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, 2006
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
Commission file number: 1-10671
THE MERIDIAN RESOURCE CORPORATION
(Exact name of registrant as specified in its charter)
TEXAS 76-0319553
(State 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 on which registered)
--------------------- -------------------------------------------
Common Stock, $0.01 par value New York Stock Exchange
Rights to Purchase Preferred Shares 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
--- ---
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. [ ]
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, 2006 $301,423,766
Number of shares of common stock outstanding at March 1, 2007: 89,259,250
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 April 30, 2007.
THE MERIDIAN RESOURCE CORPORATION
INDEX TO FORM 10-K
Page
----
PART I
Item 1. Business 3
Item 1A. Risk Factors 13
Item 1B. Unresolved Staff Comments 18
Item 2. Properties 18
Item 3. Legal Proceedings 19
Item 4. Submission of Matters to a Vote of Security Holders 19
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities 20
Item 6. Selected Financial Data 21
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations 22
Item 7A. Quantitative and Qualitative Disclosures about Market Risk 36
Item 8. Financial Statements and Supplementary Data 41
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure 74
Item 9A. Controls and Procedures 74
Item 9B. Other Information 75
PART III
Item 10. Directors, Executive Officers and Corporate Governance 76
Item 11. Executive Compensation 76
Item 12. Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters 76
Item 13. Certain Relationships and Related Transactions, and Director
Independence 76
Item 14. Principal Accountant Fees and Services 76
PART IV
Item 15. Exhibits and Financial Statement Schedules 76
Signatures 80
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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 natural gas regions in south
Louisiana, the Texas Gulf Coast and offshore in the Gulf of Mexico. During 2006,
the Company began to diversify its oil and natural gas exploration and
development portfolio to include longer-lived reserve properties with the
addition of its east and west Texas, north-central Oklahoma and Kentucky
exploration and development opportunities. Successful wells in these areas
generally exhibit lower initial production rates than the Company's traditional
styled exploration and development, yet increase the overall reserve life of the
Company. As of December 31, 2006, we had proved reserves of 95 Bcfe with a
present value of future net cash flows before income taxes of approximately $337
million ($328 million after tax). Seventy percent (70%) of our proved reserves
were natural gas and approximately seventy-two percent (72%) were classified as
proved developed. We own interests in 24 fields and 121 wells, and we operate
approximately 82% 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 to 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 329,000 gross acres in Louisiana, Texas, Oklahoma, Kentucky and
the Gulf of Mexico, including approximately 100,000 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.
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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 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 natural 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 NATURAL 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, 2006. The
reserve volumes were reviewed by T. J. Smith & Company, Inc., independent
reservoir engineers.
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GULF OF
LOUISIANA TEXAS MEXICO TOTAL
--------- ----- ------- --------
PRODUCTION FOR THE YEAR ENDED DECEMBER 31, 2006
Oil (MBbls)......................................................... 786 27 46 859
Natural Gas (MMcf).................................................. 17,035 615 520 18,170
RESERVES AS OF DECEMBER 31, 2006
Oil (MBbls)......................................................... 3,681 109 946 4,736
Natural Gas (MMcf).................................................. 56,009 2,813 7,993 66,815
ESTIMATED FUTURE NET CASH FLOWS ($000)(1).............................. $442,705
PRESENT VALUE OF FUTURE NET CASH FLOWS BEFORE INCOME TAXES ($000)(1)... $336,901
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS ($000)(1)..... $327,899
(1) The Standardized Measure of Discounted Future Net Cash Flows represents the
Present Value of Future Net Cash Flows after income taxes of $9.0 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, 2006, we used the
expected realized prices at December 31, 2006, which averaged $63.32 per
Bbl of oil and $5.69 per Mcf of natural gas over the estimated life of the
properties and do not reflect the impact of hedges.
PRODUCTIVE WELLS
At December 31, 2006, 2005 and 2004, we held interests in the following
productive wells. As of December 31, 2006, we own 24 gross (4.3 net) wells in
the Gulf of Mexico which are outside operated and net to 2.1 oil wells and 2.2
natural gas wells. In addition, of the total well count for 2006, 7 wells (3.2
net) are multiple completions.
2006 2005 2004
----------- ----------- -----------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Oil Wells............. 44 28 35 24 35 22
Natural Gas Wells..... 77 43 69 39 68 34
--- --- --- --- --- ---
Total.............. 121 71 104 63 103 56
=== === === === === ===
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,
2006. Information set forth in the following table is based on reserve reports
prepared in accordance with the rules and regulations of the SEC. The reserves
and associated cash flows were reviewed by T. J. Smith & Company, Inc.,
independent reservoir engineers.
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PROVED RESERVES AT DECEMBER 31, 2006
--------------------------------------------------
DEVELOPED DEVELOPED
PRODUCING NON-PRODUCING UNDEVELOPED TOTAL
--------- ------------- ----------- --------
(DOLLARS IN THOUSANDS)
Net Proved Reserves:
Oil (MBbls) ...................................................... 1,710 1,441 1,585 4,736
Natural Gas (MMcf) ............................................... 30,095 19,158 17,562 66,815
Natural Gas Equivalent (MMcfe) ................................... 40,354 27,806 27,069 95,229
Estimated Future Net Cash Flows(1) ............................... $442,705
Present Value of Future Net Cash Flows (before income taxes)(1) .. $336,901
Standardized Measure of Discounted Future Net Cash Flows(1) ...... $327,899
----------
(1) The Standardized Measure of Discounted Future Net Cash Flows represents the
Present Value of Future Net Cash Flows after income taxes of $9.0 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, 2006, we used the
expected realized prices at December 31, 2006, which averaged $63.32 per
Bbl of oil and $5.69 per Mcf of natural gas over the estimated life of the
properties and do not reflect the impact of hedges.
You can read additional reserve information in our Consolidated Financial
Statements and the Supplemental Oil and Natural Gas Disclosures (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 2006, 2005
and 2004.
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GROSS WELLS NET WELLS
------------------------ -------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
---------- --- ----- ---------- ---- -----
EXPLORATORY WELLS
Year ended December 31, 2006... 7 7 14 4.1 5.4 9.5
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
DEVELOPMENT WELLS
Year ended December 31, 2006... 1 -- 1 0.7 -- 0.7
Year ended December 31, 2005... 1 -- 1 0.3 -- 0.3
Year ended December 31, 2004... 4 -- 4 3.2 -- 3.2
Meridian had 8 gross (4.9 net) wells in progress at December 31, 2006.
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 (net of
commodity hedge gains/losses), from all properties in which Meridian held an
interest during 2006, 2005 and 2004.
YEAR ENDED DECEMBER 31,
---------------------------
2006 2005 2004
------- ------- -------
PRODUCTION:
Oil (MBbls) ......................... 859 882 1,270
Natural gas (MMcf) .................. 18,170 20,490 27,839
Natural gas equivalent (MMcfe) ...... 23,323 25,781 35,457
AVERAGE PRICES:
Oil ($/Bbl) ......................... $ 55.73 $ 39.29 $ 28.40
Natural gas ($/Mcf) ................. $ 7.77 $ 7.84 $ 5.98
Natural gas equivalent ($/Mcfe) ..... $ 8.11 $ 7.57 $ 5.71
PRODUCTION EXPENSES:
Lease operating expenses ($/Mcfe) ... $ 0.97 $ 0.61 $ 0.40
Severance and ad valorem
taxes ($/Mcfe) ................... $ 0.48 $ 0.34 $ 0.26
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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, 2006.
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, 2006
-----------------------------------
DEVELOPED UNDEVELOPED
--------------- -----------------
REGION GROSS NET GROSS NET
------ ------ ------ ------- -------
LOUISIANA ....... 34,275 16,020 15,877 10,885
OKLAHOMA ........ 1,648 698 19,319 18,850
KENTUCKY ........ -- -- 23,703 21,956
TEXAS ........... 6,458 4,423 156,196 83,738
GULF OF MEXICO .. 45,279 8,868 19,908 12,824
------ ------ ------- -------
TOTAL ........ 87,660 30,009 235,003 148,253
====== ====== ======= =======
In addition to the above acreage, we currently have options or farm-ins to
acquire leases on approximately 6,638 gross (5,969 net) acres of undeveloped
land located in Louisiana. 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 9,400 acres in 2007, 25,800 acres in 2008, and 43,900
acres in 2009.
GEOLOGIC/LAND AND OPERATIONS GEOPHYSICAL EXPERTISE
Meridian employs approximately 95 full-time non-union employees and 17 contract
employees. This staff includes geologists, geophysicists, land and engineering
staff with over 510 combined years of experience in generating and developing
onshore and offshore prospects in the regions in which we operate. 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 2006, 2005 and 2004.
YEAR ENDED
DECEMBER 31,
------------------
CUSTOMER 2006 2005 2004
-------- ---- ---- ----
Superior Natural Gas ............... 35% 46% 45%
Crosstex/Louisiana Intrastate Gas .. 21% 19% 22%
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 $76.98 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, 2006, was $8.11 per Mcfe
compared to $7.57 per Mcfe (each net of commodity hedge gains/losses) during the
year ended December 31, 2005. 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
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production by a well 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 natural
gas. Individual states also have statutes or regulations addressing conservation
matters, including provisions for the unitization or pooling of oil and natural
gas properties, the establishment of maximum rates of production from oil and
natural 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 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 rules or increased competition within
the natural gas transportation industry will have on us and our natural 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 natural 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 natural 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 natural 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
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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.
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 natural 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 natural 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
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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 and
natural 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, 2006, we had long-term indebtedness of approximately $75.0
million compared to approximately $320.8 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, 2006, we have outstanding indebtedness of $75.0 million under
our revolving credit facility, which is $45 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 natural 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 natural 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
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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 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 natural 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.
-14-
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.
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,
natural 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 natural disasters, 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
-15-
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 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. 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.
-16-
OUR OPERATIONS ALSO ENTAIL SIGNIFICANT OPERATING RISKS.
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.
-17-
OUR INABILITY TO ACQUIRE OR INTEGRATE ACQUIRED COMPANIES OR TO DEVELOP NEW
EXPLORATION PROSPECTS MAY INHIBIT OUR GROWTH.
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.
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ITEM 3. LEGAL PROCEEDINGS
H. L. HAWKINS LITIGATION. In December 2004, the estate of H.L. Hawkins filed a
claim against Meridian for damages "estimated to exceed several million dollars"
for Meridian's alleged gross negligence, willful misconduct and breach of
fiduciary duty under certain agreements concerning certain wells and property in
the S.W. Holmwood and E. Lake Charles Prospects in Calcasieu Parish in
Louisiana, as a result of Meridian's satisfying a prior adverse judgment in
favor of Amoco Production Company. Mr. James Bond has been added as a defendant
by Hawkins claiming Mr. Bond, when he was General Manager of Hawkins, did not
have the right to consent, could not consent or breached his fiduciary duty to
Hawkins if he did consent to all actions taken by Meridian. The Company has not
provided any amount for this matter in its financial statements at December 31,
2006.
TITLE/LEASE DISPUTES. Title and lease disputes may arise in the normal course of
the Company's operations. These disputes are usually small but could result in
an increase or decrease of our reserves once a final resolution to the title
dispute is made.
ENVIRONMENTAL LITIGATION. Various landowners have sued Meridian (along with
numerous other oil companies) in lawsuits concerning several fields in which the
Company has had operations. The lawsuits seek injunctive relief and other
relief, including unspecified amounts in both actual and punitive damages for
alleged breaches of mineral leases and alleged failure to restore the
plaintiffs' lands from alleged contamination and otherwise from the Company's
oil and natural gas operations. The Company, in certain instances, has
indemnified third parties from the claims made in these lawsuits. In three of
the lawsuits, Shell Oil Company and SWPI LP have demanded indemnity and defense
from Meridian; Meridian has denied such demands. The Company has not provided
any amount for this matter in its financial statements at December 31, 2006.
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 2006.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND
ISSUER PURCHASES OF EQUITY SECURITIES
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
----- -----
2006:
First quarter........................ $5.09 $3.75
Second quarter....................... 4.22 3.04
Third quarter........................ 3.55 3.04
Fourth quarter ...................... 3.70 2.91
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
The closing sale price of the common stock on March 1, 2007, as reported on the
New York Stock Exchange Composite Tape, was $2.59. As of March 1, 2007, we had
approximately 780 shareholders of record.
Meridian has not paid cash dividends on its common stock and does not intend to
pay cash dividends on its 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, and for amounts we may spend for purchase of shares
of common stock over $5 million per year, without the prior consent of the
lenders. See Item 7. Liquidity and Capital Resources.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table sets forth information as of December 31, 2006, 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 6,692,400 $3.26 1,785,310
Equity compensation plans not approved
by security holders -- -- --
--------- ----- ---------
Total 6,692,400 $3.26 1,785,310
========= ===== =========
(1) Does not include 4,650,000 shares which have been reserved for issuance in
lieu of cash compensation under the Company's deferred compensation plan,
which plan was approved by security holders.
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ITEM 6. SELECTED FINANCIAL DATA
All financial data should be read in conjunction with our Consolidated Financial
Statements and related notes thereto included in Item 8 and elsewhere in this
report.
YEAR ENDED DECEMBER 31,
-------------------------------------------------------
2006 2005 2004 2003 2002
-------- -------- -------- -------- --------
(In thousands, except prices and per share information)
A. SUMMARY OF OPERATING DATA
Production:
Oil (MBbls) 859 882 1,270 1,403 2,213
Natural gas (MMcf) 18,170 20,490 27,839 20,142 15,578
Natural gas equivalent (MMcfe) 23,323 25,781 35,457 28,563 28,856
Average prices:
Oil ($/Bbl) $ 55.73 $ 39.29 $ 28.40 $ 24.97 $ 24.67
Natural gas ($/Mcf) 7.77 7.84 5.98 5.07 3.36
Natural gas equivalent ($/Mcfe) 8.11 7.57 5.71 4.80 3.71
B. SUMMARY OF OPERATIONS
Total revenues $190,957 $195,696 $203,118 $137,479 $107,470
Depletion and depreciation 106,067 97,354 102,915 75,441 60,972
Net earnings (loss)(1) (73,884) 27,849 29,248 7,246 (52,012)
Net earnings (loss) per share:(1)
Basic $ (0.84) $ 0.33 $ 0.41 $ 0.14 $ (1.05)
Diluted (0.84) 0.31 0.37 0.13 (1.05)
Dividends per:
Common share $ -- $ -- $ -- $ -- $ --
Redeemable preferred share -- 2.60 8.50 8.50 5.90
Preferred share -- -- -- -- --
Weighted average common
shares outstanding - basic 87,670 84,527 72,084 53,325 49,763
C. SUMMARY BALANCE SHEET DATA
Total assets $467,895 $555,802 $513,274 $448,400 $456,240
Long-term obligations, inclusive
of current maturities 75,000 75,000 75,129 152,320 203,750
Redeemable preferred stock -- -- 31,589 60,446 69,690
Stockholders' equity 320,797 377,565 316,041 184,335 133,393
(1) Applicable to common stockholders.
-21-
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
natural gas regions in south Louisiana, the Texas Gulf Coast and offshore in the
Gulf of Mexico. During 2006, the Company began to diversify its oil and natural
gas exploration and development portfolio to include longer-lived reserve
properties with the addition of its east and west Texas, north-central Oklahoma
and Kentucky exploration and development opportunities. 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 lifting 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 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.
OPERATIONS OVERVIEW
Our four primary regions where the capital budget will be spent, and where we
are currently active are: (1) the Gulf Coast region of south Louisiana, (2)
south Texas, on and offshore, (3) east Texas, and (4) the mid-
-22-
continent region of north-central Oklahoma. Subsequent to the Company's
operational update during December 2006, the Company has participated in 12
wells (results detailed below) and currently has six wells logged with apparent
pay, awaiting completion, testing and pipeline construction.
South Louisiana. South Louisiana remains a core area for Meridian where the
Company has built a large knowledge and information base that it believes holds
value from the development of future projects that typically enjoy faster
returns of capital and higher potential returns on investment.
For calendar year 2007, the Company has scheduled participation in a minimum of
six to eight exploration wells and three development wells in the south
Louisiana region comprising approximately 25% of its exploration and development
budget. To date, the Company has drilled two wells in the south Louisiana
region, the Turning Basin Odom No. 1 well (92% WI) and the Phoenix Lake E. W.
Brown No. 1 well (92% WI). The E. W. Brown No. 1 well electric logs indicate
approximately 32 gross feet of apparent pay in the targeted Hackberry sands. The
E. W. Brown No. 1 well tested a separate prospect closure adjacent to the Odom
No. 1 well and was drilled as a sidetrack from the Odom No. 1 wellbore, saving
rig mobilization, drilling and equipment costs for the drilling of the second
well. The E. W. Brown No. 1 well has been completed and is being prepared for an
initial production test. Historic production from wells completed in the same
formation in the area and initial interpretations of the electric logs and core
samples from the well indicate the potential for natural gas rich with
condensate. Pending the results of the initial tests, the Company has initiated
permitting for the construction of the pipeline and production facilities for
the well. It is anticipated that the well will be placed into production during
late second or early third quarter of this year. The Company owns approximately
92% working interest in the well and is the operator.
In addition, Meridian will test its nitrogen injection program in the Company's
Weeks Island field located near New Iberia, Louisiana. The field was part of the
original asset package acquired from Shell Oil Company during August 1998 and
has been a prolific producer of oil and natural gas for Meridian since its
purchase. The process is intended to recover attic oil reserves adjacent to the
dome that are updip to perforations in the well bores which would otherwise
require additional wells to recover the same reserves. If successful, the
nitrogen injection will develop the additional reserves at significantly less
cost and less risk than drilling new wells adjacent to the salt dome. This
program is expected to begin during late second quarter or third quarter 2007.
The Company owns approximately 92-96% working interest and is the operator.
Deep Archtop. Upon completing the development potential of all sands in the Deep
Archtop prospect, the Company began its marketing effort in mid-January 2007.
Once completed, it began to prepare the project engineering design for drilling
and estimated costs. The project is designed to test a Jurassic Cotton Valley
four-way closure in the Biloxi Marshlands area of St. Bernard Parish Louisiana.
This 30,000 foot prospect has over 14,400 acres of closure, imaged by 3-D
seismic and offers reserve potential of up to 5 trillion cubic feet of gas. The
company will spend the coming year in pre-drill work, followed by 300-plus days
to drill the well. The projected spud date for the well is early second quarter
2008 and will cost an estimated $60 million to drill. The shallow marshlands
water location provides the potential for significant savings in drilling the
test well and post development infrastructure. Similarly sized offshore projects
typically cost much more and require longer periods of time to construct the
necessary pipelines and production facilities. Meridian owns production
facilities and pipelines in the immediate area. Meridian intends to retain and
pay it share of approximately 20% working interest to the casing point in this
well.
South Texas. As a part of the asset purchase from Oxy/Vintage during 2006, the
Company acquired approximately 3,200 gross acres in the Nueces Bay area
immediately north of Corpus Christi, Texas. Since that time the Company has
participated in three successful outside operated wells, the Countiss-McCracken
GU No.1 well, currently being re-completed and awaiting stimulation; the BP
America well which was placed on production as reported during December 2006;
and the ST 976 No.1 well. The ST 976 No. 1 well was drilled to a depth of
approximately 13,800 feet measured depth ("MD") to test the deep Frio sands. The
results of the electric logs on the ST 976 No. 1 well showed apparent gas pay in
five Frio sand intervals for a total of approximately 60 feet of net pay in the
formation, which will require fracture stimulation. The Company owns
approximately 23% working interest in these three wells.
-23-
Meridian's first operated venture in the area since closing the acquisition was
its Indian Point ST 786 No. 12 well which was drilled to a depth of
approximately 15,150 feet MD (12,600 feet TVD) to test the deep Frio sands. The
results of the electric logs reflected apparent gas pay in six Frio sand
intervals for a total of approximately 140 feet of net pay in the formation,
which will require fracture stimulation. Accordingly, the Company has elected to
move straight to preparing the well for fracture stimulation in the deep
Anderson (Frio) sand package. Should the fracture stimulation prove to be
successful, the Company has one additional well scheduled for 2007 and an
additional three to four prospective locations offset to the well. The Company
owns approximately 49% working interest in this well and is the operator.
For 2007, the Company plans to spend approximately 4% of its exploration and
development budget in this area.
Offshore Louisiana/Texas. As an extension of Meridian's onshore exploration
efforts in the south Louisiana and southeast Texas Gulf Coast region, the
Company will drill three projects in the shallow waters of the Gulf of Mexico.
The initial wells scheduled to be drilled during 2007 comprise approximately 17%
of the Company's exploration and development budget. Depending on the success of
initial wells in each area, the Company has sufficient acreage for development.
The first well is scheduled to be spud during the second quarter and is located
on leases acquired at the lease sale during 2006, specifically the West Cameron
Block 332. The well is designed to be drilled to a depth of approximately 13,800
feet MD to test sands in the Plio-Pleistocene. Meridian owns 20% working
interest before casing point and 38% working interest after casing point and
will be the operator.
The two additional prospects are being readied for drilling during the third and
fourth quarters of 2007.
East Texas Area. The East Texas area has become one of Meridian's major impact
plays added to its portfolio during 2006 and was the first step-out by the
Company in its development of extension plays beyond its south Louisiana focus
area. The Company has scheduled approximately seven wells for this field during
2007 which comprise approximately 37% of its exploration and development budget
for the year. The Company is devoting a significant effort to the development of
this play for its near and long term potential as well as its daily producing
rates and reserves.
The play was originally designed to test 3-D seismic based prospects similar to
the Woodbine production in the AA Wells Field. After drilling the initial four
wells during the first and second quarters of 2006, it appeared that each
contained the same or similar Austin Chalk section that was present in the
nearby producing field 9-12 miles to the east. Further evaluation of the Austin
Chalk was initiated with the drilling of two laterals in the BSM No. 1 well once
rig equipment was available starting in May 2006 and resulted in the successful
test of the Austin Chalk section on the Company's then approximate 7,000-acre
lease position. The well was placed on production during October 2006 at
approximately 28 MMcfe/d. The well is currently producing at a level rate of
approximately 3.8 MMcfe/d. Estimates of reserves are consistent with what the
Company believes are the better wells in the area.
During December 2006, Meridian initiated the drilling of dual laterals on the
second of the first four vertical wells, the Katherine Leary No. 1 well, and has
drilled the first or northern lateral approximately 5,000 feet from the vertical
wellbore, set the slotted liner and is currently drilling the second or southern
lateral. Based on flares from what is believed to be the first lateral, the
Leary No. 1 well appears to have potential gas and oil/condensate production
similar to the BSM No. 1. Once the second lateral is completed, both laterals
will be tested into sales.
As part of the further development of the field, the Company began an aggressive
leasing program in the area to improve its acreage position. Meridian and its
partners currently have under lease or control approximately 30,000 acres and
continue to aggressively pursue leasing additional acreage positions in the
area.
-24-
Current estimates and acreage projections suggest that the development of the
area will initially require approximately 30 to 40 additional wells. Meridian is
the operator of the field and anticipates that it will own working interest
ranging between 35% and 84% in the units in the area, depending on partner
participation and lease interests within each unit.
Rig Purchase and East Texas Development. In an effort to ensure that the
Company's development schedule is maintained, the Company recently signed an
agreement for the construction and purchase of one newly built land based
drilling rig in conjunction with an engineering design and fabrication/rig
contractor, Orion Drilling Company LP. This contractor will ultimately operate,
crew and maintain the rig. Delivery of the rig is currently expected in the
third quarter of 2007 when the rig will be mobilized to the Company's East Texas
Austin Chalk play. Depending on the success of the operations in the play, the
Company has plans for a two-rig, multi-well drilling program to exploit the
Company's acreage under lease for an anticipated three to five year period. The
first additional rig is scheduled to arrive in the area within approximately two
or three weeks. A second additional rig will be added during April or May 2007
after the completion of the Leary No. 1 well and that rig is released.
Oklahoma Hunton/Mississippian Play. The Oklahoma Hunton/Mississippian play is
another in the Company's list of primary focus areas for growth. The Company has
scheduled up to 13 wells in this play during 2007 which is located in Garfield
County, Oklahoma, and has dedicated approximately 14% of its exploration and
development budget for 2007 to this play. To date, the Company has completed the
drilling of its first salt water disposal well and the first two gas wells in
the Hunton section. Currently the Company is drilling its first Mississippian
well in the play, which will be a horizontal well and is currently at
approximately 7,600 feet MD. The Enterprise No. 7-1 and the Constellation 8-1
wells are awaiting completion of drilling operation of the Constellation 8-2
Mississippian well that is currently drilling from the same pad as the first
three wells. The Enterprise 7-1 well reached its total depth of 8,000 feet MD,
and is scheduled to be perforated and tested in the Hunton formation.
Previously, the Constellation 8-1 well also reached total depth and is scheduled
for testing in the near term.
Initially, it is anticipated that the Hunton wells will produce primarily water
with small amounts of natural gas and gradually increase to commercial
quantities of natural gas with less water over a period of months. The Company,
which will operate the field, owns approximately 19,000 acres in the area and
has targeted potential reserves for this play of approximately 30 to 40 Bcfe,
gross unrisked. Meridian will own approximately 80-92% working interest.
Unconventional Resource Plays. In the Delaware Basin, the Company and its joint
venture partner are currently evaluating recently acquired 2D data and older
re-processed 2D data from the area. Targeted formations are the Barnett and
Woodford Shale sections which range between 5,500 and 8,500 feet. Meridian's 50%
joint venture partner will operate substantially all of the drilling and
production for the project. The group owns approximately 85,000 acres in the
area and anticipates that it will drill a minimum of two wells during 2007. This
will represent approximately 3% of the Company's 2007 exploration and
development budget.
In the New Albany Shale Play in the Illinois Basin, the Company continues to
acquire leases and currently owns an approximate 30,000-acre lease position. The
primary target formation is the New Albany Shale at a depth generally between
2,000 and 5,000 feet with an expected average thickness of 300 feet. Drilling
plans for the initial wells in the area are being evaluated. The Company's
working interest in the play is 92% with Meridian as operator.
In the Palo Duro Basin Play, the Company owns approximately 35,000 gross acres
in Floyd and Motley Counties, Texas. The primary target formation is the
Pennsylvanian Shale between 8,000 and 10,000 feet with an estimated average
shale thickness of 1,000 feet. Several operators in the basin are in various
stages of testing optimal drilling and completion techniques for wells in the
area. An operator has recently reported drilling and completing a successful
well that is immediately adjacent a portion of the Company's acreage.
-25-
The Company is currently evaluating the development of the basin and its plans
for the play. Meridian currently owns between 75% and 92% of the working
interest and is the operator.
Capital Expenditure Plans for 2007. Meridian's Board of Directors has approved
the 2007 capital spending budget of approximately $127 million for new prospect
opportunities, ranging in depths from shallow to deep. This amount includes
approximately $12 million for the purchase of one drilling rig (previously
discussed). Based on current projections, these expenditures are within the
Company's expected operating cash flows (including cash on hand) and allow the
Company the flexibility to take on additional prospects, acquisitions or joint
ventures as the opportunities are presented or developed throughout the year.
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, 2006 was $8.11 per Mcfe compared to $7.57 per Mcfe during the
year ended December 31, 2005. 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 7A, 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.
-26-
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2006, COMPARED TO YEAR ENDED DECEMBER 31, 2005
Oil and natural gas revenues, which include oil and natural gas hedging
activities (see Note 12 of notes to consolidated financial statements included
elsewhere herein), during the twelve months ended December 31, 2006, decreased
$6.2 million (3%) as compared to 2005 revenues due to a 10% decrease in
production volumes primarily from natural production declines, partially offset
by a 7% increase in average commodity prices on a natural gas equivalent basis
and new discoveries brought on between the comparable periods. Our average daily
production decreased from 70.6 MMcfe during 2005 to 63.9 MMcfe for 2006. Oil and
natural gas production volume totaled 23,323 MMcfe for 2006, compared to 25,781
MMcfe for 2005. During 2006, the Company's drilling activity was primarily
focused in the East Texas project area, the Biloxi Marshlands project area and
the Terrebonne Parish area of South Louisiana. During 2006, the Company drilled
or participated in the drilling of 15 wells of which 8 wells were completed,
representing a 53% success rate. The following table summarizes Meridian's
operating revenues, production volumes and average sales prices for the years
ended December 31, 2006 and 2005.
Year Ended
December 31,
------------------- Increase
2006 2005 (Decrease)
-------- -------- ----------
Production:
Oil (MBbls) 859 882 (3%)
Natural gas (MMcf) 18,170 20,490 (11%)
Natural gas equivalent (MMcfe) 23,323 25,781 (10%)
Average Sales Price:
Oil (per Bbl) $ 55.73 $ 39.29 42%
Natural gas (per Mcf) 7.77 7.84 (1%)
Natural gas equivalent (per Mcfe) 8.11 7.57 7%
Operating Revenues (000's):
Oil $ 47,859 $ 34,647 38%
Natural gas 141,182 160,608 (12%)
-------- -------- ---
Total $189,041 $195,255 (3%)
======== ======== ===
Operating Expenses.
Oil and natural gas operating expenses on an aggregate basis increased $6.7
million (43%) to $22.6 million in 2006, compared to $15.9 million in 2005. On a
unit basis, lease operating expenses increased $0.35 per Mcfe to $0.97 per Mcfe
for the year 2006 from $0.62 per Mcfe for the year 2005. Oil and natural gas
operating expenses increased primarily due to additional properties acquired and
wells drilled since last year, industry wide increases in service costs and
significantly higher insurance costs resulting from last year's hurricane
season. The Company's insurance rates increased by more than three times the
previous year's annual premiums and represented $3.0 million of the increase for
the comparable periods. The Company anticipates that the higher insurance costs
will continue in effect for the foreseeable future.
Severance and Ad Valorem Taxes.
Severance and ad valorem taxes increased $2.5 million (28%) to $11.3 million in
2006, compared to $8.8 million in 2005, primarily because of an increase in oil
prices and a higher natural gas tax rate, partially offset by a decrease in oil
and natural gas production. Meridian's oil and natural gas production is
primarily from Louisiana and is therefore subject to Louisiana severance tax.
The severance tax rates for Louisiana are 12.5% of gross oil revenues and $0.373
per Mcf (effective July 1, 2006) for natural gas. For the first six
-27-
months of 2006, and the last six months of 2005, the rate was $0.252 per Mcf for
natural gas, an increase from $0.208 per Mcf for the first half of 2005. On an
equivalent unit of production basis, severance and ad valorem taxes increased to
$0.48 per Mcfe for 2006 from $0.34 per Mcfe for 2005.
Depletion and Depreciation.
Depletion and depreciation expense increased $8.7 million (9%) during 2006 to
$106.1 million compared to $97.4 million for 2005. This was primarily the result
of an increase in the depletion rate as compared to the 2005 period, partially
offset by the 10% decrease in production volumes in 2006 from 2005 levels. On a
unit basis, depletion and depreciation expenses increased to $4.55 per Mcfe for
2006, compared to $3.78 per Mcfe for 2005. 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.
As a result of the below-referenced ceiling test write-down, the Company's
future depletion rate per unit is expected to decrease from the 2006 levels.
Impairment of Long-Lived Assets.
A decline in oil and natural gas prices as of September 30, 2006, resulted in
the Company recognizing a non-cash impairment totaling $134.9 million ($87.7
million after tax) of its oil and natural gas properties under the full cost
method of accounting. Additionally, the effect of this write-down is projected
to result in a decrease in the Company's anticipated future depletion rate. See
Note 4 of notes to consolidated financial statements, included elsewhere herein,
for additional information.
General and Administrative Expense.
General and administrative expenses, which are net of costs capitalized in our
oil and natural gas properties (see Note 19 of notes to consolidated financial
statements included elsewhere herein), decreased $1.3 million (7%) to $16.7
million in 2006 compared to $18.0 million for the year 2005, primarily due to a
decrease in professional services, partially offset by an increase in employee
compensation associated with the higher industry-wide demand for experienced
personnel. On an equivalent unit of production basis, general and administrative
expenses increased $0.01 per Mcfe to $0.71 per Mcfe for 2006 compared to $0.70
per Mcfe for 2005.
Accretion Expense.
As a result of the Statement of Financial Accounting Standards No. 143 ("SFAS
No. 143"), "Accounting for Asset Retirement Obligations," the Company records
long-term liabilities representing the discounted present value of the estimated
asset retirement obligations with offsetting increases in capitalized oil and
natural gas properties. This liability will continue to be accreted to its
future value in subsequent reporting periods. The Company has charged
approximately $1.6 million and $1.1 million to earnings as accretion expense
during 2006 and 2005, respectively. The increase in 2006 levels in comparison to
2005 is primarily the result of a property acquisition in 2006, the additional
wells drilled and placed on production during the year, revisions to estimated
abandonment costs in the industry, and the acceleration of abandonment dates due
to year-end 2006 commodity pricing.
Hurricane Damage Repairs.
This expense of $4.3 million in 2006 and $3.1 million in 2005 is related to
damages incurred from hurricanes Katrina and Rita, primarily related to the
Company's insurance deductible and repair costs in excess of insured values. Due
to the extensive damage throughout the area and the limited resources available
for repairs, significant cost increases were experienced by the industry. The
actual repair costs were higher than originally estimated and exceeded our claim
limits and therefore resulted in increased expense. Additionally, a portion of
the 2006 expenses resulted from changes in damage classifications with different
insurance coverage. The final claim settlement negotiations were concluded in
February 2007, and 2006 expenses have been adjusted to reflect the forthcoming
settlement payment.
-28-
Interest Expense.
Interest expense increased $1.3 million (27%) to $6.0 million in 2006 compared
to $4.7 million for 2005. The increase was primarily a result of the increased
interest rates during 2006.
Taxes on Income.
The provision for income tax expense (benefit) for 2006 was ($38.5 million) as
compared to $18.0 million for 2005. Income taxes were provided on book income
after taking into account permanent differences between book income and taxable
income. The benefit for 2006 was primarily the result of the impairment of
long-lived assets recognized during the third quarter of 2006.
-29-
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 12 of notes to consolidated financial statements included
elsewhere herein), 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 $0.26
per Mcfe for 2004.
-30-
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 natural gas properties (see Note 19 of notes to consolidated financial
statements included elsewhere herein), 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.
As a result of the Statement of Financial Accounting Standards No. 143 ("SFAS
No. 143"), "Accounting for Asset Retirement Obligations," the Company records
long-term liabilities representing the discounted present value of the estimated
asset retirement obligations with offsetting increases in capitalized oil and
natural 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.
-31-
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS. Net cash flows provided by operating activities was $137.0 million
for the year ended December 31, 2006, as compared to 133.6 million for the year
ended December 31, 2005, an increase of $3.4 million or 3%. Changes in assets
and liabilities was $4.7 million primarily attributable to the reduction in
accounts receivable which includes the collection in 2006 of hurricane insurance
claim proceeds coupled with receipts of oil and natural gas revenue receivables
including the impact of lower 2006 commodity pricing. This was partially offset
by the reduction in liabilities for amounts due to affiliates, revenues and
royalty payable and asset retirement obligations.
Net cash flows used in investing activities were $130.5 million for the year
ended December 31, 2006, as compared to $132.5 million for the year ended
December 31, 2005. This slight decrease was due to higher expenditures for
property and equipment, offset by the sale of property in 2006.
Net cash flows provided by financing activities were $1.7 million for the year
ended December 31, 2006, as compared to net cash flows used in financing
activities of $2.1 million for 2005 primarily from the elimination of dividends
on 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
current borrowing base under the Credit Facility is $120 million and it was
reaffirmed by the syndication group effective October 31, 2006. As of December
31, 2006, outstanding borrowings under the Credit Facility totaled $75 million.
The Credit Facility is subject to semi-annual borrowing base redeterminations on
April 30 and October 31 of each year. In addition to the scheduled semi-annual
borrowing base redeterminations, the lenders or the Company have the right to
redetermine the borrowing base at any time, provided that no party can request
more than one such redetermination between the regularly scheduled borrowing
base redeterminations. The determination of our borrowing base is subject to a
number of factors, including quantities of proved oil and natural gas reserves,
the banks' price assumptions and other various factors unique to each member
bank. Our lenders can redetermine the borrowing base to a lower level than the
current borrowing base if they determine that our oil and natural gas reserves,
at the time of redetermination, are inadequate to support the borrowing base
then in effect.
Obligations under the Credit Facility are secured by pledges of outstanding
capital stock of the Company's subsidiaries and by a first priority lien on not
less than 75% (95% in the case of an event of default) of its present value of
proved oil and natural gas properties. In addition, the Company is required to
deliver to the lenders and maintain satisfactory title opinions covering not
less than 70% of the present value of proved oil and natural gas properties. The
Credit Facility also contains other restrictive covenants, including, among
other items, maintenance of certain financial ratios, restrictions on cash
dividends on common stock and under certain circumstances preferred stock,
limitations on the redemption of preferred stock, limitations on repurchases of
common stock and an unqualified audit report on the Company's consolidated
financial statements, all of which the Company is in compliance.
Under the Credit Facility, the Company may secure either (i) (a) an alternative
base rate loan that bears interest at a rate per annum equal to the greater of
the administrative agent's prime rate; or (b) federal funds-based rate plus 1/2
of 1%, plus an additional 0.5% to 1.25% depending on the ratio of the aggregate
outstanding loans and letters of credit to the borrowing base or; (ii) a
Eurodollar base rate loan that bears interest, generally, at a rate per annum
equal to the London interbank offered rate ("LIBOR") plus 1.5% to 2.25%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. At December 31, 2006, the three-month LIBOR interest rate
was 5.36%. The Credit Facility also provides for
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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.
CAPITAL EXPENDITURES. Capital expenditures in 2006 consisted of $148.5 million
(of which $7.0 million was funded by the issuance of common stock) for property
and equipment additions related to exploration and development of various
prospects, including leases, seismic data acquisitions, production facilities,
and related drilling and workover activities and property acquisitions. 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 2007 capital expenditures plan is currently forecast at approximately $127
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 2007 plan utilizing cash flow from operations and cash on
hand. When appropriate, excess cash flow from operations beyond that needed for
the 2007 capital expenditures plan may be used to de-lever the Company by
development of exploration discoveries, direct payment of debt, or the
repurchase of common stock.
CASH OBLIGATIONS. The following summarizes the Company's contractual obligations
at December 31, 2006 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 $ 2,754 $75,000 $ -- $77,754
Interest 5,340 5,221 -- 10,561
Non-cancelable operating leases 1,945 3,929 3,577 9,451
------- ------- ------ -------
Total contractual cash obligations $10,039 $84,150 $3,577 $97,766
======= ======= ====== =======
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.
OFF-BALANCE SHEET ARRANGEMENTS. None.
SHARE REPURCHASE PROGRAM. The Company has authorized a new share repurchase
program. Under the program, the Company may repurchase in the open market or
through privately negotiated transactions up to $5 million worth of Common
Shares per year over the next three years. The timing, volume, and nature of
share repurchases will be at the discretion of management, depending on market
conditions, applicable securities laws, and other factors.
During February 2007, the lenders in the Credit Facility unanimously approved an
amendment increasing the available limit for the Company's repurchase of its
common stock from $1.0 million to $5.0 million annually. The amendment contained
restrictive covenants on the Company's ability to repurchase its common stock
including (i) the Company cannot utilize funds under the Credit Facility to fund
any stock repurchases and (ii) immediately prior to any repurchase, availability
under the Credit Facility must be equal to at least 20% of the then effective
borrowing base.
The share repurchase program is scheduled to begin as soon as reasonably
practical. The program does not require the Company to repurchase any specific
number of shares and may be modified, suspended or terminated at any time
without prior notice. The Company expects repurchases to be funded by available
cash.
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
-33-
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 2 of the notes to the consolidated financial
statements included elsewhere herein.
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 natural gas revenues,
bad debts, oil and natural 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 2006, 2005, and 2004,
such capitalized costs totaled $15.4 million, $13.8 million, and $11.9 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 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 11%; however, a 10% increase in our reserves would
have decreased our provision for the year by approximately 9%.
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 natural 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, 2006, we had $54.4 million allocated to unevaluated oil and
natural gas properties. A 10% decrease in the unevaluated oil and natural gas
properties balance would have increased our provision for
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depletion and amortization of oil and natural gas properties by approximately
1.6% and a 10% increase would have decreased our provision by approximately 1.3%
for the year ended December 31, 2006.
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.
Accordingly, based on September 30, 2006, pricing of $4.17 per Mcf of natural
gas and $63.37 per barrel of oil, the Company recognized in the third quarter of
2006 a non-cash impairment of $134.9 million ($87.7 million after tax) of the
Company's oil and natural gas properties under the full cost method of
accounting.
Due to the imprecision in estimating oil and natural gas revenues as well as the
potential volatility in oil and natural gas prices and their effect on the
carrying value of our proved oil and natural gas reserves, there can be no
assurance that write-downs in the future will not be required as a result of
factors that may negatively affect the present value of proved oil and natural
gas reserves and the carrying value of oil and natural gas properties, including
volatile oil and natural gas prices, downward revisions in estimated proved oil
and natural gas reserve quantities and unsuccessful drilling activities.
At December 31, 2006, we had a cushion (i.e. the excess of the ceiling over our
capitalized costs) of $25.9 million (before tax). A 10% increase in prices would
have increased our cushion by approximately 180%. A 10% decrease in prices would
have decreased our cushion by approximately 183% to a level requiring a
write-down. 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 ("SFAS") 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.
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 SFAS 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 $128,000 during the year ended
December 31, 2006, a loss of $251,000 during the year ended December 31, 2005,
and a gain of $126,000 during the year ended December 31, 2004.
-35-
As of December 31, 2006, the estimated fair value of the Company's oil and
natural gas contracts was an unrealized gain of $7.2 million ($4.7 million net
of tax) which is recognized in other comprehensive income. Based upon December
31, 2006, oil and natural gas commodity prices, approximately $6.9 million of
the gain deferred in other comprehensive income could potentially increase gross
revenues in 2007. The contract agreements expire at various dates through July
31, 2008.
Net settlements under these contract agreements increased (decreased) oil and
natural gas revenues by $3,821,000, ($20,578,000) and ($18,624,000) for the
years ended December 31, 2006, 2005, and 2004, respectively.
See Item 7A, 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, 2006 and 2005, and were
determined based upon variable interest rates currently available to us for
borrowings with similar terms.
NEW ACCOUNTING PRONOUNCEMENTS. In July 2006, the Financial Accounting Standards
Board ("FASB") issued FASB Interpretation No. 48 ("FIN 48"), "Accounting for
Uncertainty in Income Taxes and Interpretation of SFAS No. 109." FIN 48
clarifies the accounting for uncertainty in income taxes recognized in an
enterprise's financial statements in accordance with SFAS No. 109, Accounting
for Income Taxes. FIN 48 prescribes a recognition threshold and measurement
attribute for the financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return. FIN 48 also provides
guidance on recognition, classification, interest and penalties, accounting in
interim periods, disclosure, and transition. FIN 48 is effective for fiscal
years beginning after December 15, 2006. The Company is in the process of
evaluating FIN 48, but does not believe that its implementation will have a
material effect on the Company's financial position or results of operation in
any period.
In September 2006, the SEC issued Staff Accounting Bulletin No. 108 ("SAB 108").
Due to diversity in practice among registrants, SAB 108 expresses SEC staff
views regarding the process by which misstatements in financial statements are
evaluated for purposes of determining whether financial statement restatement is
necessary. SAB 108 is effective for fiscal years ending after November 15, 2006,
and early application is encouraged. The adoption of SAB 108 did not have a
material impact on our financial position or results of operations.
In September 2006, the FASB issued SFAS No. 157 ("SFAS 157"), "Fair Value
Measurements." SFAS 157 defines fair value, establishes a framework for
measuring fair value in generally accepted accounting principles and expands
disclosure about fair value measurements. SFAS 157 is effective for financial
statements issued for fiscal years beginning after November 15, 2007. The
Company is evaluating the impact, if any, that SFAS 157 will have on our
financial statements.
ITEM 7A 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
-36-
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 natural gas
production. While the use of hedging arrangements limits the downside risk of
adverse price movements, it may also limit future gains from favorable
movements. Under these agreements, payments are received or made based on the
differential between a fixed and a variable product price. These agreements are
settled in cash at or prior to expiration or exchanged for physical delivery
contracts. Meridian does not obtain collateral to support the agreements, but
monitors the financial viability of counter-parties and believes its credit risk
is minimal on these transactions. In the event of nonperformance, 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 40% of our proved developed natural gas production and 26% 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 NYMEX 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, 2006, is provided below (see the Company's website
at www.tmrc.com for a quarterly breakdown of the Company's hedge position for
2007 and beyond):
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Estimated
Fair Value
Ceiling Asset (Liability)
Notional Floor Price Price December 31, 2006
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ ------------ -----------------
NATURAL GAS (MMBTU)
Jan 2007 - May 2007 Collar 2,000,000 $8.00 $10.60 $3,515
Jan 2007 - Dec 2007 Collar 4,020,000 $7.00 $11.50 3,166
------
Total Natural Gas 6,681
------
CRUDE OIL (BBLS)
Jan 2007 - July 2007 Collar 89,000 $50.00 $74.00 (74)
Aug 2007 - April 2008 Collar 54,000 $60.00 $82.00 64
May 2008 - July 2008 Collar 15,000 $60.00 $82.00 13
Jan 2007 - July 2007 Collar 27,000 $60.00 $96.10 53
Aug 2007 - July 2008 Collar 52,000 $65.00 $93.15 239
Aug 2007 - July 2008 Collar 40,000 $70.00 $87.40 268
------
Total Crude Oil 563
------
$7,244
======
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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
The definitions set forth below apply to the indicated terms as used in this
Annual Report on Form 10-K. All volumes of natural gas referred to are stated at
the legal pressure base of the state or area where the reserves exist and at 60
degrees Fahrenheit and in most instances are rounded to the nearest major
multiple.
"Bbl" One stock tank barrel, or 42 U.S. gallons liquid volume, used in
reference to crude oil or other liquid hydrocarbons.
"Bbl/d" One barrel per day.
"Bcf" Billion cubic feet.
"Bcfe" Billion cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
"Btu" British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees
Fahrenheit.
"Completion" The installation of permanent equipment for the production of
oil or natural gas, or in the case of a dry hole, the reporting of
abandonment to the appropriate agency.
"Developed acreage" The number of acres allocated or assignable to
producing wells or wells capable of production.
"Developed well" A well drilled within the proved area of an oil or natural
gas reservoir to the depth of a stratigraphic horizon known to be
productive.
"Dry hole or well" A well found to be incapable of producing hydrocarbons
in sufficient quantities such that proceeds from the sale of the production
exceed production expenses and taxes.
"Equivalents" When we refer to "equivalents," we are doing so to compare
quantities of oil with quantities of natural gas or to express these
different commodities in a common unit. In calculating equivalents, we use
a generally recognized standard in which one barrel of oil is equal to six
thousand cubic feet of natural gas.
"Exploratory well" A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field
previously found to be productive of oil or natural gas in another
reservoir or to extend a known reservoir.
"Farm-in or farm-out" An agreement where the owner of a working interest in
a natural gas and oil lease assigns the working interest or a portion of
the working interest to another party who desires to drill on the leased
acreage. Generally, the assignee is required to drill one or more wells in
order to earn its interest in the acreage. The assignor usually retains a
royalty or reversionary interest in the lease. The interest received by an
assignee is a "farm-in" while the interest transferred by the assignor is a
"farm-out."
"Field" An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
or stratigraphic condition.
"Gross acres or gross wells" The total acres or wells, as the case may be,
in which a working interest is owned.
"Intangible Drilling and Development Costs" Expenditures made by an
operator for wages, fuel, repairs, hauling, supplies, surveying, geological
works, etc., incident to and necessary for the preparing for and drilling
of wells and the construction of production facilities and pipelines.
"Lease Operating Expense" Recurring expenses incurred to operate wells and
equipment on a producing lease. Examples include pumping and gauging,
chemicals, compression, fuel and water, insurance and property taxes.
"MBbls" One thousand barrels of crude oil or other liquid hydrocarbons.
"Mcf" One thousand cubic feet.
"Mcfe" One thousand cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
"Mcfe/d" One thousand cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids, per day.
"MD" Measured depth.
"MMBls" One million barrels of crude oil or other liquid hydrocarbons.
"MMbtu" One million Btus.
"MMMbtu" One billion Btus.
"MMcf" One million cubic feet.
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"MMcf/d" One million cubic feet per day.
"MMcfe" One million cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
"Net acres or net wells" The sum of the fractional working interests owned
in gross acres or gross wells.
"Net revenue interest" An interest in the production and revenues created
from the working interest which is generally calculated "net" or after
deducting any royalty interests.
"NYMEX" New York Mercantile Exchange.
"OCS" Outer Continental Shelf in the Gulf of Mexico.
"Oil" Crude oil and condensate
"Present value or PV10" When used with respect to natural gas and oil
reserves, the estimated future gross revenue to be generated from the
production of proved reserves, net of estimated production and future
development costs, using prices and costs in effect as of the date
indicated, without giving effect to non-property related expenses such as
general and administrative expenses, debt service and future income tax
expenses or to depreciation, depletion and amortization, discounted using
an annual discount rate of 10%.
"Productive well" A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of
the production exceed production expenses and taxes.
"Proved developed nonproducing reserves" Proved developed reserves expected
to be recovered from zones behind casing in existing wells.
"Proved developed producing reserves" Proved developed reserves that are
expected to be recovered from completion intervals currently open in
existing wells and able to produce to market.
"Proved reserves" The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. In addition,
please refer to the definitions of proved oil and natural gas reserves as
provided in Rule 4-10(a)(2)(3)(4) of Regulation S-X of the federal
securities laws. The rule is available at the SEC web site,
http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.
"Proved undeveloped location" A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
"Proved undeveloped reserves" Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where
a relatively major expenditure is required from recompletion.
"Recompletion" The completion for production of an existing well bore to
another formation from that in which the well has been previously
completed.
"Reservoir" A porous and permeable underground formation containing a
natural accumulation of producible oil or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from
other reservoirs.
"Royalty interest" An interest in a natural gas and oil property entitling
the owner to a share of natural gas or oil production free of costs of
production.
"Tangible Drilling and Development Costs" The costs of physical lease and
well equipment and structures and the costs of assets that themselves have
a salvage value.
"TVD" Total vertical depth.
"Undeveloped acreage" Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial
quantities of natural gas and oil, regardless of whether the acreage
contains proved reserves.
"WI" Working interest.
"Working interest" The operating interest which gives the owner the right
to drill, produce and conduct operating activities on the property and a
share of production.
"Workover" Operations on a producing well to restore or increase
production.
-40-
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.................. 42
Consolidated Statements of Operations.................................... 43
Consolidated Balance Sheets.............................................. 44
Consolidated Statements of Cash Flows.................................... 46
Consolidated Statements of Stockholders' Equity.......................... 47
Consolidated Statements of Comprehensive Income (Loss)................... 48
Notes to Consolidated Financial Statements............................... 49
1. Organization and Basis of Presentation............................ 49
2. Summary of Significant Accounting Policies........................ 49
3. Asset Retirement Obligations...................................... 54
4. Impairment of Long-Lived Assets................................... 55
5. Debt.............................................................. 55
6. Lease Obligations................................................. 56
7. Commitments and Contingencies..................................... 57
8. Taxes on Income................................................... 58
9. Redeemable Convertible Preferred Stock............................ 59
10. Stockholders' Equity.............................................. 60
11. Profit Sharing and Savings Plan................................... 63
12. Oil and Natural Gas Hedging Activities............................ 64
13. Major Customers................................................... 66
14. Related Party Transactions........................................ 66
15. Earnings Per Share................................................ 67
16. Accrued Liabilities............................................... 67
17. Subsequent Events................................................. 68
18. Quarterly Results of Operations (Unaudited)....................... 69
19. Supplemental Oil and Natural Gas Disclosures (Unaudited).......... 70
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.
-41-
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, 2006 and 2005, and the
related consolidated statements of operations, stockholders' equity, cash flows,
and comprehensive income (loss) for each of the three years in the period ended
December 31, 2006. 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, 2006 and 2005, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2006, in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, effective
January 1, 2006, the Company adopted the provisions of Statement of Financial
Accounting Standards No. 123(R), "Share-Based Payment."
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, 2006, 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 13, 2007, expressed an
unqualified opinion thereon.
BDO SEIDMAN, LLP
Houston, Texas
March 13, 2007
-42-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands, except per share data)
YEAR ENDED DECEMBER 31,
-------------------------------
2006 2005 2004
--------- -------- --------
REVENUES:
Oil and natural gas $ 189,041 $195,255 $202,447
Price risk management activities 128 (251) 126
Interest and other 1,788 692 545
--------- -------- --------
190,957 195,696 203,118
--------- -------- --------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 22,614 15,860 14,035
Severance and ad valorem taxes 11,259 8,811 9,394
Depletion and depreciation 106,067 97,354 102,915
General and administrative 16,674 18,010 15,169
Accretion expense 1,588 1,120 601
Impairment of long-lived assets 134,865 -- --
Hurricane damage repairs 4,314 3,066 --
Write-down of securities held -- -- 195
--------- -------- --------
297,381 144,221 142,309
--------- -------- --------
EARNINGS (LOSS) BEFORE OTHER EXPENSES &
INCOME TAXES (106,424) 51,475 60,809
--------- -------- --------
OTHER EXPENSES:
Interest expense 5,982 4,724 7,154
Debt conversion expense -- -- 1,188
--------- -------- --------
5,982 4,724 8,342
--------- -------- --------
EARNINGS (LOSS) BEFORE INCOME TAXES (112,406) 46,751 52,467
--------- -------- --------
INCOME TAXES:
Current 369 (568) 834
Deferred (38,891) 18,568 18,508
--------- -------- --------
(38,522) 18,000 19,342
--------- -------- --------
NET EARNINGS (LOSS) (73,884) 28,751 33,125
Dividends on preferred stock -- 902 3,877
--------- -------- --------
NET EARNINGS (LOSS) APPLICABLE TO COMMON
STOCKHOLDERS $ (73,884) $ 27,849 $ 29,248
========= ======== ========
NET EARNINGS (LOSS) PER SHARE:
Basic $ (0.84) $ 0.33 $ 0.41
Diluted $ (0.84) $ 0.31 $ 0.37
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic 87,670 84,527 72,084
Diluted 87,670 90,090 79,033
See notes to consolidated financial statements.
-43-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
DECEMBER 31,
-----------------------
2006 2005
---------- ----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 31,424 $ 23,265
Restricted cash 1,282 1,234
Accounts receivable, less allowance for doubtful accounts
of $232 [2006] and $242 [2005] 24,285 41,188
Due from affiliates 670 --
Prepaid expenses and other 3,457 1,294
Assets from price risk management activities 7,968 528
Deferred tax asset -- 1,150
---------- ----------
Total current assets 69,086 68,659
---------- ----------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including
$54,356 [2006] and $26,623 [2005] not subject to depletion) 1,663,865 1,512,036
Land 48 48
Equipment and other 7,492 6,540
---------- ----------
1,671,405 1,518,624
Less accumulated depletion and depreciation 1,273,522 1,032,595
---------- ----------
Total property and equipment, net 397,883 486,029
---------- ----------
OTHER ASSETS:
Assets from price risk management activities 490 235
Other 436 879
---------- ----------
Total other assets 926 1,114
---------- ----------
TOTAL ASSETS $ 467,895 $ 555,802
========== ==========
See notes to consolidated financial statements.
-44-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
DECEMBER 31,
---------------------
2006 2005
--------- ---------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 9,751 $ 7,595
Revenues and royalties payable 7,933 9,149
Due to affiliates -- 4,638
Notes payable 2,754 1,103
Accrued liabilities 21,938 22,272
Liabilities from price risk management activities 1,024 3,977
Asset retirement obligations 4,803 2,879
Deferred income taxes payable 2,336 --
Current income taxes payable -- 108
--------- ---------
Total current liabilities 50,539 51,721
--------- ---------
LONG-TERM DEBT 75,000 75,000
--------- ---------
OTHER:
Deferred income taxes 3,364 41,967
Liabilities from price risk management activities 190 464
Asset retirement obligations 18,005 9,085
--------- ---------
21,559 51,516
--------- ---------
COMMITMENTS AND CONTINGENCIES (NOTES 6, 7 AND 11)
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized,
89,139,600 [2006] and 86,817,658 [2005] issued) 928 900
Additional paid-in capital 534,441 524,692
Accumulated deficit (219,279) (145,395)
Accumulated other comprehensive income (loss) 4,707 (2,314)
Unamortized deferred compensation -- (318)
--------- ---------
Total stockholders' equity 320,797 377,565
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 467,895 $ 555,802
========= =========
See notes to consolidated financial statements.
-45-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
YEAR ENDED DECEMBER 31,
---------------------------------
2006 2005 2004
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss) $ (73,884) $ 28,751 $ 33,125
Adjustments to reconcile net earnings (loss) to net cash
provided by operating activities:
Depletion and depreciation 106,067 97,354 102,915
Impairment of long-lived assets 134,865 -- --
Amortization of other assets 443 446 1,506
Non-cash compensation 2,300 1,845 1,920
Non-cash price risk management activities (128) 251 (126)
Debt conversion expense -- -- 1,188
Write-down of securities held -- -- 195
Accretion expense 1,588 1,120 601
Deferred income taxes (38,891) 18,568 18,508
Changes in assets and liabilities:
Restricted cash (48) (343) (891)
Accounts receivable 16,903 (13,425) (3,060)
Prepaid expenses and other (2,163) 969 (677)
Accounts payable 2,156 (7,388) 6,291
Due to (from) affiliates (5,308) 772 3,563
Revenues and royalties payable (1,216) 1,032 (4,318)
Asset retirement obligations (6,026) (469) (1,173)
Other assets and liabilities 355 4,127 10,751
--------- --------- ---------
Net cash provided by operating activities 137,013 133,610 170,318
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (129,803) (132,443) (141,263)
Acquisition of properties (11,734) -- --
Proceeds from (settlements on) sale of property 11,032 (51) (72)
--------- --------- ---------
Net cash used in investing activities (130,505) (132,494) (141,335)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt 10,000 10,000 75,129
Reductions in long-term debt (10,000) (10,129) (132,320)
Proceeds - Notes payable 9,248 3,142 2,537
Reductions - Notes payable (7,597) (2,909) (1,861)
Repurchase of common stock -- -- (49,291)
Issuance of stock/exercise of stock options -- 13 94,777
Preferred dividends -- (2,166) (5,248)
Additions to deferred loan costs -- (99) (1,230)
--------- --------- ---------
Net cash provided by (used in) financing activities 1,651 (2,148) (17,507)
--------- --------- ---------
NET CHANGE IN CASH AND CASH EQUIVALENTS 8,159 (1,032) 11,476
Cash and cash equivalents at beginning of year 23,265 24,297 12,821
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 31,424 $ 23,265 $ 24,297
========= ========= =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Non-cash activities:
Conversion of preferred stock $ -- $ (30,625) $ (27,734)
Issuance of shares for contract services $ (795) $ (1,932) $ --
Conversion of convertible subordinated debt $ -- $ -- $ (20,000)
Issuance of shares for acquisition of properties $ (7,000) $ -- $ --
ARO Liability - new wells drilled $ 4,559 $ 883 $ 1,051
ARO Liability - changes in estimates $ 10,723 $ 806 $ 5,043
See notes to consolidated financial statements.
-46-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2004, 2005 AND 2006 (in thousands)
Common Stock Accumulated
------------- Additional Accumulated Other Unamortized Treasury Stock
Par Paid-In Earnings Comprehensive Deferred ----------------
Shares Value Capital (Deficit) Income (Loss) Compensation Shares Cost Total
------ ----- ---------- ----------- ------------- ------------ ------ -------- --------
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 for
contract services 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
Effect of adoption of SFAS
123(R) -- -- (318) -- -- 318 -- -- --
Issuance of rights to common
stock -- 5 (5) -- -- -- -- -- --
Company's 401(k) plan
contribution 92 1 335 -- -- -- -- -- 336
Stock-based compensation -- -- 372 -- -- -- -- -- 372
Compensation expense -- -- 1,592 -- -- -- -- -- 1,592
Accum other comprehensive
income -- -- -- -- 7,021 -- -- -- 7,021
Issuance of shares for
contract services 224 2 793 -- -- -- -- -- 795
Issuance of shares - Vintage
acq. 2,006 20 6,980 -- -- -- -- -- 7,000
Net loss -- -- -- (73,884) -- -- -- -- (73,884)
------ ---- -------- --------- ------- ------- ------ -------- --------
Balance, December 31, 2006 89,140 $928 $534,441 $(219,279) $ 4,707 $ -- -- $ -- $320,797
====== ==== ======== ========= ======= ======= ====== ======== ========
See notes to consolidated financial statements.
-47-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(thousands of dollars)
YEAR ENDED DECEMBER 31,
-----------------------------
2006 2005 2004
-------- -------- -------
Net earnings (loss) applicable to common stockholders $(73,884) $ 27,849 $29,248
-------- -------- -------
Other comprehensive income (loss), net of tax, for unrealized
gains (losses) from hedging activities:
Unrealized holding gains (losses) arising during period (1) 9,505 (14,116) (6,161)
Reclassification adjustments on settlement of contracts (2) (2,484) 13,376 12,106
Write-down of securities held -- -- 185
-------- -------- -------
7,021 (740) 6,130
-------- -------- -------
Total comprehensive income (loss) $(66,863) $ 27,109 $35,378
======== ======== =======
(1) Net income tax (expense) benefit $ (5,118) $ 7,601 $ 3,317
(2) Net income tax (expense) benefit $ 1,337 $ (7,202) $(6,518)
See notes to consolidated financial statements.
-48-
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, 2006, was
$1,282,000, and at December 31, 2005, was $1,234,000. 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.
-49-
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 $5.5 million, $3.9 million and $6.3 million in 2006, 2005 and 2004,
respectively. Cash payments (refunds) for income taxes (federal and state, net
of receipts) were ($322,000) for 2006, $1,285,000 for 2005, and $950,000 for
2004.
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, 2006, and
December 31, 2005, the Company had approximately $32,475,000 and $24,370,000,
respectively, in excess of FDIC insured limits. The Company has not experienced
any losses in such accounts.
REVENUE RECOGNITION AND ACCOUNTS RECEIVABLE
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.
The Company maintains an allowance for doubtful accounts on trade receivables
equal to amounts estimated to be uncollectible. This estimate is based upon
historical collection experience, combined with a specific review of each
customer's outstanding trade receivable balance. Management believes that the
allowance for doubtful accounts is adequate, however, actual write-offs may
exceed the recorded allowance.
HURRICANE DAMAGE REPAIRS
This expense of $4.3 million in 2006 and $3.1 million in 2005 is related to
damages incurred from hurricanes Katrina and Rita, primarily related to the
Company's insurance deductible and repair costs in excess of insured values. Due
to the extensive damage throughout the area and the limited resources available
for repairs, significant cost increases were experienced by the industry. The
actual repair costs were higher than originally estimated and exceeded our claim
limits and therefore resulted in increased expense. Additionally, a portion of
the 2006 expenses resulted from changes in damage classifications with different
insurance coverage. The final claim settlement negotiations were concluded in
February 2007, and 2006 expenses have been adjusted to reflect the forthcoming
settlement payment.
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.
-50-
STOCK OPTIONS
Effective January 1, 2006, the Company adopted the provisions of Statement of
Financial Accounting Standards ("SFAS") No. 123R, "Shared-Based Payment," using
the modified prospective method. SFAS 123R replaces SFAS No. 123, "Accounting
for Stock-Based Compensation" and amends SFAS No. 95, "Statement of Cash Flows."
SFAS No. 123R addresses the accounting for share-based payment transactions in
which an enterprise received employee services in exchange (a) equity
instruments of the enterprise or (b) liabilities that are based on the fair
value of the enterprise's equity instruments or that may be settled by the
issuance of such equity instruments. SFAS No. 123R eliminates the ability to
account for share-based compensation transactions using accounting Principles
Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees, " and
generally requires instead that such transactions be accounted for using the
fair-value based method. Prior to adoption of SFAS No. 123R, the Company
followed the intrinsic value method in accordance with APB No. 25 to account for
stock options. Prior period financial statements have not been restated.
Compensation expense is recorded for stock option awards over the requisite
vesting periods based upon the market value on the date of the grant.
Stock-based compensation expense related to SFAS No. 123R of approximately
$372,000 was recorded in the year ended December 31, 2006. No stock-based
compensation expense related to SFAS No. 123R was recorded in the years ended
December 31, 2005 and 2004.
The following is a pro-forma reconciliation of reported earnings and earnings
per share for the years ended December 31, 2005 and 2004, as if the Company used
the fair value method of accounting for stock-based compensation (thousands of
dollars, except per share information):
2005 2004
------- -------
Net earnings applicable to common stockholders as reported $27,849 $29,248
Stock-based compensation expense determined under fair
method for all awards, net of tax (237) (119)
------- -------
Net earnings applicable to common stockholders (pro forma) $27,612 $29,129
======= =======
Basic earnings per share:
As reported $ 0.33 $ 0.41
Pro forma $ 0.33 $ 0.40
Diluted earnings per share:
As reported $ 0.31 $ 0.37
Pro forma $ 0.31 $ 0.37
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 4.97%, 3.97% and 3.37%; dividend yield of 0%; volatility
factors of the expected market price of the Company's common stock of 0.80, 0.92
and 0.96 for 2006, 2005 and 2004, respectively; and a weighted-average expected
life of five years. These assumptions resulted in a weighted average grant date
fair value of $2.33, $3.43 and $5.92 for options granted in 2006, 2005 and 2004,
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
-51-
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, 2006 and 2005, and were determined based
upon variable interest rates currently available to us for borrowings with
similar terms.
DERIVATIVE FINANCIAL INSTRUMENTS
The Company follows the provisions of SFAS No. 133, "Accounting for Derivative
Instruments and Certain Hedging Activities." The Company enters into derivative
contracts to hedge the price risks associated with a portion of anticipated
future oil and natural 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 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 a gain of $128,000
related to hedge ineffectiveness during the year ended December 31, 2006, a loss
of $251,000 during the year ended December 31, 2005, and a gain of $126,000
during the year ended December 31, 2004.
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.
INCOME TAXES
The Company accounts for federal income taxes using the liability method. Under
the liability method, deferred tax assets and liabilities are recognized for the
future tax consequences attributable to differences between financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. Under the liability
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method, the effect on previously recorded deferred tax assets and liabilities
resulting from a change in tax rates is recognized in earnings in the period in
which the change is enacted.
ENVIRONMENTAL EXPENDITURES
The Company is subject to extensive federal, state and local environmental laws
and regulations. These laws regulate the discharge of materials into the
environment and may require the Company to remove or mitigate the environmental
effects of the disposal or release of petroleum or chemical substances at
various sites. Environmental expenditures are expensed or capitalized depending
on their future economic benefit. Expenditures that relate to an existing
condition caused by past operations and that have no future economic benefits
are expensed. Liabilities for expenditures of a noncapital nature are recorded
when environmental assessment and or remediation is probable, and the costs can
be reasonably estimated. Such liabilities are generally undiscovered unless the
timing of cash payments for the liability or component are fixed or reliably
determinable.
NEW ACCOUNTING PRONOUNCEMENTS
In July 2006, the Financial Accounting Standard Board ("FASB") issued FASB
Interpretation No. 48 ("FIN 48"), "Accounting for Uncertainty in Income Taxes -
and interpretation of SFAS No. 109." FIN 48 clarifies the accounting for
uncertainty in income taxes recognized in an enterprise's financial statements
in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 prescribes
a recognition threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken in a
tax return. FIN 48 also provides guidance on recognition, classification,
interest and penalties, accounting in interim periods, disclosure, and
transition. FIN 48 is effective for fiscal years beginning after December 15,
2006. The Company is in the process of evaluating FIN 48 but does not believe
that its implementation will have a material effect on the Company's financial
position or results of operation in any period.
In September 2006, the SEC issued Staff Accounting Bulletin No. 108 ("SAB 108").
Due to diversity in practice among registrants, SAB 108 expresses SEC staff
views regarding the process by which misstatements in financial statements are
evaluated for purposes of determining whether financial statement restatement is
necessary. SAB 108 is effective for fiscal years ending after November 15, 2006,
and early application is encouraged. The adoption of SAB 108 did not have a
material impact on our financial position or results of operations.
In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements". SFAS
No. 157 defines fair value, establishes a framework for measuring fair value in
generally accepted accounting principles and expands disclosure about fair value
measurements. SFAS No. 157 is effective for financial statements issued for
fiscal years beginning after November 15, 2007. The Company is evaluating the
impact, if any, that SFAS No. 157 will have on our financial statements.
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 natural gas revenues, bad debts,
oil and natural 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.
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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
The Company follows SFAS No. 143, "Accounting for Asset Retirement Obligations,"
which requires entities to record the fair value of a liability for legal
obligations associated with the retirement obligations of tangible long-lived
assets in the period in which it is incurred. The fair value of asset retirement
obligation liabilities has been calculated using an expected present value
technique. Fair value, to the extent possible, should include a market risk
premium for unforeseeable circumstances. No market risk premium was included in
the Company's asset retirement obligations fair value estimate since a
reasonable estimate could not be made. When the liability is initially recorded,
the entity increases the carrying amount of the related long-lived asset. Over
time, accretion of the liability is recognized each period, and the capitalized
cost is amortized over the useful life of the related asset. Upon settlement of
the liability, an entity either settles the obligation for its recorded amount
or incurs a gain or loss upon settlement. This standard requires the Company to
record a liability for the fair value of the dismantlement and abandonment
costs, excluding salvage values.
Accretion expenses were $1.6 million, $1.1 million and $0.6 million in 2006,
2005 and 2004, respectively.
The following table describes the change in the Company's asset retirement
obligations for the years ended December 31, 2006 and 2005 (thousands of
dollars):
Asset retirement obligation at December 31, 2004 $ 9,624
Additional retirement obligations recorded in 2005 883
Settlements during 2005 (469)
Revisions to estimates during 2005 806
Accretion expense for 2005 1,120
-------
Asset retirement obligation at December 31, 2005 11,964
Additional retirement obligations recorded in 2006 4,559
Settlements during 2006 (6,026)
Revisions to estimates and other changes during 2006 10,723
Accretion expense for 2006 1,588
-------
Asset retirement obligation at December 31, 2006 $22,808
=======
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 the costs to do so.
-54-
4. IMPAIRMENT OF LONG-LIVED ASSETS
At the end of each quarter, the unamortized cost of oil and natural gas
properties, net of related deferred income taxes, is limited to the sum of the
estimated future net revenues from proved properties using period-end prices,
after giving effect to cash flow hedge positions, discounted at 10%, and the
lower of cost or fair value of unproved properties adjusted for related income
tax effects.
Accordingly, based on September 30, 2006, pricing of $4.17 per Mcf of natural
gas and $63.37 per barrel of oil, the Company recognized in the third quarter of
2006 a non-cash impairment of $134.9 million ($87.7 million after tax) of the
Company's oil and natural gas properties under the full cost method of
accounting.
Due to the substantial volatility in oil and natural gas prices and their effect
on the carrying value of the Company's proved oil and natural gas reserves,
there can be no assurance that future write-downs 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.
5. 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. The borrowing base under the
Credit Facility was redetermined by the syndication group to be $120 million,
effective October 31, 2006. As of December 31, 2006, outstanding borrowings
under the Credit Facility totaled $75 million.
The Credit Facility is subject to semi-annual borrowing base redeterminations on
April 30 and October 31 of each year. In addition to the scheduled semi-annual
borrowing base redeterminations, the lenders or the Company, have the right to
redetermine the borrowing base at any time, provided that no party can request
more than one such redetermination between the regularly scheduled borrowing
base redeterminations. The determination of our borrowing base is subject to a
number of factors including, quantities of proved oil and natural gas reserves,
the bank's price assumptions and other various factors unique to each member
bank. Our lenders can redetermine the borrowing base to a lower level than the
current borrowing base if they determine that our oil and natural gas reserves,
at the time of redetermination, are inadequate to support the borrowing base
then in effect.
Obligations under the Credit Facility are secured by pledges of outstanding
capital stock of the Company's subsidiaries and by a first priority lien on not
less than 75% (95% in the case of an event of default) of its present value of
proved oil and natural gas properties. In addition, the Company is required to
deliver to the lenders and maintain satisfactory title opinions covering not
less than 70% of the present value of proved oil and natural gas properties. The
Credit Facility also contains other restrictive covenants, including, among
other items, maintenance of certain financial ratios, restrictions on cash
dividends on common stock and under certain circumstances preferred stock,
limitations on the redemption of preferred stock, limitations on repurchases of
common stock and an unqualified audit report on the Company's consolidated
financial statements, all of which the Company is in compliance.
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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, 2006, the three-month LIBOR interest rate
was 5.36%. 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.
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
paid 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, 2006, are as follows: none in 2007, $75 million in 2008, and none
thereafter.
6. LEASE OBLIGATIONS
In April 2006, the Company completed negotiations for an amendment to the
current office building lease agreement that extends the current office lease
until September 30, 2011. The base rental payments will be $1.7 million in 2007
and 2008, $1.8 million in 2009, $2.0 million in 2010 and $1.6 million in 2011.
The Company also has operating leases for equipment with various terms, none
exceeding three years. Rental expense amounted to approximately $2.5 million,
$2.5 million and $2.4 million in 2006, 2005 and 2004, respectively. Future
minimum lease payments under all non-cancelable operating leases having initial
terms of one year or more are $1.9 million for 2007, $1.9 million for 2008, $2.0
million for 2009 and 2010, $1.6 million for 2011, and none thereafter.
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7. COMMITMENTS AND CONTINGENCIES
LITIGATION
H. L. HAWKINS LITIGATION. In December 2004, the estate of H.L. Hawkins filed a
claim against Meridian for damages "estimated to exceed several million dollars"
for Meridian's alleged gross negligence, willful misconduct and breach of
fiduciary duty under certain agreements concerning certain wells and property in
the S.W. Holmwood and E. Lake Charles Prospects in Calcasieu Parish in
Louisiana, as a result of Meridian's satisfying a prior adverse judgment in
favor of Amoco Production Company. Mr. James Bond has been added as a defendant
by Hawkins claiming Mr. Bond, when he was General Manager of Hawkins, did not
have the right to consent, could not consent or breached his fiduciary duty to
Hawkins if he did consent to all actions taken by Meridian. The Company has not
provided any amount for this matter in its financial statements at December 31,
2006.
TITLE/LEASE DISPUTES. Title and lease disputes may arise in the normal course of
the Company's operations. These disputes are usually small but could result in
an increase or decrease in reserves once a final resolution to the title dispute
is made.
ENVIRONMENTAL LITIGATION. Various landowners have sued Meridian (along with
numerous other oil companies) in lawsuits concerning several fields in which the
Company has had operations. The lawsuits seek injunctive relief and other
relief, including unspecified amounts in both actual and punitive damages for
alleged breaches of mineral leases and alleged failure to restore the
plaintiffs' lands from alleged contamination and otherwise from the Company's
oil and natural gas operations. The Company, in certain instances, has
indemnified third parties from the claims made in these lawsuits. In three of
the lawsuits, Shell Oil Company and SWPI LP have demanded indemnity and defense
from Meridian; Meridian has denied such demands. The Company has not provided
any amount for this matter in its financial statements at December 31, 2006.
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.
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8. TAXES ON INCOME
Provisions (benefits) for federal and state income taxes are as follows
(thousands of dollars):
YEAR ENDED DECEMBER 31,
----------------------------
2006 2005 2004
-------- ------- -------
Current:
Federal $ 334 $ (676) $ 905
State 35 108 (71)
Deferred:
Federal (39,108) 17,480 18,160
State 217 1,088 348
-------- ------- -------
Income tax expense (benefit) $(38,522) $18,000 $19,342
======== ======= =======
Income tax expense (benefit) as reported is reconciled to the federal statutory
rate (35%) as follows (thousands of dollars):
YEAR ENDED DECEMBER 31,
----------------------------
2006 2005 2004
-------- ------- -------
Income tax provision (benefit) computed at statutory rate $(39,342) $16,363 $18,364
Nondeductible costs 415 479 607
State income tax, net of federal tax benefit 240 1,158 302
Decrease in net operating loss carryover due to expiration 165 -- 69
-------- ------- -------
Income tax expense (benefit) $(38,522) $18,000 $19,342
======== ======= =======
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,
------------------
2006 2005
------- --------
Deferred tax assets:
Net operating tax loss carryforward $40,085 $ 51,071
Statutory depletion carryforward 950 950
Tax credits 1,644 1,311
Unrealized hedge loss -- 1,240
Other 5,860 5,214
------- --------
Total deferred tax assets 48,539 59,786
------- --------
Deferred tax liabilities:
Book basis in excess of tax basis
in oil and natural gas properties 51,705 100,603
Unrealized hedge gain 2,534 --
------- --------
Total deferred tax liabilities 54,239 100,603
------- --------
Net deferred tax liability $(5,700) $(40,817)
======= ========
As of December 31, 2006, the Company had approximately $114.5 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,
-58-
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 2018 and extend through
2025. A portion of the net operating loss carryforwards is subject to change in
ownership limitations that could restrict the Company's ability to utilize such
losses in the future.
As of December 31, 2006, 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):
YEAR OF NET AMT
EXPIRATION OPERATING LOSS OPERATING LOSS
---------- -------------- --------------
2018 $ 8,968 $ 20,965
2019 47,730 48,630
2020 31 31
2021 36 36
2022 13,053 6,502
2023 44,669 44,516
2025 42 53
-------- --------
TOTAL $114,529 $120,733
======== ========
As of December 31, 2006, the Company had approximately $1.6 million of AMT
Operating Loss carryforwards that do 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 2006.
9. REDEEMABLE CONVERTIBLE PREFERRED STOCK
A private placement totaling $66.9 million of 8.5% redeemable convertible
preferred stock was completed during May 2002. 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.
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10. 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.
WARRANTS
The Company had the following warrants outstanding at December 31, 2006:
NUMBER OF EXERCISE
WARRANTS SHARES PRICE EXPIRATION DATE
-------- --------- -------- -----------------
Executive Officers 1,428,000 $5.85 *
General Partner 1,805,432 $0.10 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, 2006, 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 1,805,432 shares of common stock at an exercise price
of $0.10 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.
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.
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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, 2006, 2005 and 2004, 1,785,310, 2,162,478, and 1,670,685
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, 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
Granted 109,668 3.40
Exercised -- --
Canceled (245,750) 7.72
--------- -----
Outstanding at December 31, 2006 3,458,968 $3.84
========= =====
Shares exercisable:
December 31, 2004 3,498,050 $4.06
December 31, 2005 3,430,050 $3.97
December 31, 2006 3,285,465 $3.76
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OPTIONS OUTSTANDING OPTIONS EXERCISABLE
---------------------------------- ----------------------------------
WEIGHTED WEIGHTED
RANGE OF OUTSTANDING AT AVERAGE EXERCISABLE AT AVERAGE
EXERCISABLE PRICES DECEMBER 31, 2006 EXERCISE PRICE DECEMBER 31, 2006 EXERCISE PRICE
------------------ ----------------- -------------- ----------------- --------------
$3.00 - $4.99 3,187,318 $ 3.38 3,092,565 $ 3.38
$5.32 - $9.00 150,000 7.77 71,250 7.90
$11.13 121,650 11.13 121,650 11.13
--------- ------ --------- ------
3,458,968 $ 3.84 3,285,465 $ 3.76
========= ====== ========= ======
The weighted average remaining contractual life of options outstanding at
December 31, 2006, was approximately two years.
The aggregate intrinsic value of options outstanding and exercisable at December
31, 2006, was de minimus. The aggregate intrinsic value represents the total
pre-tax value (the difference between the Company's closing stock price on the
last trading day of 2006 and the exercise price, multiplied by the number of
in-the-money options) that would have been received by the option holders had
all option holders exercised their options on December 31, 2006. The amount of
aggregate intrinsic value will change based on the fair market value of the
Company's common stock.
As of December 31, 2006, there was approximately $356.6 thousand of total
unrecognized compensation expense related to unvested stock-based compensation
plans. This compensation expense is expected to be recognized, net of
forfeitures, on a straight-line basis over the remaining vesting period of
approximately 2.5 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 2006, $400,000 for 2005 and $400,000 for
2004, 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, 2006, the plan had reserved 4,650,000 shares
of common stock for future issuance and 3,640,188 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
$1,593,000, $1,595,000 and $1,577,000 for 2006, 2005 and 2004
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periods, respectively, and is reflected in general and administrative expense
and in oil and natural gas properties for the years ended December 31, 2006,
2005 and 2004, 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 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.
11. 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 $381,000, $300,000, and $299,000 in 2006, 2005,
and 2004, 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 was $6.7 million, $6.4 million and
$6.9 million in 2006, 2005 and 2004, 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
-63-
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 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.
For the years ended December 31, 2006, 2005 and 2004, compensation expense in
the amounts of $137,624, $120,161, and $37,673, were recorded for each
individual. 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.
12. 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 SFAS No. 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
-64-
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 $128,000 during the year ended
December 31, 2006, a loss of $251,000 during the year ended December 31, 2005,
and a gain of $126,000 during the year ended December 31, 2004, due to hedge
ineffectiveness.
As of December 31, 2006, the estimated fair value of the Company's oil and
natural gas contracts was an unrealized gain of $7.2 million ($4.7 million net
of tax) which is recognized in other comprehensive income. Based upon oil and
natural gas commodity prices at December 31, 2006, approximately $6.9 million of
the gain deferred in other comprehensive income could potentially increase gross
revenues in 2007. These derivative agreements expire at various dates through
July 31, 2008.
Net settlements under these contracts increased (decreased) oil and natural gas
revenues by $3,821,000, ($20,578,000) and ($18,624,000) for the years ended
December 31, 2006, 2005, and 2004 respectively, as a result of hedging
transactions.
All of the Company's current hedging contracts are in the form of costless
collars. The costless collars provide the Company with a lower limit "floor"
price and an upper limit "ceiling" price on the hedged volumes. The floor price
represents the lowest price the Company will receive for the hedged volumes
while the ceiling price represents the highest price the Company will receive
for the hedged volumes. The costless collars are settled monthly based on the
NYMEX futures contract.
The notional amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 40% of proved developed natural gas production and 26% of proved
developed oil production during the respective terms of the hedging agreements.
The fair values of the hedges are based on the difference between the strike
price and the New York Mercantile Exchange future prices for the applicable
trading months.
The fair value of hedging agreements is recorded on the consolidated balance
sheet as assets or liabilities. The estimated fair value of hedging agreements
as of December 31, 2006, is provided below:
Estimated
Fair Value
Asset (Liability)
Notional Floor Price Ceiling Price December 31, 2006
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ ------------- -----------------
NATURAL GAS (MMBTU)
Jan 2007 - May 2007 Collar 2,000,000 $8.00 $10.60 $3,515
Jan 2007 - Dec 2007 Collar 4,020,000 $7.00 $11.50 3,166
------
Total Natural Gas 6,681
------
CRUDE OIL (BBLS)
Jan 2007 - July 2007 Collar 89,000 $50.00 $74.00 (74)
Aug 2007 - April 2008 Collar 54,000 $60.00 $82.00 64
May 2008 - July 2008 Collar 15,000 $60.00 $82.00 13
Jan 2007 - July 2007 Collar 27,000 $60.00 $96.10 53
Aug 2007 - July 2008 Collar 52,000 $65.00 $93.15 239
Aug 2007 - July 2008 Collar 40,000 $70.00 $87.40 268
------
Total Crude Oil 563
------
$7,244
======
-65-
13. MAJOR CUSTOMERS
Major customers for the years ended December 31, 2006, 2005 and 2004, were as
follows (based on sales exceeding 10% of total oil and natural gas revenues):
YEAR ENDED DECEMBER 31,
-----------------------
CUSTOMER 2006 2005 2004
-------- ---- ---- ----
Superior Natural Gas.................. 35% 46% 45%
Crosstex/Louisiana Intrastate Gas..... 21% 19% 22%
14. 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, 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 $7,743,000, $9,997,000, and $8,539,000 for the years ended
December 31, 2006, 2005 and 2004, respectively, in oil and natural gas drilling
activities. Net amounts due to/(from) TODD, JAR and Mr. Reeves were
approximately ($337,000) and $2,308,000 as of December 31, 2006 and 2005,
respectively. Net amounts due to/(from) Sydson and Mr. Mayell were approximately
($333,000) and $2,330,000 as of December 31, 2006 and 2005, 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, 2006, 2005 and 2004 and received fees of
approximately $227,000, $320,000 and $255,000, respectively. Such fees exceeded
5% of the gross revenues of Kares & Cihlar for those respective years. Mr. Kares
also participated in the Management Plan described in Note 11 above, pursuant to
which he was paid approximately $438,000 during 2006, $464,000 during 2005, and
$298,000 during 2004.
Mr. Gary A. Messersmith, a Director of Meridian, is currently a member of the
law firm of Looper, Reed & McGraw P.C. in Houston, Texas, which provided legal
services for the Company for the years ended December 31, 2006, 2005 and 2004,
and received fees of approximately $26,000, $19,000, and $12,000, respectively.
In addition, the Company has his firm, Gary A. Messersmith, P.C. on a retainer
of $8,333 per month relating to services provided to the Company. Mr.
Messersmith also participated in the Management Plan described in Note 11 above,
pursuant to which he was paid approximately $751,000 during 2006, $702,000
during 2005, and $688,000 during 2004.
Mr. J. Drew Reeves, the son of Mr. Joseph A. Reeves, Jr., is a staff member in
the Land Department. Mr. Drew Reeves was paid $146,000, $100,000, and $80,000
for the years 2006, 2005 and 2004, respectively. Mr. 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 $150,000, $111,000
and $101,000 for the years 2006, 2005 and 2004, respectively. Mr. 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 $337,000 in 2006 and $100,000 in 2005. Such fees exceeded 5% of
the gross revenues for these firms for those respective years.
-66-
Mr. Michael W. Mayell, the son of Mr. Michael J. Mayell, an officer and Director
of Meridian, is a staff member in the Production Department, and was paid
$114,000, $79,000, and $60,000, for the years 2006, 2005 and 2004, respectively.
Mr. James T. Bond, former Director of Meridian, is the father-in-law of Mr.
Michael J. Mayell, and has provided consultant services to the Company and
received fees in the amount of $155,000, $175,000, and $124,000, for the years
2006, 2005 and 2004, respectively.
15. EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted earnings
(loss) per share:
(in thousands, except per share)
YEAR ENDED DECEMBER 31,
--------------------------------
2006 2005 2004
-------- ------- -------
Numerator:
Net earnings (loss) applicable to common stockholders $(73,884) $27,849 $29,248
Plus income impact of assumed conversions:
Preferred stock dividends -- N/A N/A
Interest on convertible subordinated notes -- -- 270
-------- ------- -------
Net earnings (loss) applicable to common stockholders
plus assumed conversions $(73,884) $27,849 $29,518
-------- ------- -------
Denominator:
Denominator for basic earnings (loss) per
share - weighted-average shares outstanding 87,670 84,527 72,084
Effect of potentially dilutive common shares:
Warrants N/A 4,755 4,508
Employee and director stock options N/A 808 1,589
Convertible subordinated notes -- N/A 852
Redeemable preferred stock -- N/A N/A
-------- ------- -------
Denominator for diluted earnings (loss) per share
- weighted-average shares outstanding and
assumed conversions 87,670 90,090 79,033
======== ======= =======
Basic earnings (loss) per share $ (0.84) $ 0.33 $ 0.41
======== ======= =======
Diluted earnings (loss) per share $ (0.84) $ 0.31 $ 0.37
======== ======= =======
N/A = Not Applicable, meaning anti-dilutive for periods presented. Due to its
anti-dilutive effect on earnings per share, approximately 5.4 million shares in
2006, 2.1 million shares in 2005, and 9.3 million shares in 2004 related to our
redeemable preferred stock, convertible subordinated notes, stock options and
warrants were excluded from the dilutive shares.
16. ACCRUED LIABILITIES
Below is the detail of our accrued liabilities on our balance sheets as of
December 31 (thousands of dollars):
2006 2005
------- -------
Capital expenditures $13,851 $12,853
Operating expenses/Taxes 4,024 2,794
Hurricane damage repairs 71 2,717
-67-
Compensation 1,197 1,949
Interest 506 503
Other 2,289 1,456
------- -------
TOTAL $21,938 $22,272
======= =======
17. SUBSEQUENT EVENTS
RIG PURCHASE
The Company recently signed an agreement for the construction and purchase of
one newly built land based drilling rig in conjunction with an engineering
design and fabrication/rig contractor, for approximately $12 million. This
contractor will ultimately operate, crew and maintain the rig. Delivery of the
rig is currently expected in the third quarter of 2007 when the rig will be
mobilized to the Company's East Texas Austin Chalk play. Depending on the
success of the operations in the play, the Company has plans for a two-rig,
multi-well drilling program to exploit the Company's acreage under lease for an
anticipated three to five year period.
SHARE REPURCHASE PROGRAM
The Company has authorized a new share repurchase program. Under the program,
the Company may repurchase in the open market or through privately negotiated
transactions up to $5 million worth of Common Shares per year over the next
three years. The timing, volume, and nature of share repurchases will be at the
discretion of management, depending on market conditions, applicable securities
laws, and other factors.
During February 2007, the lenders in the Credit Facility unanimously approved an
amendment increasing the available limit for the Company's repurchase of its
common stock from $1.0 million to $5.0 million annually. The amendment contained
restrictive covenants on the Company's ability to repurchase its common stock
including (i) the Company cannot utilize funds under the Credit Facility to fund
any stock repurchases and (ii) immediately prior to any repurchase, availability
under the Credit Facility must be equal to at least 20% of the then effective
borrowing base.
The share repurchase program is scheduled to begin as soon as reasonably
practical. The program does not require the Company to repurchase any specific
number of shares and may be modified, suspended or terminated at any time
without prior notice. The Company expects repurchases to be funded by available
cash.
-68-
18. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
Results of operations by quarter for the year ended December 31, 2006 were
(thousands of dollars, except per share):
QUARTER ENDED
----------------------------------------
2006 MARCH 31 JUNE 30 SEPT. 30 DEC. 31
---- -------- ------- --------- -------
Revenues $57,506 $46,540 $ 46,059 $40,852
Results of operations from exploration
and production activities(1) 18,973 9,320 (127,773) 8,671
Net earnings (loss) (2) (3) $ 7,331 $ 2,843 $ (86,879) $ 2,821
Net earnings (loss) per share:(2) (3)
Basic $ 0.08 $ 0.03 $ (0.99) $ 0.03
Diluted $ 0.08 $ 0.03 $ (0.99) $ 0.03
Results of operations by quarter for the year ended December 31, 2005 were
(thousands of dollars, except per share):
QUARTER ENDED
---------------------------------------
2005 MARCH 31 JUNE 30 SEPT. 30 DEC. 31
---- -------- ------- -------- -------
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
(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, impairment
of long-lived assets, accretion and hurricane damage repairs.
(2) Applicable to common stockholders.
(3) Adopted SFAS No. 123(R) effective January 1, 2006.
-69-
19. 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
(thousands of dollars)
YEAR ENDED DECEMBER 31,
------------------------------
2006 2005 2004
-------- -------- --------
Costs incurred during the year:(1)
Property acquisition costs
Unproved $ 35,728 $ 7,097 $ 16,687
Proved 8,239 -- --
Exploration 95,486 110,669 93,682
Development 23,405 16,136 36,531
-------- -------- --------
$162,858 $133,902 $146,900
======== ======== ========
(1) Costs incurred during the years ended December 31, 2006, 2005 and 2004
include general and administrative costs related to acquisition,
exploration and development of oil and natural gas properties, net of third
party reimbursements, of $15,375,000, $13,814,000, and $11,924,000,
respectively.
CAPITALIZED COSTS RELATING TO OIL AND NATURAL GAS PRODUCING ACTIVITIES
(thousands of dollars)
DECEMBER 31,
-----------------------
2006 2005
---------- ----------
Capitalized costs $1,663,865 $1,512,036
Accumulated depletion 1,267,504 1,027,430
---------- ----------
Net capitalized costs $ 396,361 $ 484,606
========== ==========
At December 31, 2006 and 2005, unevaluated costs of $54,356,000 and $26,623,000,
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.
-70-
RESULTS OF OPERATIONS FROM OIL AND NATURAL GAS PRODUCING ACTIVITIES
(thousands of dollars)
YEAR ENDED DECEMBER 31,
------------------------------
2006 2005 2004
-------- -------- --------
Operating Revenues:
Oil $ 47,859 $ 34,647 $ 36,060
Natural Gas 141,182 160,608 166,387
-------- -------- --------
189,041 195,255 202,447
-------- -------- --------
Less:
Oil and natural gas operating costs 22,614 15,860 14,035
Severance and ad valorem taxes 11,259 8,811 9,394
Depletion 105,210 96,396 101,944
Accretion expense 1,588 1,120 601
Impairment of long-lived assets 134,865 -- --
Hurricane damage repairs 4,314 3,066 --
Income tax expense (benefit) (31,783) 24,501 26,766
-------- -------- --------
248,067 149,754 152,740
-------- -------- --------
Results of operations from oil and
natural gas producing activities $(59,026) $ 45,501 $ 49,707
======== ======== ========
Depletion expense per Mcfe $ 4.51 $ 3.74 $ 2.88
======== ======== ========
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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, 2006, 2005 and 2004, and the changes therein during the years then
ended. The reserve information was reviewed by T. J. Smith & Company, Inc.,
independent reservoir engineers, for 2006, 2005 and 2004. 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, 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
Production during 2006 (859) (18,170)
Purchase of reserves in-place 24 1,390
Discoveries and extensions 270 7,138
Revisions of previous quantity estimates and other 124 (3,460)
------ -------
Balance at December 31, 2006 4,736 66,815
====== =======
Proved Developed Reserves:
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
Balance at December 31, 2006 3,151 49,253
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.
-72-
The following table sets forth the components of the standardized measure of
discounted future net cash flows for the years ended December 31, 2006, 2005 and
2004 (thousands of dollars):
AT DECEMBER 31,
----------------------------------
2006 2005 2004
--------- ---------- ---------
Future cash flows $ 657,584 $1,122,282 $ 897,839
Future production costs (150,462) (163,804) (139,112)
Future development costs (64,417) (55,212) (39,352)
--------- ---------- ---------
Future net cash flows before income taxes 442,705 903,266 719,375
Future taxes on income (46,034) (201,582) (135,472)
--------- ---------- ---------
Future net cash flows 396,671 701,684 583,903
Discount to present value at 10 percent per annum (68,772) (144,481) (113,546)
--------- ---------- ---------
Standardized measure of discounted future net cash flows $ 327,899 $ 557,203 $ 470,357
========= ========== =========
The average expected realized price for natural gas in the above computations
was $5.69, $10.40 and $6.40 per Mcf at December 31, 2006, 2005, and 2004,
respectively. The average expected realized price used for crude oil in the
above computations was $63.32, $59.37 and $42.33 per Bbl at December 31, 2006,
2005, and 2004, 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, 2006, 2005 and 2004
(thousands of dollars):
YEAR ENDED DECEMBER 31,
---------------------------------
2006 2005 2004
--------- ---------- ---------
Balance at Beginning of Period $ 557,203 $ 470,357 $ 455,883
Sales of oil and natural gas, net of production costs (155,167) (170,584) (179,018)
Changes in sales & transfer prices, net of production costs (243,150) 293,294 32,203
Revisions of previous quantity estimates (11,022) (130,813) 22,468
Purchase of reserves-in-place 2,393 -- --
Current year discoveries, extensions
and improved recovery 30,710 107,393 117,178
Changes in estimated future
development costs (13,016) (16,764) (11,331)
Development costs incurred during the period 18,051 10,654 9,851
Accretion of discount 55,720 47,036 45,588
Net change in income taxes 114,782 (49,453) (23,278)
Change in production rates (timing) and other (28,605) (3,917) 813
--------- --------- ---------
Net change (229,304) 86,846 14,474
--------- --------- ---------
Balance at End of Period $ 327,899 $ 557,203 $ 470,357
========= ========= =========
-73-
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-15(e) under the
Securities Exchange Act of 1934) as of the end of the fourth quarter of 2006.
Based upon that evaluation, our Chief Executive Officer and Chief Accounting
Officer concluded that the design and operation of our disclosure controls and
procedures are effective. There have been no significant changes in our internal
controls or in other factors during the fourth quarter of 2006 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, 2006. 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, 2006, 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, 2006, based on criteria
established in Internal Control - Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission (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.
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
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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, 2006, 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, 2006, 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, 2006 and 2005, and the related consolidated
statements of operations, stockholders' equity, cash flows and comprehensive
income (loss) for each of the three years in the period ended December 31, 2006,
and our report dated March 13, 2007, expressed an unqualified opinion thereon.
BDO Seidman, LLP
Houston, Texas
March 13, 2007
ITEM 9B. OTHER INFORMATION.
None.
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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 April 30, 2007.
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 Firm's Report
(ii) Consolidated Statements of Operations for each of the three years
in the period ended December 31, 2006
(iii) Consolidated Balance Sheets as of December 31, 2006 and 2005
(iv) Consolidated Statements of Cash Flows for each of the three years
in the period ended December 31, 2006
(v) Consolidated Statements of Changes in Stockholders' Equity for
each of the three years in the period ended December 31, 2006
(vi) Consolidated Statements of Comprehensive Income (Loss) for each
of the three years in the period ended December 31, 2006
(vii) Notes to Consolidated Financial Statements
(viii) Supplemental Oil and Natural 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 Amendment No. 1 to Amended and Restated Bylaws (incorporated by
reference to Exhibit 3.1 of the Company's Report on Form 8-K
dated May 5, 1999).
3.4 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)).
-76-
*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. 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 The Meridian Resource Corporation 2006 Non-Employee Directors'
Incentive Plan (incorporated by reference to Exhibit A of the
Company's Proxy Statement on Schedule 14A filed May 19, 2006).
4.10 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 4.10 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).
-77-
*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).
*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
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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.
**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.
-79-
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, 2007
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, 2007
--------------------------------- (Principal Executive Officer)
Joseph A. Reeves, Jr. Director and Chairman
of the Board
BY: /s/ MICHAEL J. MAYELL President and Director March 15, 2007
---------------------------------
Michael J. Mayell
BY: /s/ LLOYD V. DELANO Chief Accounting Officer March 15, 2007
---------------------------------
Lloyd V. DeLano
BY: /s/ E. L. HENRY Director March 15, 2007
---------------------------------
E. L. Henry
BY: /s/ JOE E. KARES Director March 15, 2007
---------------------------------
Joe E. Kares
BY: /s/ GARY A. MESSERSMITH Director March 15, 2007
---------------------------------
Gary A. Messersmith
BY: /s/ DAVID W. TAUBER Director March 15, 2007
---------------------------------
David W. Tauber
BY: /s/ JOHN B. SIMMONS Director March 15, 2007
---------------------------------
John B. Simmons
BY: /s/ FENNER R. WELLER, JR. Director March 15, 2007
---------------------------------
Fenner R. Weller, Jr.
BY: /s/ C. MARK PEARSON Director March 15, 2007
---------------------------------
C. Mark Pearson
-80-
EXHIBIT INDEX
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 Amendment No. 1 to Amended and Restated Bylaws (incorporated by
reference to Exhibit 3.1 of the Company's Report on Form 8-K dated
May 5, 1999).
3.4 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. 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 The Meridian Resource Corporation 2006 Non-Employee Directors'
Incentive Plan (incorporated by reference to Exhibit A of the
Company's Proxy Statement on Schedule 14A filed May 19, 2006).
4.10 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 4.10 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).
*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.
**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.