash flows
from our short-lived reserve basin in the Gulf Coast region. These new plays,
while offering considerably reduced rates of production per well, offer more
opportunities for development wells after the play is proved. Collectively, it
is anticipated that the extension of our exploration effort into the
unconventional tight or shale gas plays can provide substantial reserve
additions and more predictable production rate increases.
As a part of our effort to mitigate the risks associated with any new
exploration play, we will continue to apply a rigorous and disciplined review of
each, utilizing the latest in technological advances, including both geophysical
and geochemical techniques, with respect to analysis, evaluation and
completions.
OIL AND GAS PROPERTIES
The following table sets forth production and reserve information by region with
respect to our proved oil and natural gas reserves as of December 31, 2005. The
reserve volumes were reviewed by T. J. Smith & Company, Inc., independent
reservoir engineers.
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GULF OF
LOUISIANA MEXICO TOTAL
--------- ------- ---------
PRODUCTION FOR THE YEAR ENDED DECEMBER 31, 2005
Oil (MBbls) 828 54 882
Natural Gas (MMcf) 19,886 604 20,490
RESERVES AS OF DECEMBER 31, 2005
Oil (MBbls) 4,273 904 5,177
Natural Gas (MMcf) 70,430 9,487 79,917
ESTIMATED FUTURE NET CASH FLOWS ($000)(1)............................. $903,266
PRESENT VALUE OF FUTURE NET CASH FLOWS BEFORE INCOME TAXES ($000)(1).. $680,987
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS ($000)(1).... $557,203
(1) The Standardized Measure of Discounted Future Net Cash Flows represents the
Present Value of Future Net Cash Flows after income taxes of $123.7
million, discounted at 10%. For calculating the Estimated Future Net Cash
Flows, the Present Value of Future Net Cash Flows and the Standardized
Measure of Discounted Future Net Cash Flows as of December 31, 2005, we
used the expected realized prices at December 31, 2005, which were $59.37
per Bbl of oil and $10.40 per Mcf of natural gas and do not reflect the
impact of hedges.
PRODUCTIVE WELLS
At December 31, 2005, 2004 and 2003, we held interests in the following
productive wells. As of December 31, 2005, we own 24 gross (4.0 net) wells in
the Gulf of Mexico which are outside operated and net to 1.5 oil wells and 2.5
natural gas wells. In addition, of the total well count for 2005, 3 wells (1.1
net) are multiple completions.
2005 2004 2003
----------- ----------- -----------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Oil Wells .......... 35 24 35 22 31 20
Natural Gas Wells .. 69 39 68 34 60 27
--- --- --- --- --- ---
Total ........... 104 63 103 56 91 47
=== === === === === ===
OIL AND NATURAL GAS RESERVES
Presented below are our estimated quantities of proved reserves of crude oil and
natural gas, Future Net Cash Flows, Present Value of Future Net Revenues and the
Standardized Measure of Discounted Future Net Cash Flows as of December 31,
2005. Information set forth in the following table is based on reserve reports
prepared in accordance with the rules and regulations of the SEC. The reserve
estimates were reviewed by T. J. Smith & Company, Inc., independent reservoir
engineers.
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PROVED RESERVES AT DECEMBER 31, 2005
--------------------------------------------------
DEVELOPED DEVELOPED
PRODUCING NON-PRODUCING UNDEVELOPED TOTAL
--------- ------------- ----------- --------
(DOLLARS IN THOUSANDS)
Net Proved Reserves:
Oil (MBbls)...................................................... 1,594 1,898 1,685 5,177
Natural Gas (MMcf)............................................... 34,700 27,824 17,393 79,917
Natural Gas Equivalent (MMcfe)................................... 44,263 39,214 27,502 110,979
Estimated Future Net Cash Flows(1)............................... $903,266
Present Value of Future Net Cash Flows (before income taxes)(1).. $680,987
Standardized Measure of Discounted Future Net Cash Flows(1)...... $557,203
----------
(1) The Standardized Measure of Discounted Future Net Cash Flows represents the
Present Value of Future Net Cash Flows after income taxes of $123.7
million, discounted at 10%. For calculating the Estimated Future Net Cash
Flows, the Present Value of Future Net Cash Flows and the Standardized
Measure of Discounted Future Net Cash Flows as of December 31, 2005, we
used the expected realized prices at December 31, 2005, which were $59.37
per Bbl of oil and $10.40 per Mcf of natural gas and do not reflect the
impact of hedges.
You can read additional reserve information in our Consolidated Financial
Statements and the Supplemental Oil and Gas Information (unaudited) included
elsewhere herein. We have not included estimates of total proved reserves,
comparable to those disclosed herein, in any reports filed with federal
authorities other than the SEC.
In general, our engineers based their estimates of economically recoverable oil
and natural gas reserves and of the future net revenues therefrom on a number of
variable factors and assumptions, such as historical production from the subject
properties, the assumed effects of regulation by governmental agencies and
assumptions concerning future oil and natural gas prices and future operating
costs, all of which may vary considerably from actual results. Therefore, the
actual production, revenues, severance and excise taxes, and development and
operating expenditures with respect to reserves likely will vary from such
estimates, and such variances could be material.
Estimates with respect to proved reserves that we may develop and produce in the
future are often based on volumetric calculations and by analogy to similar
types of reserves rather than actual production history. Estimates based on
these methods are generally less reliable than those based on actual production
history, and subsequent evaluation of the same reserves, based on production
history, will result in variations, which may be substantial, in the estimated
reserves.
In accordance with applicable requirements of the SEC, the estimated discounted
future net revenues from estimated proved reserves are based on prices and costs
as of the date of the estimate unless such prices or costs are contractually
determined at that date. Actual future prices and costs may be materially higher
or lower. Actual future net revenues also will be affected by factors such as
actual production, supply and demand for oil and natural gas, curtailments or
increases in consumption by natural gas purchasers, changes in governmental
regulations or taxation and the impact of inflation on costs.
OIL AND NATURAL GAS DRILLING ACTIVITIES
The following table sets forth the gross and net number of productive and dry
exploratory and development wells that we drilled and completed in 2005, 2004
and 2003.
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GROSS WELLS NET WELLS
------------------------ -------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
---------- --- ----- ---------- ---- -----
EXPLORATORY WELLS
Year ended December 31, 2005 ........ 10 13 23 8.0 10.8 18.8
Year ended December 31, 2004 ........ 16 11 27 14.7 8.9 23.6
Year ended December 31, 2003 ........ 5 1 6 3.8 0.4 4.2
DEVELOPMENT WELLS
Year ended December 31, 2005 ........ 1 -- 1 0.3 -- 0.3
Year ended December 31, 2004 ........ 4 -- 4 3.2 -- 3.2
Year ended December 31, 2003 ........ -- 1 1 -- 0.9 0.9
Meridian had 3 gross (1.9 net) wells in progress at December 31, 2005.
PRODUCTION
The following table summarizes the net volumes of oil and natural gas produced
and sold, and the average prices received with respect to such sales, from all
properties in which Meridian held an interest during 2005, 2004 and 2003.
YEAR ENDED DECEMBER 31,
---------------------------
2005 2004 2003
------- ------- -------
PRODUCTION:
Oil (MBbls) ................................ 882 1,270 1,403
Natural gas (MMcf) ......................... 20,490 27,839 20,142
Natural gas equivalent (MMcfe) ............. 25,781 35,457 28,563
AVERAGE PRICES:
Oil ($/Bbl) ................................ $ 39.29 $ 28.40 $ 24.97
Natural gas ($/Mcf) ........................ $ 7.84 $ 5.98 $ 5.07
Natural gas equivalent ($/Mcfe) ............ $ 7.57 $ 5.71 $ 4.80
PRODUCTION EXPENSES:
Lease operating expenses ($/Mcfe) .......... $ 0.61 $ 0.40 $ 0.39
Severance and ad valorem taxes ($/Mcfe) .... $ 0.34 $ 0.26 $ 0.27
ACREAGE
The following table sets forth the developed and undeveloped oil and natural gas
leasehold acreage in which Meridian held an interest as of December 31, 2005.
Undeveloped acreage is considered to be those lease acres on which wells have
not been drilled or completed to a point that would permit the production of
commercial quantities of oil and natural gas, regardless of whether or not such
acreage contains proved reserves.
DECEMBER 31, 2005
---------------------------------
DEVELOPED UNDEVELOPED
--------------- ---------------
REGION GROSS NET GROSS NET
------ ------ ------ ------ ------
LOUISIANA ........... 31,997 22,931 27,321 22,706
TEXAS ............... -- -- 40,229 20,327
GULF OF MEXICO ...... 29,519 6,088 7,500 2,883
------ ------ ------ ------
TOTAL ............ 61,516 29,019 75,050 45,916
====== ====== ====== ======
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In addition to the above acreage, we currently have options or farm-ins to
acquire leases on approximately 25,267 gross (17,221 net) acres of undeveloped
land located in Louisiana, and 1,750 gross (734 net) acres in Texas. Our fee
holdings of approximately 25 developed acres and 4,300 undeveloped acres have
been included in the acreage table above and have been reduced to reflect the
interest that we have leased to third parties. Our undeveloped acreage,
including optioned acreage, expires during the next three years at the rate of
5,700 acres in 2006, 23,000 acres in 2007, and 12,000 acres in 2008.
GEOLOGIC/LAND AND OPERATIONS GEOPHYSICAL EXPERTISE
Meridian employs approximately 70 full-time non-union employees and 15 contract
employees. This staff includes geologists, geophysicists, land and engineering
staff with over 540 combined years of experience in generating and developing
onshore and offshore prospects in the Louisiana and Texas Gulf Coast region. Our
geologists and geophysicists generate and review all prospects using 2-D and 3-D
seismic technology and analogues to producing wells in the areas of interest.
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MARKETING OF PRODUCTION
We market our production to third parties in a manner consistent with industry
practices. Typically, the oil production is sold at the wellhead at posted
prices, less applicable transportation deductions, and the natural gas is sold
at posted indices, less applicable transportation, gathering and dehydration
charges, adjusted for the quality of natural gas and prevailing supply and
demand conditions. The natural gas production is sold under long- and short-term
contracts (all of which are based on a published index) or in the spot market.
The following table sets forth purchasers of our oil and natural gas that
accounted for more than 10% of total revenues for 2005, 2004 and 2003.
YEAR ENDED DECEMBER 31,
-----------------------
CUSTOMER 2005 2004 2003
-------- ---- ---- ----
Superior Natural Gas ................. 46% 45% 19%
Crosstex/Louisiana Intrastate Gas .... 19% 22% 24%
Conoco, Inc. ......................... -- -- 10%
Other purchasers for our oil and natural gas are available; therefore, we
believe that the loss of any of these purchasers would not have a material
adverse effect on our results of operations.
MARKET CONDITIONS
Our revenues, profitability and future rate of growth substantially depend on
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 our
control. Since 1993, prices for West Texas Intermediate crude have ranged from
$8.00 to $69.91 per Bbl and the Gulf Coast spot market natural gas price at
Henry Hub, Louisiana, has ranged from $1.08 to $15.40 per MMBtu. The average
price we received during the year ended December 31, 2005, was $7.57 per Mcfe
compared to $5.71 per Mcfe during the year ended December 31, 2004. The volatile
nature of energy markets makes it difficult to estimate future prices of oil and
natural gas; however, any prolonged period of depressed prices would have a
material adverse effect on our results of operations and financial condition.
The marketability of our production depends in part on the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities. Federal and state regulation of oil and natural gas
production and transportation, general economic conditions, changes in supply
and changes in demand could adversely affect our ability to produce and market
our oil and natural gas. If market factors were to change dramatically, the
financial impact on us could be substantial. We do not control the availability
of markets and the volatility of product prices is beyond our control and
therefore represents significant risks.
COMPETITION
The oil and natural gas industry is highly competitive for prospects, acreage
and capital. Our competitors include numerous major and independent oil and
natural gas companies, individual proprietors, drilling and income programs and
partnerships. Many of these competitors possess and employ financial and
personnel resources substantially greater than ours and may, therefore, be able
to define, evaluate, bid for and purchase more oil and natural gas properties.
There is intense competition in marketing oil and natural gas production, and
there is competition with other industries to supply the energy and fuel needs
of consumers.
REGULATION
The availability of a ready market for any oil and natural gas production
depends on numerous factors that we do not control. These factors include
regulation of oil and natural gas production, federal and state regulations
governing environmental quality and pollution control, state limits on allowable
rates of production by a well
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or proration unit, the amount of oil and natural gas available for sale, the
availability of adequate pipeline and other transportation and processing
facilities and the marketing of competitive fuels. For example, a productive
natural gas well may be "shut-in" because of an oversupply of natural gas or
lack of available natural gas pipeline capacity in the areas in which we may
conduct operations. State and federal regulations generally are intended to
prevent waste of oil and natural gas, protect rights to produce oil and natural
gas between multiple owners in a common reservoir, control the amount of oil and
natural gas produced by assigning allowable rates of production and control
contamination of the environment. Pipelines are subject to the jurisdiction of
various federal, state and local agencies.
Oil and natural gas production operations are subject to various types of
regulation by state and federal agencies. Legislation affecting the oil and
natural gas industry is under constant review for amendment or expansion. In
addition, numerous departments and agencies, both federal and state, are
authorized by statute to issue rules and regulations that govern the oil and
natural gas industry and its individual members, some of which carry substantial
penalties for failure to comply. The regulatory burden on the oil and natural
gas industry increases our cost of doing business and, consequently, affects our
profitability.
All of our federal offshore oil and gas leases are granted by the federal
government and are administered by the U. S. Minerals Management Service (the
"MMS"). These leases require compliance with detailed federal regulations and
orders that regulate, among other matters, drilling and operations and the
calculation of royalty payments to the federal government. Ownership interests
in these leases generally are restricted to United States citizens and domestic
corporations. The MMS must approve any assignments of these leases or interests
therein.
The federal authorities, as well as many state authorities, require permits for
drilling operations, drilling bonds and reports concerning operations and impose
other requirements relating to the exploration and production of oil and gas.
Individual states also have statutes or regulations addressing conservation
matters, including provisions for the unitization or pooling of oil and gas
properties, the establishment of maximum rates of production from oil and gas
wells and the regulation of spacing, plugging and abandonment of such wells. The
statutes and regulations of the federal authorities, as well as many state
authorities, limit the rates at which we can produce oil and gas on our
properties.
FEDERAL REGULATION. The Federal Energy Regulatory Commission ("FERC") regulates
interstate natural gas pipeline transportation rates and service conditions,
both of which affect the marketing of natural gas produced by us, as well as the
revenues we receive for sales of such natural gas. Since the latter part of
1985, culminating in 1992 in the Order No. 636 series of orders, the FERC has
endeavored to make natural gas transportation more accessible to gas buyers and
sellers on an open and non-discriminatory basis. The FERC believes "open access"
policies are necessary to improve the competitive structure of the interstate
natural gas pipeline industry and to create a regulatory framework that will put
gas sellers into more direct contractual relations with gas buyers. As a result
of the Order No. 636 program, the marketing and pricing of natural gas has been
significantly altered. The interstate pipelines' traditional role as wholesalers
of natural gas has been terminated and replaced by regulations which require
pipelines to provide transportation and storage service to others who buy and
sell natural gas. In addition, on February 9, 2000, FERC issued Order No. 637
and promulgated new regulations designed to refine the Order No. 636 "open
access" policies and revise the rules applicable to capacity release
transactions. These new rules will, among other things, permit existing holders
of firm capacity to release or "sell" their capacity to others at rates in
excess of FERC's regulated rate for transportation services.
It is unclear what impact, if any, these new rules or increased competition
within the natural gas transportation industry will have on us and our gas sales
efforts. It is not possible to predict what, if any, effect the FERC's open
access or future policies will have on us. Additional proposals and/or
proceedings that might affect the natural gas industry may be considered by
FERC, Congress or state regulatory bodies. It is not possible to predict when or
if any of these proposals may become effective or what effect, if any, they may
have on our operations. We do not believe, however, that our operations will be
affected any differently than other gas producers or marketers with which we
compete.
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PRICE CONTROLS. Our sales of natural gas, crude oil, condensate and natural gas
liquids are not regulated and transactions occur at market prices.
STATE REGULATION OF OIL AND NATURAL GAS PRODUCTION. States where we conduct our
oil and natural gas activities regulate the production and sale of oil and
natural gas, including requirements for obtaining drilling permits, the method
of developing new fields, the spacing and operation of wells and the prevention
of waste of natural gas and other resources. In addition, most states regulate
the rate of production and may establish the maximum daily production allowable
for wells on a market demand or conservation basis.
ENVIRONMENTAL REGULATION. Our operations are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. These laws and regulations may
require us to acquire a permit before we commence drilling; restrict the types,
quantities and concentration of various substances that we can release into the
environment in connection with drilling and production activities; limit or
prohibit our drilling activities on certain lands lying within wilderness,
wetlands and other protected areas; and impose substantial liabilities for
pollution resulting from our operations. Moreover, the general trend toward
stricter standards in environmental legislation and regulation is likely to
continue. For instance, as discussed below, legislation has been proposed in
Congress from time to time that would cause certain oil and gas exploration and
production wastes to be classified as "hazardous wastes", which would make the
wastes subject to much more stringent handling and disposal requirements. If
such legislation were enacted, it could have a significant impact on our
operating costs, as well as on the operating costs of the oil and natural gas
industry in general. Initiatives to further regulate the disposal of oil and gas
wastes have also been considered in the past by certain states, and these
various initiatives could have a similar impact on us. We believe that our
current operations substantially comply with applicable environmental laws and
regulations and that continued compliance with existing requirements will not
have a material adverse impact on us.
OPA. The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose
a variety of regulations on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills in United States
waters. A "responsible party" includes the owner or operator of a facility or
vessel, or the lessee or permittee of the area where an offshore facility is
located. The OPA makes each responsible party liable for oil-removal costs and a
variety of public and private damages. While liability limits apply in some
circumstances, a party cannot take advantage of liability limits if the party
caused the spill by gross negligence or willful misconduct or if the spill
resulted from a violation of a federal safety, construction or operating
regulation. The liability limits likewise do not apply if the party fails to
report a spill or to cooperate fully in the cleanup. Few defenses exist to the
liability imposed by the OPA.
The OPA also imposes ongoing requirements on a responsible party, including the
requirement to maintain proof of financial responsibility to be able to cover at
least some costs if a spill occurs. In this regard, the OPA requires the lessee
or permittee of an offshore area in which a covered offshore facility is located
to establish and maintain evidence of financial responsibility in the amount of
$35 million ($10 million if the offshore facility is located landward of the
seaward boundary of a state) to cover liabilities related to a crude oil spill
for which such person is statutorily responsible. The amount of required
financial responsibility may be increased above the minimum amounts to an amount
not exceeding $150 million depending on the risk represented by the quantity or
quality of crude oil that is handled by the facility. The MMS has promulgated
regulations that implement the financial responsibility requirements of the OPA.
Under the MMS regulations, the amount of financial responsibility required for
an offshore facility is increased above the minimum amount if the "worst case"
oil spill volume calculated for the facility exceeds certain limits established
in the regulations.
The OPA also imposes other requirements, such as the preparation of an oil-spill
contingency plan. We have such a plan in place. Failure to comply with ongoing
requirements or inadequate cooperation during a spill may subject a responsible
party to civil or criminal enforcement actions. We are not aware of any action
or event that would subject us to liability under the OPA and we believe that
compliance with the OPA's financial responsibility and other operating
requirements will not have a material adverse impact on us.
-12-
CERCLA. The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, and comparable state statutes
impose liability, without regard to fault or the legality of the original
conduct, on certain classes of persons who are considered to have contributed to
the release of a "hazardous substance" into the environment. These persons
include the owner or operator of the disposal site or sites where the release
occurred and companies that disposed or arranged for the disposal of the
hazardous substances. Under CERCLA, persons or companies that are statutorily
liable for a release could be subject to joint-and-several liability for the
costs of cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources. In addition, it is not
uncommon for neighboring landowners and other third parties to file claims for
personal injury and property damage allegedly caused by the hazardous substances
released into the environment. We have not been notified by any governmental
agency or third party that we are responsible under CERCLA or a comparable state
statute for a release of hazardous substances.
CLEAN WATER ACT. The Federal Water Pollution Control Act of 1972, as amended
(the "Clean Water Act"), imposes restrictions and controls on the discharge of
produced waters and other oil and gas wastes into navigable waters. These
controls have become more stringent over the years, and it is possible that
additional restrictions will be imposed in the future. Permits must be obtained
to discharge pollutants into state and federal waters. Certain state regulations
and the general permits issued under the Federal National Pollutant Discharge
Elimination System program prohibit the discharge of produced waters and sand,
drilling fluids, drill cuttings and certain other substances related to the oil
and gas industry into certain coastal and offshore water. The Clean Water Act
provides for civil, criminal and administrative penalties for unauthorized
discharges for oil and other hazardous substances and imposes liability on
parties responsible for those discharges for the costs of cleaning up any
environmental damage caused by the release and for natural resource damages
resulting from the release. Comparable state statutes impose liability and
authorize penalties in the case of an unauthorized discharge of petroleum or its
derivatives, or other hazardous substances, into state waters. We believe that
our operations comply in all material respects with the requirements of the
Clean Water Act and state statutes enacted to control water pollution.
RESOURCE CONSERVATION AND RECOVERY ACT. The Resource Conservation and Recovery
Act ("RCRA") is the principal federal statute governing the treatment, storage
and disposal of hazardous wastes. RCRA imposes stringent operating requirements,
and liability for failure to meet such requirements, on a person who is either a
"generator" or "transporter" of hazardous waste or an "owner" or "operator" of a
hazardous waste treatment, storage or disposal facility. At present, RCRA
includes a statutory exemption that allows most crude oil and natural gas
exploration and production waste to be classified as nonhazardous waste. A
similar exemption is contained in many of the state counterparts to RCRA. As a
result, we are not required to comply with a substantial portion of RCRA's
requirements because our operations generate minimal quantities of hazardous
wastes. At various times in the past, proposals have been made to amend RCRA to
rescind the exemption that excludes crude oil and natural gas exploration and
production wastes from regulation as hazardous waste. Repeal or modification of
the exemption by administrative, legislative or judicial process, or
modification of similar exemptions in applicable state statutes, would increase
the volume of hazardous waste we are required to manage and dispose of and could
cause us to incur increased operating expenses.
TITLE TO PROPERTIES
As is customary in the oil and natural gas industry, we make only a cursory
review of title to undeveloped oil and natural gas leases at the time we acquire
them. However, before drilling commences, we search the title, and remedy any
material defects before we actually begin drilling the well. To the extent title
opinions or other investigations reflect title defects, we (rather than the
seller or lessor of the undeveloped property) typically are obligated to cure
any such title defects at our expense. If we are unable to remedy or cure any
title defects so that it would not be prudent for us to commence drilling
operations on the property, we could suffer a loss of our entire investment in
the property. We believe that we have good title to our oil and natural gas
properties, some of which are subject to immaterial encumbrances, easements and
restrictions. Under the terms of our credit facility, we may not grant liens on
various properties and must grant to our lenders a mortgage on our oil
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and gas properties of at least 75% of our present value of proved properties.
Our own oil and natural gas properties also typically are subject to royalty and
other similar noncost-bearing interests customary in the industry.
We acquired substantial portions of our 3-D seismic data through licenses and
other similar arrangements. Such licenses contain transfer and other
restrictions customary in the industry.
ITEM 1A. RISK FACTORS
Each of the following risk factors could adversely affect our business,
operating results and financial condition. It is not possible to foresee or
identify all such factors. Investors should not consider this list an exhaustive
statement of all risks and uncertainties. This report also contains
forward-looking statements that involve risks and uncertainties. Our actual
results may differ from those anticipated in these forward-looking statements as
a result of both the risks described below and factors described elsewhere in
this report. You should read the section below entitled "Forward-Looking
Statements" for further discussion of these matters.
OUR INDEBTEDNESS MAY ADVERSELY AFFECT OPERATIONS AND LIMIT OUR GROWTH.
As of December 31, 2005, we had long-term indebtedness of approximately $75.0
million compared to approximately $377.6 million of stockholders' equity. If we
are unable to generate sufficient cash flows from operations in the future to
service our debt, we may need to refinance all or a portion of our existing debt
or to obtain additional financing. Such refinancing or additional financing may
not be possible. Our ability to meet our debt service obligations and to reduce
our total indebtedness will depend on our future performance and our ability to
maintain or increase cash flows from our operations. These outcomes are subject
to general economic conditions and to financial, business and other factors
affecting our operations, many of which we do not control, including the
prevailing market prices for oil and natural gas. Our business may not continue
to generate cash flows at or above current levels.
BORROWING LIMITS UNDER OUR CREDIT FACILITY ARE SUBJECT TO REDETERMINATION.
As of December 31, 2005, we have outstanding indebtedness of $75.0 million under
our revolving credit facility, which is $55 million less than the current limit
to our borrowings under that facility. The borrowing base under that facility is
subject to semi-annual redeterminations by our lenders. Our borrowing base is
determined primarily by our oil and gas reserve amounts. 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. In the event our
then-redetermined borrowing base is less than our outstanding borrowings under
the facility, we will be required to repay the deficit within a 90-day period.
If we are required to repay debt under our credit facility as a result of a
downward borrowing base redetermination, we may not be able to obtain alternate
borrowing sources at commercially reasonable rates.
OUR LENDERS IMPOSE RESTRICTIONS ON US THAT LIMIT OUR ABILITY TO CONDUCT BUSINESS
AND COULD ADVERSELY AFFECT OPERATIONS.
Our credit facility contains restrictive covenants. The restrictive covenants
impose significant operating and financial restraints that could impair our
ability to obtain future financing, to make capital expenditures, to pay
dividends, to engage in mergers or acquisitions, to withstand future downturns
in our business or in the general economy or to otherwise conduct necessary
corporate activities. Furthermore, we have pledged substantially all of our oil
and natural gas properties and the stock of all of our principal operating
subsidiaries as collateral for the indebtedness under our credit facility. If we
are in material default of our obligations under that credit facility, the
lenders are entitled to liens on additional oil and natural gas properties. This
pledge of collateral to our credit facility lenders could impair our ability to
obtain additional financing on favorable terms.
A default under a restrictive covenant could result in the lenders accelerating
the payment of all borrowed
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funds, together with accrued and unpaid interest. We may not be able to remit
such an accelerated payment or to access sufficient funds from alternative
sources to remit any such payment. Even if we could obtain additional financing,
the terms of that financing may not be favorable or acceptable to us.
THE OIL AND NATURAL GAS MARKETS ARE VOLATILE AND EXPOSE US TO FINANCIAL RISKS.
Our profitability, cash flow and the carrying value of our oil and gas
properties are highly dependent on the market prices of oil and natural gas.
Historically, the oil and natural gas markets have proven cyclical and volatile
as a result of factors that are beyond our control. These factors include
changes in tax laws, the level of consumer product demand, weather conditions,
the price and availability of alternative fuels, the price and level of imports
and exports of oil and natural gas, worldwide economic, political and regulatory
conditions, and action taken by the Organization of Petroleum Exporting
Countries.
Any significant decline in oil and natural gas prices or any other unfavorable
market conditions could have a material adverse effect on our financial
condition and on the carrying value of our proved reserves. Consequently, we may
not be able to generate sufficient cash flows from operations to meet our
obligations and to make planned capital expenditures. Price declines may also
affect the measure of discounted future net cash flows of our reserves, a result
that could adversely impact the borrowing base under our credit facility and may
increase the likelihood that we will incur additional impairment charges on our
oil and natural gas properties for financial accounting purposes.
OUR HEDGING TRANSACTIONS MAY NOT ADEQUATELY PREVENT LOSSES.
We cannot predict future oil and natural gas prices with certainty. To manage
our exposure to the risks inherent in such a volatile market, from time to time,
we have entered into commodities futures, swap or option contracts to hedge a
portion of our oil and natural gas production against market price changes.
Hedging transactions are intended to limit the negative effect of future price
declines, but may also prevent us from realizing the benefits of price increases
above the levels reflected in the hedges.
OUR RESERVE ESTIMATES MAY PROVE TO BE INACCURATE AND FUTURE NET CASH FLOWS ARE
UNCERTAIN.
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 assumptions and estimates.
WE DEPEND ON KEY PERSONNEL TO EXECUTE OUR BUSINESS PLANS.
The loss of any key executives or any other key personnel could have a material
adverse effect on our operations. We depend on the efforts and skills of our key
executives, including Joseph A. Reeves, Jr., Chairman of the Board and Chief
Executive Officer, and Michael J. Mayell, President and Chief Operating Officer.
Moreover, as we continue to grow our asset base and the scope of our operations,
our future profitability will depend on our ability to attract and retain
qualified personnel.
WE COMPETE AGAINST SIGNIFICANT PLAYERS IN THE OIL AND NATURAL GAS INDUSTRY, AND
OUR FAILURE IN THE LONG-TERM TO COMPLETE FUTURE ACQUISITIONS SUCCESSFULLY AND
GENERATE COMMERCIAL EXPLORATION AND DEVELOPMENT DRILLING OPPORTUNITIES COULD
REDUCE OUR EARNINGS AND CAUSE REVENUES TO DECLINE.
-15-
The oil and natural gas industry is highly competitive. Our ability to acquire
additional properties and to discover additional reserves depends on our ability
to consummate transactions in this highly competitive environment. We compete
with major oil companies, other independent oil and natural gas companies, and
individual producers and operators. Many of these competitors have access to
greater financial and personnel resources than those to which we have access.
Moreover, the oil and natural gas industry competes with other industries in
supplying the energy and fuel needs of industrial, commercial and other
consumers. Increased competition causing oversupply or depressed prices could
materially adversely affect our revenues.
THE OIL AND NATURAL GAS MARKETS ARE HEAVILY REGULATED.
We are subject to various federal, state and local laws and regulations. These
laws and regulations govern safety, exploration, development, taxation and
environmental matters that are related to the oil and natural gas industry. To
conserve oil and natural gas supplies, regulatory agencies may impose price
controls and may limit our production. Certain laws and regulations require
drilling permits, govern the spacing of wells and the prevention of waste, and
limit the total number of wells drilled or the total allowable production from
successful wells. Other laws and regulations govern the handling, storage,
transportation and disposal of oil and natural gas and any byproducts produced
in oil and natural gas operations. These laws and regulations could materially
adversely impact our operations and our revenues.
Laws and regulations that affect us may change from time to time in response to
economic or political conditions. Thus, we must also consider the impact of
future laws and regulations that may be passed in the jurisdictions where we
operate. We anticipate that future laws and regulations related to the oil and
natural gas industry will become increasingly stringent and cause us to incur
substantial compliance costs.
THE NATURE OF OUR OPERATIONS EXPOSES US TO ENVIRONMENTAL LIABILITIES.
Our operations create the risk of environmental liabilities. We may incur
liability to governments or to third parties for any unlawful discharge of oil,
gas or other pollutants into the air, soil or water. We could potentially
discharge oil or natural gas into the environment in any of the following ways:
- from a well or drilling equipment at a drill site,
- from a leak in storage tanks, pipelines or other gathering and
transportation facilities,
- from damage to oil or natural gas wells resulting from accidents
during normal operations, or
- from blowouts, cratering or explosions.
Environmental discharges may move through the soil to water supplies or
adjoining properties, giving rise to additional liabilities. Some laws and
regulations could impose liability for failure to obtain the proper permits for,
to control the use of, or to notify the proper authorities of a hazardous
discharge. Such liability could have a material adverse effect on our financial
condition and our results of operations and could possibly cause our operations
to be suspended or terminated on such property.
We may also be liable for any environmental hazards created either by the
previous owners of properties that we purchase or lease or by acquired companies
prior to the date we acquire them. Such liability would affect the costs of our
acquisition of those properties. In connection with any of these environmental
violations, we may also be charged with remedial costs. Pollution and similar
environmental risks generally are not fully insurable.
Although we do not believe that our environmental risks are materially different
from those of comparable companies in the oil and natural gas industry, we
cannot assure you that environmental laws will not result in
-16-
decreased production, substantially increased costs of operations or other
adverse effects to our combined operations and financial condition.
WE REQUIRE SUBSTANTIAL CAPITAL REQUIREMENTS TO FINANCE OUR OPERATIONS.
We have substantial anticipated capital requirements. Our ongoing capital
requirements consist primarily of the need to fund our capital and exploration
budget and the acquisition, development, exploration, production and abandonment
of oil and natural gas reserves.
We plan to finance anticipated ongoing expenses and capital requirements with
funds generated from the following sources:
- cash provided by operating activities;
- available cash and cash investments;
- capital raised through debt and equity offerings; and
- funds received under our bank line of credit.
Although we believe the funds provided by these sources will be sufficient to
meet our cash requirements, the uncertainties and risks associated with future
performance and revenues will ultimately determine our liquidity and our ability
to meet anticipated capital requirements. If declining prices cause our revenues
to decrease, we may be limited in our ability to replace our reserves, to
maintain current production levels and to undertake or complete future drilling
and acquisition activities. As a result, our production and revenues would
decrease over time and may not be sufficient to satisfy our projected capital
expenditures. We may not be able to obtain additional debt or equity financing
in such a circumstance.
OUR OPERATIONS ENTAIL INHERENT CASUALTY RISKS FOR WHICH WE MAY NOT HAVE ADEQUATE
INSURANCE.
We must continually acquire, explore and develop new oil and natural gas
reserves to replace those produced and sold. Our hydrocarbon reserves and our
revenues will decline if we are not successful in our drilling, acquisition or
exploration activities. Although we have historically maintained our reserve
base primarily through successful exploration and development operations, future
efforts may not be similarly successful. Casualty risks and other operating
risks could cause reserves and revenues to decline.
Our onshore and offshore operations are subject to inherent casualty risks such
as hurricanes, fires, blowouts, cratering and explosions. Other risks include
pollution, the uncontrollable flows of oil, natural gas, brine or well fluids,
and the hazards of marine and helicopter operations such as capsizing, collision
and adverse weather and sea conditions. These risks may result in injury or loss
of life, suspension of operations, environmental damage or property and
equipment damage, all of which would cause us to experience substantial
financial losses.
Our drilling operations involve risks from high pressures and from mechanical
difficulties such as stuck pipe, collapsed casing and separated cables. Our
offshore properties involve higher exploration and drilling risks such as the
cost of constructing exploration and production platforms and pipeline
interconnections as well as weather delays and other risks. Although we carry
insurance that we believe is in accordance with customary industry practices, we
are not fully insured against all casualty risks incident to our business. We do
not carry business interruption insurance. Should an event occur against which
we are not insured, that event could have a material adverse effect on our
financial position and our results from operations.
OUR OPERATIONS ALSO ENTAIL SIGNIFICANT OPERATING RISKS.
-17-
Our drilling activities involve risks, such as drilling non-productive wells or
dry holes, which are beyond our control. The cost of drilling and operating
wells and of installing production facilities and pipelines is uncertain. Cost
overruns are common risks that often make a project uneconomical. The decision
to purchase and to exploit a property depends on the evaluations made by our
reserve engineers, the results of which are often inconclusive or subject to
multiple interpretations. We may also decide to reduce or cease our drilling
operations due to title problems, weather conditions, noncompliance with
governmental requirements or shortages and delays in the delivery or
availability of equipment or fabrication yards.
WE MAY NOT BE ABLE TO MARKET EFFECTIVELY OUR OIL AND NATURAL GAS PRODUCTION.
We may encounter difficulties in the marketing of our oil and natural gas
production. Effective marketing depends on factors such as the existing market
supply and demand for oil and natural gas and the limitations imposed by
governmental regulations. The proximity of our reserves to pipelines and the
available capacity of such pipelines and other transportation, processing and
refining facilities also affect our marketing efforts. Even if we discover
hydrocarbons in commercial quantities, a substantial period of time may elapse
before we begin commercial production. If pipeline facilities in an area are
insufficient, we may have to wait for the construction or expansion of pipeline
capacity before we can market production from that area. Another risk lies in
our ability to negotiate commercially satisfactory arrangements with the owners
and operators of production platforms in close proximity to our wells. Also,
natural gas wells may be shut in for lack of market demand or because of the
inadequate capacity or unavailability of natural gas pipelines or gathering
systems.
WE ARE DEPENDENT ON OTHER OPERATORS WHO INFLUENCE OUR PRODUCTIVITY.
We have limited influence over the nature and timing of exploration and
development on oil and natural gas properties we do not operate, including
limited control over the maintenance of both safety and environmental standards.
The operators of those properties may:
- refuse to initiate exploration or development projects (in which case
we may propose desired exploration or development activities);
- initiate exploration or development projects on a slower schedule than
we prefer; or
- drill more wells or build more facilities on a project than we can
adequately finance, which may limit our participation in those
projects or limit our percentage of the revenues from those projects.
The occurrence of any of the foregoing events could have a material adverse
effect on our anticipated exploration and development activities.
OUR WORKING INTEREST OWNERS FACE CASH FLOW AND LIQUIDITY CONCERNS.
If oil and natural gas prices decline, many of our working interest owners may
experience liquidity and cash flow problems. These problems may lead to their
attempting to delay the pace of drilling or project development in order to
conserve cash. Any such delay may be detrimental to our projects. In most cases,
we can influence the pace of development by enforcing our joint operating
agreements. Some working interest owners, however, may be unwilling or unable to
pay their share of the project costs as they become due. A working interest
owner may declare bankruptcy and refuse or be unable to pay its share of the
project costs and we would be obligated to pay that working interest owner's
share of the project costs.
OUR INABILITY TO ACQUIRE OR INTEGRATE ACQUIRED COMPANIES OR TO DEVELOP NEW
EXPLORATION PROSPECTS MAY INHIBIT OUR GROWTH.
-18-
From time to time and under certain circumstances, our business strategy may
include acquisitions of businesses that complement or expand our current
business and acquisition and development of new exploration prospects that
complement or expand our prospect inventory. We may not be able to identify
attractive acquisition or prospect opportunities. Even if we do identify
attractive opportunities, we may not be able to complete the acquisition of the
business or prospect or to do so on commercially acceptable terms. If we do
complete an acquisition, we must anticipate difficulties in integrating its
operations, systems, technology, management and other personnel with our own.
These difficulties may disrupt our ongoing operations, distract our management
and employees and increase our expenses. Even if we are able to overcome such
difficulties, we may not realize the anticipated benefits of any acquisition.
Furthermore, we may incur additional debt or issue additional equity securities
to finance any future acquisitions. Any issuance of additional securities may
dilute the value of shares currently outstanding.
TERRORIST ATTACKS AND THREATS OR ACTUAL WAR MAY NEGATIVELY AFFECT OUR BUSINESS,
FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Our business is affected by general economic conditions and fluctuations in
consumer confidence and spending, which can decline as a result of numerous
factors outside of our control, such as terrorist attacks and acts of war.
Terrorist attacks against U.S. targets, as well as events occurring in response
to or in connection with them, rumors or threats of war, actual conflicts
involving the United States or its allies, or military or trade disruptions
impacting our suppliers or our customers, may adversely impact our operations.
Strategic targets such as energy-related assets may be at greater risk of future
terrorist attacks than other targets in the United States. These occurrences
could have an adverse impact on energy prices, including prices for our natural
gas and crude oil production. In addition, disruption or significant increases
in energy prices could result in government-imposed price controls. It is
possible that any or a combination of these occurrences could have a material
adverse effect on our business, financial condition and results of operations.
FORWARD-LOOKING INFORMATION
From time to time, we may make certain statements that contain "forward-looking"
information as defined in the Private Securities Litigation Reform Act of 1995
and that involve risk and uncertainty. These forward-looking statements may
include, but are not limited to exploration and seismic acquisition plans,
anticipated results from current and future exploration prospects, future
capital expenditure plans, anticipated results from third party disputes and
litigation, expectations regarding compliance with our credit facility, the
anticipated results of wells based on logging data and production tests, future
sales of production, earnings, margins, production levels and costs, market
trends in the oil and natural gas industry and the exploration and development
sector thereof, environmental and other expenditures and various business
trends. Forward-looking statements may be made by management orally or in
writing including, but not limited to, this Risk Factors section, the
Management's Discussion and Analysis of Financial Condition and Results of
Operations section and other sections of this report and our other filings with
the Securities and Exchange Commission under the Securities Act of 1933, as
amended, and the Securities Exchange Act of 1934, as amended.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM 2. PROPERTIES
PRODUCING PROPERTIES
For information regarding Meridian's properties, see "Item 1. Business" above.
ITEM 3. LEGAL PROCEEDINGS
H. L. HAWKINS LITIGATION. In December 2004, the estate of H.L. Hawkins filed a
claim against Meridian for
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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 December
31, 2005.
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 this matter in its financial statements at
December 31, 2005.
LITIGATION INVOLVING INSURABLE ISSUES. There are no other material legal
proceedings which exceed our insurance limits to which the Company 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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of Meridian's security holders during the
fourth quarter of 2005.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
Our common stock is traded on the New York Stock Exchange under the symbol
"TMR." The following table sets forth, for the periods indicated, the high and
low sale prices per share for the common stock as reported on the New York Stock
Exchange:
HIGH LOW
----- -----
2005:
First quarter ... $6.36 $4.88
Second quarter .. 5.45 3.77
Third quarter ... 5.31 3.39
Fourth quarter .. 4.90 3.77
2004:
First quarter ... $6.52 $5.00
Second quarter .. 7.65 6.03
Third quarter ... 9.00 6.76
Fourth quarter .. 9.02 5.20
The closing sale price of the common stock on March 1, 2006, as reported on the
New York Stock Exchange Composite Tape, was $4.16. As of March 1, 2006, we had
approximately 792 shareholders of record.
Meridian has not paid cash dividends on the common stock and does not intend to
pay cash dividends on the common stock in the foreseeable future. We currently
intend to retain our cash for the continued development of our business,
including exploratory and development drilling activities. We also are currently
restricted under our senior secured credit facility from paying any cash
dividends on common stock or for purchase of shares of common stock without the
prior consent of the lenders.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table sets forth information as of December 31, 2005, with respect
to our compensation plans (including individual compensation arrangements) under
which equity securities are authorized for issuance:
Number of securities
remaining available for
Number of securities to Weighted-average future issuance under
be issued upon exercise exercise price of equity compensation plans
of outstanding options, outstanding options, (excluding securities
Plan Category warrants and rights warrants and rights reflected in column (a)(1))
------------- ----------------------- -------------------- ---------------------------
(a) (b) (c)
Equity compensation plans approved by
security holders 6,781,454 $3.44 2,162,478
Equity compensation plans not approved
by security holders -- -- --
--------- ----- ---------
Total 6,781,454 $3.44 2,162,478
========= ===== =========
(1) Does not include 3,850,000 shares which have been reserved for issuance in
lieu of cash compensation under the Company's deferred compensation plan,
which plan was approved by security holders.
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ITEM 6. SELECTED FINANCIAL DATA
All financial data should be read in conjunction with our Consolidated Financial
Statements and related notes thereto included in Item 8 and elsewhere in this
report.
YEAR ENDED DECEMBER 31,
----------------------------------------------------
2005 2004 2003 2002 2001
-------- -------- -------- -------- --------
(In thousands, except prices and per share information)
A. SUMMARY OF OPERATING DATA
Production:
Oil (MBbls) 882 1,270 1,403 2,213 2,918
Natural gas (MMcf) 20,490 27,839 20,142 15,578 22,085
Natural gas equivalent (MMcfe) 25,781 35,457 28,563 28,856 39,594
Average prices:
Oil ($/Bbl) $ 39.29 $ 28.40 $ 24.97 $ 24.67 $ 25.17
Natural gas ($/Mcf) 7.84 5.98 5.07 3.36 4.67
Natural gas equivalent ($/Mcfe) 7.57 5.71 4.80 3.71 4.46
B. SUMMARY OF OPERATIONS
Total revenues $195,696 $203,118 $137,479 $107,470 $178,060
Depletion and depreciation 97,354 102,915 75,441 60,972 67,450
Net earnings (loss)(1) 27,849 29,248 7,246 (52,012) 22,551
Net earnings (loss) per share:(1)
Basic $ 0.33 $ 0.41 $ 0.14 $ (1.05) $ 0.47
Diluted 0.31 0.37 0.13 (1.05) 0.43
Dividends per:
Common share $ -- $ -- $ -- $ -- $ --
Redeemable preferred share 2.60 8.50 8.50 5.90 --
Preferred share -- -- -- -- 0.11
Weighted average common
shares outstanding - basic 84,527 72,084 53,325 49,763 48,350
C. SUMMARY BALANCE SHEET DATA
Total assets $555,802 $513,274 $448,400 $456,240 $507,900
Long-term obligations, inclusive
of current maturities 75,000 75,129 152,320 203,750 210,000
Redeemable preferred stock -- 31,589 60,446 69,690 --
Stockholders' equity 377,565 316,041 184,335 133,393 188,221
(1) Applicable to common stockholders.
-22-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
Meridian is an independent oil and natural gas company that explores for,
acquires and develops oil and natural gas properties utilizing 3-D seismic
technology. Our operations have historically been focused on the onshore oil and
gas regions in south Louisiana, the Texas Gulf Coast and offshore in the Gulf of
Mexico. Declines in the existence of conventional exploration projects in very
mature producing basins, such as south Louisiana and the shallow shelf areas of
the Gulf of Mexico, have impacted the number of economic prospects available for
drilling. This is partly the result of better technology that has improved the
industry's ability to determine probabilities of success, and partly the result
of new projects being smaller in size compared to the decline rates exhibited by
the giant fields discovered, generally, prior to the 1980s.
As a result, the Company made a shift during 1999 and extended what had been a
highly successful exploration program during the early 1990s, from drilling
purely deep, higher-risk, yet higher-potential prospects, to place more emphasis
on the development of an exploration inventory of shallower, lower-risk,
repeatable, multi-well plays. This shift was the genesis of two very successful
exploration plays--Thornwell and Biloxi Marshlands--where multiple wells were
drilled either just above pressures, or the first sands into geo-pressures. In
both instances, the Company developed processing and interpretation techniques
that identified direct hydrocarbon indicators and developed reserves with
probabilities of success levels greater than 60% each.
Meridian's management believes that the basin itself still contains both
tremendous attributes--high producing rates, high cash flows and returns, plus
lower lift costs once proved--and remaining opportunities for a company, such as
Meridian, that possesses a unique position in the region--a position marked by
technical knowledge and expertise, relationships, acreage positions, seismic
inventory and data and prospect inventory. However, the fact remains that the
replacement of reserves year after year in this region continues to be more and
more difficult under current conditions.
With the recent increase in commodity prices, the industry is now experiencing a
new paradigm in domestic exploration. Recent price increases and enhanced
technology has enabled the industry, as a whole, to consider domestic
exploration projects that were once uneconomic. These are predominantly classed
as "unconventional" (tight gas) and "resource" (shale or resource material)
plays. The Barnett Shale field in northern Texas is the best, but not the only,
example of this type of play. It is estimated that as much as 40% of current
domestic production now stems from accumulation of this nature. These fields are
quite prolific, extend over large areas, but are also very cost sensitive, with
breakeven costs often at $5-$6 per mcf or more on large capital investments.
In recognition of the totality of circumstances, including the availability of
these styles of play opportunities and the Company's high current cash position
stemming from its higher-producing rate Gulf Coast properties, in early 2005,
Meridian's management introduced as a part of its business plan, the further
expansion of its exploration program to include the identification and
development of unconventional and resource plays into its portfolio. Since that
decision, the Company has entered into joint ventures and acquired strategic
acreage positions in basins recognized for both the unconventional and resource
exploration plays. The first of these was an unconventional or tight gas play in
East Texas, near the highly prolific Double A field, where we own approximately
7,000 acres and began to drill our first wells during the first quarter of 2006.
Others include the purchase of two separate acreage positions of approximately
18,000 acres and 15,000 acres, with plans to extend positions in each, based on
the Company's research and drilling operations. The location of the Company's
resource plays will not be identified until it has had the opportunity to secure
control of protective acreage positions within each. In addition, the Company
has expanded its technical and business development staff to include a team of
experienced professionals and consultants who will be primarily responsible for
the further extension of the Company's reserve base and reserve life in the
unconventional resource plays.
Our drilling program for 2005 was dominated by exploration in the Biloxi
Marshlands area and exploitation of seismic anomalies in Terrebonne Parish,
under an old 3-D survey that we had reprocessed. The impact of
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hurricanes Katrina and Rita combined to destroy or damage substantial portions
of our production facilities across the state, and severely damaged two of the
drilling rigs being utilized in the area. Overall, the storms had a very large
impact on the timing (four months) of our drilling activities and an even
greater impact on our production volumes for the year. As reported, none of our
personnel suffered physical injuries, and our insurance coverage will handle the
substantial portion of costs to replace and repair the damage. However, the
delays, coupled with the underlying decline, decreased the 2005 average
production to 70.6 Mcfe per day, from 96.9 Mmcfe per day.
From a financial perspective, in 2005 we noted the following:
- Average daily production: 70.6 Mmcfe per day
- Total revenues: $195.7 million
- Net cash provided by operating activities: $134.1 million
- Diluted earnings per share: $0.31 per share
- Debt to total capitalization: 17%
- Drilling capital deployed: $86.2 million
- Reserves added from exploration: 17.5 Bcfe
- Reserve reductions from adjustments: 19.9 Bcfe
(Thibodaux 3 and CL&F A-2)
Since December 2002, when we acquired our first land and seismic positions in
the Biloxi Marshlands project, the Company has expended a total of approximately
$190 million for all land, seismic, drilling and completions, production
facilities and pipelines, over both evaluated and unevaluated areas. Through
December 31, 2005, we have received net field cash flow since first production
in March 2003, or less than three years, of $221 million, and the project
continues to generate significant monthly cash flow, depending on prevailing
commodity prices. In addition, the field continues to provide additional
investment opportunities and we expect to keep one drilling rig working in the
field during 2006, drilling 10 to 12 additional wells. Early up-front seismic
and land, drilling and pipeline costs for the entire field has skewed the
finding and development cost on an Mcfe basis, but we believe this will continue
to be reduced as we resume our drilling activities, add new reserves and
production therefrom.
For 2006, the Company has set its capital budget at approximately $132 million
for new prospect opportunities, ranging in depths from shallow to deep, exposing
the Company to unrisked reserve additions of approximately 80 Bcfe.
Industry Conditions. Our revenues, profitability and cash flow 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. The average price we received during the year
ended December 31, 2005 was $7.57 per Mcfe compared to $5.71 per Mcfe during the
year ended December 31, 2004. Fluctuations in prevailing prices for oil and
natural gas have several important consequences to us, including affecting the
level of cash flow received from our producing properties, the timing of
exploration of certain prospects and our access to capital markets, which could
impact our revenues, profitability and ability to maintain or increase our
exploration and development program. Refer to Item 7.A., Quantitative and
Qualitative Disclosures about Market Risk, for a discussion of commodity price
risk management activities utilized to mitigate a portion of the near term
effects of this exposure to price volatility.
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RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2005, COMPARED TO YEAR ENDED DECEMBER 31, 2004
Oil and natural gas revenues, which include oil and natural gas hedging
activities (see note 11 of notes to consolidated financial statements), during
the twelve months ended December 31, 2005, decreased $7.2 million (4%) as
compared to 2004 revenues due to a 27% decrease in production volumes primarily
from natural production declines, mechanical issues on a few wells and from the
effects of hurricanes (see "General" above), partially offset by a 33% increase
in average commodity prices on a natural gas equivalent basis and the expiration
of unfavorable hedge contracts. Our average daily production decreased from 96.9
Mmcfe during 2004 to 70.6 Mmcfe for 2005. Oil and natural gas production volume
totaled 25,781 Mmcfe for 2005, compared to 35,457 Mmcfe for 2004. During 2005,
the Company's drilling activity was primarily focused in the Biloxi Marshlands
("BML") project area and the Terrebonne Parish area of South Louisiana. During
2005, the Company drilled or participated in the drilling of 24 wells of which
11 wells were completed, representing a 46% success rate. The following table
summarizes Meridian's operating revenues, production volumes and average sales
prices for the years ended December 31, 2005 and 2004.
Year Ended
December 31,
------------------- Increase
2005 2004 (Decrease)
-------- -------- ----------
Production:
Oil (MBbls) 882 1,270 (31%)
Natural gas (MMcf) 20,490 27,839 (26%)
Natural gas equivalent (MMcfe) 25,781 35,457 (27%)
Average Sales Price:
Oil (per Bbl) $ 39.29 $ 28.40 38%
Natural gas (per Mcf) 7.84 5.98 31%
Natural gas equivalent (per Mcfe) 7.57 5.71 33%
Operating Revenues (000's):
Oil $ 34,647 $ 36,060 (4%)
Natural gas 160,608 166,387 (4%)
-------- -------- ---
Total $195,255 $202,447 (4%)
======== ======== ===
Operating Expenses.
Oil and natural gas operating expenses on an aggregate basis increased $1.9
million (13%) to $15.9 million in 2005, compared to $14.0 million in 2004. On a
unit basis, lease operating expenses increased $0.22 per Mcfe to $0.62 per Mcfe
for the year 2005 from $0.40 per Mcfe for the year 2004. Oil and natural gas
operating expenses increased primarily due to (1) operating expenses associated
with new wells; (2) salt water disposal expense in the Hornet Nest area of BML;
and (3) an overall industry-wide increase in service costs.
Severance and Ad Valorem Taxes.
Severance and ad valorem taxes decreased $0.6 million (6%) to $8.8 million in
2005, compared to $9.4 million in 2004, primarily because of the decrease in
natural gas production, partially offset by a higher natural gas tax rate.
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 (effective July 1,
2005) for natural gas. For the first six months of 2005, and the last six months
of 2004, the rate was $0.208 per Mcf for natural gas, an increase from $0.171
per Mcf for the first half of 2004. On an equivalent unit of production basis,
severance and ad valorem taxes increased to $0.34 per Mcfe for 2005 from
-25-
$0.26 per Mcfe for 2004.
Depletion and Depreciation.
Depletion and depreciation expense decreased $5.5 million (5%) during 2005 to
$97.4 million compared to $102.9 million for 2004. This was primarily the result
of the 27% decrease in production volumes in 2005 from 2004 levels, partially
offset by an increase in the depletion rate as compared to the 2004 period. On a
unit basis, depletion and depreciation expenses increased to $3.78 per Mcfe for
2005, compared to $2.90 per Mcfe for 2004. Depletion and depreciation expense on
a per Mcfe basis increased primarily due to the impact of negative reserve
revisions during the year, an overall industry-wide increase in drilling,
completion and facility costs, and upward revisions of future development costs.
General and Administrative Expense.
General and administrative expenses, which are net of costs capitalized in our
oil and gas properties (see note 17 of notes to consolidated financial
statements), increased $2.8 million (19%) to $18.0 million in 2005 compared to
$15.2 million for the year 2004, primarily due to an increase in employee
compensation associated with the higher industry-wide demand for experienced
personnel. Additionally, legal services were higher during 2005 as a result of
various litigation matters. On an equivalent unit of production basis, general
and administrative expenses increased $0.27 per Mcfe to $0.70 per Mcfe for 2005
compared to $0.43 per Mcfe for 2004.
Accretion Expense.
On January 1, 2003, the Company adopted Statement of Financial Accounting
Standards No. 143 ("SFAS No. 143"), "Accounting for Asset Retirement
Obligations." As a result, the Company began recording long-term liabilities
representing the discounted present value of the estimated asset retirement
obligations with offsetting increases in capitalized oil and gas properties.
This liability will continue to be accreted to its future value in subsequent
reporting periods. The Company has charged approximately $1.1 million and $0.6
million to earnings as accretion expense during 2005 and 2004, respectively.
Hurricane Damage Repairs.
This expense of $3.1 million is related to damages incurred from hurricanes
Katrina and Rita, primarily related to the Company's insurance deductible and
costs in excess of insured values.
Interest Expense.
Interest expense decreased $2.5 million (34%) to $4.7 million in 2005 compared
to $7.2 million for 2004. The decrease was primarily a result of the reduction
in long-term borrowings. This realized interest savings was due to the 2004
conversion of the $20 million convertible subordinated notes into common stock
and the 2004 net repayments of $57.2 million on our long-term debt.
Taxes on Income.
The provision for income taxes for 2005 was $18.0 million as compared to $19.3
million for 2004. Income taxes were provided on book income after taking into
account permanent differences between book income and taxable income.
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YEAR ENDED DECEMBER 31, 2004, COMPARED TO YEAR ENDED DECEMBER 31, 2003
Oil and natural gas revenues, which include oil and natural gas hedging
activities (see note 11 of notes to consolidated financial statements), during
the twelve months ended December 31, 2004, increased $65.3 million (48%) as
compared to 2003 revenues due primarily to a 24% increase in production volumes
primarily from the Company's drilling results in the BML project area and Weeks
Island, coupled with successful workover operations in the Company's Ramos and
Weeks Island fields, partially offset by natural production declines and
property sales during 2003. Further, revenues were enhanced by a 19% increase in
average commodity prices on a natural gas equivalent basis. Drilling and
workover success increased our average daily production from 78.3 Mmcfe during
2003 to 96.9 Mmcfe for 2004. Oil and natural gas production volume totaled
35,457 Mmcfe for 2004, compared to 28,563 Mmcfe for 2003. During 2004, the
Company's drilling activity was primarily focused in the BML project area and
the Weeks Island field. During 2004, the Company drilled or participated in the
drilling of 31 wells of which 20 wells were completed and placed on production,
representing a 65% success rate. The following table summarizes Meridian's
operating revenues, production volumes and average sales prices for the years
ended December 31, 2004 and 2003.
Year Ended
December 31,
------------------- Increase
2004 2003 (Decrease)
-------- -------- ----------
Production:
Oil (MBbls) 1,270 1,403 (10%)
Natural gas (MMcf) 27,839 20,142 38%
Natural gas equivalent (MMcfe) 35,457 28,563 24%
Average Sales Price:
Oil (per Bbl) $ 28.40 $ 24.97 14%
Natural gas (per Mcf) 5.98 5.07 18%
Natural gas equivalent (per Mcfe) 5.71 4.80 19%
Operating Revenues (000's):
Oil $ 36,060 $ 35,032 3%
Natural gas 166,387 102,092 63%
-------- -------- ----
Total $202,447 $137,124 48%
======== ======== ====
Operating Expenses.
Oil and natural gas operating expenses on an aggregate basis increased $2.7
million (25%) to $14.0 million in 2004, compared to $11.3 million in 2003. On a
unit basis, lease operating expenses increased $0.01 per Mcfe to $0.40 per Mcfe
for the year 2004 from $0.39 per Mcfe for the year 2003. Oil and natural gas
operating expenses increased primarily due to additional operating expenses
associated with new wells and facilities in the BML project area and to
increased workover activity in the Weeks Island, Ramos and Turtle Bayou fields
during the year, partially offset by savings resulting from sold properties in
the latter portion of 2003, combined with other cost savings initiated during
2004.
Severance and Ad Valorem Taxes.
Severance and ad valorem taxes increased $1.8 million (23%) to $9.4 million in
2004, compared to $7.6 million in 2003, primarily because of an increase in
natural gas production and a higher natural gas tax rate, partially offset by a
tax refund from Louisiana for prior periods. 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 $0.208 per Mcf (effective July 1, 2004) for natural gas. For the
first six months of 2004, and the last six months of 2003, the rate was $0.171
per Mcf for natural gas, an
-27-
increase from $0.122 per Mcf for the first half of 2003. On an equivalent unit
of production basis, severance and ad valorem taxes decreased to $0.26 per Mcfe
for 2004 from $0.27 per Mcfe for 2003, reflecting a tax refund from Louisiana
for prior periods.
Depletion and Depreciation.
Depletion and depreciation expense increased $27.5 million (36%) during 2004 to
$102.9 million compared to $75.4 million for 2003. This was primarily the result
of the 24% increase in production volumes in 2004 over 2003 levels, and an
increase in the depletion rate as compared to the 2003 period. On a unit basis,
depletion and depreciation expenses increased to $2.90 per Mcfe for 2004,
compared to $2.64 per Mcfe for 2003.
General and Administrative Expense.
General and administrative expenses, which are net of costs capitalized in our
oil and gas properties (see note 17 of notes to consolidated financial
statements), increased $3.6 million (31%) to $15.2 million in 2004 compared to
$11.6 million for the year 2003, primarily due to an increase in accounting and
professional fees associated with implementing the expanded compliance burden
required by the Sarbanes-Oxley Act of 2002, an increase in insurance costs
primarily due to additional coverage and to increased production activity. On an
equivalent unit of production basis, general and administrative expenses
increased $0.02 per Mcfe to $0.43 per Mcfe for 2004 compared to $0.41 per Mcfe
for 2003.
Interest Expense.
Interest expense decreased $4.3 million (38%) to $7.2 million in 2004 compared
to $11.5 million for 2003. The decrease was primarily a result of the reduction
in long-term borrowings. During 2004, the Company converted $20 million of
convertible subordinated notes into common stock and made net repayments of
$57.2 million on our long-term debt. The reduction in long-term debt was partly
the result of our August 2004 common stock offering.
Taxes on Income.
The provision for income taxes for 2004 was $19.3 million as compared to $4.2
million for 2003. Income taxes were provided on book income after taking into
account permanent differences between book income and taxable income, and after
reducing the income tax valuation allowance by $2.7 million in 2003.
Adoption of Statement of Financial Accounting Standards No. 143.
On January 1, 2003, the Company adopted Statement of Financial Accounting
Standards No. 143 ("SFAS No. 143"), "Accounting for Asset Retirement
Obligations." As a result, the Company began recording long-term liabilities
representing the discounted present value of the estimated asset retirement
obligations with offsetting increases in capitalized oil and gas properties.
This liability will continue to be accreted to its future value in subsequent
reporting periods. The Company has charged approximately $0.6 million and $0.7
million to earnings as accretion expense during 2004 and 2003, respectively. In
2003, the Company recorded a long-term liability of $4.5 million representing
the discounted present value of the estimated retirement obligations and an
increase in capitalized oil and gas properties of $3.2 million. The cumulative
effect of the change in accounting principle for 2003 totaled $1.3 million or
$0.02 per share, and was charged to earnings in 2003.
-28-
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS. Net cash flows provided by operating activities were $134.1 million
for the year ended December 31, 2005, as compared to $171.5 million for the year
ended December 31, 2004, a decrease of $37.4 million or 22%. This decrease was
attributable to a $7.2 million decline in revenue due to lower production,
partially offset by higher commodity prices and higher cash expenditures in 2005
of approximately $4.4 million, including hurricane damage repairs. Additionally,
approximately $9 million of hurricane expenditures are included in year end 2005
accounts receivable, for which we have filed insurance claims. Also, changes in
accounts payable when comparing 2005 to 2004, resulted in a use of cash of $13.7
million. Other changes in working capital are due to the timing of cash receipts
and disbursements.
Net cash flows used in investing activities were $133 million for the year ended
December 31, 2005, as compared to $142.5 million for the year ended December 31,
2004. The decrease was due to lower capital expenditures of $9.5 million.
Drilling activity during the latter part of 2005 was delayed due to hurricane
damage resulting in lower capital expenditures of $9.5 million when comparing
2005 to 2004.
Net cash flows used in financing activities were $2.1 million for the year ended
December 31, 2005, as compared to net cash flows used in financing activities of
$17.5 million for 2004. In 2005, the Company paid $2.2 million of preferred
stock dividends, compared to $5.2 million in 2004. Also included in 2004 were
net repayments of $57.2 million of debt, partially offset by $45.8 million
raised by selling common stock. (See "Common Stock," below.)
COMMON STOCK. In August 2004, the Company completed a public offering of
13,800,000 shares of common stock at a price of $7.25 per share. The total
proceeds of the offering, net of issuance costs, received by the Company were
approximately $94.6 million. A portion of the proceeds from the offering were
utilized to repurchase all of the 7,082,030 shares of its common stock that were
beneficially owned by Shell Oil Company for $49.3 million and a portion of the
remaining proceeds of that equity offering were used to repay borrowings under
the Company's senior secured credit agreement. The repurchased 7,082,030 shares
of common stock that were held in Treasury Stock, subsequent to the offering,
were retired as of September 30, 2004.
In August 2003, the Company completed a private offering of 8,703,537 shares of
common stock at a price of $3.87 per share. The total proceeds of the offering,
net of issuance costs, received by the Company were approximately $33.0 million.
The Company used the majority of these funds to retire $31.8 million in
long-term debt, with the remainder of the proceeds being used for exploration
activities and other general corporate purposes. As discussed below, during
2004, approximately 10.7 million shares of common stock were issued for the
early conversion and retirement of the Company's 9 1/2% convertible subordinated
notes and a portion of the Series C redeemable preferred stock. During 2005, an
additional 7.1 million shares of common stock were issued for conversion and
retirement of the remaining Series C redeemable preferred stock.
CURRENT CREDIT FACILITY. On December 23, 2004, the Company amended its 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
PLC, RZB Finance LLC and Standards Bank PLC completed the syndication group. The
initial borrowing base under the Credit Facility was $130 million and it was
reaffirmed by the syndication group effective November 1, 2005. As of December
31, 2005, 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
-29-
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 would exist
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 expects to be in full compliance
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 December 31, 2005, the three-month LIBOR interest rate
was 4.54%. The Credit Facility also provides for commitment fees of 0.375%
calculated on the difference between the borrowing base and the aggregate
outstanding loans and letters of credit under the Credit Facility.
FORMER CREDIT FACILITY. In 2002-2004, the Company had a $175 million senior
secured credit agreement. In the first nine months of 2004, the Company made
repayments of $48.3 million, bringing the outstanding balance to $74 million as
of September 30, 2004. On December 23, 2004, the Company made a final debt
repayment of $74 million, which paid off this senior secured credit agreement in
full.
SUBORDINATED CREDIT AGREEMENT. The Company had a short-term subordinated credit
agreement with Fortis Capital Corp. for $25 million that had a maturity date of
December 31, 2004. Note payments totaling $6.25 million were paid in 2002, $8.75
million was paid in 2003, and the remaining $10 million was paid in 2004.
9 1/2% CONVERTIBLE SUBORDINATED NOTES During June 1999, the Company completed
private placements of an aggregate of $20 million of its 9 1/2% convertible
subordinated notes ("Notes") due June 18, 2005. The Notes were unsecured and
contained customary events of default, but did not contain any maintenance or
other restrictive covenants. Interest was payable on a quarterly basis. The
Company was in compliance with the financial covenants under this agreement.
During March 2002, the Company and the holders of the Notes amended the
conversion price from $7.00 to $5.00 per share. The Notes were convertible at
any time by the holders of the Notes into shares of the Company's common stock,
$0.01 par value, utilizing the conversion price. The conversion price was
subject to customary anti-dilution provisions. The holders of the Notes were
granted registration rights with respect to the shares of common stock that
would be issued upon conversion of the Notes.
During March 2004, the Notes were converted into 4.0 million shares of the
Company's common stock at a conversion price of $5.00 per share, and included an
additional non-cash conversion expense of approximately
-30-
$1.2 million that was incurred and paid via the issuance of common stock priced
at market. All of the common stock issued in connection with the conversion of
the notes was issued under Section 4(2) of the Securities Act.
8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK. A private placement under Section
4(2) and Regulation D of the Securities Act totaling $66.9 million of 8.5%
redeemable convertible preferred stock was completed during May 2002. The
preferred stock was convertible into shares of the Company's common stock at a
conversion price of $4.45 per share. Dividends were payable semi-annually in
cash or additional preferred stock. At the option of the Company, one-third of
the preferred shares could be forced to convert to common stock if the closing
price of the Company's common stock exceeded 150% of the conversion price for 30
out of 40 consecutive trading days on the New York Stock Exchange. The preferred
stock was subject to redemption at the option of the Company after March 2005,
and mandatory redemption on March 31, 2009. The holders of the preferred stock
were granted registration rights with respect to the shares of common stock
issued upon conversion of the preferred stock. In the last quarter of 2003,
$12.2 million of preferred stock was converted into 2.7 million shares of common
stock.
In 2004, a total of $28.9 million of preferred stock was converted into 6.5
million shares of common stock. During the first six months of 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.
CAPITAL EXPENDITURES. Capital expenditures in 2005 consisted of $132.9 million
for property and equipment additions primarily related to exploration and
development of various prospects, including leases, seismic data acquisitions,
production facilities, and related drilling and workover activities. Our
strategy is to blend exploration drilling activities with high-confidence
workover and development projects selected from our broad asset inventory in
order to capitalize on periods of high commodity prices.
The 2006 capital expenditures plan is currently forecast at approximately $132
million. The final projects 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.
SALE OF PROPERTIES. During 2003, the Company sold certain non-strategic oil and
gas properties located in south Louisiana for approximately $4.9 million. The
sale was comprised of approximately 4 Bcfe proved developed reserves and 1 Bcfe
of undeveloped reserves. Benefits of the sale include the reduction of total
debt by an additional $4.9 million resulting in an immediate savings in interest
costs on the Company's senior bank debt, the elimination of $3.1 million in
future capital expenditures associated with the properties, and the elimination
of over $1.5 million in annual lease operating expenses.
CASH OBLIGATIONS. The following summarizes the Company's contractual obligations
at December 31, 2005 and the effect such obligations are expected to have on its
liquidity and cash flow in future periods (in thousands):
LESS THAN 1-3 AFTER
ONE YEAR YEARS 3 YEARS TOTAL
--------- ------- ------- -------
Short and long term debt $1,103 $75,000 $-- $76,103
Interest 4,718 9,330 14,048
Non-cancelable operating leases 1,757 125 -- 1,882
------ ------- --- -------
Total contractual cash obligations $7,578 $84,455 $-- $92,033
====== ======= === =======
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.
-31-
For the year 2005, $0.8 million of dividends were accumulated (net of $0.1
million of deferred preferred stock offering costs amortized during 2005) of
which all was paid in 2005. During the first six months of 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.
For the year ended December 31, 2004, $3.5 million of dividends were accumulated
(net of $0.4 million of deferred preferred stock offering costs amortized during
2004), of which $2.2 million was paid in cash in July 2004 and $1.3 million was
paid in cash in January 2005. During 2003, dividends of $6.0 million were
accumulated (net of $0.6 million of deferred preferred stock offering costs
amortized during 2003), of which $3.0 million was satisfied with the issuance of
additional shares of redeemable preferred stock and $3.0 million was paid in
cash in January 2004.
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 in the
United States of America. The following summarizes several of our critical
accounting policies. See a complete list of significant accounting policies in
Note 1 to the Consolidated Financial Statements.
USE OF ESTIMATES. 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, and disclosure of contingent assets
and liabilities, if any, at the date of the financial statements. The Company
analyzes its estimates, including those related to oil and gas revenues, bad
debts, oil and gas properties, marketable securities, income taxes and
contingencies and litigation. The Company bases its estimates on historical
experience and various other assumptions that are believed to be reasonable
under the circumstances. Actual results may differ from these estimates under
different assumptions or conditions. The Company believes the following critical
accounting policies affect its more significant judgments and estimates used in
the preparation of its consolidated financial statements.
PROPERTY AND EQUIPMENT. The Company follows the full cost method of accounting
for its investments in oil and natural gas properties. All costs incurred with
the acquisition, exploration and development of oil and natural gas properties,
including unproductive wells, are capitalized. Under the full cost method of
accounting, such costs may be incurred both prior to or after the acquisition of
a property and include lease acquisitions, geological and geophysical services,
drilling, completion and equipment. Included in capitalized costs are general
and administrative costs that are directly related to acquisition, exploration
and development activities, and which are not related to production, general
corporate overhead or similar activities. For the years 2005, 2004, and 2003,
such capitalized costs totaled $13.8 million, $11.9 million, and $10.0 million,
respectively. General and administrative costs related to production and general
overhead are expensed as incurred.
Proceeds from the sale of oil and natural gas properties are credited to the
full cost pool, except in transactions involving a significant quantity of
reserves or where the proceeds received from the sale would significantly alter
the relationship between capitalized costs and proved reserves, in which case a
gain or loss would be recognized.
Future development, site restoration, and dismantlement and abandonment costs,
net of salvage values, are estimated property by property based upon current
economic conditions and are included in our amortization of our oil and natural
gas property costs.
The provision for depletion and amortization of oil and natural gas properties
is computed by the unit-of-production method. Under this computation, the total
unamortized costs of oil and natural gas properties (including future
development, site restoration, and dismantlement and abandonment costs, net of
salvage value), excluding costs of unproved properties, are divided by the total
estimated units of proved oil and
-32-
natural gas reserves at the beginning of the period to determine the depletion
rate. This rate is multiplied by the physical units of oil and natural gas
produced during the period.
Changes in the quantities of our reserves could significantly impact the
Company's provision for depletion and amortization of oil and natural gas
properties. A 10% decrease in reserves would have increased our provision for
the year by approximately 12%; however, a 10% increase in our reserves would
have decreased our provision for the year by approximately 10%.
The cost of unevaluated oil and natural gas properties not being amortized is
assessed quarterly to determine whether such properties have been impaired. In
determining impairment, an evaluation is performed on current drilling results,
lease expiration dates, current oil and gas industry conditions, and available
geological and geophysical information. Any impairment assessed is added to the
cost of proved properties being amortized.
At December 31, 2005, we had $26.6 million allocated to unevaluated oil and
natural gas properties. A 10% increase or decrease in the unevaluated oil and
natural gas properties balance would have increased or decreased our provision
for depletion and amortization of oil and natural gas properties by
approximately 1% for the year ended December 31, 2005.
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 gas prices and their effect on the carrying
value of our proved oil and 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 December 31, 2005, we had a cushion (i.e. the excess of the ceiling over our
capitalized costs) of $236.6 million (before tax). A 10% increase in prices
would have increased our cushion by approximately 35%. A 10% decrease in prices
would have decreased our cushion by approximately 25%. Our hedging program would
reduce some of the impact of a price decline.
PRICE RISK MANAGEMENT ACTIVITIES. The Company follows the Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" which requires that changes in the derivatives' fair value be
recognized currently in earnings unless specific cash flow hedge accounting
criteria are met. The statement also establishes accounting and reporting
standards requiring that every derivative instrument be reported in the balance
sheet as either an asset or liability measured at its fair value. Cash flow
hedge accounting for qualifying hedges allows the gains and losses on
derivatives to offset related results on the hedged item in the earnings
statements and requires that a company formally document, designate, and assess
the effectiveness of transactions that receive hedge accounting. We adopted FAS
133 effective January 1, 2001.
-33-
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 our hedged
production. Although derivatives often fail to achieve 100% effectiveness for
accounting purposes, our derivative instruments continue to be highly effective
in achieving the risk management objectives for which they were intended. These
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 gain of $126,000 during the year ended
December 31, 2004, and a loss of $251,000 during the year ended December 31,
2005.
During the year ended December 31, 2005, the change in estimated fair value of
the Company's oil and natural gas contracts was an unrealized loss of $3.6
million ($2.3 million net of tax) which is recognized in other comprehensive
income. Based upon December 31, 2005, oil and natural gas commodity prices,
approximately $3.4 million of the loss deferred in other comprehensive income
could potentially lower gross revenues in 2006. The contract agreements expire
at various dates through July 31, 2007.
Net settlements under these contract agreements reduced oil and natural gas
revenues by $20,578,000 and $18,624,000 and $14,916,000 for the years ended
December 31, 2005, 2004, and 2003, respectively.
See Item 7.A., Quantitative and Qualitative Disclosures about Market Risk, for
additional discussion of disclosures about market risk.
FAIR VALUE OF FINANCIAL INSTRUMENTS. Our financial instruments consist of cash
and cash equivalents, accounts receivable, accounts payable, and bank
borrowings. The carrying amounts of cash and cash equivalents, accounts
receivable and accounts payable approximate fair value due to the highly liquid
nature of these short-term instruments. The fair values of the bank borrowings
approximate the carrying amounts as of December 31, 2005 and 2004, and were
determined based upon variable interest rates currently available to us for
borrowings with similar terms.
NEW ACCOUNTING PRONOUNCEMENTS. On September 28, 2004, the SEC released Staff
Accounting Bulletin ("SAB") 106 regarding the application of SFAS 143,
"Accounting for Asset Retirement Obligations ("AROs")," by oil and gas producing
companies following the full cost accounting method. Pursuant to SAB 106, oil
and gas producing companies that have adopted SFAS 143 should exclude the future
cash outflows associated with settling AROs (ARO liabilities) from the
computation of the present value of estimated future net revenues for the
purposes of the full cost ceiling calculation. In addition, estimated
dismantlement and abandonment costs, net of estimated salvage values, that have
been capitalized (ARO assets) should be included in the amortization base for
computing depreciation, depletion and amortization expense. Disclosures are
required to include discussion of how a company's ceiling test and depreciation,
depletion and amortization calculations are impacted by the adoption of SFAS
143. SAB 106 was effective as of the beginning of the first fiscal quarter
beginning after October 4, 2004. Since our adoption of SFAS 143 on January 1,
2003, we have calculated the ceiling test and our depreciation, depletion and
amortization expense in accordance with the interpretations set forth in SAB
106; therefore, the adoption of SAB 106 had no effect on our financial
statements.
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 would eliminate the
ability to account for share-based compensation transactions using APB Opinion
No. 25, "Accounting for Stock Issued to Employees," and generally would require
instead that such
-34-
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. Under this method, compensation cost will be recognized in
our financial statements beginning January 1, 2006, based on the requirements of
SFAS No. 123R, for all share-based payments granted or modified after that date,
and based on the requirements of SFAS No. 123R for all unvested awards granted
prior to the adoption date of SFAS No. 123R. The impact on the Company's results
of operations is expected to be similar to the pro forma disclosures included in
the notes to the financial statements.
In May 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error
Corrections" which replaces Accounting Principles Board Opinions No. 20,
"Accounting Changes" and Statement of Financial Accounting Standards No. 3,
"Reporting Accounting Changes in Interim Financial Statements - An Amendment of
APB Opinion No. 28." SFAS No. 154 provides guidance on the accounting for and
reporting of accounting changes and error corrections. It establishes
retrospective application, or the latest practicable date, as the required
method for reporting a change in accounting principle and the reporting of a
correction of an error. SFAS No. 154 is effective for accounting changes and
correction of errors made in fiscal years beginning after December 15, 2005. The
Company adopted the provisions of SFAS No. 154 on January 1, 2006.
-35-
ITEM 7.A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk from changes in interest rates and hedging
contracts. 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
Facility.
HEDGING CONTRACTS
From time to time, Meridian addresses 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 gas
production. While the use of hedging arrangements limits the downside risk of
adverse price movements, it may also limit future gains from favorable
movements. Under these agreements, payments are received or made based on the
differential between a fixed and a variable product price. These agreements are
settled in cash at or prior to expiration or exchanged for physical delivery
contracts. Meridian does not obtain collateral to support the agreements, but
monitors the financial viability of counter-parties and believes its credit risk
is minimal on these transactions. In the event of nonperformance, we would be
exposed to price risk. Meridian has some risk of accounting loss since the price
received for the product at the actual physical delivery point may differ from
the prevailing price at the delivery point required for settlement of the
hedging transaction.
All of the Company's current hedging contracts are 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 are settled monthly based on the
NYMEX futures contract.
The notional amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 16% of our proved developed natural gas production and 28% of our
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 our hedging agreements is recorded on our consolidated balance
sheet as assets or liabilities. The estimated fair value of our hedging
agreements as of December 31, 2005, is provided below (see the Company's website
at www.tmrc.com for a quarterly breakdown of the Company's hedge position for
2006 and beyond):
-36-
Ceiling Fair Value
Notional Floor Price Price Dec 31, 2005
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ ------------ --------------
NATURAL GAS (MMBTU)
Jan 2006 - Mar 2006 Collar 1,690,000 $ 7.50 $11.25 $(1,282)
Apr 2006 - Oct 2006 Collar 1,130,000 $ 8.00 $14.50 37
-------
Total Natural Gas (1,245)
-------
CRUDE OIL (BBLS)
Jan 2006 - Jul 2006 Collar 113,000 $37.50 $47.50 (1,712)
Jan 2006 - Jul 2006 Collar 25,000 $40.00 $50.00 (331)
Aug 2006 - Jul 2007 Collar 168,000 $50.00 $74.00 (391)
-------
Total Crude Oil (2,434)
=======
$(3,679)
=======
-37-
GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
The definitions set forth below apply to the indicated terms commonly used in
the oil and natural gas industry and in this Form 10-K. Mcfe is calculated using
the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural
gas liquids, which approximates the relative energy content of crude oil,
condensate and natural gas liquids as compared to natural gas. Prices have
historically been substantially higher for crude oil than natural gas on an
energy equivalent basis. Any reference to net wells or net acres was determined
by multiplying gross wells or acres by our working percentage interest therein.
"Bbl" means barrel and "Bbls" means barrels.
"Bcfe" means billion cubic feet of natural gas equivalent.
"Btu" means British Thermal Unit.
"FERC" means the Federal Energy Regulatory Commission.
"MBbls" means thousand barrels.
"Mcf" means thousand cubic feet.
"Mcfe" means thousand cubic feet of natural gas equivalent.
"MMBtu" means million Btus.
"MMcf" means million cubic feet.
"MMcfe" means million cubic feet of natural gas equivalent.
"Present Value of Future Net Cash Flows" or "Present Value of Proved
Reserves" means the present value of estimated future revenues to be
generated from the production of proved reserves calculated in accordance
with Securities and Exchange Commission guidelines, net of estimated
production and future development costs, using prices and costs as of the
date of estimation without future escalation, without giving effect to
non-property related expenses such as general and administrative expenses,
debt service, future income tax expenses and depreciation, depletion and
amortization, and discounted using an annual discount rate of 10%.
-38-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements
Below is an index to the financial statements and notes contained in Financial
Statements and Supplementary Data.
Page
----
Report of Independent Registered Public Accounting Firm.................. 40
Consolidated Statements of Operations.................................... 41
Consolidated Balance Sheets.............................................. 42
Consolidated Statements of Cash Flows.................................... 44
Consolidated Statements of Stockholders' Equity.......................... 45
Consolidated Statements of Comprehensive Income.......................... 46
Notes to Consolidated Financial Statements............................... 47
1. Organization and Basis of Presentation.......................... 47
2. Summary of Significant Accounting Policies...................... 47
3. Asset Retirement Obligations.................................... 51
4. Debt............................................................ 53
5. Lease Obligations............................................... 54
6. Commitments and Contingencies................................... 54
7. Taxes on Income................................................. 55
8. Redeemable Convertible Preferred Stock.......................... 57
9. Stockholders' Equity............................................ 58
10. Profit Sharing and Savings Plan................................. 61
11. Oil and Natural Gas Hedging Activities.......................... 62
12. Major Customers................................................. 63
13. Related Party Transactions...................................... 63
14. Earnings Per Share.............................................. 65
15. Accrued Liabilities............................................. 65
16. Quarterly Results of Operations (Unaudited)..................... 66
17. Supplemental Oil and Natural Gas Disclosures (Unaudited)........ 67
CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
All schedules for which provision is made in the applicable accounting
regulations of the Securities and Exchange Commission are not required under the
related instructions or are inapplicable and therefore have been omitted.
-39-
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors
The Meridian Resource Corporation
We have audited the accompanying consolidated balance sheets of The Meridian
Resource Corporation and subsidiaries as of December 31, 2005 and 2004, and the
related consolidated statements of operations, stockholders' equity, cash flows,
and comprehensive income for each of the three years in the period ended
December 31, 2005. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of The Meridian
Resource Corporation and subsidiaries at December 31, 2005 and 2004, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2005, in conformity with accounting principles
generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of The Meridian
Resource Corporation and subsidiaries' internal control over financial reporting
as of December 31, 2005, based on criteria established in Internal Control -
Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO) and our report dated March 10, 2006, expressed an
unqualified opinion thereon.
BDO SEIDMAN, LLP
Houston, Texas
March 10, 2006
-40-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands, except per share data)
YEAR ENDED DECEMBER 31,
------------------------------
2005 2004 2003
-------- -------- --------
REVENUES:
Oil and natural gas $195,255 $202,447 $137,124
Price risk management activities (251) 126 --
Interest and other 692 545 355
-------- -------- --------
195,696 203,118 137,479
-------- -------- --------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 15,860 14,035 11,260
Severance and ad valorem taxes 8,811 9,394 7,608
Depletion and depreciation 97,354 102,915 75,441
General and administrative 18,010 15,169 11,610
Accretion expense 1,120 601 667
Hurricane damage repairs 3,066 -- --
Write-down of securities held -- 195 --
-------- -------- --------
144,221 142,309 106,586
-------- -------- --------
EARNINGS BEFORE OTHER EXPENSES & INCOME TAXES 51,475 60,809 30,893
-------- -------- --------
OTHER EXPENSES:
Interest expense 4,724 7,154 11,496
Debt conversion expense -- 1,188 --
-------- -------- --------
4,724 8,342 11,496
-------- -------- --------
EARNINGS BEFORE INCOME TAXES 46,751 52,467 19,397
-------- -------- --------
INCOME TAXES:
Current (568) 834 (731)
Deferred 18,568 18,508 4,980
-------- -------- --------
18,000 19,342 4,249
-------- -------- --------
EARNINGS BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 28,751 33,125 15,148
Cumulative effect of change in accounting principle -- -- (1,309)
-------- -------- --------
NET EARNINGS 28,751 33,125 13,839
Dividends on preferred stock 902 3,877 6,593
-------- -------- --------
NET EARNINGS APPLICABLE TO COMMON STOCKHOLDERS $ 27,849 $ 29,248 $ 7,246
======== ======== ========
NET EARNINGS PER SHARE BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE:
Basic $ 0.33 $ 0.41 $ 0.16
Diluted $ 0.31 $ 0.37 $ 0.15
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE
PER SHARE:
Basic and Diluted $ -- $ -- $ (0.02)
NET EARNINGS PER SHARE:
Basic $ 0.33 $ 0.41 $ 0.14
Diluted $ 0.31 $ 0.37 $ 0.13
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic 84,527 72,084 53,325
Diluted 90,090 79,033 57,144
See notes to consolidated financial statements.
-41-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
DECEMBER 31,
-----------------------
2005 2004
---------- ----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 23,265 $ 24,297
Restricted cash 1,234 891
Accounts receivable, less allowance for doubtful
accounts of $242 [2005 and 2004] 41,188 27,763
Prepaid expenses and other 1,294 2,263
Assets from price risk management activities 528 5,705
Deferred tax asset 1,150 882
---------- ----------
Total current assets 68,659 61,801
---------- ----------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method
(including $26,623 [2005] and $34,731 [2004] not
subject to depletion) 1,512,036 1,377,649
Land 48 478
Equipment and other 6,540 10,039
---------- ----------
1,518,624 1,388,166
Less accumulated depletion and depreciation 1,032,595 938,965
---------- ----------
Total property and equipment, net 486,029 449,201
---------- ----------
OTHER ASSETS:
Assets from price risk management activities 235 --
Other 879 2,272
---------- ----------
Total other assets 1,114 2,272
---------- ----------
TOTAL ASSETS $ 555,802 $ 513,274
========== ==========
See notes to consolidated financial statements.
-42-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
DECEMBER 31,
---------------------
2005 2004
--------- ---------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 7,595 $ 14,983
Revenues and royalties payable 9,149 8,117
Due to affiliates 4,638 3,866
Notes payable 1,103 870
Accrued liabilities 22,272 21,406
Liabilities from price risk management activities 3,977 8,003
Asset retirement obligations 2,879 1,331
Current income taxes payable 108 105
--------- ---------
Total current liabilities 51,721 58,681
--------- ---------
LONG-TERM DEBT 75,000 75,129
--------- ---------
OTHER:
Deferred income taxes 41,967 23,521
Liabilities from price risk management activities 464 --
Asset retirement obligations 9,085 8,293
Other -- 20
--------- ---------
51,516 31,834
--------- ---------
COMMITMENTS AND CONTINGENCIES (NOTES 5, 6 AND 10)
REDEEMABLE CONVERTIBLE PREFERRED STOCK:
Preferred stock, 8.5%, $1.00 par value (1,500,000
shares authorized, none [2005] and 315,886
[2004] shares of Series C redeemable preferred
issued at stated value) -- 31,589
--------- ---------
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares
authorized, 86,817,658 [2005] and 79,215,394
[2004] issued) 900 821
Additional paid-in capital 524,692 490,351
Accumulated deficit (145,395) (173,244)
Accumulated other comprehensive loss (2,314) (1,574)
Unamortized deferred compensation (318) (313)
--------- ---------
Total stockholders' equity 377,565 316,041
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 555,802 $ 513,274
========= =========
See notes to consolidated financial statements.
-43-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
YEAR ENDED DECEMBER 31,
--------------------------------
2005 2004 2003
--------- --------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $ 28,751 $ 33,125 $ 13,839
Adjustments to reconcile net earnings to net cash
provided by operating activities:
Cumulative effect of change in accounting principle -- -- 1,309
Depletion and depreciation 97,354 102,915 75,441
Amortization of other assets 446 1,506 1,715
Non-cash compensation 1,845 1,920 1,579
Non-cash price risk management activities 251 (126) --
Debt conversion expense -- 1,188 --
Write-down of securities held -- 195 --
Accretion expense 1,120 601 667
Deferred income taxes 18,568 18,508 4,980
Changes in assets and liabilities:
Restricted cash (343) (891) --
Accounts receivable (13,425) (3,060) (536)
Due from affiliates -- -- 1,557
Prepaid expenses and other 969 (677) 635
Accounts payable (7,388) 6,291 (8,150)
Due to affiliates 772 3,563 303
Revenues and royalties payable 1,032 (4,318) 57
Other assets and liabilities 4,127 10,751 (1,774)
--------- --------- --------
Net cash provided by operating activities 134,079 171,491 91,622
--------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (132,912) (142,436) (71,920)
Proceeds from (settlements on) sale of property (51) (72) 4,893
--------- --------- --------
Net cash used in investing activities (132,963) (142,508) (67,027)
--------- --------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt 10,000 75,129 --
Reductions in long-term debt (10,129) (132,320) (51,430)
Proceeds - Notes payable 3,142 2,537 1,888
Reductions - Notes payable (2,909) (1,861) (2,525)
Repurchase of common stock -- (49,291) --
Issuance of stock/exercise of stock options 13 94,777 33,185
Preferred dividends (2,166) (5,248) --
Additions to deferred loan costs (99) (1,230) (179)
--------- --------- --------
Net cash used in financing activities (2,148) (17,507) (19,061)
--------- --------- --------
NET CHANGE IN CASH AND CASH EQUIVALENTS (1,032) 11,476 5,534
Cash and cash equivalents at beginning of year 24,297 12,821 7,287
--------- --------- --------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 23,265 $ 24,297 $ 12,821
========= ========= ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Non-cash financing activities:
Conversion of preferred stock $ (30,625) $ (27,734) $ --
Issuance of shares for settlement of accrued liabilities $ (1,932) $ -- $ --
Conversion of convertible subordinated debt $ -- $ (20,000) $ --
See notes to consolidated financial statements.
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THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2003, 2004 AND 2005 (in thousands)
Accumulated
Common Stock Additional Other Unamortized Treasury Stock
----------------- Paid-In Accumulated Comprehensive Deferred ----------------
Shares Par Value Capital Deficit Loss Compensation Shares Cost Total
------ --------- ---------- ----------- ------------- ------------ ------ -------- --------
Balance, December 31, 2002 50,089 $ 557 $ 378,215 $ (209,738) $ (4,938) $ (356) 3,779 $(30,347) $133,393
Issuance of rights to common
stock -- 8 1,256 -- -- (1,264) -- -- --
Company's 401(k) plan
contribution 109 -- (498) -- -- -- (93) 747 249
Exercise of stock options 80 1 78 -- -- -- (22) 177 256
Compensation expense -- -- -- -- -- 1,330 -- -- 1,330
Issuance of shares frm stock
offering 8,704 50 3,456 -- -- -- (3,664) 29,423 32,929
Accum. other comprehensive income -- -- -- -- (2,766) -- -- -- (2,766)
Issuance for conversion of pref
stock 2,743 28 11,670 -- -- -- -- -- 11,698
Preferred dividends -- -- -- (6,593) -- -- -- -- (6,593)
Net earnings -- -- -- 13,839 -- -- -- -- 13,839
------ ----- -------- --------- ------- ------- ------ -------- --------
Balance, December 31, 2003 61,725 644 394,177 (202,492) (7,704) (290) -- -- 184,335
Issuance of rights to common
stock -- 3 1,597 -- -- (1,600) -- -- --
Company's 401(k) plan
contribution 52 -- 343 -- -- -- -- -- 343
Exercise of stock options 27 -- 131 -- -- -- -- -- 131
Compensation expense -- -- -- -- -- 1,577 -- -- 1,577
Accum. other comprehensive income -- -- -- -- 5,945 -- -- -- 5,945
Write-down of securities held -- -- -- -- 185 -- -- -- 185
Issuance for conversion of pref
stock 6,484 65 27,669 -- -- -- -- -- 27,734
Issuance for conversion of sub
debt 4,209 42 21,146 -- -- -- -- -- 21,188
Issuance of shares frm stock
offering 13,800 138 94,508 -- -- -- -- -- 94,646
Repurchase of common stock -- -- -- -- -- -- (7,082) (49,291) (49,291)
Retirement of treasury stock
(09/04) (7,082) (71) (49,220) -- -- -- 7,082 49,291 --
Preferred dividends -- -- -- (3,877) -- -- -- -- (3,877)
Net earnings -- -- -- 33,125 -- -- -- -- 33,125
------ ----- -------- --------- ------- ------- ------ -------- --------
Balance, December 31, 2004 79,215 821 490,351 (173,244) (1,574) (313) -- -- 316,041
Issuance of rights to common
stock -- 3 1,597 -- -- (1,600) -- -- --
Company's 401(k) plan
contribution 53 -- 250 -- -- -- -- -- 250
Exercise of stock options 49 -- 163 -- -- -- -- -- 163
Compensation expense -- -- -- -- -- 1,595 -- -- 1,595
Accum. other comprehensive income -- -- -- -- (740) -- -- -- (740)
Issuance for conversion of pref
stock 7,099 71 30,554 -- -- -- -- -- 30,625
Issuance cost - 2004 stock
offering -- -- (150) -- -- -- -- -- (150)
Issuance of shares as
compensation 402 5 1,927 -- -- -- -- -- 1,932
Preferred dividends -- -- -- (902) -- -- -- -- (902)
Net earnings -- -- -- 28,751 -- -- -- -- 28,751
------ ----- -------- --------- ------- ------- ------ -------- --------
Balance, December 31, 2005 86,818 $ 900 $524,692 $(145,395) $(2,314) $ (318) -- $ -- $377,565
====== ===== ======== ========= ======= ======= ====== ======== ========
See notes to consolidated financial statements.
-45-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(thousands of dollars)
YEAR ENDED DECEMBER 31,
-----------------------------
2005 2004 2003
-------- ------- --------
Net earnings applicable to common stockholders $ 27,849 $29,248 $ 7,246
-------- ------- --------
Other comprehensive income (loss), net of tax, for
unrealized losses from hedging activities:
Unrealized holding losses arising during period (1) (14,116) (6,161) (12,461)
Reclassification adjustments on settlement of contracts (2) 13,376 12,106 9,695
Write-down of securities held -- 185 --
-------- ------- --------
(740) 6,130 (2,766)
-------- ------- --------
Total comprehensive income $ 27,109 $35,378 $ 4,480
======== ======= ========
(1) Net of income tax (expense) benefit $ 7,601 $ 3,317 $ 6,710
(2) Net of income tax expense $ (7,202) $(6,518) $ (5,221)
See notes to consolidated financial statements.
-46-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
The Meridian Resource Corporation and its subsidiaries, (the "Company" or
"Meridian") explores for, acquires, develops and produces oil and natural gas
reserves, principally located onshore in south Louisiana, the Texas Gulf Coast
and offshore in the Gulf of Mexico. The Company was initially organized in 1985
as a master limited partnership and operated as such until 1990 when it
converted into a Texas corporation.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company and
its wholly owned subsidiaries, after eliminating all significant intercompany
transactions.
RESTRICTED CASH
The Company classifies cash balances as restricted cash when cash is restricted
as to withdrawal or usage. The restricted cash balance at December 31, 2005, was
$1,234,000, and at December 31, 2004, was $891,000. The restricted cash is
related to a contractual obligation with respect to royalties payable.
PROPERTY AND EQUIPMENT
The Company follows the full cost method of accounting for its investments in
oil and natural gas properties. All costs incurred in the acquisition,
exploration and development of oil and natural gas properties, including
unproductive wells, are capitalized. Included in capitalized costs are general
and administrative costs that are directly related with acquisition, exploration
and development activities. Proceeds from the sale of oil and natural gas
properties are credited to the full cost pool, except in transactions involving
a significant quantity of reserves, or where the proceeds received from the sale
would significantly alter the relationship between capitalized costs and proved
reserves, in which case a gain or loss is recognized. Under the rules of the
Securities and Exchange Commission ("SEC") for the full cost method of
accounting, the net carrying value of oil and natural gas properties, reduced by
the asset retirement obligation, is limited to the sum of the present value (10%
discount rate) of the estimated future net cash flows from proved reserves,
based on the current prices and costs as adjusted for the Company's cash flow
hedge positions, plus the lower of cost or estimated fair market value of
unproved properties adjusted for related income tax effects.
Capitalized costs of proved oil and natural gas properties are depleted on a
units of production method using proved oil and natural gas reserves. Costs
depleted include net capitalized costs subject to depletion and estimated future
dismantlement, restoration, and abandonment costs. Estimated future abandonment,
dismantlement and site restoration costs include costs to dismantle, relocate
and dispose of the Company's offshore production platforms, gathering systems,
wells and related structures, considering related salvage values.
Equipment, which includes computer equipment, hardware and software, furniture
and fixtures, leasehold improvements and automobiles, is recorded at cost and is
generally depreciated on a straight-line basis over the estimated useful lives
of the assets, which range in periods of three to seven years.
Repairs and maintenance are charged to expense as incurred.
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STATEMENT OF CASH FLOWS
For purposes of the statements of cash flows, cash equivalents include time
deposits, certificates of deposit and all highly liquid instruments with
original maturities of three months or less. The Company made cash payments for
interest of $3.9 million, $6.3 million and $9.6 million in 2005, 2004 and 2003,
respectively. Cash payments for income taxes (federal and state, net of
receipts) were $1,285,000 for 2005, $950,000 for 2004, and $23,000 for 2003.
CONCENTRATIONS OF CREDIT RISK
Substantially all of the Company's receivables are due from oil and natural gas
purchasers and other oil and natural gas producing companies located in the
United States. Accounts receivable are generally not collateralized.
Historically, credit losses incurred on receivables of the Company have not been
significant.
The Company maintains its cash in bank deposit accounts which, at times, may
exceed federally insured limits. Accounts are guaranteed by the Federal Deposit
Insurance Corporation ("FDIC") up to $100,000. At December 31, 2005, and
December 31, 2004, the Company had approximately $24,370,000 and $22,970,000,
respectively, in excess of FDIC insured limits. The Company has not experienced
any losses in such accounts.
REVENUE RECOGNITION
Meridian recognizes oil and natural gas revenue from its interests in producing
wells as oil and natural gas is produced and sold from those wells (the sales
method). Oil and natural gas sold is not significantly different from the
Company's share of production.
EARNINGS PER SHARE
Basic earnings per share amounts are calculated based on the weighted average
number of shares of common stock outstanding during each period. Diluted
earnings per share is based on the weighted average number of shares of common
stock outstanding for the periods, including the dilutive effects of stock
options, warrants granted and convertible debt. Dilutive options and warrants
that are issued during a period or that expire or are canceled during a period
are reflected in the computations for the time they were outstanding during the
periods being reported. Options where the exercise price of the options exceeds
the average price for the period are considered antidilutive, and therefore are
not included in the calculation of dilutive shares.
STOCK OPTIONS
As permitted by SFAS No. 123, "Accounting for Stock Based Compensation," the
Company applied the existing accounting requirements for stock options and
stock-based awards contained in Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees," and related Interpretations and
consensus of the Emerging Issues Task Force in terms of measuring compensation
expense.
SFAS 123, "Accounting for Stock-Based Compensation," as amended by SFAS 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure,"
established accounting and disclosure requirements using a fair value-based
method of accounting for stock-based employee compensation plans. As provided
for under SFAS 123, there has been no amount of compensation expense recognized
for the Company's stock option plans. The Company accounts for stock-based
compensation using the intrinsic value method prescribed in Accounting
Principles Board Opinion 25, "Accounting for Stock Issued to Employees."
Compensation expense is recorded for restricted stock awards over the requisite
vesting periods based upon the market value on the date of the grant. No
stock-based compensation expense was recorded in the years ended December 31,
2005, 2004 or 2003.
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The following is a reconciliation of reported earnings and earnings per share as
if the Company used the fair value method of accounting for stock-based
compensation (thousands of dollars, except per share information):
2005 2004 2003
------- ------- ------
Net earnings applicable to common stockholders as reported $27,849 $29,248 $7,246
Stock-based compensation (expense) benefit determined
under fair value method for all awards, net of tax (237) (119) 63
------- ------- ------
Net earnings applicable to common stockholders pro forma $27,612 $29,129 $7,309
======= ======= ======
Basic earnings per share:
As reported $ 0.33 $ 0.41 $ 0.14
Pro forma $ 0.33 $ 0.40 $ 0.14
Diluted earnings per share:
As reported $ 0.31 $ 0.37 $ 0.13
Pro forma $ 0.31 $ 0.37 $ 0.13
Fair value was estimated at the date of grant using the Black-Scholes option
pricing model with the following weighted average assumptions: risk-free
interest rate of 3.97%, 3.37% and 2.87%; dividend yield of 0%; volatility
factors of the expected market price of the Company's common stock of 0.92, 0.96
and 1.02 for 2005, 2004 and 2003, respectively; and a weighted-average expected
life of five years. These assumptions resulted in a weighted average grant date
fair value of $3.43, $5.92 and $3.44 for options granted in 2005, 2004 and 2003,
respectively. For purposes of the pro forma disclosures, the estimated fair
value is amortized to expense over the awards' vesting period.
FAIR VALUE OF FINANCIAL INSTRUMENTS.
Our financial instruments consist of cash and cash equivalents, accounts
receivable, accounts payable and bank borrowings. The carrying amounts of cash
and cash equivalents, accounts receivable and accounts payable approximate fair
value due to the highly liquid nature of these short-term instruments. The fair
values of the bank borrowings approximate the carrying amounts as of December
31, 2005 and 2004, and were determined based upon variable interest rates
currently available to us for borrowings with similar terms.
DERIVATIVE FINANCIAL INSTRUMENTS
In June 1998 the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative
Instruments and Certain Hedging Activities. In June 2000 the FASB issued SFAS
No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activity, an Amendment of SFAS 133. SFAS No. 133 and SFAS No. 138 require that
all derivative instruments be recorded on the balance sheet at their respective
fair values.
The Company enters into derivative contracts to hedge the price risks associated
with a portion of anticipated future oil and gas production. The Company's
derivative financial instruments have not been entered into for trading purposes
and the Company has the ability and intent to hold these instruments to
maturity. Counterparties to the Company's derivative agreements are major
financial institutions.
All derivatives are recognized on the balance sheet at their fair value. On the
date the derivative contract is entered into, the Company designates the
derivative as either a hedge of the fair value of a recognized asset or
liability or of an unrecognized firm commitment ("fair value" hedge) or a hedge
of a forecasted transaction or the variability of cash flows to be received or
paid related to a recognized asset or liability ("cash flow" hedge). The Company
formally documents all relationships between hedging instruments and hedged
items, as well as
-49-
its risk management objective and strategy for undertaking various hedge
transactions. This process includes linking all derivatives that are designated
as fair-value or cash-flow hedges to specific assets and liabilities on the
balance sheet or to specific firm commitments or forecasted transactions. The
Company also formally assesses, both at the hedge's inception and on an ongoing
basis, whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in fair values or cash flows of hedged items.
Changes in the fair value of a derivative that is highly effective and that is
designated and qualifies as a cash-flow hedge are recorded in other
comprehensive income, until earnings are affected by the variability in cash
flows of the designated hedged item. The Company recognized minimal losses
related to hedge ineffectiveness during the year ended December 31, 2003, a gain
of $126,000 during the year ended December 31, 2004, and a loss of $251,000
during the year ended December 31, 2005.
The Company discontinues cash flow hedge accounting prospectively when it is
determined that the derivative is no longer effective in offsetting changes in
the fair value or cash flows of the hedged item, the derivative expires or is
sold, terminated, or exercised, the derivative is redesignated as a hedging
instrument because it is unlikely that a forecasted transaction will occur, or
management determines that designation of the derivative as a hedging instrument
is no longer appropriate.
When cash flow hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the Company continues to carry the
derivative on the balance sheet at its fair value with subsequent changes in
fair value included in earnings, and gains and losses that were accumulated in
other comprehensive income immediately recognized in earnings. In all other
situations in which hedge accounting is discontinued, the Company continues to
carry the derivative at its fair value on the balance sheet and recognizes any
subsequent changes in its fair value in earnings. Gains or losses accumulated in
other comprehensive income at the time the hedge relationship is terminated are
recorded in earnings.
NEW ACCOUNTING PRONOUNCEMENTS
On September 28, 2004, the SEC released Staff Accounting Bulletin ("SAB") 106
regarding the application of SFAS 143, "Accounting for Asset Retirement
Obligation ("AROs")," by oil and gas producing companies following the full cost
accounting method. Pursuant to SAB 106, oil and gas producing companies that
have adopted SFAS 143 should exclude the future cash outflows associated with
settling AROs (ARO liabilities) from the computation of the present value of
estimated future net revenues for the purposes of the full cost ceiling
calculation. In addition, estimated dismantlement and abandonment costs, net of
estimated salvage values, that have been capitalized (ARO assets) should be
included in the amortization base for computing depreciation, depletion and
amortization expense. Disclosures are required to include discussion of how a
company's ceiling test and depreciation, depletion and amortization calculations
are impacted by the adoption of SFAS 143. SAB 106 is effective prospectively as
of the beginning of the first fiscal quarter beginning after October 4, 2004.
Since our adoption of SFAS 143 on January 1, 2003, we have calculated the
ceiling test and our depreciation, depletion and amortization expense in
accordance with the interpretations set forth in SAB 106; therefore, the
adoption of SAB 106 had no effect on our financial statements.
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 would eliminate the
ability to account for share-based compensation transactions using APB Opinion
No. 25, "Accounting for Stock Issued to Employees," and generally would require
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. Under this method, compensation cost will be
recognized in our financial statements beginning January 1, 2006, based on the
requirements of SFAS
-50-
No. 123R for all share-based payments granted or modified after that date, and
based on the requirements of SFAS No. 123R for all unvested awards granted prior
to the adoption date of SFAS No.123R. The impact on the Company's results of
operations is expected to be similar to the pro forma disclosures made above.
In May 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error
Corrections" which replaces Accounting Principles Board Opinions No. 20,
"Accounting Changes" and Statement of Financial Accounting Standards No. 3,
"Reporting Accounting Changes in Interim Financial Statements - An Amendment of
APB Opinion No. 28." SFAS No. 154 provides guidance on the accounting for and
reporting of accounting changes and error corrections. It establishes
retrospective application, or the latest practicable date, as the required
method for reporting a change in accounting principle and the reporting of a
correction of an error. SFAS No. 154 is effective for accounting changes and
correction of errors made in fiscal years beginning after December 15, 2005. The
Company adopted the provisions of SFAS No. 154 on January 1, 2006.
USE OF ESTIMATES
The preparation of financial statements in accordance with accounting principles
generally accepted in the United States of America requires the Company to make
estimates and judgments that affect the reported amounts of assets, liabilities,
revenues and expenses, and disclosure of contingent assets and liabilities, if
any, at the date of the financial statements. The Company analyzes its
estimates, including those related to oil and gas revenues, bad debts, oil and
gas properties, income taxes and contingencies and litigation. The Company bases
its estimates on historical experience and various other assumptions that are
believed to be reasonable under the circumstances. Actual results may differ
from these estimates under different assumptions or conditions.
RECLASSIFICATION OF PRIOR PERIOD STATEMENTS
Certain minor reclassifications have been made to the prior period financial
statements to conform to current year presentation.
3. 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
the dismantlement and abandonment costs, excluding salvage values.
Upon adoption, the Company recorded transition amounts for liabilities related
to its wells, and the associated costs to be capitalized. A liability of $4.5
million was recorded to long-term liabilities and a net asset of $3.2 million
was recorded to oil and natural gas properties on January 1, 2003. This resulted
in a cumulative effect of an accounting change of ($1.3) million. Accretion
expenses subsequent to the adoption of this accounting statement decreased net
earnings $1.1 million, $0.6 million and $0.7 million in 2005, 2004 and 2003,
respectively.
-51-
The pro forma effects of the application of SFAS 143, as if the statement had
been adopted on January 1, 2001, is presented below (thousands of dollars except
per share information):
2005 2004 2003
------- ------- ------
Net earnings applicable to common stockholders $27,849 $29,248 $7,246
Cumulative effect of accounting change -- -- 1,309
------- ------- ------
Pro forma net earnings applicable to common
stockholders $27,849 $29,248 $8,555
------- ------- ------
Pro forma earnings per share:
Basic $ 0.33 $ 0.41 $ 0.16
Diluted $ 0.31 $ 0.37 $ 0.15
The following table describes the change in the Company's asset retirement
obligations for the years ended December 31, 2005 and 2004 (thousands of
dollars):
Asset retirement obligation at December 31, 2003 $ 4,102
Additional retirement obligations recorded in 2004 1,051
Settlements during 2004 (972)
Revisions to estimates during 2004 4,842
Accretion expense for 2004 601
-------
Asset retirement obligation at December 31, 2004 9,624
Additional retirement obligations recorded in 2005 883
Settlements during 2005 (182)
Revisions to estimates and other changes during 2005 519
Accretion expense for 2005 1,120
-------
Asset retirement obligation at December 31, 2005 $11,964
=======
Our revisions to estimates represent changes to the expected amount and timing
of payments to settle our asset retirement obligations. These changes primarily
result from obtaining new information about the timing of our obligations to
plug our natural gas and oil wells and costs to do so.
-52-
4. DEBT
CURRENT REVOLVING CREDIT AGREEMENT
On December 23, 2004, the Company amended its credit agreement 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 PLC, 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 November 1, 2005. As of December 31, 2005,
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 would exist
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 expects to be in full compliance
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 December 31, 2005, the three-month LIBOR interest rate
was 4.54%. The Credit Facility also provides for commitment fees of 0.375%
calculated on the difference between the borrowing base and the aggregate
outstanding loans and letters of credit under the Credit Facility.
FORMER CREDIT FACILITY
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In 2002-2004, the Company had a $175 million senior secured credit agreement. In
the first nine months of 2004, the Company made repayments of $48.3 million,
bringing the outstanding balance to $74 million as of September 30, 2004. On
December 23, 2004, the Company made a final debt repayment of $74 million, which
paid off this senior secured credit agreement in full.
SUBORDINATED CREDIT AGREEMENT
The Company had a short-term subordinated credit agreement with Fortis Capital
Corp. for $25 million that had a maturity date of December 31, 2004. Note
payments totaling $6.25 million were paid in 2002, $8.75 million was paid in
2003, and the remaining $10 million was paid in 2004.
9 1/2% CONVERTIBLE SUBORDINATED NOTES
During June 1999, the Company completed private placements of an aggregate of
$20 million of its 9 1/2% convertible subordinated Notes ("Notes") due June 18,
2005. The Notes were unsecured and contained customary events of default, but
did not contain any maintenance or other restrictive covenants. Interest was
payable on a quarterly basis. The Company was in compliance with the financial
covenants under this agreement.
During March 2002, the Company and the holders of the Notes amended the
conversion price from $7.00 to $5.00 per share. The Notes were convertible at
any time by the holders of the Notes into shares of the Company's common stock,
$0.01 par value, utilizing the conversion price. The conversion price was
subject to customary anti-dilution provisions. The holders of the Notes were
granted registration rights with respect to the shares of common stock that
would be issued upon conversion of the Notes.
During March 2004, the Notes were converted into 4.0 million shares of the
Company's common stock at a conversion price of $5.00 per share, and included an
additional non-cash conversion expense of approximately $1.2 million that was
incurred via the issuance of common stock priced at market.
CURRENT DEBT MATURITIES
Scheduled debt maturities for the next five years and thereafter, as of December
31, 2005, are as follows: none in 2006 or 2007, $75 million in 2008, and none
thereafter.
5. LEASE OBLIGATIONS
The Company has a seven-year operating lease for office space with a primary
term expiring in September 2006. The Company is currently in negotiations for
office lease terms beyond September 2006. The Company also has operating leases
for equipment with various terms, none exceeding three years. Rental expense
amounted to approximately $2.5 million, $2.4 million and $2.3 million in 2005,
2004 and 2003, respectively. Future minimum lease payments under all
non-cancelable operating leases having initial terms of one year or more are
$1.8 million for 2006, $0.1 million for 2007 and none thereafter.
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 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
-54-
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 December 31, 2005.
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
December 31, 2005.
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.
7. TAXES ON INCOME
Provisions (benefits) for federal and state income taxes are as follows
(thousands of dollars):
YEAR ENDED DECEMBER 31,
--------------------------
2005 2004 2003
------- ------- ------
Current:
Federal $ (676) $ 905 $ (568)
State 108 (71) (163)
Deferred:
Federal 17,480 18,160 4,980
State 1,088 348 --
------- ------- ------
Income tax expense $18,000 $19,342 $4,249
======= ======= ======
The Company's income tax provision is attributed to the following items
(thousands of dollars):
YEAR ENDED DECEMBER 31,
---------------------------
2005 2004 2003
------- ------- -------
Earnings before cumulative effect of change in
accounting principle $18,000 $19,342 $ 4,249
Losses on derivatives recognized in other
comprehensive income (loss) (390) 3,199 (1,489)
------- ------- -------
Total income tax provision $17,610 $22,541 $ 2,760
======= ======= =======
-55-
Income tax expense as reported is reconciled to the federal statutory rate (35%)
as follows (thousands of dollars):
YEAR ENDED DECEMBER 31,
---------------------------
2005 2004 2003
------- ------- -------
Income tax provision computed at statutory rate $16,363 $18,364 $ 6,331
Nondeductible costs 479 607 758
State income tax, net of federal tax benefit 1,158 302 (106)
Decrease in net operating loss carryover due to
expiration -- 69 --
Change in valuation allowance -- -- (2,734)
------- ------- -------
Income tax expense $18,000 $19,342 $ 4,249
======= ======= =======
Deferred income taxes reflect the net tax effects of net operating losses,
depletion carryovers, and temporary differences between the carrying amounts of
assets and liabilities for financial reporting purposes and the amounts used for
income tax purposes. Significant components of the Company's deferred tax assets
and liabilities are as follows (thousands of dollars):
DECEMBER 31,
-------------------
2005 2004
-------- --------
Deferred tax assets:
Net operating tax loss carryforward $ 51,071 $ 41,244
Statutory depletion carryforward 950 950
Tax credits 1,311 1,987
Unrealized hedge loss 1,240 850
Other 5,214 4,698
-------- --------
Total deferred tax assets 59,786 49,729
-------- --------
Deferred tax liabilities:
Book in excess of tax basis in oil and gas
properties 100,603 72,298
Basis differential in long-term investments 0 70
-------- --------
Total deferred tax liabilities 100,603 72,368
-------- --------
Net deferred tax asset (liability) $(40,817) $(22,639)
======== ========
As of December 31, 2005, the Company has approximately $145.9 million of tax net
operating loss carryforwards. The net operating loss carryforwards assume that
certain items, primarily intangible drilling costs, have been deducted to the
maximum extent allowed under the tax laws for the current year. However, the
Company has not made a final determination if an election will be made to
capitalize all or part of these items for tax purposes.
The net operating loss carryforwards begin to expire in 2006 and extend through
2023. A portion of the net operating loss carryforwards is subject to change in
ownership and separate return limitations that could restrict the Company's
ability to utilize such losses in the future.
As of December 31, 2005, the Company had net operating loss carryforwards for
regular tax and alternative minimum taxable income (AMT) purposes available to
reduce future taxable income. These carryforwards expire as follows (in
thousands of dollars):
-56-
NET AMT
YEAR OF OPERATING OPERATING
EXPIRATION LOSS LOSS
---------- --------- ---------
2006 $ 699 $ 699
2018 39,701 26,184
2019 47,730 48,630
2020 31 31
2021 36 36
2022 13,053 13,786
2023 44,668 44,516
-------- --------
TOTAL $145,918 $133,882
======== ========
As of December 31, 2005, the Company had approximately $1.3 million of
alternative minimum tax (credit) carryover that does not expire.
Generally Accepted Accounting Principles require a valuation allowance to be
recognized if, based on the weight of available evidence, it is more likely than
not that some portion or all of the deferred tax asset will not be realized. The
Company expects to fully utilize its net operating loss carryforward tax
benefits, and therefore did not record a valuation allowance in 2005.
8. REDEEMABLE CONVERTIBLE PREFERRED STOCK
A private placement totaling $66.9 million of 8.5% redeemable convertible
preferred stock was completed during May 2002. The preferred stock was
convertible into shares of the Company's common stock at a conversion price of
$4.45 per share. Dividends were payable semi-annually in cash or additional
preferred stock. At the option of the Company, one-third of the preferred shares
could be forced to convert to common stock if the closing price of the Company's
common stock exceeded 150% of the conversion price for 30 out of 40 consecutive
trading days on the New York Stock Exchange. The preferred stock was subject to
redemption at the option of the Company after March 2005, and mandatory
redemption on March 31, 2009. The holders of the preferred stock were granted
registration rights with respect to the shares of common stock issued upon
conversion of the preferred stock. In the last quarter of 2003, $12.2 million of
preferred stock was converted into 2.7 million shares of common stock.
In 2004, a total of $28.9 million of preferred stock was converted into 6.5
million shares of common stock. No gain or loss was recorded as a result of the
conversion. During the first six months of 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.
During 2005, $0.8 million of dividends were accumulated (net of $0.1 million of
deferred preferred stock offering costs amortized during 2005) and paid as the
Company completed the conversion of the remaining shares of preferred stock to
common stock. For the year ended December 31, 2004, $3.5 million of dividends
were accumulated (net of $0.4 million of deferred preferred stock offering costs
amortized during 2004), of which $2.2 million was paid in cash in July 2004 and
$1.3 million was paid in cash in January 2005. During 2003, dividends of $6.0
million were accumulated (net of $0.6 million of deferred preferred stock
offering costs amortized during 2003), of which $3.0 million was satisfied with
the issuance of additional shares of redeemable preferred stock and $3.0 million
was paid in cash in January 2004.
-57-
9. STOCKHOLDERS' EQUITY
COMMON STOCK
In August 2004, the Company completed a public offering of 13,800,000 shares of
common stock at a price of $7.25 per share. The total proceeds of the offering,
net of issuance costs, received by the Company were approximately $94.6 million.
A portion of the proceeds from the offering were utilized to repurchase all of
the 7,082,030 shares of its common stock that were beneficially owned by Shell
Oil Company for $49.3 million and a portion of the remaining proceeds of that
equity offering was used to repay borrowings under the Company's senior secured
credit agreement. The repurchased 7,082,030 shares of common stock that were
held in Treasury Stock, subsequent to the offering, were retired as of September
30, 2004.
In August 2003, the Company completed a private offering of 8,703,537 shares of
common stock at a price of $3.87 per share. The total proceeds of the offering,
net of issuance costs, received by the Company were approximately $33.0 million.
The Company used the majority of these funds to retire $31.8 million in
long-term debt, and the remainder of the proceeds was used for exploration
activities and for other general corporate purposes.
WARRANTS
The Company had the following warrants outstanding at December 31, 2005:
NUMBER OF EXERCISE
WARRANTS SHARES PRICE EXPIRATION DATE
-------- --------- -------- -----------------
Executive Officers 1,428,000 $5.85 *
General Partner 1,758,404 $0.11 December 31, 2015
* A date one year following the date on which the respective officer ceases
to be an employee of the Company.
As of December 31, 2005, the Company had outstanding (i) warrants (the "General
Partner Warrants") that entitle Joseph A. Reeves, Jr. and Michael J. Mayell to
purchase an aggregate of 1,758,404 shares of common stock at an exercise price
of $0.11 per share through December 31, 2015 and (ii) executive officer warrants
that entitle each of Joseph A. Reeves, Jr. and Michael J. Mayell to purchase an
aggregate of 714,000 shares of common stock at an exercise price of $5.85 for a
period until one year following the date on which the respective individual
ceases to be an employee of the Company ("Executive Officer Warrants").
The number of shares of common stock purchasable upon the exercise of each
warrant described above and its corresponding exercise price are subject to
customary anti-dilution adjustments. In addition to such customary adjustments,
the number of shares of common stock and exercise price per share of the General
Partner Warrants are subject to adjustment for any issuance of common stock by
the Company such that each warrant will permit the holder to purchase at the
same aggregate exercise price, a number of shares of common stock equal to the
percentage of outstanding shares of the common stock that the holder could
purchase before the issuance. Currently each of these warrants permits the
holder to purchase approximately 1% of the outstanding shares of the common
stock for an aggregate exercise price of $94,303. The General Partner Warrants
were issued to Messrs. Reeves and Mayell in conjunction with certain
transactions with Messrs. Reeves and Mayell that took place in anticipation of
the Company's consolidation in December 1990 and were a component of the total
consideration issued for various interests that Messrs. Reeves and Mayell had as
general partners in TMR, Ltd., a predecessor entity of the Company. There are
adequate authorized unissued common stock shares that are required to be issued
upon conversion of the General Partner Warrants. The Company is not required to
redeem the General Partner Warrants.
-58-
On June 7, 1994, the shareholders of the Company approved a conversion of Class
"B" Warrants into Executive Officer Warrants, held by Joseph A. Reeves, Jr. and
Michael J. Mayell, which entitled each of them to purchase an aggregate of
714,000 shares of common stock. The Executive Officer Warrants expire one year
following the date on which the respective officer ceases to be an employee of
the Company. The Executive Officer Warrants further provide that in the event
the officer's employment with the Company is terminated by the Company without
"cause" or by the officer for "good reason," the officer will have the option to
require the Company to purchase some or all of the Executive Officer Warrants
held by the officer for an amount per Executive Officer Warrant equal to the
difference between the exercise price, $5.85 per share, and the then prevailing
market price of the common stock. The Company may satisfy this obligation with
shares of common stock.
STOCK OPTIONS
Options to purchase the Company's common stock have been granted to officers,
employees, nonemployee directors and certain key individuals, under various
stock option plans. Options generally become exercisable in 25% cumulative
annual increments beginning with the date of grant and expire at the end of ten
years. At December 31, 2005, 2004 and 2003, 2,162,478, 1,670,685, and 2,130,334
shares, respectively, were available for grant under the plans. A summary of
option transactions follows:
WEIGHTED
NUMBER AVERAGE
OF SHARES EXERCISE PRICE
--------- --------------
Outstanding at December 31, 2002 4,164,075 $4.55
Granted 15,000 4.51
Exercised (80,000) 3.19
Canceled (540,250) 7.87
--------- -----
Outstanding at December 31, 2003 3,558,825 $4.08
Granted 173,750 7.94
Exercised (34,875) 4.49
Canceled (4,650) 5.78
--------- -----
Outstanding at December 31, 2004 3,693,050 $4.25
Granted 45,000 4.68
Exercised (48,500) 3.37
Canceled (94,500) 9.93
--------- -----
Outstanding at December 31, 2005 3,595,050 $4.12
========= =====
Shares exercisable:
December 31, 2003 3,510,700 $4.06
December 31, 2004 3,498,050 $4.06
December 31, 2005 3,430,050 $3.97
-59-
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
---------------------------------- ----------------------------------
WEIGHTED WEIGHTED
RANGE OF OUTSTANDING AT AVERAGE EXERCISABLE AT AVERAGE
EXERCISABLE PRICES DECEMBER 31, 2005 EXERCISE PRICE DECEMBER 31, 2005 EXERCISE PRICE
------------------ ----------------- -------------- ----------------- --------------
$3.00 - $4.99 3,107,650 $ 3.39 3,081,400 $ 3.38
$5.32 - $9.00 365,750 8.00 227,000 8.16
$11.13 121,650 11.13 121,650 11.13
--------- ------ --------- ------
3,595,050 $ 4.12 3,430,050 $ 3.97
========= ====== ========= ======
The weighted average remaining contractual life of options outstanding at
December 31, 2005, was approximately three years.
DEFERRED COMPENSATION
In July 1996, the Company through the Compensation Committee of the Board of
Directors offered to Messrs. Reeves and Mayell (the Company's Chief Executive
Officer and President, respectively) the option to accept in lieu of cash
compensation for their respective base salaries common stock pursuant to the
Company's Long Term Incentive Plan. Under such grants, Messrs. Reeves and Mayell
each elected to defer $400,000 for 2005, $400,000 for 2004 and $316,000 for
2003, which is substantially all of their salaried compensation for each of the
years. In exchange for and in consideration of their accepting this option to
reduce the Company's cash payments to each of Messrs. Reeves and Mayell, the
Company granted to each officer a matching deferral equal to 100% of that amount
deferred, which is subject to a one-year vesting period. Under the terms of the
grants, the employee and matching deferrals are allocated to a common stock
account in which units are credited to the accounts of the officer based on the
number of shares that could be purchased at the market price of the common
stock. For 1997, the price was determined at December 31, 1996, and for all
years subsequent to 1997, it was determined on a semi-annual basis at December
31st and June 30th. At December 31, 2005, the plan had reserved 3,850,000 shares
of common stock for future issuance and 3,225,988 rights have been granted. No
actual shares of common stock have been issued and the officer has no rights
with respect to any shares unless and until there is a distribution.
Distributions are to be made upon the death, retirement or termination of
employment of the officer.
The obligations of the Company with respect to the deferrals are unsecured
obligations. The shares of common stock that may be issuable upon distribution
of deferrals have been treated as a common stock equivalent in the financial
statements of the Company. Although no cash has been paid, to either Mr. Reeves
or Mr. Mayell for their base salaries during these periods, the compensation
expense required to be reported by the Company for the equity grants was
$1,595,000, $1,577,000 and $1,330,000 for 2005, 2004 and 2003 periods,
respectively, and is reflected in general and administrative expense and in oil
and gas properties for the years ended December 31, 2005, 2004 and 2003,
respectively.
STOCKHOLDER RIGHTS PLAN
On May 5, 1999, the Company's Board of Directors declared a dividend
distribution of one "Right" for each then-current and future outstanding share
of common stock. Each Right entitles the registered holder to purchase one
one-thousandth percent interest in a share of the Company's Series B Junior
Participating preferred stock with a par value of $.01 per share and an exercise
price of $30. Unless earlier redeemed by the Company at a price of $.01 each,
the Rights become exercisable only in certain circumstances constituting a
potential change in control of the Company and will expire on May 5, 2009.
Each share of Series B Junior Participating preferred stock purchased upon
exercise of the Rights will be
-60-
entitled to certain minimum preferential quarterly dividend payments as well as
a specified minimum preferential liquidation payment in the event of a merger,
consolidation or other similar transaction. Each share will also be entitled to
100 votes to be voted together with the common stockholders and will be junior
to any other series of preferred stock authorized or issued by the Company,
unless the terms of such other series provides otherwise.
In the event of a potential change in control, each holder of a Right, other
than Rights beneficially owned by the acquiring party (which will have become
void), will have the right to receive upon exercise of a Right that number of
shares of common stock of the Company, or, in certain instances, common stock of
the acquiring party, having a market value equal to two times the current
exercise price of the Right.
10. PROFIT SHARING AND SAVINGS PLAN
The Company has a 401(k) profit sharing and savings plan (the "Plan") that
covers substantially all employees and entitles them to contribute up to 15% of
their annual compensation, subject to maximum limitations imposed by the
Internal Revenue Code. The Company matches 100% of each employee's contribution
up to 6.5% of annual compensation subject to certain limitations as outlined in
the Plan. In addition, the Company may make discretionary contributions which
are allocable to participants in accordance with the Plan. Total expense related
to the Company's 401(k) plan was $300,000, $299,000 and $331,000 in 2005, 2004,
and 2003, respectively.
During 1998, the Company implemented a net profits program that was adopted
effective as of November 1997. All employees participate in this program.
Pursuant to this program, the Company adopted three separate well bonus plans:
(i) The Meridian Resource Corporation Geoscientist Well Bonus Plan (the
"Geoscientist Plan"); (ii) The Meridian Resource Corporation TMR Employees Trust
Well Bonus Plan (the "Trust Plan") and (iii) The Meridian Resource Corporation
Management Well Bonus Plan (the "Management Plan" and with the Management Plan
and the Geoscientist Plan, the "Well Bonus Plans"). Payments under the plans are
calculated based on revenues from production on previously discovered reserves,
as realized by the Company at current commodity prices, less operating expenses.
Total compensation related to these plans totaled $6.4 million, $6.9 million and
$4.3 million in 2005, 2004 and 2003, respectively. A portion of these amounts
has been capitalized with regard to personnel engaged in activities associated
with exploratory projects. The Executive Committee of the Board of Directors,
which is comprised of Messrs. Reeves and Mayell, administers each of the Well
Bonus Plans. The participants in each of the Well Bonus Plans are designated by
the Executive Committee in its sole discretion. Participants in the Management
Plan are limited to executive officers of the Company and other key management
personnel designated by the Executive Committee. Neither Messrs. Reeves nor
Mayell participate in the Management Plan. The participants in the Trust Plan
generally will be employees of the Company that do not participate in one of the
other Well Bonus Plans. Effective March 2001, the participants in the
Geoscientist Plan were notified that no additional future wells would be placed
into the plan. During 2002, the Executive Committee decided to modify this
position and for certain key geoscientists the plan will include future new
wells.
Pursuant to the Well Bonus Plans, the Executive Committee designates, in its
sole discretion, the individuals and wells that will participate in each of the
Well Bonus Plans. The Executive Committee also determines the percentage bonus
that will be paid under each well and the individuals that will participate
thereunder. The Well Bonus Plans cover all properties on which the Company
expends funds during each participant's employment with the Company, with the
percentage bonus generally ranging from less than .1% to .5%, depending on the
level of the employee. It is intended that these well bonuses function similar
to an actual net profit interests, except that the employee will not have a real
property interest and his or her rights to such bonuses will be subject to a
one-year vesting period, and will be subject to the general credit of the
Company. Payments under vested bonus rights will continue to be made after an
employee leaves the employment of the Company based on their adherence to the
obligations required in their non-compete agreement upon termination. The
Company has the option to make payments in whole, or in part, utilizing shares
of common
-61-
stock. The determination whether to pay cash or issue common stock will be based
upon a variety of factors, including the Company's current liquidity position
and the fair market value of the common stock at the time of issuance.
In connection with the execution of their employment contracts in 1994, both
Messrs. Reeves and Mayell were granted a 2% net profit interest in the oil and
natural gas production from the Company's properties to the extent the Company
acquires a mineral interest therein. The net profits interest for Messrs. Reeves
and Mayell applies to all properties on which the Company expends funds during
their employment with the Company. Each grant of a net profits interest is
reflected at a value based on a third party appraisal of the interest granted.
The net profit interests represent real property rights that are not subject to
vesting or continued employment with the Company. Messrs. Reeves and Mayell will
not participate in the Well Bonus Plans for any particular property to the
extent the original net profit interest grants covers such property.
11. OIL AND NATURAL GAS HEDGING ACTIVITIES
The Company may address market risk by selecting instruments whose value
fluctuations correlate strongly with the underlying commodity being hedged. 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 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 minimal losses
related to hedge ineffectiveness during the year ended December 31, 2003, a gain
of $126,000 during the year ended December 31, 2004, and a loss of $251,000
during the year ended December 31, 2005.
For the year ended December 31, 2005, the change in estimated fair value of the
Company's oil and natural gas contracts was an unrealized loss of $3.6 million
($2.3 million net of tax) which is recognized in other comprehensive income.
Based upon oil and natural gas commodity prices at December 31, 2005,
approximately $3.4 million of the loss deferred in other comprehensive income
could potentially lower gross revenues in 2006. These derivative agreements
expire at various dates through July 31, 2007.
Net settlements under these contracts reduced oil and natural gas revenues by
$20,578,000, $18,624,000 and $14,916,000 for the years ended December 31, 2005,
2004, and 2003 respectively, as a result of hedging transactions.
-62-
All of the Company's current hedging contracts are in the form of costless
collars. The costless collars provide the Company with a lower limit "floor"
price and an upper limit "ceiling" price on the hedged volumes. The floor price
represents the lowest price the Company will receive for the hedged volumes
while the ceiling price represents the highest price the Company will receive
for the hedged volumes. The costless collars are settled monthly based on the
NYMEX futures contract.
The notional amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 16% of proved developed natural gas production and 28% of proved
developed oil production during the respective terms of the hedging agreements.
The fair values of the hedges are based on the difference between the strike
price and the New York Mercantile Exchange future prices for the applicable
trading months.
The fair value of hedging agreements is recorded on the consolidated balance
sheet as assets or liabilities. The estimated fair value of hedging agreements
as of December 31, 2005, is provided below:
Ceiling Fair Value
Notional Floor Price Price Dec 31, 2005
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------- ------------ --------------
NATURAL GAS (MMBTU)
Jan 2006 - Mar 2006 Collar 1,690,000 $ 7.50 $11.25 $(1,282)
Apr 2006 - Oct 2006 Collar 1,130,000 $ 8.00 $14.50 37
-------
Total Natural Gas (1,245)
-------
CRUDE OIL (BBLS)
Jan 2006 - Jul 2006 Collar 113,000 $37.50 $47.50 (1,712)
Jan 2006 - Jul 2006 Collar 25,000 $40.00 $50.00 (331)
Aug 2006 - Jul 2007 Collar 168,000 $50.00 $74.00 (391)
-------
Total Crude Oil (2,434)
-------
$(3,679)
=======
12. MAJOR CUSTOMERS
Major customers for the years ended December 31, 2005, 2004 and 2003, were as
follows (based on sales exceeding 10% of total oil and natural gas revenues):
YEAR ENDED DECEMBER 31,
-----------------------
CUSTOMER 2005 2004 2003
-------- ---- ---- ----
Superior Natural Gas................. 46% 45% 19%
Crosstex/Louisiana Intrastate Gas.... 19% 22% 24%
Conoco, Inc.......................... -- -- 10%
13. RELATED PARTY TRANSACTIONS
Historically since 1994, affiliates of Meridian have been permitted to hold
interests in projects of the Company. With the approval of the Board of
Directors, Texas Oil Distribution and Development, Inc. ("TODD"), JAR Resources
LLC ("JAR") and Sydson Energy, Inc. ("Sydson"), entities controlled by Joseph A.
Reeves, Jr. and Michael J. Mayell, respectively, have each invested in all
Meridian drilling locations on a promoted basis, where applicable, at a 1.5% to
4% working interest basis. The maximum percentage that either may elect to
participate in any prospect is a 4% working interest. On a collective basis,
TODD, JAR and Sydson invested $9,997,000, $8,539,000 and $5,161,000 for the
years ended December 31, 2005, 2004 and 2003, respectively, in oil and natural
gas drilling activities for which the Company was the operator. Net amounts due
to TODD,
-63-
JAR and Mr. Reeves were approximately $2,308,000 and $1,751,000 as of December
31, 2005 and 2004, respectively. Net amounts due to Sydson and Mr. Mayell were
approximately $2,330,000 and $2,115,000 as of December 31, 2005 and 2004,
respectively.
Mr. Joe Kares, a Director of Meridian, is a partner in the public accounting
firm of Kares & Cihlar, which provided the Company with accounting services for
the years ended December 31, 2005, 2004 and 2003 and received fees of
approximately $320,000, $255,000 and $210,000, respectively. Such fees exceeded
5% of the gross revenues of Kares & Cihlar for those respective years.
Management believes that such fees were equivalent to fees that would have been
paid to similar firms providing such services in arm's length transactions. Mr.
Kares also participated in the Management Plan described in Note 10 above,
pursuant to which he was paid approximately $464,000 during 2005, $298,000
during 2004, and $61,000 during 2003.
Mr. Gary A. Messersmith, a Director of Meridian, is currently a partner in the
law firm of Looper, Reed and McGraw in Houston, Texas, which provided legal
services for the Company for the years ended December 31, 2005, 2004 and 2003,
and received fees of approximately $19,000, $12,000 and $49,000, respectively.
Management believes that such fees were equivalent to fees that would have been
paid to similar firms providing such services in arm's length transactions. In
addition, the Company has Mr. Messersmith on a personal retainer of $8,333 per
month relating to his services provided to the Company. Mr. Messersmith also
participated in the Management Plan described in Note 10 above, pursuant to
which he was paid approximately $702,000 during 2005, $688,000 during 2004 and
$360,000 during 2003.
Mr. Joseph A. Reeves, Jr., an officer and Director of Meridian, has two
relatives currently employed by the Company. J. Drew Reeves, his son, is a staff
member in the Land Department. He has a Masters degree in Business
Administration from Louisiana State University and was employed as a Landman for
the firm of Land Management LLC in Metairie, Louisiana, prior to joining
Meridian in 2003. Mr. Drew Reeves was paid $100,000, $80,000 and $40,000 for the
years 2005, 2004 and 2003, respectively. Jeff Robinson is the son-in-law of
Joseph A. Reeves, Jr. and is employed as the Manager of the Company's
Information Technology Department and has been paid $111,000, $101,000 and
$42,000 for the years 2005, 2004 and 2003, respectively. Mr. Robinson earned his
undergraduate degree in MIS from Auburn University and was employed by BSI
Consulting for 5 years prior to joining Meridian in 2003. J. Todd Reeves, a
previous partner in the law firm of Creighton, Richards, Higdon and Reeves in
Covington, Louisiana, is the son of Joseph A. Reeves, Jr. This law firm provided
legal services for the Company for the years ended December 31, 2005 and 2004,
and received fees of approximately $32,000 and $67,000, respectively. Currently
he is a partner in the law firm of J. Todd Reeves and Associates, and is
providing legal services to the Company and received fees of approximately
$100,000 in 2005. Such fees exceeded 5% of the gross revenues for these firms
for those respective years. Management believes that such fees were equivalent
to fees that would have been paid to similar firms providing such services in
arm's length transactions.
Michael W. Mayell, the son of Michael J. Mayell, an officer and Director of
Meridian, is a staff member in the Production Department, and was paid $79,000,
$60,000, and $30,000, for the years 2005, 2004 and 2003, respectively. James T.
Bond, former Director of Meridian, is the father-in-law of Michael J. Mayell,
and has provided consultant services to the Company and received fees in the
amount of $175,000, $124,000, and $115,000, for the years 2005, 2004 and 2003,
respectively.
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14. EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted earnings per
share:
(in thousands, except per share)
YEAR ENDED DECEMBER 31,
---------------------------
2005 2004 2003
------- ------- -------
Numerator:
Net earnings applicable to common stockholders $27,849 $29,248 $ 7,246
Plus income impact of assumed conversions:
Preferred stock dividends N/A N/A N/A
Interest on convertible subordinated notes -- 270 N/A
Net earnings applicable to common stockholders
------- ------- -------
plus assumed conversions $27,849 $29,518 $ 7,246
------- ------- -------
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 84,527 72,084 53,325
Effect of potentially dilutive common shares:
Warrants 4,755 4,508 3,393
Employee and director stock options 808 1,589 426
Convertible subordinated notes N/A 852 N/A
Redeemable preferred stock N/A N/A N/A
------- ------- -------
Denominator for diluted earnings per share
- weighted-average shares outstanding and
assumed conversions 90,090 79,033 57,144
======= ======= =======
Basic earnings per share $ 0.33 $ 0.41 $ 0.14
======= ======= =======
Diluted earnings per share $ 0.31 $ 0.37 $ 0.13
======= ======= =======
N/A = Not Applicable, meaning anti-dilutive for periods presented. Due to its
anti-dilutive effect on earnings per share, approximately 2.1 million shares in
2005, 9.8 million shares in 2004 and 22.7 million shares in 2003 related to our
redeemable preferred stock, convertible subordinated notes, stock options and
warrants were excluded from the dilutive shares.
15. ACCRUED LIABILITIES
Below is the detail of our accrued liabilities on our balance sheets as of
December 31 (thousands of dollars):
2005 2004
------- -------
Capital expenditures $12,853 $12,662
Operating expenses/Taxes 2,794 2,005
Hurricane damage repairs 2,717 --
Compensation 1,949 3,355
Interest 503 60
Dividends -- 1,346
Other 1,456 1,978
------- -------
TOTAL $22,272 $21,406
======= =======
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16. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
Results of operations by quarter for the year ended December 31, 2005 were
(thousands of dollars, except per share):
QUARTER ENDED
---------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
2005
Revenues $50,044 $44,103 $36,845 $64,704
Results of operations from exploration
and production activities(1) 17,486 12,675 10,534 29,307
Net earnings(2) $ 6,127 $ 4,126 $ 3,276 $14,320
Net earnings per share:(2)
Basic $ 0.08 $ 0.05 $ 0.04 $ 0.17
Diluted $ 0.07 $ 0.05 $ 0.04 $ 0.16
Results of operations by quarter for the year ended December 31, 2004 were
(thousands of dollars, except per share) as follows:
QUARTER ENDED
---------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
2004
Revenues $46,192 $50,103 $53,037 $53,786
Results of operations from exploration
and production activities(1) 17,229 19,545 19,428 20,272
Net earnings (2) $ 5,287 $ 7,745 $ 7,786 $ 8,430
Net earnings per share:(2)
Basic $ 0.08 $ 0.11 $ 0.10 $ 0.11
Diluted 0.08 0.10 0.09 0.10
(1) Results of operations from exploration and production activities, which
approximate gross profit, are computed as operating revenues less lease
operating expenses, severance and ad valorem taxes, depletion, accretion
and hurricane damage repairs.
(2) Applicable to common stockholders
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17. SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (UNAUDITED)
The following information is being provided as supplemental information in
accordance with the provisions of SFAS No. 69, "Disclosures about Oil and Gas
Producing Activities."
COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES
YEAR ENDED DECEMBER 31,
-----------------------------
2005 2004 2003
-------- -------- -------
(thousands of dollars)
Costs incurred during the year:(1)
Property acquisition costs
Unproved $ 7,097 $ 16,687 $ 4,107
Proved -- -- --
Exploration 110,669 93,682 42,081
Development 14,916 31,610 25,586
Asset retirement cost accruals, net 1,220 4,921 1,326
-------- -------- -------
$133,902 $146,900 $73,100
======== ======== =======
(1) Costs incurred during the years ended December 31, 2005, 2004 and 2003
include general and administrative costs related to acquisition,
exploration and development of oil and natural gas properties, net of third
party reimbursements, of $13,814,000, $11,924,000 and $10,030,000,
respectively.
CAPITALIZED COSTS RELATING TO OIL AND NATURAL GAS PRODUCING ACTIVITIES
DECEMBER 31,
-----------------------
2005 2004
---------- ----------
(thousands of dollars)
Capitalized costs $1,512,036 $1,377,649
Accumulated depletion 1,027,430 931,033
---------- ----------
Net capitalized costs $ 484,606 446,616
========== ==========
At December 31, 2005 and 2004, unevaluated costs of $26,623,000 and $34,731,000,
respectively, were excluded from the depletion base. These costs are expected to
be evaluated within the next three years. These costs consist primarily of
acreage acquisition costs and related geological and geophysical costs.
-67-
RESULTS OF OPERATIONS FROM OIL AND NATURAL GAS PRODUCING ACTIVITIES
YEAR ENDED DECEMBER 31,
------------------------------
2005 2004 2003
-------- -------- --------
(thousands of dollars)
Operating Revenues:
Oil $ 34,647 $ 36,060 $ 35,032
Natural Gas 160,608 166,387 102,092
-------- -------- --------
$195,255 202,447 137,124
-------- -------- --------
Less:
Oil and natural gas operating costs 15,860 14,035 11,260
Severance and ad valorem taxes 8,811 9,394 7,608
Depletion 96,396 101,944 74,456
Accretion expense 1,120 601 667
Hurricane damage repairs 3,066 -- --
Income tax 26,950 19,342 4,249
-------- -------- --------
152,203 145,316 98,240
-------- -------- --------
Results of operations from oil and
natural gas producing activities $ 43,052 $ 57,131 $ 38,884
======== ======== ========
Depletion expense per Mcfe $ 3.74 $ 2.88 $ 2.61
======== ======== ========
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ESTIMATED QUANTITIES OF PROVED RESERVES
The following table sets forth the net proved reserves of the Company as of
December 31, 2005, 2004 and 2003, and the changes therein during the years then
ended. The reserve information was reviewed by T. J. Smith & Company, Inc.,
independent reservoir engineers, for 2005, 2004 and 2003. All of the Company's
oil and natural gas producing activities are located in the United States.
Oil Gas
(MBbls) (MMcf)
------ -------
TOTAL PROVED RESERVES:
BALANCE AT DECEMBER 31, 2002 9,925 107,626
Production during 2003 (1,403) (20,142)
Discoveries and extensions 31 18,474
Sale of reserves in-place (571) (1,238)
Revisions of previous quantity estimates and other (90) (6,251)
------ -------
BALANCE AT DECEMBER 31, 2003 7,892 98,469
Production during 2004 (1,270) (27,839)
Discoveries and extensions 212 21,783
Revisions of previous quantity estimates and other (470) 8,586
------ -------
BALANCE AT DECEMBER 31, 2004 6,364 100,999
Production during 2005 (882) (20,490)
Discoveries and extensions 366 15,283
Revisions of previous quantity estimates and other (671) (15,875)
------ -------
BALANCE AT DECEMBER 31, 2005 5,177 79,917
====== =======
PROVED DEVELOPED RESERVES:
Balance at December 31, 2002 6,841 86,248
Balance at December 31, 2003 5,016 82,279
Balance at December 31, 2004 4,716 85,507
Balance at December 31, 2005 3,492 62,524
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The information that follows has been developed pursuant to SFAS No. 69 and
utilizes reserve and production data reviewed by our independent petroleum
consultants. Reserve estimates are inherently imprecise and estimates of new
discoveries are less precise than those of producing oil and natural gas
properties. Accordingly, these estimates are expected to change as future
information becomes available.
The estimated discounted future net cash flows from estimated proved reserves
are based on prices and costs as of the date of the estimate unless such prices
or costs are contractually determined at such date. Actual future prices and
costs may be materially higher or lower. Actual future net revenues also will be
affected by factors such as actual production, supply and demand for oil and
natural gas, curtailments or increases in consumption by natural gas purchasers,
changes in governmental regulations or taxation and the impact of inflation on
costs. Future income tax expense has been reduced for the effect of available
net operating loss carryforwards.
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AT DECEMBER 31,
-----------------------------------
2005 2004 2003
----------- --------- ---------
(thousands of dollars)
Future cash flows $1,122,282 $ 897,839 $ 842,945
Future production costs (163,804) (139,112) (118,775)
Future development costs (55,212) (39,352) (30,044)
---------- --------- ---------
Future net cash flows before income taxes 903,266 719,375 694,126
Future taxes on income (201,582) (135,472) (116,570)
---------- --------- ---------
Future net cash flows 701,684 583,903 577,556
Discount to present value at 10 percent per annum (144,481) (113,546) (121,673)
---------- --------- ---------
Standardized measure of discounted future net cash flows $ 557,203 $ 470,357 $ 455,883
========== ========= =========
The average expected realized price for natural gas in the above computations
was $10.40, $6.40 and $6.07 per Mcf at December 31, 2005, 2004, and 2003,
respectively. The average expected realized price used for crude oil in the
above computations was $59.37, $42.33 and $32.05 per Bbl at December 31, 2005,
2004, and 2003, respectively. No consideration has been given to the Company's
hedged transactions.
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The following table sets forth the changes in standardized measure of discounted
future net cash flows for the years ended December 31, 2005, 2004 and 2003
(thousands of dollars):
YEAR ENDED DECEMBER 31,
---------------------------------
2005 2004 2003
--------- --------- ---------
Balance at Beginning of Period $ 470,357 $ 455,883 $ 429,835
Sales of oil and gas, net of production costs (170,584) (179,018) (118,256)
Changes in sales & transfer prices, net of production costs 293,294 32,203 82,200
Revisions of previous quantity estimates (130,813) 22,468 (24,563)
Sales of reserves-in-place -- -- (5,026)
Current year discoveries, extensions, and improved recovery 107,393 117,178 67,676
Changes in estimated future development costs (16,764) (11,331) (7,824)
Development costs incurred during the period 10,654 9,851 20,511
Accretion of discount 47,036 45,588 42,983
Net change in income taxes (49,453) (23,278) (21,186)
Change in production rates (timing) and other (3,917) 813 (10,467)
--------- --------- ---------
Net change 86,846 14,474 26,048
--------- --------- ---------
Balance at End of Period $ 557,203 $ 470,357 $ 455,883
========= ========= =========
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
ITEM 9A. CONTROLS AND PROCEDURES
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-14(c) under the
Securities Exchange Act of 1934) as of the end of the fourth quarter of 2005.
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 fourth quarter of 2005 that could
significantly affect these controls.
MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining a system of adequate
internal control over the Company's financial reporting, which is designed to
provide reasonable assurance regarding the preparation of reliable published
consolidated financial statements. All internal control systems, no matter how
well designed, have inherent limitations. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to
financial statement preparation and presentation.
The Company's management assessed the effectiveness of the Company's system of
internal control over financial reporting as of December 31, 2005. In making
this assessment, the Company's management used the criteria for effective
internal control over financial reporting described in "Internal Control -
Integrated Framework" that the Committee of Sponsoring Organizations of the
Treadway Commission issued.
Based on its assessment using those criteria, management believes that, as of
December 31, 2005, the Company's system of internal control over financial
reporting was effective.
The Company's independent registered public accounting firm has audited our
assessment of the Company's internal control over financial reporting, which
report follows.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
To the Stockholders and Board of Directors
The Meridian Resource Corporation
We have audited management's assessment, included in Management's Annual Report
on Internal Control Over Financial Reporting, that The Meridian Resource
Corporation and subsidiaries (the "Company") maintained effective internal
control over financial reporting as of December 31, 2005, based on criteria
established in Internal Control - Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The
Company's management is responsible for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express an opinion on
management's assessment and an opinion on the effectiveness of the Company's
internal control over financial reporting based on our audit.
-71-
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
In our opinion, management's assessment that the Company maintained effective
internal control over financial reporting as of December 31, 2005, is fairly
stated, in all material respects, based on the COSO criteria. Also, in our
opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2005, based on the COSO
criteria.
We also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated balance sheets of
the Company as of December 31, 2005 and 2004, and the related consolidated
statements of operations, stockholders' equity, cash flows and comprehensive
income for each of the three years in the period ended December 31, 2005, and
our report dated March 10, 2006, expressed an unqualified opinion thereon.
BDO Seidman, LLP
Houston, Texas
March 10, 2006
PART III
The information required in Items 10, 11, 12, 13 and 14 is incorporated by
reference to the Company's definitive Proxy Statement to be filed with the SEC
on or before May 1, 2006.
-72-
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Documents filed as part of this report:
1. Financial Statements included in Item 8:
(i) Independent Registered Public Accounting Firms' Reports
(ii) Consolidated Balance Sheets as of December 31, 2005 and 2004
(iii) Consolidated Statements of Operations for each of the three
years in the period ended December 31, 2005
(iv) Consolidated Statements of Changes in Stockholders' Equity for
each of the three years in the period ended December 31, 2005
(v) Consolidated Statements of Cash Flows for each of the three years
in the period ended December 31, 2005
(vi) Notes to Consolidated Financial Statements
(vii) Consolidated Supplemental Oil and Gas Information (Unaudited)
2. Financial Statement Schedules:
(i) All schedules are omitted as they are not applicable, not
required or the required information is included in the
consolidated financial statements or notes thereto.
3. Exhibits:
3.1 Third Amended and Restated Articles of Incorporation of the
Company (incorporated by reference to the Company's Quarterly
Report on Form 10-Q for the three months ended September 30,
1998).
3.2 Amended and Restated Bylaws of the Company (incorporated by
reference to the Company's Quarterly Report on Form 10-Q for the
three months ended September 30, 1998).
3.3 Certificate of Designation for Series C Redeemable Convertible
Preferred Stock dated March 28, 2002 (incorporated by reference
to Exhibit 3.1 of the Company's Quarterly Report on Form 10-Q for
the three months ended March 31, 2002).
4.1 Specimen Common Stock Certificate (incorporated by reference to
Exhibit 4.1 of the Company's Registration Statement on Form S-1,
as amended (Reg. No. 33-65504)).
*4.2 Common Stock Purchase Warrant of the Company dated October 16,
1990, issued to Joseph A. Reeves, Jr. (incorporated by reference
to Exhibit 10.8 of the Company's Annual Report on Form 10-K for
the year ended December 31, 1991, as amended by the Company's
Form 8 filed March 4, 1993).
*4.3 Common Stock Purchase Warrant of the Company dated October 16,
1990, issued to Michael J. Mayell (incorporated by reference to
Exhibit 10.9 of the Company's Annual Report on Form 10-K for the
year ended December 31, 1991, as amended by the Company's Form 8
filed March 4, 1993).
*4.4 Registration Rights Agreement dated October 16, 1990, among the
Company, Joseph A.
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Reeves, Jr. and Michael J. Mayell (incorporated by reference to
Exhibit 10.7 of the Company's Registration Statement on Form S-4,
as amended (Reg. No. 33-37488)).
*4.5 Warrant Agreement dated June 7, 1994, between the Company and
Joseph A. Reeves, Jr. (incorporated by reference to Exhibit 4.1
of the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1994).
*4.6 Warrant Agreement dated June 7, 1994, between the Company and
Michael J. Mayell (incorporated by reference to Exhibit 4.1 of
the Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 1994).
4.7 Amended and Restated Credit Agreement, dated December 23, 2004,
among the Company, Fortis Capital Corp., as Administrative Agent,
Sole Lead Arranger and Bookrunner, Comerica Bank, as Syndication
Agent, Union Bank of California, N.A., as Documentation Agent,
and the several lenders from time to time parties thereto
(incorporated by reference to Exhibit 10.1 to the Company's
Current Report on Form 8-K dated December 23, 2004).
4.8 The Meridian Resource Corporation Directors' Stock Option Plan
(incorporated by reference to Exhibit 10.5 of the Company's
Annual Report on Form 10-K for the year ended December 31, 1991,
as amended by the Company's Form 8 filed March 4, 1993).
4.9 Amendment No. 1, dated as of January 29, 2001, to Rights
Agreement, dated as of May 5, 1999, by and between the Company
and American Stock Transfer & Trust Co., as rights agent
(incorporated by reference from the Company's Current Report on
Form 8-K dated January 29, 2001).
10.1 See exhibits 4.2 through 4.9 for additional material contracts.
*10.2 The Meridian Resource Corporation 1990 Stock Option Plan
(incorporated by reference to Exhibit 10.6 of the Company's
Annual Report on Form 10-K for the year ended December 31, 1991,
as amended by the Company's Form 8 filed March 4, 1993).
*10.3 Employment Agreement dated August 18, 1993, between the Company
and Joseph A. Reeves, Jr. (incorporated by reference from the
Company's Annual Report on Form 10-K for the year ended December
31, 1995).
*10.4 Employment Agreement dated August 18, 1993, between the Company
and Michael J. Mayell (incorporated by reference from the
Company's Annual Report on Form 10-K for the year ended December
31, 1995).
*10.5 Form of Indemnification Agreement between the Company and its
executive officers and directors (incorporated by reference to
Exhibit 10.6 of the Company's Annual Report on Form 10-K for the
year ended December 31, 1994).
*10.6 Deferred Compensation agreement dated July 31, 1996, between the
Company and Joseph A. Reeves, Jr. (incorporated by reference to
Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q for
the quarter ended September 30, 1996).
*10.7 Deferred Compensation agreement dated July 31, 1996, between the
Company and Michael J. Mayell (incorporated by reference to
Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q for
the quarter ended September 30, 1996).
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*10.8 Texas Meridian Resources Corporation 1995 Long-Term Incentive
Plan (incorporated by reference to the Company's Annual Report on
Form 10-K for the year-ended December 31, 1996).
*10.9 Texas Meridian Resources Corporation 1997 Long-Term Incentive
Plan (incorporated by reference from the Company's Quarterly
Report on Form 10-Q for the three months ended June 30, 1997).
*10.14 Employment Agreement with Lloyd V. DeLano effective November 5,
1997 (incorporated by reference from the Company's Quarterly
Report on Form 10-Q for the three months ended September 30,
1998).
*10.15 The Meridian Resource Corporation TMR Employee Trust Well Bonus
Plan (incorporated by reference from the Company's Annual Report
on Form 10-K for the year ended December 31, 1998).
*10.16 The Meridian Resource Corporation Management Well Bonus Plan
(incorporated by reference from the Company's Annual Report on
Form 10-K for the year ended December 31, 1998).
*10.17 The Meridian Resource Corporation Geoscientist Well Bonus Plan
(incorporated by reference from the Company's Annual Report on
Form 10-K for the year ended December 31, 1998).
*10.18 Modification Agreement effective January 2, 1999, by and among
the Company and affiliates of Joseph A. Reeves, Jr. (incorporated
by reference from the Company's Annual Report on Form 10-K for
the year ended December 31, 1998).
*10.19 Modification Agreement effective January 2, 1999, by and among
the Company and affiliates of Michael J. Mayell (incorporated by
reference from the Company's Annual Report on Form 10-K for the
year ended December 31, 1998).
10.20 Amended and Restated Credit Agreement, dated December 23, 2004,
among The Meridian Resource Corporation, Fortis Capital Corp., as
administrative agent, sole lead arranger and bookrunner, Comerica
Bank, as syndication agent, and Union Bank of California, N.A.,
as documentation agent, and the several lenders from time to time
parties thereto (incorporated by reference from the Company's
Current Report on Form 8-K dated December 23, 2004).
21.1 Subsidiaries of the Company (incorporated by reference to Exhibit
21.1 of the Company's Annual Report on Form 10-K for the year
ended December 31, 2000).
**23.1 Consent of BDO Seidman, LLP.
**23.2 Consent of T. J. Smith & Company, Inc.
**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.
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**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.
* Management contract or compensation plan.
** Filed herewith.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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
BY: /s/ JOSEPH A. REEVES, JR.
------------------------------------
Chief Executive Officer
(Principal Executive Officer)
Director and Chairman of the Board
Date: March 15, 2006
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
Name Title Date
---- ----- ----
BY: /s/ JOSEPH A. REEVES, JR. Chief Executive Officer March 15, 2006
--------------------------------- (Principal Executive Officer)
Joseph A. Reeves, Jr. Director and Chairman
of the Board
BY: /s/ MICHAEL J. MAYELL President and Director March 15, 2006
---------------------------------
Michael J. Mayell
BY: /s/ LLOYD V. DELANO Chief Accounting Officer March 15, 2006
---------------------------------
Lloyd V. DeLano
BY: /s/ E. L. HENRY Director March 15, 2006
---------------------------------
E. L. Henry
BY: /s/ JOE E. KARES Director March 15, 2006
---------------------------------
Joe E. Kares
BY: /s/ GARY A. MESSERSMITH Director March 15, 2006
---------------------------------
Gary A. Messersmith
BY: /s/ DAVID W. TAUBER Director March 15, 2006
---------------------------------
David W. Tauber
BY: /s/ JOHN B. SIMMONS Director March 15, 2006
---------------------------------
John B. Simmons
BY: /s/ FENNER R. WELLER, JR. Director March 15, 2006
---------------------------------
Fenner R. Weller, Jr.
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Index To Exhibit
23.1 Consent of BDO Seidman, LLP.
23.2 Consent of T. J. Smith & Company, Inc.
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.
-78-