e10vk
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2007
OR
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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)
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TEXAS
(State of incorporation)
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76-0319553
(I.R.S. Employer Identification No.) |
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1401 Enclave Parkway, Suite 300, Houston, Texas
(Address of principal executive offices)
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77077
(Zip Code) |
Registrants telephone number, including area code: 281-597-7000
Securities registered pursuant to Section 12(b) of the Act:
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(Title of each class) |
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(Name of each exchange on which registered) |
Common Stock, $0.01 par value
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New York Stock Exchange |
Rights to Purchase Preferred Shares
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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 o No þ
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 o No þ
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. Yesþ No o
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 registrants 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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in
Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer o
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Accelerated filer þ
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o
No þ
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Aggregate market value of shares of common stock held by non-affiliates
of the Registrant at June 30, 2007 |
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$ |
266,718,455 |
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Number of shares of common stock outstanding at March 3, 2008: |
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89,363,795 |
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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 registrants Proxy Statement to be filed on or before April 29, 2008.
THE MERIDIAN RESOURCE CORPORATION
INDEX TO FORM 10-K
-2-
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 the
latest in completion and 3-D seismic technology. Our operations have historically focused on the
onshore oil and natural gas regions in south Louisiana, Texas and offshore in the Gulf of Mexico.
Beginning in 2005, the Company diversified its exploration and development portfolio to include
unconventional styled reserve properties, first with the addition of its east Texas Austin Chalk
play, and continuing in areas such as north-central Oklahoma and Kentucky exploration and
development opportunities. Successful wells in these areas generally exhibit lower initial
production rates than the Companys traditional styled exploration and development, yet increase
the overall reserve life of the Company. As of December 31, 2007, we had proved reserves of 90 Bcfe
with a present value of future net cash flows before income taxes of approximately $415 million
($391 million after tax). Sixty-eight percent (68%) of our proved reserves were natural gas and
approximately sixty-six percent (66%) were classified as proved developed. We own interests in 26
fields and 121 producing wells, and operate approximately 81% 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 processing and interpretive
technology and have participated in the discovery of more than 900 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, cash flows, strategic acreage positions and large database of 2-D and 3-D seismic data
provide us with a significant presence in our core Gulf Coast area and beyond, enabling us to
exploit multiple exploratory and development prospects in multiple basins. The Companys goal is
to balance the distribution of 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:
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Generate reserve additions through exploration, exploitation, development and acquisition
of a risk balanced portfolio of high potential projects; |
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Supplement and balance our historical 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; |
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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; |
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Maximize percentage ownership in each drilling prospect relative to the probability of
success, increasing the impact of discoveries on shareholder value; and |
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Maintain operational control to manage quality, costs and timing of our drilling and
production activities. |
As of December 31, 2007, we had interests in leases and options to lease acreage in approximately
363,000 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 8,600
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.
-3-
Meridian was incorporated in Texas in 1990, with headquarters located at 1401 Enclave Parkway,
Suite 300, Houston, Texas 77077. The Companys common stock is traded on the New York Stock
Exchange under the ticker symbol TMR. You can locate additional information, including the
Companys 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 processing and 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 Companys 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 development of a balanced exploration inventory,
geologically and geographically, including deeper higher-risk, 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. To maintain our competitive advantage
and protect our exploration opportunities, we will typically operate our plays, acquire large
acreage positions, and focus on reducing our costs of operations. We believe that our 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, as well as with respect to
analysis, evaluation and completions.
-4-
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, 2007. The reserve volumes were reviewed by
T. J. Smith & Company, Inc., independent reservoir engineers.
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Gulf of |
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Louisiana |
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Texas |
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Mexico |
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Total |
Production for the year ended December 31, 2007 |
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Oil (MBbls) |
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645 |
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124 |
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69 |
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838 |
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Natural Gas (MMcf) |
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11,468 |
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1,095 |
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676 |
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13,239 |
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Reserves as of December 31, 2007 |
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Oil (MBbls) |
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3,198 |
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724 |
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934 |
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4,856 |
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Natural Gas (MMcf) |
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48,221 |
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6,922 |
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6,186 |
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61,329 |
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Estimated future net cash flows
($000)(1) |
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$ |
576,562 |
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Present value of future net cash flows
before income taxes ($000)(2) |
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$ |
414,918 |
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Standardized measure of discounted
future net cash flows ($000)(3) |
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$ |
391,464 |
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(1) |
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Estimated Future Net Cash Flows represent the net undiscounted future revenues to be
generated from the production of proved reserves, net of estimated production and future
development costs, using expected realized prices at December 31, 2007, which averaged
$95.54 per Bbl of oil and $6.66 per Mcf of natural gas over the estimated life of the
properties and do not reflect the impact of hedges. |
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(2) |
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The Present Value of Future Net Cash Flows Before Taxes represents Estimated Future Net
Cash Flows discounted to present value using an annual discount rate of 10%. |
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(3) |
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The Standardized Measure of Discounted Future Net Cash Flows represents the Present
Value of Future Net Cash Flows after income taxes of $23.4 million. |
Productive Wells
At December 31, 2007, 2006 and 2005, we held interests in the following productive wells. As of
December 31, 2007, we own interests in 26 gross (4.5 net) wells in the Gulf of Mexico which are
outside operated and net to 2.1 oil wells and 2.4 natural gas wells. In addition, of the total
well count for 2007, 7 wells (2.9 net) are multiple completions.
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2007 |
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2006 |
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2005 |
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Gross |
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Net |
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Gross |
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Net |
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Gross |
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Net |
Oil Wells |
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33 |
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19 |
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44 |
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28 |
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35 |
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24 |
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Natural Gas Wells |
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88 |
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43 |
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77 |
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43 |
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69 |
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39 |
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Total |
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121 |
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62 |
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121 |
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71 |
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104 |
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63 |
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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, 2007. 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.
-5-
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Proved Reserves at December 31, 2007 |
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Developed |
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Developed |
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Producing |
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Non-Producing |
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Undeveloped |
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Total |
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(dollars in thousands) |
Net Proved Reserves: |
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Oil (MBbls) |
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1,502 |
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1,390 |
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1,964 |
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4,856 |
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Natural Gas (MMcf) |
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24,182 |
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18,373 |
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18,774 |
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61,329 |
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Natural Gas Equivalent (MMcfe) |
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33,194 |
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26,711 |
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30,559 |
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|
90,464 |
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Estimated Future Net Cash
Flows(1) |
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$ |
576,562 |
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Present Value of Future Net
Cash Flows (before income
taxes)(2) |
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|
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$ |
414,918 |
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Standardized Measure of
Discounted Future Net Cash
Flows(3) |
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$ |
391,464 |
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(1) |
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Estimated Future Net Cash Flows represent the net undiscounted future revenues to be
generated from the production of proved reserves, net of estimated production and future
development costs, using expected realized prices at December 31, 2007, which averaged
$95.54 per Bbl of oil and $6.66 per Mcf of natural gas over the estimated life of the
properties and do not reflect the impact of hedges. |
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(2) |
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The Present Value of Future Net Cash Flows Before Taxes represents Estimated Future Net
Cash Flows discounted to present value using an annual discount rate of 10%. |
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(3) |
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The Standardized Measure of Discounted Future Net Cash Flows represents the Present
Value of Future Net Cash Flows after income taxes of $23.4 million. |
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 2007, 2006 and 2005.
-6-
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Gross Wells |
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Net Wells |
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Productive |
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Dry |
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Total |
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Productive |
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Dry |
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Total |
Exploratory Wells |
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Year ended December 31, 2007 |
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13 |
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12 |
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25 |
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4.2 |
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6.6 |
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10.8 |
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Year ended December 31, 2006 |
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7 |
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7 |
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14 |
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4.1 |
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5.4 |
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9.5 |
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Year ended December 31, 2005 |
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10 |
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13 |
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23 |
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8.0 |
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10.8 |
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18.8 |
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Development Wells |
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Year ended December 31, 2007 |
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Year ended December 31, 2006 |
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1 |
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1 |
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0.7 |
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0.7 |
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Year ended December 31, 2005 |
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1 |
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1 |
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0.3 |
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0.3 |
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Meridian had 9 gross (5.9 net) wells in progress at December 31, 2007.
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 2007, 2006 and 2005.
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Year Ended December 31, |
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2007 |
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2006 |
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2005 |
Production: |
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Oil (MBbls) |
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838 |
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859 |
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882 |
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Natural gas (MMcf) |
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13,239 |
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18,170 |
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|
20,490 |
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Natural gas equivalent (MMcfe) |
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18,269 |
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23,323 |
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25,781 |
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Average Prices: |
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Oil ($/Bbl) |
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$ |
64.70 |
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$ |
55.73 |
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$ |
39.29 |
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Natural gas ($/Mcf) |
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$ |
7.29 |
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$ |
7.77 |
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$ |
7.84 |
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Natural gas equivalent ($/Mcfe) |
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$ |
8.25 |
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$ |
8.11 |
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$ |
7.57 |
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Production Expenses: |
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Lease operating expenses ($/Mcfe) |
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$ |
1.55 |
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$ |
0.97 |
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$ |
0.61 |
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Severance and ad valorem
taxes ($/Mcfe) |
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$ |
0.52 |
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$ |
0.48 |
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$ |
0.34 |
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-7-
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, 2007. 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.
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December 31, 2007 |
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Developed |
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Undeveloped |
Region |
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Gross |
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Net |
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Gross |
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Net |
Louisiana |
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29,826 |
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20,950 |
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11,576 |
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9,059 |
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Oklahoma |
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2,958 |
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1,397 |
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32,473 |
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25,206 |
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Kentucky |
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46,676 |
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35,280 |
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Texas |
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7,044 |
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4,278 |
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183,382 |
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93,510 |
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Gulf of Mexico |
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33,759 |
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5,988 |
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14,908 |
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10,673 |
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Total |
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73,587 |
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32,613 |
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289,015 |
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173,728 |
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In addition to the above acreage, we currently have options or farm-ins to acquire leases on
approximately 4,702 gross (3,634 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 18,800 acres in 2008, 46,000 acres in 2009, and 34,600 acres in 2010.
Geologic/Land and Operations Geophysical Expertise
Meridian employs approximately 91 full-time non-union employees and 13 contract employees. This
staff includes geologists, geophysicists, land and engineering staff with over 620 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.
-8-
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 2007, 2006 and 2005.
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Year Ended December 31, |
Customer |
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2007 |
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2006 |
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2005 |
Superior Natural Gas |
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23 |
% |
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35 |
% |
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46 |
% |
Crosstex/Louisiana Intrastate Gas |
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16 |
% |
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21 |
% |
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19 |
% |
Shell Trading (U.S.) |
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14 |
% |
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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 approximately $110.00 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, 2007, was $8.25 per Mcfe compared to $8.11 per
Mcfe (each net of commodity hedge gains/losses) during the year ended December 31, 2006. 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
-9-
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. It
is not possible to predict what, if any, effect the FERCs future policies will have on us.
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.
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
-10-
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 are in material compliance 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 waters of the United States. A responsible party includes
the owner or operator of a facility or vessel, or the lessee or permittee of the area where an
offshore facility is located. The OPA makes each responsible party liable for oil-removal costs
and a variety of public and private damages. While liability limits apply in some circumstances, a
party cannot take advantage of liability limits if the party caused the spill by gross negligence
or willful misconduct or if the spill resulted from a violation of a federal safety, construction
or operating regulation. The liability limits likewise do not apply if the party fails to report a
spill or to cooperate fully in the cleanup. Few defenses exist to the liability imposed by the
OPA.
The OPA also imposes ongoing requirements on a responsible party, including the requirement to
maintain proof of financial responsibility to be able to cover at least some costs if a spill
occurs. In this regard, the OPA requires the lessee or permittee of an offshore area in which a
covered offshore facility is located to establish and maintain evidence of financial responsibility
in the amount of $35 million ($10 million if the offshore facility is located landward of the
seaward boundary of a state) to cover liabilities related to a crude oil spill for which such
person is statutorily responsible. The amount of required financial responsibility may be increased
above the minimum amounts to an amount not exceeding $150 million depending on the risk represented
by the quantity or quality of crude oil that is handled by the facility. The MMS has promulgated
regulations that implement the financial responsibility requirements of the OPA. Under the MMS
regulations, the amount of financial responsibility required for an offshore facility is increased
above the minimum amount if the worst case oil spill volume calculated for the facility exceeds
certain limits established in the regulations.
The OPA also imposes other requirements, such as the preparation of an oil-spill contingency plan.
We have such a plan in place. Failure to comply with ongoing requirements or inadequate
cooperation during a spill may subject a responsible party to civil or criminal enforcement
actions. We are not aware of any action or event that would subject us to liability under the OPA
and we believe that compliance with the OPAs 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. Except
as described in Item 3. Legal Proceedings, we are not aware of any hazardous substance
contamination for which we may be liable.
-11-
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 of 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. Except as described in Item 3. Legal Proceedings, 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
RCRAs requirements because our operations generate minimal quantities of hazardous wastes. At
various times in the past, proposals have been made to amend RCRA to rescind the exemption that
excludes crude oil and natural gas exploration and production wastes from regulation as hazardous
waste. Repeal or modification of the exemption by administrative, legislative or judicial process,
or modification of similar exemptions in applicable state statutes, would increase the volume of
hazardous waste we are required to manage and dispose of and could cause us to incur increased
operating expenses.
Title to Properties
As is customary in the oil and natural gas industry, we make only a cursory review of title to
undeveloped oil and natural gas leases at the time we acquire them. However, before drilling
commences, we search the title, and remedy any material defects before we actually begin drilling
the well. To the extent title opinions or other investigations reflect title defects, we (rather
than the seller or lessor of the undeveloped property) typically are obligated to cure any such
title defects at our expense. If we are unable to remedy or cure any title defects so that it
would not be prudent for us to commence drilling operations on the property, we could suffer a loss
of our entire investment in the property. We believe that we have good title to our oil and
natural gas properties, some of which are subject to immaterial encumbrances, easements and
restrictions. Under the terms of our credit facility, we may not grant liens on various properties
and must grant to our lenders a mortgage on our oil 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
-12-
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, 2007, we had long-term indebtedness of $75.0 million compared to approximately
$325.4
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, 2007, we had outstanding indebtedness of $75.0 million under our revolving
credit facility, which was $40 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 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.
-13-
Any significant decline in oil and natural gas prices or any other unfavorable market conditions
could have a material adverse effect on our financial condition and on the carrying value of our
proved reserves. Consequently, we may not be able to generate sufficient cash flows from
operations to meet our obligations and to make planned capital expenditures. Price declines may
also affect the measure of discounted future net cash flows of our reserves, a result that could
adversely impact the borrowing base under our credit facility and may increase the likelihood that
we will incur additional impairment charges on our oil and natural gas
properties for financial accounting purposes.
Our hedging transactions may not adequately prevent losses.
We cannot predict future oil and natural gas prices with certainty. To manage our exposure to the
risks inherent in such a volatile market, from time to time, we have entered into commodities
futures, swap or option contracts to hedge a portion of our oil and natural gas production against
market price changes. Hedging transactions are intended to limit the negative effect of future
price declines, but may also prevent us from realizing the benefits of price increases above the
levels reflected in the hedges.
Our reserve estimates may prove to be inaccurate and future net cash flows are uncertain.
Reserve engineering is a subjective process of estimating the recovery from underground
accumulations of oil and natural gas we cannot measure in an exact manner, and the accuracy of any
reserve estimate is a function of the quality of available data and of engineering and geological
interpretation and judgment. Reserve estimates may be imprecise and may be expected to change as
additional information becomes available. There are numerous uncertainties inherent in estimating
quantities and values of proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond our control. The quantities of oil and
natural gas that we ultimately recover, production and operating costs, the amount and timing of
future development expenditures and future oil and natural gas sales prices may differ from those
assumed in these estimates. Significant downward revisions to our existing reserve estimates could
cause the actual results to differ from those reflected in our assumptions and estimates.
We depend on key personnel to execute our business plans.
The loss of any key executives or any other key personnel could have a material adverse effect on
our operations. We depend on the efforts and skills of our key executives, including Joseph A.
Reeves, Jr., Chairman of the Board and Chief Executive Officer, and Michael J. Mayell, President
and Chief Operating Officer. Moreover, as we continue to grow our asset base and the scope of our
operations, our future profitability will depend on our ability to attract and retain qualified
personnel.
We compete against significant players in the oil and natural gas industry, and our failure in the
long-term to complete future acquisitions successfully and generate commercial exploration and
development drilling opportunities could reduce our earnings and cause revenues to decline.
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
-14-
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:
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from a well or drilling equipment at a drill site, |
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from a leak in storage tanks, pipelines or other gathering and transportation facilities, |
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from damage to oil or natural gas wells resulting from accidents during normal
operations or natural disasters, or |
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from blowouts, cratering or explosions. |
Environmental discharges may move through the soil to water supplies or adjoining properties,
giving rise to additional liabilities. Some laws and regulations could impose liability for
failure to obtain the proper permits for, to control the use of, or to notify the proper
authorities of a hazardous discharge. Such liability could have a material adverse effect on our
financial condition and our results of operations and could possibly cause our operations to be
suspended or terminated on such property.
We may also be liable for any environmental hazards created either by the previous owners of
properties that we purchase or lease or by acquired companies prior to the date we acquire them.
Such liability would affect the costs of our acquisition of those properties. In connection with
any of these environmental violations, we may also be charged with remedial costs. Pollution and
similar environmental risks generally are not fully insurable.
Although we do not believe that our environmental risks are materially different from those of
comparable companies in the oil and natural gas industry, we cannot assure you that environmental
laws will not result in 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:
-15-
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cash provided by operating activities; |
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available cash and cash investments; |
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capital raised through debt and equity offerings; and |
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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.
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.
-16-
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. In 2007, 19% of our production and 21% of our reserves were
outside operated. The operators of those properties may:
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refuse to initiate exploration or development projects (in which case we may
propose desired exploration or development activities); |
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initiate exploration or development projects on a slower schedule than we
prefer; or |
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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 may 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. Some working interest owners 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
owners share of the project costs.
Our exploratory drilling projects are based in part on seismic data, which is costly and cannot
ensure the commercial success of the project.
Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on
data obtained through geophysical and geological analyses, production data and engineering studies,
the results of which are often uncertain. Even when used and properly interpreted, 3-D seismic data
and visualization techniques only assist geoscientists and geologists in identifying subsurface
structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if
hydrocarbons are present or producible economically. In addition, the use of 3-D seismic and other
advanced technologies require greater predrilling expenditures than traditional drilling
strategies, resulting in higher finding costs. Because of these factors, we could incur losses as a
result of exploratory drilling expenditures. Poor results from exploration activities could have a
material adverse effect on our future cash flows, ability to replace reserves and results of
operations.
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
-17-
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 Managements 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 Meridians properties, see Item 1. Business above.
Item 3. Legal Proceedings
H. L. Hawkins litigation. In December 2004, the estate of H.L. Hawkins filed a claim against
Meridian for
-18-
damages estimated to exceed several million dollars for Meridians 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 Meridians satisfying a prior adverse judgment in favor of Amoco
Production Company. Mr. James Bond had 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. Mr.
James T. Bond was employed by H.L. Hawkins Jr. and his companies as General Manager until 2002. He
served on the Board of Directors of the Company from March 1997 to August 2004. After Mr. Bonds
employment with Mr. Hawkins, Jr., and his companies ended, Mr. Bond was engaged by The Meridian
Resource & Exploration LLC as a consultant. This relationship continued until his death. Mr. Bond
was also the father-in-law of Michael J. Mayell, the President of the Company. Management continues
to vigorously defend this action on the basis that Mr. Hawkins individually and through his agent,
Mr. Bond, agreed to the course of action adopted by Meridian and further that Meridians actions were not
grossly negligent, but were within the business judgment rule. Since Mr. Bonds death, a pleading
has recently been filed substituting the proper party for Mr. Bond. The Company is unable to
express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to
estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, the
Company has not provided any amount for this matter in its financial statements at December 31,
2007.
Title/lease disputes. Title and lease disputes may arise in the normal course of the Companys
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 Companys oil and natural gas
operations. In some of the lawsuits, Shell Oil Company and SWEPI LP have demanded contractual
indemnity and defense from Meridian based upon the terms of the purchase and sale agreement related
to the fields, and in another lawsuit, Exxon Mobil Corporation has demanded contractual indemnity
and defense from Meridian on the basis of a purchase and sale agreement related to the field(s)
referenced in the lawsuit; Meridian has challenged such demands. In some cases, Meridian has also
demanded defense and indemnity from their subsequent purchasers of the fields. The Company is
unable to express an opinion with respect to the likelihood of an unfavorable outcome of these
matters or to estimate the amount or range of potential loss should any outcome be unfavorable.
Therefore, the Company has not provided any amount for these matters in its financial statements at
December 31, 2007.
Consent Decree. During the fourth quarter of 2007 the Company entered into a Consent Decree with
the United States Environmental Protection Agency (EPA) in settlement of alleged violations of
the Clean Water Act, as amended by the Oil Pollution Act of 1990. Under the Consent Decree, the
Company paid $504,000 in civil penalties for alleged discharges of crude oil into navigable waters
or adjoining shorelines from the Companys operations at the Weeks Island field in Iberia Parish,
Louisiana. The Company will also be subject to certain injunctive relief, requiring the Company to
enhance certain pipeline survey, monitoring and reporting activities. Under the Consent Decree,
the Company does not admit any liability arising out of the occurrences described in the Consent
Decree or the related Complaint. The Company recorded an expense for the above amount in oil and
natural gas operating expenses.
Litigation involving insurable issues. There are no material legal proceedings involving insurable
issues which exceed insurance limits to which Meridian or any of its subsidiaries is a party or to
which any of its property is subject, other than ordinary and routine litigation incidental to the
business of producing and exploring for crude oil and natural gas.
-19-
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of Meridians security holders during the fourth quarter of
2007.
-20-
PART II
Item 5. Market for Registrants 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 |
2007: |
|
|
|
|
|
|
|
|
First quarter |
|
$ |
3.01 |
|
|
$ |
2.28 |
|
Second quarter |
|
|
3.38 |
|
|
|
2.31 |
|
Third quarter |
|
|
3.08 |
|
|
|
2.24 |
|
Fourth quarter |
|
|
2.58 |
|
|
|
1.63 |
|
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 |
|
The closing sale price of the common stock on March 3, 2008, as reported on the New York Stock
Exchange Composite Tape, was $1.57. As of March 1, 2008, we had approximately 768 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. Managements
Discussion and Analysis of Financial Condition and Results Operations Liquidity and Capital
Resources.
Repurchase of Common Stock
Following is a summary of our repurchase activity for the three-month period ending December 31,
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
|
|
Approximate Dollar Value |
|
|
Number of |
|
Average Price |
|
Total Number of Shares |
|
of Shares That May Be |
|
|
Shares |
|
Paid Per |
|
Purchased as Part of a |
|
Purchased Under the |
Period |
|
Purchased |
|
Share |
|
Publicly Announced Plan (a) |
|
Plan During 2008 |
|
October 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
November 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 2007 |
|
|
142,000 |
|
|
$ |
1.76 |
|
|
|
142,000 |
|
|
$ |
5,000,000 |
|
|
Total |
|
|
142,000 |
|
|
$ |
1.76 |
|
|
|
142,000 |
|
|
$ |
5,000,000 |
|
|
|
|
|
|
(a) |
|
In March 2007, our Board of Directors authorized the repurchase in the open market or through
privately negotiated transactions of up to $5 million worth of common shares per year over
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. As of
December 31, 2007, the Company had repurchased 501,300 common shares in the open market at an
aggregate cost of $1,158,000 of which 342,617 shares have been issued for 401(k) contributions, for
contract services and for compensation. Such shares are reflected in the accompanying Consolidated
Balance Sheet as treasury stock. See Note 10 of the Notes to Consolidated Financial Statements.
It is our intent to continue this program through this and future
years subject to certain limitations within our Credit Facility. |
-21-
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth information as of December 31, 2007, 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 |
|
|
6,636,204 |
|
|
$ |
3.11 |
|
|
|
3,850,000 |
|
|
Equity compensation
plans not approved
by security holders |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
6,636,204 |
|
|
$ |
3.11 |
|
|
|
3,850,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Does not include 4,650,000 shares which have been reserved for issuance in lieu of cash
compensation under the Companys deferred compensation plan, which plan was approved by security
holders. |
-22-
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, |
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
|
|
|
|
(In thousands, except prices and per share information) |
|
|
|
|
A. Summary of Operating Data |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
838 |
|
|
|
859 |
|
|
|
882 |
|
|
|
1,270 |
|
|
|
1,403 |
|
Natural gas (MMcf) |
|
|
13,239 |
|
|
|
18,170 |
|
|
|
20,490 |
|
|
|
27,839 |
|
|
|
20,142 |
|
Natural gas equivalent (MMcfe) |
|
|
18,269 |
|
|
|
23,323 |
|
|
|
25,781 |
|
|
|
35,457 |
|
|
|
28,563 |
|
Average prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl) |
|
$ |
64.70 |
|
|
$ |
55.73 |
|
|
$ |
39.29 |
|
|
$ |
28.40 |
|
|
$ |
24.97 |
|
Natural gas ($/Mcf) |
|
|
7.29 |
|
|
|
7.77 |
|
|
|
7.84 |
|
|
|
5.98 |
|
|
|
5.07 |
|
Natural gas equivalent ($/Mcfe) |
|
|
8.25 |
|
|
|
8.11 |
|
|
|
7.57 |
|
|
|
5.71 |
|
|
|
4.80 |
|
B. Summary of Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
152,178 |
|
|
$ |
190,957 |
|
|
$ |
195,696 |
|
|
$ |
203,118 |
|
|
$ |
137,479 |
|
Depletion and depreciation |
|
|
77,076 |
|
|
|
106,067 |
|
|
|
97,354 |
|
|
|
102,915 |
|
|
|
75,441 |
|
Net earnings (loss)(1) |
|
|
7,137 |
|
|
|
(73,884 |
) |
|
|
27,849 |
|
|
|
29,248 |
|
|
|
7,246 |
|
Net earnings (loss) per share:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.08 |
|
|
$ |
(0.84 |
) |
|
$ |
0.33 |
|
|
$ |
0.41 |
|
|
$ |
0.14 |
|
Diluted |
|
|
0.08 |
|
|
|
(0.84 |
) |
|
|
0.31 |
|
|
|
0.37 |
|
|
|
0.13 |
|
Dividends per: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common share |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Redeemable preferred share |
|
|
|
|
|
|
|
|
|
|
2.60 |
|
|
|
8.50 |
|
|
|
8.50 |
|
Preferred share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common
shares outstanding basic |
|
|
89,307 |
|
|
|
87,670 |
|
|
|
84,527 |
|
|
|
72,084 |
|
|
|
53,325 |
|
C. Summary Balance Sheet Data |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
483,775 |
|
|
$ |
467,895 |
|
|
$ |
555,802 |
|
|
$ |
513,274 |
|
|
$ |
448,400 |
|
Long-term obligations, inclusive
of current maturities |
|
|
75,000 |
|
|
|
75,000 |
|
|
|
75,000 |
|
|
|
75,129 |
|
|
|
152,320 |
|
Redeemable preferred stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31,589 |
|
|
|
60,446 |
|
Stockholders equity |
|
|
325,430 |
|
|
|
320,797 |
|
|
|
377,565 |
|
|
|
316,041 |
|
|
|
184,335 |
|
|
|
|
(1) |
|
Applicable to common stockholders. |
-23-
Item 7. Managements 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. Beginning in 2005, the Company continued to diversify its oil and
natural gas exploration and development portfolio to include unconventional-styled reserve
properties with the addition of its east Texas Austin Chalk play, and continuing in areas such as
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 industrys 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 playsThornwell and Biloxi Marshlandswhere 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.
Meridians management believes that south Louisiana still contains both tremendous attributeshigh
producing rates, high cash flows and returns, plus lower lifting costs once provedand remaining
opportunities for a company, such as Meridian, that possesses a unique position in the regiona
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 Companys high current cash position stemming from its higher-producing rate
Gulf Coast properties, in early 2005, Meridians 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 Companys reserve
base and reserve life in the unconventional resource plays.
-24-
Operations Overview
Our four primary regions where the capital budget will be spent, and where we are currently active
are: (1) East Texas, (2) South Louisiana, (3) North Louisiana, and (4) South Texas.
East Texas Austin Chalk
Meridian is on track with its plans to develop this growing core area. The Company originally
acquired an interest in this play as a 50% working interest owner in approximately 7,600 acres
during mid-year 2005. The original plan was to develop the Woodbine sand section offsetting the
prolific Double A Wells field. Additional objectives were the Austin Chalk and Buda formations.
Meridian was granted operatorship of the play and has since developed a current gross acreage
position of approximately 83,000 contiguous acres in this play area. This will provide enough
acreage for a drilling inventory of up to 80 possible dual lateral well locations. Since initial
drilling starting in 2006, the Company has drilled or participated in the drilling of eight Austin
Chalk wells (six are producing, one is drilling, one is currently completing and about to be
tested). The aggregate gross proved reserves discovered as a result of the completed wells,
including PUD locations, equal over 50 Bcfe (12 Bcfe net to Meridian). Average wells in the area
reportedly recover approximately 3.8 Bcfe, with the best wells recovering as much as 15 Bcfe. This
plays contribution to the Companys net proven reserve base has grown from 0% to approximately 11%
over the course of the past 18 months and is projected to be one of the top four cash flow
producing fields in the Company. Scheduled wells for 2008 are in the thicker, shallower chalk
areas that are expected to produce higher oil ratios than the Companys initial wells that were
primarily focused on the original Woodbine test locations.
As stated above, two wells are currently being drilled and completed in this area. The BSM No. 5
well (65% WI), has drilled two horizontal laterals with approximate lengths of 5,000 and 5,500 feet
measured depth (MD), respectively. Currently a liner is being run in the second lateral and is
expected to be completed and tested in the coming weeks. The Freeman No. 1 well (84% WI) has
completed its first lateral at approximately 5,000 feet MD. The second lateral is currently at a
length of approximately 1,400 feet MD, going to a targeted 6,000 feet MD in length. The vertical
depth of the Austin Chalk formation in this area is approximately 13,500 feet. Additionally,
Meridian participated in the outside operated BSM A-917 No. 1H, which was a single lateral well
that reached a total depth of 18,800 MD. The well was recently tested at 2.8 Mmcf/d with 700
barrels of oil per day. Meridian holds approximately 9% working interest in this well.
The key to this project is management of the cost of drilling and completing dual laterals within
estimated cost levels and leveraging the large acreage position to increase production and reserves
with continual drilling. We have achieved these goals in a relatively short cycle and, in doing so,
believe that with the addition of our recently acquired and constructed new drilling rig, we will
be able to maintain a continuous drilling program within this region.
Levering off the knowledge and experience of the Company in this play, the Company has expanded
beyond its currently established boundaries to explore and test acreage located in two separate
south-central Texas areas. Meridian is building leasehold positions and has budgeted four test
wells in these areas for calendar year 2008. It is anticipated that in these areas, the production
will have a higher liquid (oil) content than its current production in the initial wells in east
Texas. The expanded play areas are unproven and in the early stage, therefore, as they are tested,
the Company will release additional details on these opportunities as they develop.
South Louisiana
South Louisiana remains a core area for near term and long term upside for Meridian. Weeks Island
field continues to be the Companys largest oil field and render additional opportunities from new
well locations, sidetracks and development drilling. The Company is currently reprocessing its 3-D
seismic data over Weeks Island and regions in its south Louisiana play area, the expectations being
that the re-processed and newly acquired 3-D data will enhance the Companys generation of lower to
moderate risk new projects in this core
-25-
area where it is already active and has operations and
production facilities in place.
Currently, in the Weeks Island field, work is being done on the Myles Salt No. 27 development well
located in
Iberia Parish. The well was re-entered and is being sidetracked to approximately 11,400 feet MD.
Currently the well is drilling at approximately 10,900 feet MD. The targeted sands for this
re-entry are the O, P and Q sands. These are primarily oil based sands in the Miocene formation.
Meridian owns a 72% working interest and is the operator of the well.
Recently in the Weeks Island field, the Goodrich Cocke No. 7 well was recompleted in the BF4 sand
in the Miocene formation. Average daily production from the well is approximately 650 barrels of
oil (equivalent). Flowing tubing pressure was measured at approximately 1,100 psi through a
13/64th-inch choke. The Company is the operator and owns a 69% working interest in the
well.
North Louisiana
The Company is in the early stages of establishing foothold lease positions in two different
repeatable project opportunities in north Louisiana. Meridian will release additional details on
these opportunities as the plays develop.
New Albany Shale Play
In the New Albany Shale Play in the Illinois Basin, two wells were drilled and tested during the
fourth quarter of 2007. The first well, the Farms of Meadow Hills No. 1 well was drilled to 4,600
feet, targeting the Devonian New Albany Shale formation. A second well, the Keach No. 1, was
drilled to approximately the same depth, also targeting the New Albany Shale formation. Both wells
were fracture stimulated and allowed to flow back the water used in the frac. Subsequent pumping of
the load water off the formation resulted in the production of minor amounts of natural gas from
each well. The results of the completion process have not been economic to date, and the Company is
currently reviewing its options for this area for an additional test of its southern acreage
position.
Oklahoma
In the Mid-Continent area, the Company tested the Hunton De-watering play and concluded that it did
not fit the criteria of the Company for near or long term economic growth. The underlying
assumptions as presented in this play were not achieved and therefore the Company took advantage of
the opportunity to sell the remainder of its acreage position in the area recouping relatively all
of its costs for the leasehold position in this area for approximately $5 million, the proceeds of
which were received in 2008. Although the last well drilled, the Benkendorf No. 21-1 well appeared
to be economic based on initial data points, the Company concluded that the risk of development
beyond this limited acreage to other positions in the area constituted too high of a risk and that
it was more prudent to deploy the capital into other areas with less risk and better economics.
Rig Status
The Companys new rig, the Triton, is anticipated to be delivered by the end of March 2008 to
either the next well in the Companys East Texas Austin Chalk play, or one of the previously
referenced wells in the south Texas area. Orion Drilling Company, LP will be operating, maintaining
and crewing two rigs used by Meridian. One of the rigs will be owned by Meridian and one will be on
a long term contract. It is anticipated that Orions management and operations of the rigs will
improve drilling efficiencies and costs for the wells it drills.
Capital Expenditure Plans for 2008. The Company anticipates a 2008 capital spending budget of
approximately $74.3 million for new prospect opportunities, ranging in depths from shallow to deep.
Based
-26-
on current projections, these expenditures are within the Companys 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, 2007 was $8.25 per Mcfe compared to $8.11 per Mcfe
during the year ended December 31, 2006. Fluctuations in prevailing prices for oil and natural gas
have several important consequences to us, including affecting the level of cash flow received from
our producing properties, the timing of exploration of certain prospects and 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.
-27-
Results of Operations
Year Ended December 31, 2007, Compared to Year Ended December 31, 2006
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, 2007, decreased $38.3 million (20%) as compared to 2006 revenues due to a 22%
decrease in production volumes primarily from natural production declines, partially offset by a 2%
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 63.9 MMcfe during
2006 to 50.1 MMcfe for 2007. Oil and natural gas production volume totaled 18,269 MMcfe for 2007,
compared to 23,323 MMcfe for 2006. During 2007, the Companys drilling activity was primarily
focused in the East Texas project area, the Oklahoma project area and the Terrebonne Parish area of
South Louisiana. During 2007, the Company drilled or participated in the drilling of 25 wells of
which 13 wells were completed, representing a 52% success rate. The following table summarizes
Meridians operating revenues, production volumes and average sales prices for the years ended
December 31, 2007 and 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
|
|
|
|
December 31, |
|
|
Increase |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
Production: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
838 |
|
|
|
859 |
|
|
|
(2 |
%) |
Natural gas (MMcf) |
|
|
13,239 |
|
|
|
18,170 |
|
|
|
(27 |
%) |
Natural gas equivalent (MMcfe) |
|
|
18,269 |
|
|
|
23,323 |
|
|
|
(22 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
64.70 |
|
|
$ |
55.73 |
|
|
|
16 |
% |
Natural gas (per Mcf) |
|
|
7.29 |
|
|
|
7.77 |
|
|
|
(6 |
%) |
Natural gas equivalent (per Mcfe) |
|
|
8.25 |
|
|
|
8.11 |
|
|
|
2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues (000s): |
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
54,218 |
|
|
$ |
47,859 |
|
|
|
13 |
% |
Natural gas |
|
|
96,491 |
|
|
|
141,182 |
|
|
|
(32 |
%) |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
150,709 |
|
|
$ |
189,041 |
|
|
|
(20 |
%) |
|
|
|
|
|
|
|
|
|
|
Operating Expenses.
Oil and natural gas operating expenses on an aggregate basis increased $5.7 million (25%) to $28.3
million in 2007, compared to $22.6 million in 2006. On a unit basis, lease operating expenses
increased $0.58 per Mcfe to $1.55 per Mcfe for the year 2007 from $0.97 per Mcfe for the year 2006.
Oil and natural gas operating expenses increased between the periods primarily due to
significantly higher insurance costs, industry wide increases in service costs and increased
maintenance-related activities. For the policy year beginning in May 2006 through April 2007,
insurance premiums increased over 450% from the prior policy year. During 2007, insurance premiums
increased by $2.2 million and represented 39% of the difference in lease operating expenses between
the periods. During the second quarter of 2007 approximately $0.5 million was expensed due to a
civil penalty arising from environmental litigation (see Note 7 to Consolidated Financial
Statements). The remaining $3.0 million increase in operating expenses was associated with the
addition and acquisition of producing wells and additional costs related to Biloxi Marshlands area
production and facilities including compression, storage, and repairs. Although the Companys
insurance costs rose for the period from May 2006 through April 2007, the premium for the policy
for May 2007 through April 2008 has decreased by approximately 30%. We continue to insure our
assets with improved coverage as a safeguard against losses for the Company in the event of another
hurricane. The increase in the per Mcfe rate was additionally attributable to the lower production
between the two corresponding periods.
-28-
Severance and Ad Valorem Taxes.
Severance and ad valorem taxes decreased $1.9 million (16%) to $9.4 million in 2007, compared to
$11.3 million in 2006, primarily because of a decrease in oil and natural gas production partially
offset by a higher average natural gas tax rate. Meridians 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 $0.269 per Mcf (effective July 1, 2007) for
natural gas. For the first six months of 2007, and the last six months of 2006, the rate was
$0.373 per Mcf for natural gas, an increase from $0.252 per Mcf for the first half of 2006. On an
equivalent unit of production basis, severance and ad valorem taxes increased to $0.52 per Mcfe for
2007 from $0.48 per Mcfe for 2006.
Depletion and Depreciation.
Depletion and depreciation expense decreased $29.0 million (27%) during 2007 to $77.1 million
compared to $106.1 million for 2006. This was primarily the result of a decrease in the depletion
rate as compared to the 2006 period and the 22% decrease in production volumes in 2007 from 2006
levels. On a unit basis, depletion and depreciation expenses decreased to $4.22 per Mcfe for 2007,
compared to $4.55 per Mcfe for 2006. Depletion and depreciation expense on a per Mcfe basis
decreased primarily due to the impact of the impairment of long-lived assets during 2006 as
referenced below.
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 resulted in a decrease in the Companys depletion rate for 2007. 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 $0.5 million (3%) to $16.2 million in 2007 compared to $16.7 million for the year 2006,
primarily due to a decrease in professional services. On an equivalent unit of production basis,
general and administrative expenses increased $0.18 per Mcfe to $0.89 per Mcfe for 2007 compared to
$0.71 per Mcfe for 2006.
Accretion Expense.
In accordance with the Statement of Financial Accounting Standards (SFAS) No. 143, Accounting
for Asset Retirement Obligations, (SFAS 143) 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 $2.2 million and $1.6 million to earnings as accretion expense during 2007 and 2006,
respectively. The increase in 2007 levels in comparison to 2006 is primarily the result of
additional wells drilled and placed on production during the year and revisions to estimated
abandonment costs in the industry.
Hurricane Damage Repairs.
There were no hurricane damage repairs recorded in 2007, as compared to $4.3 million in 2006
related to damages incurred from the 2005 hurricanes Katrina and Rita, primarily related to the
Companys 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
-29-
actual repair costs were higher than originally estimated and exceeded our claim limits and therefore
resulted in increased expense.
Interest Expense.
Interest expense increased $0.1 million (2%) to $6.1 million in 2007 compared to $6.0 million for
2006. The increase was primarily a result of increased interest rates during 2007.
Taxes on Income.
The provision for income tax expense (benefit) for 2007 was $5.7 million as compared to ($38.5
million) for 2006. 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.
-30-
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 Companys 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 Meridians 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 (000s): |
|
|
|
|
|
|
|
|
|
|
|
|
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 the previous year, industry wide increases in service costs and
significantly higher insurance costs resulting from the previous years hurricane season. The
Companys insurance rates increased by more than three times the previous years annual premiums
and represented $3.0 million of the increase for the comparable periods.
-31-
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. Meridians 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 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.
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. 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.
In accordance with the Statement SFAS 143, 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 acquisition of properties
during 2006.
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 Companys insurance deductible and repair
costs in excess of insured values. Due to the extensive damage throughout the area and the limited
resources available for
-32-
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.
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.
-33-
Liquidity and Capital Resources
Cash Flows. Net cash flows provided by operating activities was $97.0 million for the year ended
December 31, 2007, as compared to $137.3 million for the year ended December 31, 2006, a decrease
of $40.3 million or 29%, primarily due to the decrease in revenues and production volumes and the
increase in operating expenses. Changes in assets and liabilities was $2.6 million primarily
attributable to the reduction in accounts receivable and an increase in advances from
non-operators.
Net cash flows used in investing activities were $113.6 million for the year ended December 31,
2007, as compared to $130.8 million for the year ended December 31, 2006. This decrease was due to
lower expenditures for property and equipment in 2007.
Net cash flows used in financing activities were $1.3 million for the year ended December 31, 2007,
as compared to net cash flows provided by financing activities of $1.7 million for 2006 primarily
from the repurchase of common stock and a decrease in notes payable.
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,
collectively the Lenders. 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 $115
million effective October 31, 2007. As of December 31, 2007, outstanding borrowings under the
Credit Facility totaled $75 million.
The Credit Facility is subject to semi-annual borrowing base redeterminations on April 30 and
October 31 of each year. In addition to the scheduled semi-annual borrowing base redeterminations,
the lenders or the Company have the right to redetermine the borrowing base at any time, provided
that no party can request more than one such redetermination between the regularly scheduled
borrowing base redeterminations. The determination of 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
Companys 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 Companys consolidated financial statements,
with, 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 agents 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, 2007, the
three-month LIBOR interest rate was 4.70%. 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.
-34-
On February 21, 2008, the Company amended this credit facility (Amended Credit Facility). The
lending institutions under the Amended Credit Facility include Fortis Capital Corp. as
administrative agent, co-lead arranger and bookrunner; The Bank of Nova Scotia, as co-lead arranger
and syndication agent; Comerica Bank, US Bank NA and Allied Irish Bank plc each in their respective
capacities as lenders. The borrowing base under the Amended Credit Facility is $110 million. The
maturity date was extended to February 21, 2012.
Under the Amended 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 agents
prime rate; or (b) federal funds-based rate plus 1/2 of 1%, plus an additional 0.75% to 1.75%
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 LIBOR plus 1.5% to 2.5%, depending on the ratio of the aggregate outstanding loans and letters
of credit to the borrowing base. The Amended Credit Facility continues to provide 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 agreements. As of March 14, 2008, outstanding
borrowing under the Amended Credit Facility totaled $80 million.
Capital Expenditures. Capital expenditures in 2007 consisted of $121.5 million 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 2008 capital expenditures plan is currently forecast at approximately $74.3 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 2008 plan utilizing cash flow from operations and cash on hand.
When appropriate, excess cash flow from operations beyond that needed for the 2008 capital
expenditures plan may be used to reduce debt or to repurchase common stock.
Cash Obligations. The following summarizes the Companys contractual obligations at December 31,
2007, including adjustments for the Amended Credit Facility, 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 |
|
$ |
2,662 |
|
|
$ |
|
|
|
$ |
75,000 |
|
|
$ |
77,662 |
|
Interest |
|
|
5,223 |
|
|
|
10,400 |
|
|
|
5,994 |
|
|
|
21,617 |
|
Drilling rigs |
|
|
16,400 |
|
|
|
11,975 |
|
|
|
|
|
|
|
28,375 |
|
Non-cancelable operating leases |
|
|
1,990 |
|
|
|
4,060 |
|
|
|
1,580 |
|
|
|
7,630 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash obligations |
|
$ |
26,275 |
|
|
$ |
26,435 |
|
|
$ |
82,574 |
|
|
$ |
135,284 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
-35-
Off-Balance Sheet Arrangements. None.
Share Repurchase Program. In March 2007, the Companys Board of Directors authorized a 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 three
years. The timing, volume, and nature of share repurchases will be at the discretion of
management, depending on market conditions, applicable securities laws, and other factors.
Prior to implementing this program, the Company was required to seek approval of the repurchase
program from the Lenders under the Credit Facility. The repurchase program was approved by the
Lenders, subject to certain restrictive covenants. During February 2007, the Lenders in the Credit
Facility unanimously approved an amendment increasing the available limit for the Companys
repurchase of its common stock from $1.0 million to $5.0 million annually. The amendment contained
restrictive covenants on the Companys 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.
As of December 31, 2007, the Company had repurchased 501,300 common shares at a cost of $1,158,000,
of which 342,617 shares have been issued for 401(k) contributions for contract services and for
compensation. 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. It is the intent of the Company to continue this
program through this and future years.
Critical Accounting Policies and Estimates
The Companys discussion and analysis of its financial condition and results of operation are based
upon consolidated financial statements, which have been prepared in accordance with accounting
principles generally accepted in the United States of America. The following summarizes several of
our critical accounting policies. See a complete list of significant accounting policies in Note 2
of the notes to the consolidated financial statements included 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. Reserve estimates significantly impact depletion and potential impairments of oil and
natural gas properties. The Company analyzes its estimates, including those related to oil and
natural gas revenues, bad debts, oil and natural gas properties, derivative contracts, 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. 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
2007, 2006, and 2005, such capitalized costs totaled $16.5 million, $15.4 million, and $13.8
million, respectively. General and administrative costs related to production and general overhead
are expensed as incurred.
-36-
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 Companys 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 10.5%; however, a 10% increase in our
reserves would have decreased our provision for the year by approximately 8.7%.
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, 2007, we had $53.6 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 depletion and amortization of oil and natural gas properties by approximately 1.1%
and a 10% increase would have decreased our provision by approximately 1.3% for the year ended
December 31, 2007.
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 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 Companys 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
-37-
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, 2007, we had a cushion (i.e. the excess of the ceiling over our capitalized costs)
of $62.2 million (before tax). A 10% increase in prices would have increased our cushion by
approximately 32%. A 10% decrease in prices would have decreased our cushion by approximately 34%.
Our hedging program would reduce some of the impact of a price decline.
Price Risk Management Activities. The Company follows SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities (SFAS 133) 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 Companys 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 $21,000 during the year ended December 31, 2007, a gain of $128,000 during the
year ended December 31, 2006, and a loss of $251,000 during the year ended December 31, 2005.
As of December 31, 2007, the estimated fair value of the Companys oil and natural gas contracts
was an unrealized loss of $0.3 million ($0.2 million net of tax) which is recognized in other
comprehensive income. Based upon December 31, 2007, oil and natural gas commodity prices,
approximately $0.3 million of the loss deferred in other comprehensive income could potentially
decrease gross revenues in 2008. The contract agreements expire at various dates through December
31, 2009.
Net settlements under these contract agreements increased (decreased) oil and natural gas revenues
by $3,252,000, $3,821,000 and ($20,578,000) for the years ended December 31, 2007, 2006, and 2005,
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, 2007 and 2006, 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, Accounting for Uncertainty in Income Taxes and Interpretation
of SFAS No. 109 (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes
recognized in an enterprises financial statements in accordance with SFAS No. 109, Accounting for
Income Taxes. FIN 48
-38-
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. The Company adopted the provisions of FIN 48 on
January 1, 2007, and the adoption had no material impact on the Companys results of operations and
financial position.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and
Financial Liabilities Including an amendment of FASB Statement No. 115 (SFAS 159). SFAS 159
permits entities to choose to measure eligible financial assets and liabilities at fair value.
Unrealized gains and loses on items for which the fair value option has been elected are reported
in earnings. SFAS 159 is effective for years beginning after November 15, 2007. We adopted SFAS
159 on January 1, 2008 and did not elect to apply the fair value method to any eligible assets or
liabilities at that time.
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. The Company adopted the provisions of SAB 108 on January 1,
2007, and the adoption 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 157). SFAS 157
defines fair value, establishes a framework for measuring fair value in generally accepted
accounting principles and expands disclosure about fair value measurements. The standard applies
prospectively to new fair value measurements performed after the required effective dates, which
are as follows: on January 1, 2008, the standard became applicable to measurements of the fair
values of financial instruments and recurring fair value measurements of non-financial assets and
liabilities; on January 1, 2009, the standard will apply to all remaining fair value measurements,
including non-recurring measurements of non-financial assets and liabilities, such as asset
retirement obligations and impairments of long-lived assets. The Company adopted the effective
portion of SFAS 157 on January 1, 2008; we do not expect the adoption to have a material impact on
our financial position or results of operations.
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations. SFAS 141(R) replaces
SFAS No. 141, Business Combinations. SFAS 141(R) retains the purchase method of accounting for
acquisitions, but requires a number of changes, including changes in the way assets and liabilities
are recognized in purchase accounting. It also changes the recognition of assets acquired and
liabilities assumed arising from contingencies and requires the expensing of acquisition-related
costs as incurred. Generally, SFAS 141(R) is effective on a prospective basis for all business
combinations completed on or after January 1, 2009. We do not expect the adoption of SFAS 141(R)
to have a material impact on our financial position or results of operations, provided we do not
undertake a significant acquisition or business combination.
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 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.
-39-
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 Companys 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 35% 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 values of our hedging agreements are recorded on our consolidated balance sheet as assets
or liabilities. The estimated fair value of our hedging agreements as of December 31, 2007, is
provided below (see the Companys website at www.tmrc.com for a quarterly breakdown of the
Companys hedge position for 2007 and beyond):
-40-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset (Liability) |
|
|
|
|
|
|
|
Notional |
|
|
Floor Price |
|
|
Ceiling Price |
|
|
December 31, 2007 |
|
|
|
Type |
|
|
Amount |
|
|
($ per unit) |
|
|
($ per unit) |
|
|
(in thousands) |
|
Natural Gas (mmbtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan 2008 - Dec 2008 |
|
Collar |
|
|
2,230,000 |
|
|
$ |
7.00 |
|
|
$ |
12.15 |
|
|
$ |
606 |
|
Jan 2008 - Dec 2008 |
|
Collar |
|
|
1,010,000 |
|
|
$ |
7.50 |
|
|
$ |
11.50 |
|
|
|
479 |
|
Jan 2008 - Dec 2008 |
|
Collar |
|
|
1,830,000 |
|
|
$ |
7.50 |
|
|
$ |
10.10 |
|
|
|
655 |
|
Jan 2009 - Dec 2009 |
|
Collar |
|
|
1,230,000 |
|
|
$ |
7.50 |
|
|
$ |
10.45 |
|
|
|
108 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,848 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (bbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan 2008 - Dec 2008 |
|
Collar |
|
|
40,000 |
|
|
$ |
55.00 |
|
|
$ |
83.00 |
|
|
|
(492 |
) |
Jan 2008 - Dec 2008 |
|
Collar |
|
|
20,000 |
|
|
$ |
65.00 |
|
|
$ |
80.60 |
|
|
|
(280 |
) |
Jan 2008 - Dec 2008 |
|
Collar |
|
|
30,000 |
|
|
$ |
65.00 |
|
|
$ |
85.00 |
|
|
|
(319 |
) |
Jan 2008 - April 2008 |
|
Collar |
|
|
24,000 |
|
|
$ |
60.00 |
|
|
$ |
82.00 |
|
|
|
(341 |
) |
May 2008 - July 2008 |
|
Collar |
|
|
15,000 |
|
|
$ |
60.00 |
|
|
$ |
82.00 |
|
|
|
(198 |
) |
Jan 2008 - July 2008 |
|
Collar |
|
|
28,000 |
|
|
$ |
65.00 |
|
|
$ |
93.15 |
|
|
|
(183 |
) |
Jan 2008 - July 2008 |
|
Collar |
|
|
21,000 |
|
|
$ |
70.00 |
|
|
$ |
87.40 |
|
|
|
(204 |
) |
Jan 2008 - Dec 2008 |
|
Collar |
|
|
19,000 |
|
|
$ |
75.00 |
|
|
$ |
102.50 |
|
|
|
(42 |
) |
Jan 2009 - Dec 2009 |
|
Collar |
|
|
23,000 |
|
|
$ |
70.00 |
|
|
$ |
93.55 |
|
|
|
(104 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Crude Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,163 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(315 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-41-
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.
-42-
MMMbtu One billion Btus.
MMcf One million cubic feet.
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.
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 for 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.
-43-
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.
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Page |
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46 |
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47 |
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49 |
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50 |
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51 |
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52 |
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52 |
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52 |
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57 |
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59 |
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59 |
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60 |
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60 |
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62 |
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63 |
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63 |
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67 |
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68 |
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70 |
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70 |
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72 |
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72 |
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73 |
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74 |
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71 |
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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.
-44-
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors
The Meridian Resource Corporation
Houston, Texas
We have audited the accompanying consolidated balance sheets of The Meridian Resource Corporation
and subsidiaries as of December 31, 2007 and 2006, 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, 2007. These financial statements are the responsibility of
the Companys 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.
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.
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, 2007 and 2006, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2007, in conformity with accounting principles
generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the effectiveness of The Meridian Resource Corporation and subsidiaries
internal control over financial reporting as of December 31, 2007, 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 14, 2008, expressed an unqualified opinion
thereon.
BDO SEIDMAN, LLP
Houston, Texas
March 14, 2008
-45-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
REVENUES: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas |
|
$ |
150,709 |
|
|
$ |
189,041 |
|
|
$ |
195,255 |
|
Price risk management activities |
|
|
21 |
|
|
|
128 |
|
|
|
(251 |
) |
Interest and other |
|
|
1,448 |
|
|
|
1,788 |
|
|
|
692 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
152,178 |
|
|
|
190,957 |
|
|
|
195,696 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING COSTS AND EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas operating |
|
|
28,338 |
|
|
|
22,614 |
|
|
|
15,860 |
|
Severance and ad valorem taxes |
|
|
9,409 |
|
|
|
11,259 |
|
|
|
8,811 |
|
Depletion and depreciation |
|
|
77,076 |
|
|
|
106,067 |
|
|
|
97,354 |
|
General and administrative |
|
|
16,221 |
|
|
|
16,674 |
|
|
|
18,010 |
|
Accretion expense |
|
|
2,230 |
|
|
|
1,588 |
|
|
|
1,120 |
|
Impairment of long-lived assets |
|
|
|
|
|
|
134,865 |
|
|
|
|
|
Hurricane damage repairs |
|
|
|
|
|
|
4,314 |
|
|
|
3,066 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
133,274 |
|
|
|
297,381 |
|
|
|
144,221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS (LOSS) BEFORE OTHER EXPENSES &
INCOME TAXES |
|
|
18,904 |
|
|
|
(106,424 |
) |
|
|
51,475 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
6,090 |
|
|
|
5,982 |
|
|
|
4,724 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS (LOSS) BEFORE INCOME TAXES |
|
|
12,814 |
|
|
|
(112,406 |
) |
|
|
46,751 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAXES: |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
650 |
|
|
|
369 |
|
|
|
(568 |
) |
Deferred |
|
|
5,027 |
|
|
|
(38,891 |
) |
|
|
18,568 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,677 |
|
|
|
(38,522 |
) |
|
|
18,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS (LOSS) |
|
|
7,137 |
|
|
|
(73,884 |
) |
|
|
28,751 |
|
Dividends on preferred stock |
|
|
|
|
|
|
|
|
|
|
902 |
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS (LOSS) APPLICABLE TO COMMON STOCKHOLDERS |
|
$ |
7,137 |
|
|
$ |
(73,884 |
) |
|
$ |
27,849 |
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS (LOSS) PER SHARE: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.08 |
|
|
$ |
(0.84 |
) |
|
$ |
0.33 |
|
Diluted |
|
$ |
0.08 |
|
|
$ |
(0.84 |
) |
|
$ |
0.31 |
|
WEIGHTED AVERAGE NUMBER OF COMMON SHARES: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
89,307 |
|
|
|
87,670 |
|
|
|
84,527 |
|
Diluted |
|
|
94,944 |
|
|
|
87,670 |
|
|
|
90,090 |
|
See notes to consolidated financial statements.
-46-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT ASSETS: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
13,526 |
|
|
$ |
31,424 |
|
Restricted cash |
|
|
30 |
|
|
|
1,282 |
|
Accounts receivable, less allowance for doubtful accounts
of $210 [2007] and $232 [2006] |
|
|
19,874 |
|
|
|
24,285 |
|
Due from affiliates |
|
|
2,580 |
|
|
|
670 |
|
Prepaid expenses and other |
|
|
4,538 |
|
|
|
3,457 |
|
Assets from price risk management activities |
|
|
2,453 |
|
|
|
7,968 |
|
Deferred tax asset |
|
|
164 |
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
43,165 |
|
|
|
69,086 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT: |
|
|
|
|
|
|
|
|
Oil and natural gas properties, full cost method (including
$53,645 [2007] and $54,356 [2006] not subject to depletion) |
|
|
1,771,768 |
|
|
|
1,663,865 |
|
Land |
|
|
48 |
|
|
|
48 |
|
Equipment and other |
|
|
18,503 |
|
|
|
7,492 |
|
|
|
|
|
|
|
|
|
|
|
1,790,319 |
|
|
|
1,671,405 |
|
Less accumulated depletion and depreciation |
|
|
1,350,577 |
|
|
|
1,273,522 |
|
|
|
|
|
|
|
|
Total property and equipment, net |
|
|
439,742 |
|
|
|
397,883 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS: |
|
|
|
|
|
|
|
|
Assets from price risk management activities |
|
|
865 |
|
|
|
490 |
|
Other |
|
|
3 |
|
|
|
436 |
|
|
|
|
|
|
|
|
Total other assets |
|
|
868 |
|
|
|
926 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS |
|
$ |
483,775 |
|
|
$ |
467,895 |
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
-47-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
9,583 |
|
|
$ |
6,700 |
|
Advances from non-operators |
|
|
6,996 |
|
|
|
3,051 |
|
Revenues and royalties payable |
|
|
6,592 |
|
|
|
7,933 |
|
Notes payable |
|
|
2,662 |
|
|
|
2,754 |
|
Accrued liabilities |
|
|
22,011 |
|
|
|
21,938 |
|
Liabilities from price risk management activities |
|
|
2,772 |
|
|
|
1,024 |
|
Asset retirement obligations |
|
|
3,365 |
|
|
|
4,803 |
|
Deferred income taxes payable |
|
|
|
|
|
|
2,336 |
|
Current income taxes payable |
|
|
147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
54,128 |
|
|
|
50,539 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM DEBT |
|
|
75,000 |
|
|
|
75,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER: |
|
|
|
|
|
|
|
|
Deferred income taxes |
|
|
8,238 |
|
|
|
3,364 |
|
Liabilities from price risk management activities |
|
|
861 |
|
|
|
190 |
|
Asset retirement obligations |
|
|
20,118 |
|
|
|
18,005 |
|
|
|
|
|
|
|
|
|
|
|
29,217 |
|
|
|
21,559 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES (Notes 6, 7, and 11) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY: |
|
|
|
|
|
|
|
|
Common stock, $0.01 par value (200,000,000 shares authorized,
89,450,466 [2007] and 89,139,600 [2006] shares issued)
|
|
|
936 |
|
|
|
928 |
|
Additional paid-in capital |
|
|
537,145 |
|
|
|
534,441 |
|
Accumulated deficit |
|
|
(212,142 |
) |
|
|
(219,279 |
) |
Accumulated other comprehensive income (loss) |
|
|
(221 |
) |
|
|
4,707 |
|
|
|
|
|
|
|
|
|
|
|
325,718 |
|
|
|
320,797 |
|
|
|
|
|
|
|
|
|
|
Less treasury stock, at cost 158,683 [2007] shares |
|
|
288 |
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
325,430 |
|
|
|
320,797 |
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY |
|
$ |
483,775 |
|
|
$ |
467,895 |
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
-48-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
|
$ |
7,137 |
|
|
$ |
(73,884 |
) |
|
$ |
28,751 |
|
Adjustments to reconcile net earnings (loss) to net cash
provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depletion and depreciation |
|
|
77,076 |
|
|
|
106,067 |
|
|
|
97,354 |
|
Impairment of long-lived assets |
|
|
|
|
|
|
134,865 |
|
|
|
|
|
Amortization of other assets |
|
|
436 |
|
|
|
443 |
|
|
|
446 |
|
Non-cash compensation |
|
|
2,549 |
|
|
|
2,300 |
|
|
|
1,845 |
|
Non-cash price risk management activities |
|
|
(21 |
) |
|
|
(128 |
) |
|
|
251 |
|
Accretion expense |
|
|
2,230 |
|
|
|
1,588 |
|
|
|
1,120 |
|
Deferred income taxes |
|
|
5,027 |
|
|
|
(38,891 |
) |
|
|
18,568 |
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash |
|
|
1,252 |
|
|
|
(48 |
) |
|
|
(343 |
) |
Accounts receivable |
|
|
4,411 |
|
|
|
16,903 |
|
|
|
(13,425 |
) |
Prepaid expenses and other |
|
|
(1,081 |
) |
|
|
(2,163 |
) |
|
|
969 |
|
Accounts payable |
|
|
(946 |
) |
|
|
362 |
|
|
|
(118 |
) |
Advances from non-operators |
|
|
3,945 |
|
|
|
3,051 |
|
|
|
|
|
Due to (from) affiliates |
|
|
(1,910 |
) |
|
|
(5,308 |
) |
|
|
772 |
|
Revenues and royalties payable |
|
|
(1,341 |
) |
|
|
(1,216 |
) |
|
|
1,032 |
|
Asset retirement obligations |
|
|
(2,055 |
) |
|
|
(6,026 |
) |
|
|
(469 |
) |
Other assets and liabilities |
|
|
282 |
|
|
|
(643 |
) |
|
|
3,936 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
96,991 |
|
|
|
137,272 |
|
|
|
140,689 |
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property and equipment |
|
|
(116,696 |
) |
|
|
(130,062 |
) |
|
|
(139,522 |
) |
Acquisition of properties |
|
|
|
|
|
|
(11,734 |
) |
|
|
|
|
Proceeds from (settlements on) sale of property |
|
|
3,060 |
|
|
|
11,032 |
|
|
|
(51 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(113,636 |
) |
|
|
(130,764 |
) |
|
|
(139,573 |
) |
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt |
|
|
3,000 |
|
|
|
10,000 |
|
|
|
10,000 |
|
Reductions in long-term debt |
|
|
(3,000 |
) |
|
|
(10,000 |
) |
|
|
(10,129 |
) |
Proceeds Notes payable |
|
|
9,540 |
|
|
|
9,248 |
|
|
|
3,142 |
|
Reductions Notes payable |
|
|
(9,632 |
) |
|
|
(7,597 |
) |
|
|
(2,909 |
) |
Repurchase of common stock |
|
|
(1,158 |
) |
|
|
|
|
|
|
|
|
Issuance of stock/exercise of stock options |
|
|
|
|
|
|
|
|
|
|
13 |
|
Preferred dividends |
|
|
|
|
|
|
|
|
|
|
(2,166 |
) |
Additions to deferred loan costs |
|
|
(3 |
) |
|
|
|
|
|
|
(99 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
(1,253 |
) |
|
|
1,651 |
|
|
|
(2,148 |
) |
|
|
|
|
|
|
|
|
|
|
NET CHANGE IN CASH AND CASH EQUIVALENTS |
|
|
(17,898 |
) |
|
|
8,159 |
|
|
|
(1,032 |
) |
Cash and cash equivalents at beginning of year |
|
|
31,424 |
|
|
|
23,265 |
|
|
|
24,297 |
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT END OF YEAR |
|
$ |
13,526 |
|
|
$ |
31,424 |
|
|
$ |
23,265 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION |
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Conversion of preferred stock |
|
$ |
|
|
|
$ |
|
|
|
$ |
(30,625 |
) |
Issuance of shares for contract services |
|
$ |
(1,033 |
) |
|
$ |
(795 |
) |
|
$ |
(1,932 |
) |
Issuance of shares for acquisition of properties |
|
$ |
|
|
|
$ |
(7,000 |
) |
|
$ |
|
|
Accrual of capital expenditures |
|
$ |
4,799 |
|
|
$ |
(259 |
) |
|
$ |
(7,079 |
) |
ARO Liability new wells drilled |
|
$ |
476 |
|
|
$ |
4,559 |
|
|
$ |
883 |
|
ARO Liability changes in estimates |
|
$ |
24 |
|
|
$ |
10,723 |
|
|
$ |
806 |
|
See notes to consolidated financial statements.
-49-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
Years Ended December 31, 2005, 2006 and 2007 (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
Accumulated |
|
|
Other |
|
|
Unamortized |
|
|
|
|
|
|
|
|
|
Common Stock |
|
|
Paid-In |
|
|
Earnings |
|
|
Comprehensive |
|
|
Deferred |
|
|
Treasury Stock |
|
|
|
|
|
|
Shares |
|
|
Par Value |
|
|
Capital |
|
|
(Deficit) |
|
|
Income (Loss) |
|
|
Compensation |
|
|
Shares |
|
|
Cost |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Companys 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 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Companys 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 |
|
Shares repurchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
501 |
|
|
|
(1,158 |
) |
|
|
(1,158 |
) |
Issuance of rights to common stock |
|
|
|
|
|
|
5 |
|
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Companys 401(k) plan contribution |
|
|
42 |
|
|
|
1 |
|
|
|
155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(157 |
) |
|
|
390 |
|
|
|
546 |
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
294 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
294 |
|
Compensation expense |
|
|
|
|
|
|
|
|
|
|
1,598 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,598 |
|
Accum. other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,928 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,928 |
) |
Issuance of shares for contract
services |
|
|
237 |
|
|
|
2 |
|
|
|
584 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(175 |
) |
|
|
447 |
|
|
|
1,033 |
|
Issuance of shares as compensation |
|
|
31 |
|
|
|
|
|
|
|
78 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10 |
) |
|
|
33 |
|
|
|
111 |
|
Net earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,137 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,137 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007 |
|
|
89,450 |
|
|
$ |
936 |
|
|
$ |
537,145 |
|
|
$ |
(212,142 |
) |
|
$ |
(221 |
) |
|
$ |
|
|
|
|
159 |
|
|
$ |
(288 |
) |
|
$ |
325,430 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
-50-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) applicable to common stockholders |
|
$ |
7,137 |
|
|
$ |
(73,884 |
) |
|
$ |
27,849 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax, for
unrealized gains (losses) from hedging activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized holding gains (losses) arising during period (1) |
|
|
(2,814 |
) |
|
|
9,505 |
|
|
|
(14,116 |
) |
Reclassification adjustments on settlement of contracts (2) |
|
|
(2,114 |
) |
|
|
(2,484 |
) |
|
|
13,376 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,928 |
) |
|
|
7,021 |
|
|
|
(740 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income (loss) |
|
$ |
2,209 |
|
|
$ |
(66,863 |
) |
|
$ |
27,109 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Net income tax (expense) benefit |
|
$ |
1,515 |
|
|
$ |
(5,118 |
) |
|
$ |
7,601 |
|
(2) Net income tax (expense) benefit |
|
$ |
1,138 |
|
|
$ |
1,337 |
|
|
$ |
(7,202 |
) |
See notes to consolidated financial statements.
-51-
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, Texas 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, 2007, was $30,000, and at December 31, 2006,
was $1,282,000. 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 Companys 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 Companys offshore production platforms, gathering systems, wells and
related structures, considering related salvage values.
Equipment, which includes a drilling rig, computer equipment, computer 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.
-52-
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 $6.0 million, $5.5 million, and $3.9 million in 2007,
2006 and 2005, respectively. Cash payments (refunds) for income taxes (federal and state, net of
receipts) were $61,000 for 2007, ($322,000) for 2006 and $1,285,000 for 2005.
Concentrations of Credit Risk
Substantially all of the Companys 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, 2007, and December 31, 2006, the Company had approximately $13,318,000
and $32,475,000, 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 Companys share of production. Accounts receivable includes
accrued oil and natural gas revenue receivables of approximately $16.6 million and $18.3 million as
of December 31, 2007 and 2006, respectively.
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 customers 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 Companys 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.
Capitalized Interest
Interest cost is capitalized as part of the historical cost of assets. During 2007, interest of
approximately $323,000 was capitalized on the construction of our drilling rig purchase. Our oil
and natural gas properties not being amortized, did not include significant investments qualifying
for capitalized interest. Interest is capitalized using a weighted average interest rate based on
our outstanding borrowings.
Earnings Per Share
-53-
Basic earnings per share amounts are calculated based on the weighted average number of shares of
common
stock outstanding during each period. Diluted earnings per share is based on the weighted average
number of shares of common stock outstanding for the periods, including the dilutive effects of
stock options, warrants granted and convertible debt. Dilutive options and warrants that are
issued during a period or that expire or are canceled during a period are reflected in the
computations for the time they were outstanding during the periods being reported. Options where
the exercise price of the options exceeds the average price for the period are considered
antidilutive, and therefore are not included in the calculation of dilutive shares.
Stock Options
Effective January 1, 2006, the Company adopted the provisions of SFAS No. 123R, Shared-Based
Payment, (SFAS 123R) 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
123R addresses the accounting for share-based payment transactions in which an enterprise received
employee services in exchange for (a) equity instruments of the enterprise or (b) liabilities that
are based on the fair value of the enterprises equity instruments or that may be settled by the
issuance of such equity instruments. SFAS 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,(APB 25) and generally requires instead that such transactions be
accounted for using the fair-value based method. Prior to adoption of SFAS 123R, the Company
followed the intrinsic value method in accordance with APB 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
SFAS123R of approximately $294,000 and $372,000 was recorded in the years ended December 31, 2007
and 2006, respectively. No stock-based compensation expense related to SFAS 123R was recorded in
the year ended December 31, 2005.
The following is a pro-forma reconciliation of reported earnings and earnings per share for the
year ended December 31, 2005, as if the Company used the fair value method of accounting for
stock-based compensation (thousands of dollars, except per share information):
|
|
|
|
|
|
|
2005 |
|
|
|
|
|
|
Net earnings applicable to common stockholders as reported |
|
$ |
27,849 |
|
Stock-based compensation expense determined under fair
method for all awards, net of tax |
|
|
(237 |
) |
|
|
|
|
|
|
|
|
|
Net earnings applicable to common stockholders (pro forma) |
|
$ |
27,612 |
|
|
|
|
|
Basic earnings per share: |
|
|
|
|
As reported |
|
$ |
0.33 |
|
Pro forma |
|
$ |
0.33 |
|
|
|
|
|
|
Diluted earnings per share: |
|
|
|
|
As reported |
|
$ |
0.31 |
|
Pro forma |
|
$ |
0.31 |
|
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 4.54%, 4.97%, and 3.97%;
dividend yield of 0%; volatility factors of the expected market price of the Companys common stock
of 0.59, 0.80 and 0.92 for 2007, 2006 and 2005, respectively; and a weighted-average expected life
of five years. These assumptions resulted in a weighted average grant date fair value of $1.36,
$2.33 and $3.43 for options granted in 2007,
-54-
2006 and 2005,
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, accounts payable, and accrued liabilities 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, 2007 and 2006, and were determined based upon variable
interest rates currently available to us for borrowings with similar terms.
Notes Payable.
Notes payable are related to the financing of the Companys insurance program. The weighted
average interest rates on the notes payable were 6.76% and 6.86%, as of December 31, 2007 and 2006,
respectively.
Lease Accounting.
The Company amortizes the cost of leasehold improvements over the term of the lease. Rent
incentives, such as holidays, are also amortized over the life of the lease.
Derivative Financial Instruments
The Company follows the provisions of SFAS No. 133, Accounting for Derivative Instruments and
Certain Hedging Activities (SFAS 133). The Company enters into derivative contracts to hedge the
price risks associated with a portion of anticipated future oil and natural gas production. The
Companys 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
Companys 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 hedges 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
gains of $21,000 and $128,000 related to hedge ineffectiveness during the years ended December 31,
2007 and 2006, respectively, and a loss of $251,000 during the year ended December 31, 2005.
The Company discontinues cash flow hedge accounting prospectively when it is determined that the
derivative is no longer effective in offsetting changes in the fair value or cash flows of the
hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is
redesignated as a hedging instrument
-55-
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 are 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 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.
The Company may from time to time be assessed interest or penalties by major tax jurisdictions,
although any such assessments historically have been minimal and immaterial to our financial
results. Should the Company determine that any of its tax positions are uncertain, it may record
related interest and penalties that may be assessed. Interest recorded, if any, will be charged to
interest expense and penalties recorded will be charged to operating expenses in the Companys
statement of operations.
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 not estimable 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,
Accounting for Uncertainty in Income Taxes and interpretation of SFAS No. 109 (FIN 48). FIN
48 clarifies the accounting for uncertainty in income taxes recognized in an enterprises financial
statements in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 prescribes a
recognition threshold and measurement attribute for the financial statement recognition and
measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides
guidance on recognition, classification, interest and penalties, accounting in interim periods,
disclosure, and transition. The Company adopted the provisions of FIN 48 on January 1, 2007, and
the adoption had no material impact on the Companys results of operations and financial position.
-56-
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and
Financial Liabilities Including an amendment of FASB Statement No. 115 (SFAS 159). SFAS 159
permits entities to choose to measure eligible financial assets and liabilities at fair value.
Unrealized gains and loses on items for which the fair value option has been elected are reported
in earnings. SFAS 159 is effective for years beginning after November 15, 2007. We adopted SFAS
159 on January 1, 2008 and did not elect to apply the fair value method to any eligible assets or
liabilities at that time.
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. The Company adopted the provisions of SAB 108 on January 1,
2007, and the adoption 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 157). SFAS 157
defines fair value, establishes a framework for measuring fair value in generally accepted
accounting principles and expands disclosure about fair value measurements. The standard applies
prospectively to new fair value measurements performed after the required effective dates, which
are as follows: on January 1, 2008, the standard became applicable to measurements of the fair
values of financial instruments and recurring fair value measurements of non-financial assets and
liabilities; on January 1, 2009, the standard will apply to all remaining fair value measurements,
including non-recurring measurements of non-financial assets and liabilities, such as asset
retirement obligations and impairments of long-lived assets. The Company adopted the effective
portion of SFAS 157 on January 1, 2008; we do not expect the adoption to have a material impact on
our financial position or results of operations.
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations. SFAS 141(R) replaces
SFAS No. 141, Business Combinations. SFAS 141(R) retains the purchase method of accounting for
acquisitions, but requires a number of changes, including changes in the way assets and liabilities
are recognized in purchase accounting. It also changes the recognition of assets acquired and
liabilities assumed arising from contingencies and requires the expensing of acquisition-related
costs as incurred. Generally, SFAS 141(R) is effective on a prospective basis for all business
combinations completed on or after January 1, 2009. We do not expect the adoption of SFAS 141(R)
to have a material impact on our financial position or results of operations, provided we do not
undertake a significant acquisition or business combination.
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. Reserve estimates
significantly impact depreciation and depletion expense and potential impairments of oil and
natural gas properties. The Company analyzes its estimates, including those related to oil and
natural gas revenues, bad debts, oil and natural gas properties, derivative contracts, 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.
Reclassification of Prior Period Statements
Certain reclassifications of prior period financial statements have been made to conform to current
reporting practices.
3. ASSET RETIREMENT OBLIGATIONS
-57-
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 Companys 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 $2.2 million, $1.6 million and $1.1 million in 2007, 2006 and 2005,
respectively.
The following table describes the change in the Companys asset retirement obligations for the
years ended December 31, 2007 and 2006 (thousands of dollars):
|
|
|
|
|
Asset retirement obligation at December 31, 2005 |
|
$ |
11,964 |
|
|
|
|
|
|
Additional retirement obligations recorded in 2006 |
|
|
4,559 |
|
Settlements during 2006 |
|
|
(6,026 |
) |
Revisions to estimates and other changes during 2006 |
|
|
10,723 |
|
Accretion expense for 2006 |
|
|
1,588 |
|
|
|
|
|
Asset retirement obligation at December 31, 2006 |
|
|
22,808 |
|
|
|
|
|
|
Additional retirement obligations recorded in 2007 |
|
|
476 |
|
Settlements during 2007 |
|
|
(2,055 |
) |
Revisions to estimates and other changes during 2007 |
|
|
24 |
|
Accretion expense for 2007 |
|
|
2,230 |
|
|
|
|
|
Asset retirement obligation at December 31, 2007 |
|
$ |
23,483 |
|
|
|
|
|
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.
-58-
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 Companys 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 Companys 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, collectively the Lenders. 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 $115 million, effective October 31,
2007. As of December 31, 2007, outstanding borrowings under the Credit Facility totaled $75
million.
The Credit Facility is subject to semi-annual borrowing base redeterminations on April 30 and
October 31 of each year. In addition to the scheduled semi-annual borrowing base redeterminations,
the lenders or the Company, have the right to redetermine the borrowing base at any time, provided
that no party can request more than one such redetermination between the regularly scheduled
borrowing base redeterminations. The determination of 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
Companys 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 Companys consolidated financial statements,
with, all of which, the Company is in compliance.
-59-
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 agents 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, 2007, the
three-month LIBOR interest rate was 4.70%. 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.
On February 21, 2008, the Company amended this credit facility (Amended Credit Facility). The
lending institutions under the Amended Credit Facility include Fortis Capital Corp. as
administrative agent, co-lead arranger and bookrunner; The Bank of Nova Scotia, as co-lead arranger
and syndication agent; Comerica Bank, US Bank NA and Allied Irish Bank plc each in their respective
capacities as lenders. The borrowing base under the Amended Credit Facility is $110 million. The
maturity date was extended to February 21, 2012.
Under the Amended 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 agents
prime rate; or (b) federal funds-based rate plus 1/2 of 1%, plus an additional 0.75% to 1.75%
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 LIBOR plus 1.5% to 2.5%, depending on the ratio of the aggregate outstanding loans and letters
of credit to the borrowing base. The Amended Credit Facility continues to provide 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 agreements. As of March 14, 2008, outstanding
borrowing under the Amended Credit Facility totaled $80 million.
Current Debt Maturities
Scheduled debt maturities for the next five years and thereafter, as of December 31, 2007, are as
follows: none in 2008 through 2011, $75 million in 2012, and none thereafter.
6. CONTRACTUAL OBLIGATIONS
In April 2006, the Company negotiated an amendment to its office building lease agreement that
extended the Companys office lease until September 30, 2011. As of December 31, 2007, the
remaining base rental payments will be $1.7 million in 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 $2.0 million, $2.5
million and $2.5 million in 2007, 2006 and 2005, respectively. Future minimum lease payments under
all non-cancelable operating leases having initial terms of one year or more are $2.0 million for
each of 2008, 2009 and 2010, $1.6 million for 2011, and none thereafter. In addition, over the
next three years, the Company has contractual obligations for the use of drilling rigs. These
obligations are $16.4 million in 2008, $10.1 million in 2009, and $1.9 million in 2010.
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 Meridians 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 Meridians
-60-
satisfying a prior adverse judgment in favor of Amoco
Production Company. Mr. James Bond had 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. Mr.
James T. Bond was employed by H.L. Hawkins Jr. and his companies as General Manager until 2002. He
served on the Board of Directors of the Company from March 1997 to August 2004. After Mr. Bonds
employment with Mr. Hawkins, Jr., and his companies ended, Mr. Bond was engaged by The Meridian
Resource & Exploration LLC as a consultant. This relationship continued until his death. Mr. Bond
was also the father-in-law of Michael J. Mayell, the President of the Company. Management continues
to vigorously defend this action on the basis that Mr. Hawkins individually and through his agent,
Mr. Bond, agreed to the course of action adopted by Meridian and further that Meridians actions
were not grossly negligent, but were within the business judgment rule. Since Mr. Bonds death, a
pleading has recently been filed substituting the proper party for Mr. Bond. The Company is unable
to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to
estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, the
Company has not provided any amount for this matter in its financial statements at December 31,
2007.
Title/lease disputes. Title and lease disputes may arise in the normal course of the Companys
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 Companys oil and natural gas
operations. In some of the lawsuits, Shell Oil Company and SWEPI LP have demanded contractual
indemnity and defense from Meridian based upon the terms of the purchase and sale
agreement related to the fields, and in another lawsuit, Exxon Mobil Corporation has demanded
contractual indemnity and defense from Meridian on the basis of a purchase and sale agreement
related to the field(s) referenced in the lawsuit; Meridian has challenged such demands. In some
cases, Meridian has also demanded defense and indemnity from their subsequent purchasers of the
fields. The Company is unable to express an opinion with respect to the likelihood of an
unfavorable outcome of these matters or to estimate the amount or range of potential loss should
any outcome be unfavorable. Therefore, the Company has not provided any amount for these matters in
its financial statements at December 31, 2007.
Consent Decree. During the fourth quarter of 2007 the Company entered into a Consent Decree with
the United States Environmental Protection Agency (EPA) in settlement of alleged violations of
the Clean Water Act, as amended by the Oil Pollution Act of 1990. Under the Consent Decree, the
Company paid $504,000 in civil penalties for alleged discharges of crude oil into navigable waters
or adjoining shorelines from the Companys operations at the Weeks Island field in Iberia Parish,
Louisiana. The Company will also be subject to certain injunctive relief, requiring the Company to
enhance certain pipeline survey, monitoring and reporting activities. Under the Consent Decree,
the Company does not admit any liability arising out of the occurrences described in the Consent
Decree or the related Complaint. During 2007, the Company recorded an expense for the above amount
in oil and natural gas operating expenses.
Litigation involving insurable issues. There are no material legal proceedings involving insurable
issues which exceed insurance limits to which Meridian or any of its subsidiaries is a party or to
which any of its property is subject, other than ordinary and routine litigation incidental to the
business of producing and exploring for crude oil and natural gas.
-61-
8. TAXES ON INCOME
Provisions (benefits) for federal and state income taxes are as follows (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
$ |
560 |
|
|
$ |
334 |
|
|
$ |
(676 |
) |
State |
|
|
90 |
|
|
|
35 |
|
|
|
108 |
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
4,470 |
|
|
|
(39,108 |
) |
|
|
17,480 |
|
State |
|
|
557 |
|
|
|
217 |
|
|
|
1,088 |
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) |
|
$ |
5,677 |
|
|
$ |
(38,522 |
) |
|
$ |
18,000 |
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) as reported is reconciled to the federal statutory rate (35%) as
follows (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Income tax provision (benefit) computed at statutory rate |
|
$ |
4,485 |
|
|
$ |
(39,342 |
) |
|
$ |
16,363 |
|
Nondeductible costs |
|
|
577 |
|
|
|
415 |
|
|
|
479 |
|
State income tax, net of federal tax benefit |
|
|
615 |
|
|
|
240 |
|
|
|
1,158 |
|
Decrease in net operating loss carryover due to expiration |
|
|
|
|
|
|
165 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) |
|
$ |
5,677 |
|
|
$ |
(38,522 |
) |
|
$ |
18,000 |
|
|
|
|
|
|
|
|
|
|
|
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
Companys deferred tax assets and liabilities are as follows (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Net operating tax loss carryforward |
|
$ |
27,391 |
|
|
$ |
40,085 |
|
Statutory depletion carryforward |
|
|
950 |
|
|
|
950 |
|
Tax credits |
|
|
2,205 |
|
|
|
1,644 |
|
Unrealized hedge loss |
|
|
119 |
|
|
|
|
|
Deferred compensation |
|
|
6,232 |
|
|
|
5,673 |
|
Other |
|
|
44 |
|
|
|
187 |
|
|
|
|
|
|
|
|
Total deferred tax assets |
|
|
36,941 |
|
|
|
48,539 |
|
|
|
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Book basis in excess of tax basis in oil and natural gas properties |
|
|
45,015 |
|
|
|
51,705 |
|
Unrealized hedge gain |
|
|
|
|
|
|
2,534 |
|
|
|
|
|
|
|
|
Total deferred tax liabilities |
|
|
45,015 |
|
|
|
54,239 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability |
|
$ |
(8,074 |
) |
|
$ |
(5,700 |
) |
|
|
|
|
|
|
|
As of December 31, 2007, the Company had approximately $78.3 million of tax net operating loss
carryforwards. The net operating loss carryforwards assume that certain items, primarily
intangible drilling
-62-
costs, have been capitalized and are being amortized under the tax laws for the
current year. However, the Company has not made a final determination if an election will be made
to capitalize all or part of these items for tax purposes.
The net operating loss carryforwards begin to expire in 2019 and extend through 2026. A portion of
the net operating loss carryforwards is subject to change in ownership limitations that could
restrict the Companys ability to utilize such losses in the future.
As of December 31, 2007, 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):
|
|
|
|
|
|
|
|
|
|
|
Net |
|
|
AMT |
|
|
|
Operating |
|
|
Operating |
|
Year of Expiration |
|
Loss |
|
|
Loss |
|
2019 |
|
$ |
20,379 |
|
|
$ |
44,170 |
|
2020 |
|
|
30 |
|
|
|
30 |
|
2021 |
|
|
36 |
|
|
|
36 |
|
2022 |
|
|
13,053 |
|
|
|
6,502 |
|
2023 |
|
|
44,669 |
|
|
|
44,516 |
|
2025 |
|
|
42 |
|
|
|
54 |
|
2026 |
|
|
52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
78,261 |
|
|
$ |
95,308 |
|
|
|
|
|
|
|
|
As of December 31, 2007, the Company had approximately $2.2 million of AMT tax credit 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 2007.
9. REDEEMABLE CONVERTIBLE PREFERRED STOCK
During the first six months of 2005, the Company completed the conversion of all of the remaining
outstanding shares of its 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 Companys
common stock. In 2005, the Company paid $2.2 million of preferred dividends, which included $1.3
million accumulated from the prior year.
10. STOCKHOLDERS EQUITY
Common Stock
In March 2007, the Companys Board of Directors authorized a 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 three years. The timing, volume, and nature
of share repurchases will be at the discretion of management, depending on market conditions,
applicable securities laws, and other factors. Prior to implementing this
program, the Company was required to seek approval of the repurchase program from the Lenders under
the Credit Facility. The repurchase program was approved by the Lenders, subject to certain
restrictive covenants. During February 2007, the lenders in the Credit Facility unanimously
approved an amendment increasing the available limit for the Companys repurchase of its
-63-
common stock from $1.0 million to $5.0 million annually. The amendment contained restrictive covenants on
the Companys 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. As of December 31, 2007, the Company had repurchased 501,300 common
shares at a cost of $1,158,000, of which 342,617 shares have been reissued for 401(k)
contributions, for contract services and for compensation. 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.
It is the intent of the Company to continue this program through this and future years.
Warrants
The Company had the following warrants outstanding at December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
|
Exercise |
|
|
|
|
Warrants |
|
Shares |
|
|
Price |
|
|
Expiration Date |
|
Executive Officers |
|
|
1,428,000 |
|
|
$ |
5.85 |
|
|
|
* |
|
General Partner |
|
|
1,808,516 |
|
|
$ |
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, 2007, 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 1,808,516
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 Companys 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 in cash 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
officers 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.
-64-
Stock Options
Options to purchase the Companys 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, 2007, 2006 and 2005, 3,850,000, 1,785,310, and
2,162,478 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, 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 |
|
Granted |
|
|
115,000 |
|
|
|
2.69 |
|
Exercised |
|
|
|
|
|
|
|
|
Canceled |
|
|
(174,280 |
) |
|
|
8.80 |
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007 |
|
|
3,399,688 |
|
|
$ |
3.55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares exercisable: |
|
|
|
|
|
|
|
|
December 31, 2005 |
|
|
3,430,050 |
|
|
$ |
3.97 |
|
December 31, 2006 |
|
|
3,285,465 |
|
|
$ |
3.76 |
|
December 31, 2007 |
|
|
3,252,001 |
|
|
$ |
3.57 |
|
-65-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding |
|
|
Options Exercisable |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
Range of |
|
Outstanding at |
|
|
Average |
|
|
Exercisable at |
|
|
Average |
|
Exercisable Prices |
|
December 31, 2007 |
|
|
Exercise Price |
|
|
December 31, 2007 |
|
|
Exercise Price |
|
$1.79 - $2.71 |
|
|
55,000 |
|
|
$ |
2.34 |
|
|
|
17,083 |
|
|
$ |
2.36 |
|
$3.00 - $3.99 |
|
|
3,173,947 |
|
|
|
3.37 |
|
|
|
3,076,048 |
|
|
|
3.37 |
|
$4.01 - 8.42 |
|
|
170,741 |
|
|
|
7.36 |
|
|
|
158,870 |
|
|
|
7.54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,399,688 |
|
|
$ |
3.55 |
|
|
|
3,252,001 |
|
|
$ |
3.57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted average remaining contractual life of options outstanding at December 31, 2007, was
approximately two years.
The aggregate intrinsic value of options outstanding and exercisable at December 31, 2007, was de
minimis. The aggregate intrinsic value represents the total pre-tax value (the difference between
the Companys closing stock price on the last trading day of 2007 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, 2007. The amount of
aggregate intrinsic value will change based on the fair market value of the Companys common stock.
As of December 31, 2007, there was approximately $175.4 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 Companys Chief Executive Officer and President, respectively) the
option to accept in lieu of an electable portion of their cash compensation rights to common stock
pursuant to the Companys Long Term Incentive Plan. Under the terms of this deferred compensation
plan, Messrs., Reeves and Mayell each elected to defer $400,000 for 2007, $400,000 for 2006 and
$400,000 for 2005. In exchange for and in consideration of their accepting this option to reduce
the Companys cash payments to each of Messrs. Reeves and Mayell, the Company granted to each
officer a matching deferral equal to 100% of the amount deferred, which is subject to a one-year
vesting period. Under the terms of the deferred compensation plan, the employee and matching
deferrals are allocated to a notional common stock account in which notional shares of common stock
are credited to the accounts of the officers 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, 2007, the plan had reserved 5,650,000
shares of common stock for future issuance and 4,163,332 notional shares had been granted. No
actual shares of common stock have been issued and the officers have 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 and matching grants 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 these deferred portions of their base
salaries during these periods, the compensation expense required to be reported by the Company for
these equity grants was $1,598,000
-66-
$1,593,000, and $1,595,000 for 2007, 2006 and 2005 periods,
respectively, and is reflected in general and administrative expense and in oil and natural gas
properties for the years ended December 31, 2007, 2006 and 2005, respectively.
Stockholder Rights Plan
On May 5, 1999, the Companys 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 Companys
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
employees 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 Companys
401(k) plan was $545,000, $381,000, and $300,000 in 2007, 2006, and 2005, 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 $4.7 million, $6.7 million and $6.4 million in 2007, 2006 and 2005,
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
-67-
additional future wells would be placed into the Geoscientist Plan. During 2002, the Executive
Committee decided to modify this position and for certain key geoscientists the Geoscientist 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 participants 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 Companys 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
Companys 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, 2007, 2006 and 2005, compensation expense in the amounts of $78,054, $137,624, and
$120,161 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 Companys 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 133 and any changes in fair value are recorded in
-68-
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 gains of
$21,000 and $128,000 during the years ended December 31, 2007 and 2006, respectively, and a loss of
$251,000 during the year ended December 31, 2005 due to hedge ineffectiveness.
As of December 31, 2007, the estimated fair value of the Companys oil and natural gas contracts
was an unrealized loss of $0.3 million ($0.2 million net of tax) which is recognized in other
comprehensive income. Based upon oil and natural gas commodity prices at December 31, 2007,
approximately $0.3 million of the loss deferred in other comprehensive income could potentially
decrease gross revenues in 2008. These derivative agreements expire at various dates through
December 31, 2009.
Net settlements under these contracts increased (decreased) oil and natural gas revenues by
$3,252,000, $3,821,000, and ($20,578,000) for the years ended December 31, 2007, 2006, and 2005
respectively, as a result of hedging transactions.
All of the Companys current hedging contracts are in the form of costless collars. The costless
collars provide the Company with a lower limit floor price and an upper limit ceiling price on
the hedged volumes. The floor price represents the lowest price the Company will receive for the
hedged volumes while the ceiling price represents the highest price the Company will receive for
the hedged volumes. The costless collars are settled monthly based on the NYMEX futures contract.
The notional amount is equal to the total net volumetric hedge position of the Company during the
periods presented. The positions effectively hedge approximately 35% of proved developed natural
gas production and 26% of proved developed oil production during the respective terms of the
hedging agreements. The fair values of the hedges are based on the difference between the strike
price and the New York Mercantile Exchange future prices for the applicable trading months.
-69-
The fair value of hedging agreements is recorded on the consolidated balance sheet as assets or
liabilities. The estimated fair value of hedging agreements as of December 31, 2007, is provided
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset (Liability) |
|
|
|
|
|
|
|
Notional |
|
|
Floor Price |
|
|
Ceiling Price |
|
|
December 31, 2007 |
|
|
|
Type |
|
|
Amount |
|
|
($ per unit) |
|
|
($ per unit) |
|
|
(in thousands) |
|
Natural Gas (mmbtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan 2008 - Dec 2008 |
|
Collar |
|
|
2,230,000 |
|
|
$ |
7.00 |
|
|
$ |
12.15 |
|
|
$ |
606 |
|
Jan 2008 - Dec 2008 |
|
Collar |
|
|
1,010,000 |
|
|
$ |
7.50 |
|
|
$ |
11.50 |
|
|
|
479 |
|
Jan 2008 - Dec 2008 |
|
Collar |
|
|
1,830,000 |
|
|
$ |
7.50 |
|
|
$ |
10.10 |
|
|
|
655 |
|
Jan 2009 - Dec 2009 |
|
Collar |
|
|
1,230,000 |
|
|
$ |
7.50 |
|
|
$ |
10.45 |
|
|
|
108 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,848 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (bbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan 2008 - Dec 2008 |
|
Collar |
|
|
40,000 |
|
|
$ |
55.00 |
|
|
$ |
83.00 |
|
|
|
(492 |
) |
Jan 2008 - Dec 2008 |
|
Collar |
|
|
20,000 |
|
|
$ |
65.00 |
|
|
$ |
80.60 |
|
|
|
(280 |
) |
Jan 2008 - Dec 2008 |
|
Collar |
|
|
30,000 |
|
|
$ |
65.00 |
|
|
$ |
85.00 |
|
|
|
(319 |
) |
Jan 2008 - April
2008 |
|
Collar |
|
|
24,000 |
|
|
$ |
60.00 |
|
|
$ |
82.00 |
|
|
|
(341 |
) |
May 2008 - July 2008 |
|
Collar |
|
|
15,000 |
|
|
$ |
60.00 |
|
|
$ |
82.00 |
|
|
|
(198 |
) |
Jan 2008 - July 2008 |
|
Collar |
|
|
28,000 |
|
|
$ |
65.00 |
|
|
$ |
93.15 |
|
|
|
(183 |
) |
Jan 2008 - July 2008 |
|
Collar |
|
|
21,000 |
|
|
$ |
70.00 |
|
|
$ |
87.40 |
|
|
|
(204 |
) |
Jan 2008 - Dec 2008 |
|
Collar |
|
|
19,000 |
|
|
$ |
75.00 |
|
|
$ |
102.50 |
|
|
|
(42 |
) |
Jan 2009 - Dec 2009 |
|
Collar |
|
|
23,000 |
|
|
$ |
70.00 |
|
|
$ |
93.55 |
|
|
|
(104 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Crude Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,163 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(315 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13. MAJOR CUSTOMERS
Major customers for the years ended December 31, 2007, 2006 and 2005, were as follows (based on
sales exceeding 10% of total oil and natural gas revenues):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
Customer |
|
2007 |
|
2006 |
|
2005 |
Superior Natural Gas |
|
|
23 |
% |
|
|
35 |
% |
|
|
46 |
% |
Crosstex/Louisiana Intrastate Gas |
|
|
16 |
% |
|
|
21 |
% |
|
|
19 |
% |
Shell Trading (U.S.) |
|
|
14 |
% |
|
|
|
|
|
|
|
|
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 $9,871,000, $7,743,000, and
$9,997,000 for the years ended December 31, 2007, 2006 and 2005,
-70-
respectively, in oil and natural gas drilling activities. Net amounts due from TODD, JAR and Mr.
Reeves were approximately $1,753,000 and $337,000 as of December 31, 2007 and 2006, respectively.
Net amounts due from Sydson and Mr. Mayell were approximately $827,000 and $333,000 as of December
31, 2007 and 2006, 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, 2007,
2006 and 2005 and received fees of approximately $231,000, $227,000, and $320,000 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 $275,000 during 2007, $438,000 during 2006, and $464,000 during 2005.
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, 2007, 2006 and 2005, and received fees of approximately $73,000, $26,000, and
$19,000, respectively. In addition, the Company pays Gary A. Messersmith, P.C. $8,333 per month
relating to his 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 $441,000
during 2007, $751,000 during 2006, and $702,000 during 2005.
Mr. G. M. Larberg, a recently added Director of Meridian, is a petroleum industry consultant that
provided the Company with services for the years ended December 31, 2007 and 2006, and received
consulting fees of approximately $223,000 and $21,000, respectively.
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 $168,000, $146,000, and $100,000 for the years 2007, 2006 and 2005,
respectively. Mr. Jeff Robinson is the son-in-law of Joseph A. Reeves, Jr. and is employed as the
Manager of the Companys Information Technology Department and has been paid $164,000, $150,000,
and $111,000 for the years 2007, 2006 and 2005, 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 year
ended December 31, 2005 and received fees of approximately $32,000. 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 $371,000 in 2007, $337,000 in 2006 and $100,000 in 2005. Such fees
exceeded 5% of the gross revenues for these firms for those respective years.
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 $129,000, $114,000, and $79,000 for the
years 2007, 2006 and 2005, respectively. Mr. James T. Bond, former Director of Meridian, was the
father-in-law of Mr. Michael J. Mayell, and was providing consultant services to the Company and
received fees in the amount of $48,000, $155,000, and $175,000, for the years 2007, 2006 and 2005,
respectively.
-71-
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, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) applicable to common stockholders |
|
$ |
7,137 |
|
|
$ |
(73,884 |
) |
|
$ |
27,849 |
|
Plus income impact of assumed conversions: |
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividends (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) applicable to common stockholders
plus assumed conversions |
|
$ |
7,137 |
|
|
$ |
(73,884 |
) |
|
$ |
27,849 |
|
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic earnings (loss) per
share weighted-average shares outstanding |
|
|
89,307 |
|
|
|
87,670 |
|
|
|
84,527 |
|
Effect of potentially dilutive common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
Warrants and rights (a) |
|
|
5,637 |
|
|
|
N/A |
|
|
|
4,755 |
|
Employee and director stock options (b) |
|
|
|
|
|
|
N/A |
|
|
|
808 |
|
Redeemable preferred stock (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted earnings (loss) per share
weighted-average shares outstanding and
assumed conversions |
|
|
94,944 |
|
|
|
87,670 |
|
|
|
90,090 |
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per share |
|
$ |
0.08 |
|
|
$ |
(0.84 |
) |
|
$ |
0.33 |
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share |
|
$ |
0.08 |
|
|
$ |
(0.84 |
) |
|
$ |
0.31 |
|
|
|
|
|
|
|
|
|
|
|
Warrants and stock options for which the exercise prices were greater than the average market price
of the Companys common stock are excluded from the computation of diluted earnings per share.
Stock rights issued under our deferred compensation plan have no exercise price and are included in
diluted earnings per share in all years, unless there is a loss. Redeemable preferred stock,
outstanding only in 2005, is considered for inclusion based on the if converted method. Under
this method, the shares are assumed converted, and any related preferred dividends earned are added
to income. The result may be dilutive to earnings per share, in which case the shares are included
in our computation of diluted earnings per share, or it may be anti-dilutive, in which case the
shares are excluded. All potentially dilutive shares, whether from options, warrants, rights, or
redeemable preferred stock, are excluded when there is an operating loss, because inclusion of such
shares would be anti-dilutive.
|
|
|
(a) |
|
The number of warrants excluded totaled approximately 1.4 million, 3.2 million, and 1.4
million in 2007, 2006 and 2005, respectively. The number of stock rights excluded totaled
approximately 3.6 million in 2006. |
|
(b) |
|
The number of stock options excluded totaled approximately 3.6 million, 3.7 million,
and 0.5 million in 2007, 2006 and 2005, respectively. |
|
(c) |
|
A weighted average of approximately 2.1 million redeemable preferred shares were
excluded in 2005. |
16. ACCRUED LIABILITIES
Below is the detail of our accrued liabilities on our balance sheets as of December 31 (thousands
of dollars):
-72-
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
Capital expenditures |
|
$ |
14,821 |
|
|
$ |
13,851 |
|
Operating expenses/Taxes |
|
|
3,881 |
|
|
|
4,024 |
|
Hurricane damage repairs |
|
|
|
|
|
|
71 |
|
Compensation |
|
|
853 |
|
|
|
1,197 |
|
Interest |
|
|
460 |
|
|
|
506 |
|
Other |
|
|
1,996 |
|
|
|
2,289 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
22,011 |
|
|
$ |
21,938 |
|
|
|
|
|
|
|
|
17. SUBSEQUENT EVENTS
During February 2008, the Company entered into a series of hedging contracts to hedge a portion of
its crude oil and natural gas production for the period from March 2008 through December 2009. The
hedge contracts were completed in the form of costless collars. The costless collars provide the
Company with a lower limit floor price and an upper limit ceiling price on the hedged volumes. The
floor price represents the lowest price the Company will receive for the hedged volumes, while the
ceiling price represents the highest price the Company will receive for the hedged volumes. The
costless collars will be settled monthly based on the NYMEX futures contract of oil and natural gas
during each respective month. These hedge contracts, combined with those discussed in Note 12,
effectively hedge approximately 41% of the estimated proved developed natural gas production, and
38% of the estimated proved developed oil production during the respective terms of the hedging
agreements. The following table summarizes the contracted volumes and prices for the costless
collars.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional |
|
Floor Price |
|
Ceiling Price |
|
|
Amount |
|
($ per unit) |
|
($ per unit) |
Natural Gas (mmbtu) |
|
|
|
|
|
|
|
|
|
|
|
|
Mar 2008 - Dec 2008
|
|
|
200,000 |
|
|
$ |
8.00 |
|
|
$ |
10.50 |
|
Jan 2009 - Dec 2009
|
|
|
760,000 |
|
|
$ |
8.00 |
|
|
$ |
10.30 |
|
Crude Oil (bbls) |
|
|
|
|
|
|
|
|
|
|
|
|
Mar 2008 - Dec 2008
|
|
|
66,000 |
|
|
$ |
85.00 |
|
|
$ |
111.40 |
|
Jan 2009 - Dec 2009
|
|
|
43,000 |
|
|
$ |
80.00 |
|
|
$ |
111.00 |
|
-73-
18. QUARTERLY RESULTS OF OPERATIONS (Unaudited)
Results of operations by quarter for the year ended December 31, 2007 were (thousands of dollars,
except per share):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended |
2007 |
|
March 31 |
|
June 30 |
|
Sept. 30 |
|
Dec. 31 |
Revenues |
|
$ |
40,143 |
|
|
$ |
39,716 |
|
|
$ |
33,709 |
|
|
$ |
37,141 |
|
Results of operations from exploration
and production activities(1) |
|
|
8,107 |
|
|
|
10,033 |
|
|
|
6,557 |
|
|
|
9,375 |
|
Net earnings (2) |
|
$ |
1,668 |
|
|
$ |
2,705 |
|
|
$ |
750 |
|
|
$ |
2,014 |
|
Net earnings per share:(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.02 |
|
|
$ |
0.03 |
|
|
$ |
0.01 |
|
|
$ |
0.02 |
|
Diluted |
|
$ |
0.02 |
|
|
$ |
0.03 |
|
|
$ |
0.01 |
|
|
$ |
0.02 |
|
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)(4) |
|
$ |
7,331 |
|
|
$ |
2,843 |
|
|
$ |
(86,879 |
) |
|
$ |
2,821 |
|
Net earnings (loss) per share:(2) (3)(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.08 |
|
|
$ |
0.03 |
|
|
$ |
(0.99 |
) |
|
$ |
0.03 |
|
Diluted |
|
$ |
0.08 |
|
|
$ |
0.03 |
|
|
$ |
(0.99 |
) |
|
$ |
0.03 |
|
|
|
|
(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 123(R) effective January 1, 2006. |
|
(4) |
|
Includes impairment of long-lived assets of $134.9 million in the third quarter. |
-74-
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 (SFAS 69).
Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities
(thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Costs incurred during the year:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition costs |
|
|
|
|
|
|
|
|
|
|
|
|
Unproved |
|
$ |
9,589 |
|
|
$ |
35,728 |
|
|
$ |
7,097 |
|
Proved |
|
|
|
|
|
|
8,239 |
|
|
|
|
|
Exploration |
|
|
92,320 |
|
|
|
95,486 |
|
|
|
110,669 |
|
Development |
|
|
9,026 |
|
|
|
23,405 |
|
|
|
16,136 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
110,935 |
|
|
$ |
162,858 |
|
|
$ |
133,902 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Costs incurred during the years ended December 31, 2007, 2006 and 2005 include
general and administrative costs related to acquisition, exploration and development of oil
and natural gas properties, net of third party reimbursements, of $16,492,000, $15,375,000,
and $13,814,000 respectively. |
Capitalized Costs Relating to Oil and Natural Gas Producing Activities
(thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
Capitalized costs |
|
$ |
1,771,768 |
|
|
$ |
1,663,865 |
|
Accumulated depletion |
|
|
1,344,164 |
|
|
|
1,267,504 |
|
|
|
|
|
|
|
|
Net capitalized costs |
|
$ |
427,604 |
|
|
$ |
396,361 |
|
|
|
|
|
|
|
|
At December 31, 2007 and 2006, unevaluated costs of $53,645,000 and $54,356,000, 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.
-75-
Costs Not Being Amortized
(thousands of dollars)
The following table sets forth a summary of oil and natural gas property costs not being amortized
at December 31, 2007, by the year in which such costs were incurred. There are no individually
significant properties or significant development projects included in costs not being amortized.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2004&Prior |
|
|
Leasehold and Geological & Geophysical |
|
$ |
39,478 |
|
|
$ |
21,443 |
|
|
$ |
16,621 |
|
|
$ |
1,409 |
|
|
$ |
5 |
|
Exploration Drilling |
|
|
14,167 |
|
|
|
13,693 |
|
|
|
272 |
|
|
|
202 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
53,645 |
|
|
$ |
35,136 |
|
|
$ |
16,893 |
|
|
$ |
1,611 |
|
|
$ |
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-76-
Results of Operations from Oil and Natural Gas Producing Activities
(thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Operating Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
54,218 |
|
|
$ |
47,859 |
|
|
$ |
34,647 |
|
Natural Gas |
|
|
96,491 |
|
|
|
141,182 |
|
|
|
160,608 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
150,709 |
|
|
|
189,041 |
|
|
|
195,255 |
|
|
|
|
|
|
|
|
|
|
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas operating costs |
|
|
28,338 |
|
|
|
22,614 |
|
|
|
15,860 |
|
Severance and ad valorem taxes |
|
|
9,409 |
|
|
|
11,259 |
|
|
|
8,811 |
|
Depletion |
|
|
76,660 |
|
|
|
105,210 |
|
|
|
96,396 |
|
Accretion expense |
|
|
2,230 |
|
|
|
1,588 |
|
|
|
1,120 |
|
Impairment of long-lived assets |
|
|
|
|
|
|
134,865 |
|
|
|
|
|
Hurricane damage repairs |
|
|
|
|
|
|
4,314 |
|
|
|
3,066 |
|
Income tax expense (benefit) |
|
|
14,992 |
|
|
|
(31,783 |
) |
|
|
24,501 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
131,629 |
|
|
|
248,067 |
|
|
|
149,754 |
|
|
|
|
|
|
|
|
|
|
|
Results of operations from oil and
natural gas producing activities |
|
$ |
19,080 |
|
|
$ |
(59,026 |
) |
|
$ |
45,501 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion expense per Mcfe |
|
$ |
4.20 |
|
|
$ |
4.51 |
|
|
$ |
3.74 |
|
|
|
|
|
|
|
|
|
|
|
-77-
Estimated Quantities of Proved Reserves
The following table sets forth the net proved reserves of the Company as of December 31, 2007, 2006
and 2005, and the changes therein during the years then ended. Proved oil and natural gas reserves
are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date
the estimate is made. The reserve information was reviewed by T. J. Smith & Company, Inc.,
independent reservoir engineers, for 2007, 2006 and 2005. All of the Companys oil and natural gas
producing activities are located in the United States.
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Gas |
|
|
|
(MBbls) |
|
|
(MMcf) |
|
Total Proved Reserves: |
|
|
|
|
|
|
|
|
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 |
|
Production during 2007 |
|
|
(838 |
) |
|
|
(13,239 |
) |
Sale of reserves in-place |
|
|
(3 |
) |
|
|
(413 |
) |
Discoveries and extensions |
|
|
634 |
|
|
|
5,465 |
|
Revisions of previous quantity estimates and other |
|
|
327 |
|
|
|
2,701 |
|
|
|
|
|
|
|
|
Balance at December 31, 2007 |
|
|
4,856 |
|
|
|
61,329 |
|
|
|
|
|
|
|
|
Proved Developed Reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
Balance at December 31, 2007 |
|
|
2,892 |
|
|
|
42,555 |
|
Standardized Measure of Discounted Future Net Cash Flows
The information that follows has been developed pursuant to SFAS 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.
-78-
The following table sets forth the components of the standardized measure of discounted future net
cash flows for the years ended December 31, 2007, 2006 and 2005 (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash flows |
|
$ |
842,986 |
|
|
$ |
657,584 |
|
|
$ |
1,122,282 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future production costs |
|
|
(185,768 |
) |
|
|
(150,462 |
) |
|
|
(163,804 |
) |
Future development costs |
|
|
(80,656 |
) |
|
|
(64,417 |
) |
|
|
(55,212 |
) |
Future taxes on income |
|
|
(80,029 |
) |
|
|
(46,034 |
) |
|
|
(201,582 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
496,533 |
|
|
|
396,671 |
|
|
|
701,684 |
|
Discount to present value at 10 percent per annum |
|
|
(105,069 |
) |
|
|
(68,772 |
) |
|
|
(144,481 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net
cash flows |
|
$ |
391,464 |
|
|
$ |
327,899 |
|
|
$ |
557,203 |
|
|
|
|
|
|
|
|
|
|
|
The average expected realized price for natural gas in the above computations was $6.66, $5.69, and
$10.40 per Mcf at December 31, 2007, 2006, and 2005, respectively. The average expected realized
price used for crude oil in the above computations was $95.54, $63.32, and $59.37 per Bbl at
December 31, 2007, 2006, and 2005, respectively. No consideration has been given to the Companys
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, 2007, 2006 and 2005 (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Balance at Beginning of Period |
|
$ |
327,899 |
|
|
$ |
557,203 |
|
|
$ |
470,357 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of oil and natural gas, net of production costs |
|
|
(112,962 |
) |
|
|
(155,167 |
) |
|
|
(170,584 |
) |
Changes in sales & transfer prices, net of
production costs |
|
|
125,623 |
|
|
|
(243,150 |
) |
|
|
293,294 |
|
Revisions of previous quantity estimates |
|
|
25,751 |
|
|
|
(11,022 |
) |
|
|
(130,813 |
) |
Purchase of reserves-in-place |
|
|
|
|
|
|
2,393 |
|
|
|
|
|
Sale of reserves in-place |
|
|
(2,233 |
) |
|
|
|
|
|
|
|
|
Current year discoveries, extensions
and improved recovery |
|
|
32,939 |
|
|
|
30,710 |
|
|
|
107,393 |
|
Changes in estimated future
development costs |
|
|
(7,917 |
) |
|
|
(13,016 |
) |
|
|
(16,764 |
) |
Development costs incurred during the period |
|
|
8,526 |
|
|
|
18,051 |
|
|
|
10,654 |
|
Accretion of discount |
|
|
32,790 |
|
|
|
55,720 |
|
|
|
47,036 |
|
Net change in income taxes |
|
|
(14,451 |
) |
|
|
114,782 |
|
|
|
(49,453 |
) |
Change in production rates (timing) and other |
|
|
(24,501 |
) |
|
|
(28,605 |
) |
|
|
(3,917 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change |
|
|
63,565 |
|
|
|
(229,304 |
) |
|
|
86,846 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Period |
|
$ |
391,464 |
|
|
$ |
327,899 |
|
|
$ |
557,203 |
|
|
|
|
|
|
|
|
|
|
|
-79-
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 Meridians
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
2007. 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 2007 that could significantly affect these controls.
Managements Annual Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining a system of adequate internal control
over the Companys 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 Companys management assessed the effectiveness of the Companys system of internal control
over financial reporting as of December 31, 2007. In making this assessment, the Companys
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, 2007,
the Companys system of internal control over financial reporting was effective.
The Companys independent registered public accounting firm has issued a report on the
effectiveness of the Companys internal control over financial reporting, which report follows.
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial
Reporting
Board of Directors and Shareholders
The Meridian Resource Corporation
Houston, Texas
We have audited The Meridian Resource Corporations internal control over financial reporting as of
December 31, 2007, based on criteria established in Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The
Meridian Resource Corporations management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of internal control
over financial reporting, included in the accompanying Item 9A, Managements Annual Report on
Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the
Companys internal control over financial reporting based on our audit.
-80-
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, and testing and evaluating the
design and operating effectiveness of internal control based on the assessed risk. Our audit also
included performing such other procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our opinion.
A companys 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
companys 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 companys 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, The Meridian Resource Corporation maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2007, 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 Meridian Resource Corporation and
subsidiaries as of December 31, 2007 and 2006, 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, 2007, and our report dated March 14, 2008 expressed an
unqualified opinion thereon.
BDO Seidman, LLP
Houston, Texas
March 14, 2008
Item 9B. Other Information.
None.
-81-
PART III
The information required in Items 10, 11, 12, 13 and 14 is incorporated by reference to the
Companys definitive Proxy Statement to be filed with the SEC on or before April 29, 2008.
PART IV
Item 15. Exhibits and Financial Statement Schedules
|
(a) |
|
Documents filed as part of this report: |
|
|
1. |
|
Financial Statements included in Item 8: |
|
(i) |
|
Independent Registered Public Accounting Firms Report |
|
|
(ii) |
|
Consolidated Statements of Operations for each of the three years in
the period ended December 31, 2007 |
|
|
(iii) |
|
Consolidated Balance Sheets as of December 31, 2007 and 2006 |
|
|
(iv) |
|
Consolidated Statements of Cash Flows for each of the three years in
the period ended December 31, 2007 |
|
|
(v) |
|
Consolidated Statements of Changes in Stockholders Equity for each of
the three years in the period ended December 31, 2007 |
|
|
(vi) |
|
Consolidated Statements of Comprehensive Income (Loss) for each of the
three years in the period ended December 31, 2007 |
|
|
(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. |
|
|
|
3.1
|
|
Third Amended and Restated Articles of Incorporation of the Company
(incorporated by reference to the Companys 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 Companys 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 Companys 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 Companys 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 Companys Registration Statement on Form S-1, as amended (Reg. No. 33-65504)). |
-82-
|
|
|
*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 Companys
Annual Report on Form 10-K for the year ended December 31, 1991, as amended by the
Companys 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 Companys Annual
Report on Form 10-K for the year ended December 31, 1991, as amended by the
Companys 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 Companys 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 Companys 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 Companys Quarterly Report
on Form 10-Q for the quarter ended June 30, 1994). |
|
|
|
|
|
|
4.8
|
|
The Meridian Resource Corporation Directors Stock Option Plan
(incorporated by reference to Exhibit 10.5 of the Companys Annual Report on Form
10-K for the year ended December 31, 1991, as amended by the Companys 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 Companys 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 Companys 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 Companys Annual Report on Form 10-K for the
year ended December 31, 1991, as amended by the Companys 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 Companys Annual Report on
Form 10-K for the year ended December 31, 1995). |
-83-
|
|
|
*10.4
|
|
Employment Agreement dated August 18, 1993, between the Company and
Michael J. Mayell (incorporated by reference from the Companys 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 Companys
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
Companys 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 Companys
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 Companys 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys
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 Companys 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 |
-84-
|
|
|
|
|
California, N.A., as documentation agent, and the several lenders from time to
time parties thereto (incorporated by reference from the Companys Current
Report on Form 8-K dated December 23, 2004). |
|
|
|
**10.21
|
|
First Amendment to Credit Agreement, dated February 21, 2008, among
The Meridian Resource Corporation, Fortis Capital Corp., as administrative agent,
co-lead arranger and bookrunner; The Bank of Nova Scotia, as co-lead arranger and
syndication agent; Comerica Bank, US Bank NA, and Allied Irish Bank plc each in
their respective capacities as lenders. |
|
|
|
**21.1
|
|
Subsidiaries of the Company |
|
|
|
**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. |
-85-
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.
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THE MERIDIAN RESOURCE CORPORATION
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BY: |
/s/ JOSEPH A. REEVES, JR.
|
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Chief Executive Officer |
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(Principal Executive Officer)
Director and Chairman of the Board |
|
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Date: March 14, 2008
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.
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Name |
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Title |
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Date |
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BY:
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/s/ JOSEPH A. REEVES, JR.
Joseph A. Reeves, Jr.
|
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Chief Executive Officer
(Principal Executive Officer)
Director and Chairman
of the Board
|
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March 14, 2008 |
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BY:
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/s/ MICHAEL J. MAYELL
|
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President and Director
|
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March 14, 2008 |
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Michael J. Mayell |
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BY:
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/s/ LLOYD V. DELANO
|
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Chief Accounting Officer
|
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March 14, 2008 |
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Lloyd V. DeLano |
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BY:
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Director
|
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March 14, 2008 |
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E. L. Henry |
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BY:
|
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/s/ JOE E. KARES
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Director
|
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March 14, 2008 |
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Joe E. Kares |
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BY:
|
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/s/ GARY A. MESSERSMITH
|
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Director
|
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March 14, 2008 |
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Gary A. Messersmith |
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BY:
|
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/s/ DAVID W. TAUBER
|
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Director
|
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March 14, 2008 |
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David W. Tauber |
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BY:
|
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/s/ JOHN B. SIMMONS
|
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Director
|
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March 14, 2008 |
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John B. Simmons |
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BY:
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Director
|
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March 14, 2008 |
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Fenner R. Weller, Jr. |
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BY:
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|
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Director
|
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March 14, 2008 |
|
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C. Mark Pearson |
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-86-
|
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Name |
|
Title |
|
Date |
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BY:
|
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/s/ PAUL D. CHING
|
|
Director
|
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March 14, 2008 |
|
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Paul D. Ching |
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BY:
|
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/s/ G.M. LARBERG
|
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Director
|
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March 14, 2008 |
|
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G.M. Larberg |
|
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|
|
-87-
Exhibit
Index
|
|
|
3.1
|
|
Third Amended and Restated Articles of Incorporation of the Company
(incorporated by reference to the Companys 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys
Annual Report on Form 10-K for the year ended December 31, 1991, as amended by the
Companys 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 Companys Annual
Report on Form 10-K for the year ended December 31, 1991, as amended by the
Companys 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys Annual Report on Form
10-K for the year ended December 31, 1991, as amended by the Companys 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 Companys 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 Companys 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 Companys Annual Report on Form 10-K for the
year ended December 31, 1991, as amended by the Companys 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 Companys 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 Companys 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 Companys
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
Companys 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 Companys
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 Companys 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys
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 Companys 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 Companys Current
Report on Form 8-K dated December 23, 2004). |
|
|
|
**10.21
|
|
Amended and Restated Credit Agreement, dated February 21, 2008, among
The Meridian Resource Corporation, Fortis Capital Corp., as administrative agent,
co-lead arranger and bookrunner; The Bank of Nova Scotia, as co-lead arranger and
syndication agent; Comerica Bank, US Bank NA, and Allied Irish Bank plc each in
their respective capacities as lenders. |
|
|
|
**21.1
|
|
Subsidiaries of the Company |
|
|
|
**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. |