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
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For the fiscal year ended December 31, 2009
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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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)
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Registrant’s 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)
Common Stock, $0.01 par value
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(Name of each exchange on which registered)
New York Stock Exchange
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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
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No
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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
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No
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Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of regulation S-T (§232.405 of this chapter) during the preceding 12
months (or for such shorter period that the registrant was required to submit and post such files).
Yes
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No
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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes
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No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrant’s knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K.
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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
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Accelerated filer
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Non-accelerated filer
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Smaller reporting company
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(Do not check if a smaller reporting company)
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes
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No
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Aggregate market value of shares of common stock held by non-affiliates of the Registrant at June
30, 2009: $31,337,635
Number of shares of common stock outstanding at March 31, 2010: 92,475,527
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Form (Items 10, 11, 12, 13 and 14) is incorporated by
reference from the registrant’s Form 10-K/A to be filed on or before April 30, 2010.
THE MERIDIAN RESOURCE CORPORATION
INDEX TO FORM 10-K
2
PART I
Item 1. Business
General
The Meridian Resource Corporation (“Meridian,” the “Company,” “us,” “our,” or “we”) is an
independent oil and natural gas company that explores for, acquires and develops oil and natural
gas properties. The Company was incorporated in Texas in 1990, with headquarters located at 1401
Enclave Parkway, Suite 300, Houston, Texas 77077. The Company’s common stock is traded on the New
York Stock Exchange under the ticker symbol “TMR.” You can locate additional information, including
the Company’s filings with the Securities and Exchange Commission (“SEC”), on the internet at
www.tmrc.com and www.sec.gov.
Through our wholly owned subsidiaries, we hold interests primarily in the onshore oil and natural
gas regions of south Louisiana and Texas and offshore in the Gulf of Mexico. We treat all
operations as one line of business.
As of December 31, 2009, we had proved reserves of 75 Bcfe with a present value of future net cash
flows of approximately $139 million. Seventy percent (70%) of our proved reserves were natural gas
and approximately 64% were classified as proved developed. We own interests in 20 fields and 76
producing wells, and operated approximately 89% of our total production in 2009.
Recent developments, 2008-2009
The Company has historically been highly focused on exploration and reserve replacement. We relied
on our Amended and Restated Credit Agreement (as amended, the “Credit Facility”) for funds during
times of increased capital expenditures or decreased cash flow from operations, gradually
increasing the amount outstanding under the facility. Typically, until late 2008, we had not
always fully utilized the borrowing base. However, in the second half of 2008, global economic
events occurred which significantly impacted our industry and company. Prices for oil and natural
gas, which had recently reached historic highs, dropped precipitously. This was related to the
onset of a global recession, marked by extreme disruption in the credit markets which persisted
throughout 2009.
In December 2008, two events marked a significant change in our financial position, both related to
the Credit Facility. On December 19, 2008, our lenders under the facility (“Lenders”) reduced the
borrowing base to $95 million, the amount which was outstanding at that time, thus eliminating our
access to additional capital from that source. In addition, as of December 31, 2008, we
experienced a covenant default under the Credit Facility, based on a failure to meet a financial
ratio test. A test of the ratio of our current assets to current liabilities, as defined in the
Credit Facility, resulted in a value less than the required one to one ratio. As a result of the
default, and a cross-default which then occurred under our other principal debt arrangement, a
fixed term financing arrangement (the “rig note”), our ability to continue as a going concern was
in doubt. Accordingly, in our annual financial report on Form 10-K for 2008, our independent
registered public accounting firm included a “going concern” explanatory paragraph that expressed
substantial doubt as to the Company’s ability to continue as a going concern. The firm has also
included a “going concern” explanatory paragraph in this report for 2009.
The Company’s credit situation was exacerbated in April, 2009, when the Lenders reduced the
borrowing base under the Credit Facility from $95 million to $60 million. As a result, a $34.5
million payment to the Lenders for the borrowing base deficiency was due July 29, 2009, based on
the borrowings outstanding on that date. The Company did not have sufficient cash available to
repay the deficiency and, consequently, failed to pay such amount when due. Prior to July 29, 2009,
the Company was in covenant default under the terms of the Credit Facility; on and after that date
it was in covenant default and payment default as well.
3
We responded to these events by pursuing several courses of action beginning in late 2008. The
capital expenditures budget for 2009 was severely reduced to include drilling only two wells during
the first quarter, which had already been committed. In January 2009, the Company reduced its
workforce significantly in the Houston office and in the field. Further headcount reductions were
undertaken in 2009. Our operations group re-examined all field level expenses and initiated cost
reductions in the field. As a result, gross general and administrative expenses before
capitalization of a portion of those costs to the full cost pool, decreased $15.8 million, or 43%
from 2008 to 2009; year over year operating expenses decreased $6.7 million, or 28%; and capital
expenditures on an accrual basis decreased $105 million, or 89%. However, these savings were
offset by decreases in revenue of $59.4 million, or 40%, caused primarily by further decreases in
the price of natural gas, augmented by a decline in natural gas production. The decrease in oil
and natural gas prices also caused us to record significant non-cash impairments, or ceiling test
write-downs, to our oil and natural gas properties of $63.5 million in 2009, and $216.8 million in
2008.
We also worked to resolve the credit situation by soliciting offers from potential strategic
partners for a possible capital infusion, merger or sale of properties. Ultimately, we agreed to
the merger with Alta Mesa described below under “-Proposed Merger”.
As work continued through the year on a potential strategic transaction, our finance department
worked with our lenders with regard to the Credit Facility and the rig note. As a result, in
September 2009, we entered into forbearance agreements with both those parties, which would allow
us time to pursue an appropriate strategic transaction and ultimately provide the funds to repay
our borrowing base deficit. The forbearance period under these agreements has been extended
several times, and currently will terminate at the latest on May 31, 2010. The forbearance
agreements included requirements that the Company pay a total of $1.5 million in forbearance fees,
primarily to the Lenders under the Credit Facility, with a minor amount related to the rig note.
The forbearance agreements also increased our interest rates for “default interest,” and cost
approximately $2.3 million in legal and professional fees to originate and amend the various
agreements. In addition, certain paydowns of principal under the Credit Facility were required,
and are continuing at approximately $1 million per month. Through April 12, 2010, the Company has
paid $11.5 million pursuant to the terms of the Credit Facility forbearance agreement, and an
additional $1 million was paid on the rig note when we entered into that forbearance agreement.
We also worked to resolve two major obligations which encumbered our efforts to find a suitable
strategic partner for the Company. First, we entered into a forbearance agreement with a major
vendor, our drilling contractor, Orion Drilling Company, LLC (“Orion”). The Company has two
long-term drilling contracts with Orion at dayrates which exceed the current market, and we have
been unable to utilize the rigs since early 2009 when we significantly reduced our capital
expenditures. The forbearance agreement defers payment of the accrued shortfall in dayrate
payments (we receive credit against our obligation when third parties utilize the rigs) in exchange
for the possibility of transfer of title to our Company-owned drilling rig to Orion, prospectively
in 2013. The Company also has the option to retain title to the rig, however, and pay the
obligation in cash at that time.
The other obligation we addressed was an outstanding arbitration action from Shell Oil Company and
one of its subsidiaries (“Shell”) against the Company, regarding certain environmental claims on
properties we purchased from Shell in 1998. The amount claimed by Shell was substantial and
created significant uncertainty for potential buyers or partners of the Company. The action was
settled by an agreement in January 2010, under which the Company will pay Shell $5 million over a
five year term, beginning in 2010. The Shell agreement terminates and becomes void if the first
annual payment of $1 million is not made by May 1, 2010, unless extended at Shell’s discretion.
All of these forbearance and settlement agreements are interdependent, and have been constructed
such that they all may fail if the forbearance period under the Credit Facility forbearance
agreement terminates without payment of the borrowing base deficit. Several of the agreements
have already been extended, but no assurance can be provided that the
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parties will continue to extend their forbearance. Each of the Company’s counterparties under
these various agreements is individually motivated and although they have extended forbearance in
tandem thus far, they may not continue to do so.
Our creditors under the Credit Facility and the rig note have available to them various remedies if
they choose to terminate forbearance, including acceleration of payment of all principal and
interest and foreclosing on substantially all of our assets. In that event, we may be forced to
liquidate or to otherwise seek protection under federal bankruptcy laws, and there is no assurance
that in a bankruptcy proceeding the Meridian shareholders would receive any value for their shares.
Proposed Merger
As a result of our continued efforts to find a strategic partner for the Company, on December 22,
2009, the Company entered into an Agreement and Plan of Merger (“Merger Agreement”) with Alta Mesa
Holdings, LP (“Alta Mesa”) and Alta Mesa Acquisition Sub, LLC, a direct wholly owned subsidiary of
Alta Mesa (“Merger Sub”). Under the terms of the Merger Agreement, as amended, shareholders will
receive $0.33 per share of common stock, to be paid in cash, and Alta Mesa will assume the
Company’s debts and obligations. The Company would be merged into Alta Mesa Acquisition Sub, LLC
with the Merger Sub as the surviving entity. The Company’s stock would cease to be publicly
traded. The merger is subject to approval by holders of two thirds of the Company’s outstanding
shares of common stock; a shareholder meeting and vote are currently scheduled for April 28, 2010.
The Company filed a proxy statement regarding the proposed merger on February 8, 2010, in which
the Company’s board recommended that shareholders vote in favor of the merger. For further
information on the proposed merger, refer to the proxy statement.
The Company’s various forbearance agreements have been extended to allow for completion of the
merger, assuming shareholder approval is obtained. However, the most recent amendment to the
Credit Facility forbearance agreement also allows the Lenders to terminate the forbearance period
on or after February 28, 2010, without cause, so long as the decision to terminate is unanimous
among the Lenders.
There can be no assurance that the proposed merger will be completed. Approval by the shareholders
is not assured. Litigation was filed by a group of shareholders claiming the Company’s directors
breached their fiduciary duties in approving the merger. To avoid the risk of the litigation
delaying or adversely affecting the merger and to minimize the expense of defending the Company
against the lawsuit, in March 2010 management agreed to a proposed settlement of the litigation (see Note 7 of the
accompanying Notes to Consolidated Financial Statements for further information). There can be no
assurance the bank forbearance period will not be terminated by the Lenders before the proposed
merger can be completed. If the merger is not completed, we may be forced to liquidate or to
otherwise seek protection under federal bankruptcy laws.
The Merger Agreement with Alta Mesa includes a reimbursement clause under which the Company will
pay Alta Mesa’s reasonable costs of the merger, not to exceed $1 million, in case of termination of
the agreement under various circumstances, including expiration of the term on May 31, 2010 without
consummation of the merger, and also including termination of the Merger Agreement due to
non-approval in the shareholder vote. In addition to reimbursement of Alta Mesa’s costs, the
Company would pay Alta Mesa a $3 million termination fee if, among other reasons, the Company
terminates the Alta Mesa agreement and accepts another offer for the Company, so long as the
definitive agreement related to the other offer is entered into within nine months after
termination of the Merger Agreement with Alta Mesa. The termination fee would be payable no later
than two business days after consummation of the transaction which triggered the fee.
Alta Mesa has the right to terminate the Merger Agreement at any time, whether before or after
approval by the Company’s shareholders, upon payment of a termination fee of $3 million to the
Company. The terms of the Company’s
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Credit Facility forbearance agreement require any such termination payment received by Meridian to
be used to repay any outstanding balance under the Credit Facility.
Our oil and natural gas properties.
Our operations have historically focused on the onshore oil and natural gas regions in south
Louisiana and offshore in the Gulf of Mexico. While maintaining and exploiting our older
properties, until 2009 we had expanded exploration into new areas. Our objective was to replace our
reserves, and to strengthen our reserve base with longer lived properties from unconventional gas
plays in various regions of Texas, Oklahoma, and Kentucky. We also invested in conventional
horizontal gas plays in Texas.
In exploring these new areas, we invested in seismic data, geological research, acreage, and
drilling. Our strategy included building a large inventory of lease acreage to provide ourselves a
wide range of opportunities and ensure that new discoveries were highly repeatable.
After thorough testing and analysis, some of our new exploration areas showed only limited promise
and were dropped or sold. The most significant success has been in the East Texas Austin Chalk
formation, where our acreage is primarily in Polk County. We have 14 producing wells in this area.
We have pursued our historical strategy of limiting participations with partners; we operate many
of our more recent discoveries as well as our older properties.
Our properties in onshore Louisiana continue to be our most valuable assets, comprising the
majority of our reserve base and current cash flow. These mature fields represent 78% of our
proved reserves, and 80% of our estimated future net revenues. Although these fields are mature,
we continue to review them for any opportunities for increased or prolonged production.
In addition to these areas of interest, we acquired a number of acres of exploratory leases in
Karnes and Lavaca Counties of South Texas. The objective of these leases was the Austin Chalk
formation, as well as the Eagle Ford Shale, where others have had successful drilling. In 2009, we
sold our acreage in Lavaca County, retaining an overriding royalty interest, and sold down our
position in Karnes County. This augmented our cash flow while retaining for the Company the
opportunity to participate in Karnes County wells at up to a 25% working interest, plus an
overriding royalty, or receive an overriding royalty interest only, if we choose not to
participate. The Karnes County leases are currently beginning to be explored by an outside
operator. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of
Operations, Operations Overview” for further information on exploration in Karnes County.
We have sought to create a competitive advantage for the Company in the areas where we operate
through acquiring a large inventory of lease acreage and related seismic data, and by retaining
experienced geotechnical, land and operational staff. Although some of these advantages have been
eroded by the events of the past year, including the sale of some acreage and reductions in staff,
we believe we are still positioned to exploit the opportunities offered by our portfolio. We also
believe that our operational control over most of our properties adds to our competitive advantage,
through greater flexibility and control of costs. Our ability to exploit these advantages, however,
depends upon having access to additional capital to resume exploration and development activities,
and we do not currently have capital available for those activities.
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, 2009. The reserve volumes were prepared by
T. J. Smith & Company, Inc., independent reservoir engineers.
6
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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
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Production for the year ended
December 31, 2009
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Oil (MBbls)
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613
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184
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37
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834
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Natural Gas (MMcf)
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6,567
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690
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292
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7,549
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Reserves as of December 31, 2009
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Oil (MBbls)
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2,336
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1,309
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123
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3,768
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Natural Gas (MMcf)
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44,616
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6,363
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1,384
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52,363
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Estimated future net cash flows ($000)(1)
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$
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189,163
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Standardized measure of discounted future net cash flows ($000)(2)
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$
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138,955
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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 based on the average prices for the most
recent twelve months at December 31, 2009. Over the estimated life of the properties, the
prices average $59.94 per Bbl of oil and $3.97 per Mcf of natural gas.
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(2)
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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 zero. Income taxes are zero because the tax basis
of oil and natural gas properties exceeds the estimated future taxable income.
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Productive Wells
At December 31, 2009, 2008 and 2007, we held interests in the following productive wells:
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2009
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2008
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2007
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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
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Oil Wells
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27
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16
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34
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20
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33
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19
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Natural Gas Wells
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49
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24
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66
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37
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88
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43
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Total
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76
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40
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100
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57
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121
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62
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As of December 31, 2009, we own interests in 15 gross (3 net) wells in the Gulf of Mexico which are
outside operated and net to 2 oil wells and 1 natural gas well. In addition, of the total well
count for 2009, 1 well (1 net) is a multiple completion.
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, 2009. 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 prepared by T. J. Smith & Company, Inc., independent
reservoir engineers. Mr. T. J. Smith is the person primarily responsible for overseeing the
preparation of our annual reserve estimates. Mr. Smith is a graduate of Mississippi State
University with a Bachelor of Science degree in Petroleum Engineering. He has over 40 years’
experience with approximately 35 years focused on reserve evaluation. He is a member of the
Society of Petroleum Engineers and is a Registered Professional Engineer in the states of Texas and
Louisiana. Under new rules issued by the SEC, our estimated proved oil and natural gas
reserves as of December 31, 2009, were valued using average prices for the most recent twelve months.
The average is calculated using
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the first day of the month price for each of the twelve months that make up the
reporting period. As of December 31, 2008 and 2007, previous rules required that we value our
estimated proved oil and natural gas reserves using period end prices.
The reserve estimates for producing properties are based on production trends, material balance
calculations, analogy to comparable properties, or volumetric analysis. Performance methods are
preferred. Reserve estimates for developed non-producing properties and for undeveloped properties
are based primarily on volumetric analysis or analogy to offset production in the same field. Much
of the data utilized by Mr. Smith in preparing these reserve estimates is provided by the
engineering department of the Company, although it may be originally obtained from other
departments. The individual responsible for this process and for other aspects of reserve
estimation is a member of the Society of Petroleum Engineers with 10 years’ experience in reservoir
engineering. Various procedures are used to ensure the accuracy of the data provided to Mr.
Smith, including review processes. Changes in reserves are closely monitored from quarter to
quarter, as well as from year to year at the close of the fiscal year. Mr. Smith prepares our
annual reserves estimates, whereas quarterly estimates are internally prepared. The reconciliation
of reserves from the previous quarter to the current, which includes an explanation of all
significant changes, is reviewed by both the engineering department and upper management, including
our CEO. The relatively smaller size of the Company allows us to perform this analysis at the well
level.
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Proved Reserves at December 31, 2009
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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)
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Net Proved Reserves:
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Oil (MBbls)
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1,432
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1,139
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1,197
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3,768
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Natural Gas (MMcf)
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18,058
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14,502
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19,803
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52,363
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Natural Gas Equivalent (MMcfe)
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26,650
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21,336
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26,985
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74,971
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Estimated Future Net Cash Flows(1)
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$
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189,163
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Standardized Measure of
Discounted Future Net Cash
Flows(2)
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$
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138,955
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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 based on the most recent twelve months at
December 31, 2009. Over the estimated life of the properties, the prices average $59.94 per
Bbl of oil and $3.97 per Mcf of natural gas.
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(2)
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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 zero. Income taxes are zero because the tax basis
of oil and natural gas properties exceeds the book basis.
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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
8
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 as of December 31, 2009 are based on average prices for oil and
natural gas for the most recent twelve months, unless such prices or costs are contractually
determined at the date of the report. As of December 31, 2008 and 2007, the estimated discounted
future net revenues from estimated proved reserves are based on period-end prices, unless such
prices are contractually determined at the date of the report. Future operating and capital costs
are based on current levels as of the date of the report. 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.
Proved Undeveloped Reserves
The total of the Company’s proved undeveloped reserves (“PUD’s”) is 27 Bcfe, or approximately 36%
of total proved reserves at December 31, 2009. The undeveloped properties are primarily in our
East Texas area and in two of our mature fields in Louisiana and are the same or similar properties
to those reported in 2008, which totaled 29 Bcfe. Reductions in PUD’s from the prior year include
a decrease of 5.6 Bcfe at the outside-operated East Cameron 331/332 field offshore. We have
eliminated these non-operated reserves as there is substantial uncertainty as to their development
as the field has undergone numerous operator changes (again in 2009) and we have no firm plans to
develop them at this time. Other changes in PUD’s include a reduction of 3.7 Bcfe for several oil
wells that had been candidates for updip oil development; however, there is no certainty that these
updip locations will be oil. We have, for reserve purposes, estimated that the section will be
natural gas, and hence, the reserves are uneconomic and have been eliminated.
Increases to PUD’s were due primarily to upward revisions of estimates and the addition of several
new locations in East Texas totaling 5.8 Bcfe, based on new drilling and production information for
that area. Progress toward development of our portfolio of PUD’s was necessarily minimal during
2009, as we minimized capital spending due to our Credit Facility defaults.
Approximately 11.5 Bcfe of our PUD’s at December 31, 2009 originated more than five years ago.
Certain PUD’s in our mature fields in Louisiana have been included for more than five years,
because they have been planned as sidetracks and cannot be developed until the current producing
well bores have been depleted and abandoned. We have been exploring and developing our East Texas
acreage since 2005, and now have a total of 14 producing wells in that area.
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 2009, 2008 and 2007.
9
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|
|
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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
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Exploratory Wells
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December
31, 2009
|
|
|
1
|
|
|
|
—
|
|
|
|
1
|
|
|
|
0.2
|
|
|
|
—
|
|
|
|
0.2
|
|
|
Year ended December
31, 2008
|
|
|
6
|
|
|
|
4
|
|
|
|
10
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|
|
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2.7
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|
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3.1
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|
|
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5.8
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|
|
Year ended December
31, 2007
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13
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|
|
|
12
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|
|
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25
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|
|
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4.2
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|
|
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6.6
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|
|
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10.8
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|
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Development Wells
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December
31, 2009
|
|
|
1
|
|
|
|
—
|
|
|
|
1
|
|
|
|
0.7
|
|
|
|
—
|
|
|
|
0.7
|
|
|
Year ended December
31, 2008
|
|
|
7
|
|
|
|
4
|
|
|
|
11
|
|
|
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5.0
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|
|
|
3.2
|
|
|
|
8.2
|
|
|
Year ended December
31, 2007
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
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|
|
|
—
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|
Meridian had no wells in progress at December 31, 2009. In addition to the wells noted above, we
participated in two successful recompletion operations in 2009 and one sidetrack.
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 2009, 2008 and 2007.
|
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|
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|
|
|
|
|
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|
Year Ended December 31,
|
|
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|
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2009
|
|
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2008
|
|
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2007
|
|
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Production:
|
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|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
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|
|
834
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|
|
|
765
|
|
|
|
838
|
|
|
Natural gas (MMcf)
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|
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7,549
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|
|
|
9,369
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|
|
|
13,239
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|
|
Natural gas equivalent (MMcfe)
|
|
|
12,551
|
|
|
|
13,958
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|
|
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18,269
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|
|
Average Prices:
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|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
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$
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59.02
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|
|
$
|
83.18
|
|
|
$
|
64.70
|
|
|
Natural gas ($/Mcf)
|
|
$
|
5.30
|
|
|
$
|
9.07
|
|
|
$
|
7.29
|
|
|
Natural gas equivalent ($/Mcfe)
|
|
$
|
7.11
|
|
|
$
|
10.65
|
|
|
$
|
8.25
|
|
|
Production Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses ($/Mcfe)
|
|
$
|
1.40
|
|
|
$
|
1.74
|
|
|
$
|
1.55
|
|
|
Severance and ad valorem taxes ($/Mcfe)
|
|
$
|
0.53
|
|
|
$
|
0.70
|
|
|
$
|
0.52
|
|
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, 2009. 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.
10
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|
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|
|
|
|
December 31, 2009
|
|
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
Region
|
|
Gross
|
|
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Net
|
|
|
Gross
|
|
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Net
|
|
|
Louisiana
|
|
|
27,828
|
|
|
|
19,447
|
|
|
|
13,763
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|
|
|
11,942
|
|
|
Oklahoma
|
|
|
1,809
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|
|
|
699
|
|
|
|
—
|
|
|
|
—
|
|
|
Kentucky
|
|
|
—
|
|
|
|
—
|
|
|
|
27,094
|
|
|
|
22,615
|
|
|
Texas
|
|
|
14,805
|
|
|
|
8,593
|
|
|
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73,222
|
|
|
|
33,032
|
|
|
Gulf of Mexico
|
|
|
28,759
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|
|
|
5,613
|
|
|
|
5,000
|
|
|
|
765
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
73,201
|
|
|
|
34,352
|
|
|
|
119,079
|
|
|
|
68,354
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our undeveloped net acreage, including optioned acreage, expires during the next three years at the
rate of 10,400 acres in 2010, 45,400 acres in 2011, and 10,400 acres in 2012.
Employees
Meridian employs 45 full-time non-union employees and one part-time employee. We use contract
employees to a limited extent on an as-needed basis.
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 prices listed in industry publications,
less applicable transportation deductions, and the natural gas is sold at published indices, less
applicable transportation 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 2009, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Customer
|
|
2009
|
|
2008
|
|
2007
|
|
Shell Trading (U.S.)
|
|
|
28
|
%
|
|
|
21
|
%
|
|
|
14
|
%
|
|
Stone Energy Corporation
|
|
|
17
|
%
|
|
|
8
|
%
|
|
|
8
|
%
|
|
Superior Natural Gas
|
|
|
11
|
%
|
|
|
17
|
%
|
|
|
23
|
%
|
|
Crosstex Gulfcoast Marketing
|
|
|
10
|
%
|
|
|
14
|
%
|
|
|
16
|
%
|
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 $145.00 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, 2009, was $7.11 per Mcfe compared to $10.65
per Mcfe (each net of commodity hedge gains/losses) during the year ended December 31, 2008. The
volatile nature of energy
11
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 risk.
Competition
The oil and natural gas industry is highly competitive for prospects, acreage and capital. Our
competitors include numerous major and independent oil and natural gas companies, individual
proprietors, drilling and income programs and partnerships. Many of these competitors possess and
employ financial and personnel resources substantially greater than ours and may, therefore, be
able to define, evaluate, bid for and purchase more oil and natural gas properties. There is
intense competition in marketing oil and natural gas production, and there is competition with
other industries to supply the energy and fuel needs of consumers.
Regulation
The availability of a ready market for any oil and natural gas production depends on numerous
factors that we do not control. These factors include regulation of oil and natural gas production,
federal and state regulations governing environmental quality and pollution control, state limits
on allowable rates of production by a well 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
12
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 FERC’s 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 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
13
financial responsibility in the amount of $35 million ($10 million if the offshore facility is
located landward of the seaward boundary of a state) to cover liabilities related to a crude oil
spill for which such person is statutorily responsible. The amount of required financial
responsibility may be increased above the minimum amounts to an amount not exceeding $150 million
depending on the risk represented by the quantity or quality of crude oil that is handled by the
facility. The MMS has promulgated regulations that implement the financial responsibility
requirements of the OPA. Under the MMS regulations, the amount of financial responsibility required
for an offshore facility is increased above the minimum amount if the “worst case” oil spill volume
calculated for the facility exceeds certain limits established in the regulations.
The OPA also imposes other requirements, such as the preparation of an oil-spill contingency plan.
We have such a plan in place. Failure to comply with ongoing requirements or inadequate cooperation
during a spill may subject a responsible party to civil or criminal enforcement actions. We are not
aware of any action or event that would subject us to liability under the OPA and we believe that
compliance with the OPA’s financial responsibility and other operating requirements will not have a
material adverse impact on us.
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.
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
RCRA’s requirements because our operations generate minimal quantities of hazardous wastes. At
various times in the past, proposals have been made to amend RCRA to rescind the exemption that
excludes crude oil and natural gas exploration and production wastes from regulation as
14
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 (such requirements increased to 95% as a result of our defaults under
the Credit Facility). Our own oil and natural gas properties also typically are subject to royalty
and other similar non-cost-bearing interests customary in the industry.
We have acquired substantial portions of our 3-D seismic data through licenses and other similar
arrangements. Such licenses contain transfer and other restrictions customary in the industry.
Item 1A. Risk Factors
Each of the following risk factors could adversely affect our business, operating results and
financial condition. It is not possible to foresee or identify all such factors. Investors should
not consider this list an exhaustive statement of all risks and uncertainties. This report also
contains forward-looking statements that involve risks and uncertainties. Our actual results may
differ from those anticipated in these forward-looking statements as a result of both the risks
described below and factors described elsewhere in this report. You should read the section below
entitled “Forward-Looking Statements” for further discussion of these matters.
We are currently in payment default under our Credit Facility and in covenant default under certain
of the covenants in our Credit Facility. As a result of such defaults under the Credit Facility, we
are also in default under our drilling rig financing with CIT Group/Equipment Financing, Inc. due
to cross default provisions therein. It is unlikely that we will be able to return to compliance
with the Credit Facility and the drilling rig financing, and if we are unable to return to
compliance, our Lenders may exercise remedies that would have a material adverse effect on us and
our shareholders.
Under our Credit Facility, our borrowing base was redetermined effective April 30, 2009, at which
time the borrowing base was reduced to $60 million from $95 million. As of March 31, 2010, we have
outstanding indebtedness of $83 million under the Credit Facility, and a borrowing base payment
deficiency of $23 million. We do not currently have sufficient cash available to repay the
borrowing base deficiency.
As a result of the payment default for the borrowing base deficiency and financial covenant
defaults under the Credit Facility, we are also in default under our drilling rig financing with
CIT Group/Equipment Financing, Inc. (“CIT”) due to cross default provisions therein. We currently
owe approximately $6.2 million to CIT under the drilling rig financing, and we have additional
substantial financial obligations under related drilling rig contracts.
Under each of the Credit Facility and the rig note, remedies available to the creditors include
acceleration of all principal and interest payments. Although we have obtained short-term
forbearance agreements for each of these agreements in
15
default, we may not be able to comply with the conditions and covenants set forth in those
forbearance agreements. There can be no assurance that these forbearance agreements provide us the
time to resolve the deficiencies and forestall further default.
Our proposed merger with Alta Mesa may not be completed due to lack of shareholder approval or
other circumstances. We may not be able to sell assets on terms that we consider advantageous to
us and our shareholders, and capital on acceptable terms may not be available from other sources.
We may be unable to find an acceptable alternate candidate for a corporate merger or sale. If we
are unable to comply with the terms of the forbearance agreements, we will be in default under the
Credit Facility and the CIT financing, and we will be subject to the exercise of remedies by such
parties on account of such defaults. The exercise of such remedies may force us to liquidate or to
otherwise seek protection under federal bankruptcy laws. Such relief would materially and adversely
affect the Company and its shareholders.
As a result of our current lack of financial liquidity, we have received a “going concern”
modification to our independent registered public accounting firm’s opinion on our consolidated
financial statements.
Our independent registered public accounting firm has included an explanatory paragraph in their
report on our December 31, 2009 consolidated financial statements regarding their substantial doubt
as to our ability to continue as a going concern. Our lack of sufficient liquidity makes it more
difficult for us to secure additional financing or enter into strategic relationships on terms
acceptable to us, if at all, and may materially and adversely affect the terms of any financing
that we may obtain and our public stock price generally.
If the merger with Alta Mesa is not completed, we may be forced to liquidate or to otherwise seek
protection under federal bankruptcy laws.
If the merger is not consummated for any reason, our shareholders will not receive the merger
consideration and our current management under the direction of our board of directors will
continue to manage us as a stand-alone, independent business and the value of shares of our common
stock will continue to be subject to the risks and uncertainties identified herein and any updates
to those risks and uncertainties set forth in our subsequent filings. In addition, if the merger
is not completed, the forbearance agreements with our creditors and certain others would terminate,
allowing them to take action to enforce their rights with respect to the outstanding obligations.
Because substantially all of our assets are pledged as collateral under our Credit Facility, if our
Lenders declare an event of default, they would be entitled to foreclose on and take possession of
our assets, including our cash balances. In such an event, we may be forced to liquidate or to
otherwise seek protection under federal bankruptcy laws, and we can give you no assurance that in a
bankruptcy proceeding you would receive any value for your shares.
Our efforts to cure the deficiency under the Credit Facility may not be successful and we may be
required to seek bankruptcy protection under Chapter 11 of Title 11 of the United States Code (the
“Bankruptcy Code”). Even if our efforts are successful, we may still be required to seek protection
under the Bankruptcy Code to consummate a corporate transaction such as a merger or sale of the
Company.
There can be no assurance that we will be able to further extend the terms of the forbearance
agreements with the Lenders under the Credit Facility and CIT, nor the terms of other related
agreements. There can be no assurance that we will be able to comply with the terms of those
agreements. If we are unable to comply, and no further extensions are granted, the forbearance
periods end. Our creditors would then have various remedies available to them under the terms of
our debt agreements, including acceleration of all principal and interest. The exercise of such
remedies could potentially result in us seeking protection under the Bankruptcy Code. Even under a
proposed corporate transaction such as a merger or sale of the Company, we may still be required to
seek protection under the Bankruptcy Code to consummate such a transaction.
16
Under the priority scheme established by the Bankruptcy Code, pre-petition and post-petition
liabilities (including certain fees and interest) must be satisfied in full before stockholders are
entitled to receive any distribution or retain any property under a plan of reorganization. Amounts
that would need to be satisfied in full before any recovery by our stockholders would include,
among other things, $83 million currently owed in principal plus any accrued interest which is owed
under our Credit Facility and approximately $6.2 million owed under the rig note. In addition, as
of December 31, 2009, we have a working capital deficit of $6.6 million in addition to amounts owed
under the Credit Facility and the rig note, which generally represents amounts owed to vendors and
others which exceed cash and amounts collectible from customers and others. The total amount of
this liquidation preference is approximately $95.8 million and any recovery for our common
stockholders would only be available if the value available in any Bankruptcy Code proceeding
exceeded the amount required to repay all of our outstanding indebtedness and other obligations
(including trade payables and other unsecured claims). The ultimate recovery to creditors and/or
stockholders, if any, would not be determined until the confirmation of any plan of reorganization.
No assurance can be given as to what values, if any, would be ascribed in any potential Chapter 11
filing to each of these constituencies or what types or amounts of distributions, if any, they
would receive. If certain requirements of the Bankruptcy Code are met, a plan of reorganization can
be confirmed notwithstanding its rejection by equity holders and notwithstanding the fact that
equity holders do not receive or retain any property under the plan of reorganization.
If Meridian is forced to liquidate or to otherwise seek protection under federal bankruptcy laws, there is no assurance that in a bankruptcy proceeding the Meridian shareholders would receive any value for their shares.
Our common stock could be delisted from the New York Stock Exchange.
On December 4, 2008, we received notification from the New York Stock Exchange (“NYSE”) that the
Company had fallen below certain continued listing criteria that require a minimum average closing
price of $1.00 per share over 30 consecutive trading days. The NYSE temporarily suspended the
minimum average closing price requirement during part of the first half of 2009. We received
notification from the NYSE that our common stock would potentially be delisted if we were not in
compliance with that requirement by November 9, 2009. To date we have not been delisted from the
NYSE.
In addition, we are currently monitoring the Company’s compliance with another listing criterion.
This criterion requires that average market capital over 30 consecutive trading days must be at
least $15 million. Based on shares outstanding at March 31, 2010, the Company’s average market
capital decreases below this level when the stock price drops below approximately $0.16 per share.
Some closing prices in the first half of 2009 have been below this price. If the Company becomes
non-compliant with this criterion, our common stock would be subject to the NYSE’s delisting
procedures.
During 2008 and part of 2009, the Company was also non-compliant with an NYSE listing criterion
which requires that a majority of our directors be independent. However, after the voluntary
resignations of three non-independent directors effective October 13, 2009, the Company is now in
compliance with this listing criterion, and has been removed from the NYSE’s list of issuers
non-compliant with corporate governance listing standards on www.nyse.com. The resignations were
not the result of any disagreement with the Company on any matter relating to the Company’s
operations, policies or practices. Rather, the resigning directors agreed to resign to facilitate
compliance with NYSE rules for listed companies. The Company currently has seven directors, of
which four are independent.
In our communication with the NYSE they noted that we have not held a shareholders’ meeting in more
than 12 months, since August 6, 2008, and we are not in compliance with NYSE rules in that respect.
Finally, the NYSE also noted that it can take accelerated listing action in the event that our
common stock trades at levels viewed to be “abnormally low” over a sustained period of time, and
that it is continuing to evaluate the trading levels of our stock, including the price per share.
17
There can be no assurance that the stock of the Company will continue to be listed on the NYSE;
there can be no assurance that we will obtain listing on an alternate stock exchange or automated
quotation service in the event we are delisted from the NYSE. A delisting of our common stock could
materially and adversely affect, among other things, the liquidity and market price of our common
stock; the number of investors willing to hold or acquire our common stock; and our access to
capital markets to raise capital in the future.
Our Credit Facility has substantial restrictions and financial covenants. We are currently in
default under, and it is unlikely that we will be able to return to compliance with, certain of the
covenants in our Credit Facility, including our covenant to maintain a ratio of current assets to
current liabilities of not less than 1.0 to 1.0, and our covenant to deliver to our Lenders audited
financial statements for each fiscal year that do not have a “going concern” or like qualification
or exception.
Our current Credit Facility contains restrictive covenants that 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 downturns in our
business or in the general economy or to otherwise conduct necessary corporate activities. We are
also required to comply with certain financial covenants and ratios. We are currently in default
under certain of those covenants. Our ability to return to compliance and maintain compliance in
the future is unlikely. Our ability to comply with these covenants and restrictions will be
affected by the levels of cash flow from our operations and events or circumstances beyond our
control, including events and circumstances that may stem from the condition of financial markets
and commodity price levels.
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. This pledge of collateral to our Credit Facility Lenders would impair our ability to
obtain additional financing on favorable terms, or at all.
Our failure to comply with any of the restrictions and covenants under our Credit Facility results
in an event of default under the facility, which results in an event of default on our rig note as
well. The total balance outstanding under the rig note at December 31, 2009 is $6.2 million. The
remedies available to the lender under the rig note include acceleration of all principal and
interest payments. 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. Although these
defaults have been mitigated with short term forbearance agreements, the terms of forbearance under
the Credit Facility include the Lenders’ right to terminate forbearance without cause at any time
after February 28, 2010. We cannot predict what action they may take. Furthermore, forbearance
under the CIT agreement is tied to forbearance under the Credit Facility, such that if forbearance
under the Credit Facility is early terminated, then forbearance under the CIT agreement will also
terminate.
Our Credit Facility has periodic borrowing base redeterminations and we will have difficulty
maintaining our total borrowing base at the current level of $60 million at future
redeterminations, or maintaining or obtaining additional credit at similar terms, which could
adversely affect our operations.
As of December 31, 2009, we had outstanding indebtedness of $87.5 million ($ 83 million as of March 31, 2010) under our Credit
Facility, which exceeded the current limit to our borrowings under that facility. The Credit
Facility limits the amounts we can borrow to the borrowing base amount, determined by the Lenders
in their sole discretion. We have exceeded that amount and are currently in a deficit as to the
borrowing base. The borrowing base will be redetermined quarterly, and may be redetermined at our
request more frequently and by the Lenders in their sole discretion based on reserve reports
prepared by reserve engineers, together with, among other things, the oil and natural gas prices
existing at the time. The Lenders can unilaterally adjust the borrowing base and the borrowings
permitted to be outstanding under the Credit Facility. Any increase in the borrowing base requires
the consent of all the Lenders. Outstanding borrowings in excess of the borrowing base must be
repaid within 100 days, either in prescribed installments beginning 40 days after the incurrence of
a
18
borrowing base deficit, or all at once. This term has been mitigated with a short-term forbearance
agreement, which is subject to termination by the Lenders without cause after February 28, 2010.
Further redeterminations of the borrowing base have been postponed until termination of the
forbearance period. We may not have the financial resources in the future to make any mandatory
principal repayments required under the Credit Facility.
Because of the recent deterioration of the credit and capital markets, we may be unable to obtain
financing from sources other than our Credit Facility on acceptable terms or at all.
Global market and economic conditions have been, and continue to be, disruptive and volatile. The
debt and equity capital markets have been adversely affected by significant write-offs in the
financial services sector relating to subprime mortgages, and the re-pricing of credit risk in the
broadly syndicated market, among other things. These events have led to poor general economic
conditions.
In particular, the cost of capital in the debt and equity capital markets has increased
substantially, while the availability of funds from those markets has diminished significantly.
Also, concerns about the stability of financial markets generally and the solvency of
counterparties specifically have led to increases in the cost of obtaining money from the credit
markets as many lenders and institutional investors have increased interest rates, enacted tighter
lending standards and reduced funding and, in some cases, ceased to provide funding to borrowers.
In order to explore for and develop our oil and natural gas properties, we would need substantial
capital. Historically, we have relied heavily on our credit facilities for our capital needs. Due
to our default, the Credit Facility is not currently a source of funds for the Company. If we were
to raise capital from a source other than our Credit Facility, it is unlikely that additional
capital will be available to the extent required and on acceptable terms. We are currently unable
to fully execute our growth strategy, or take advantage of business opportunities, and we may be
unable to respond to competitive pressures, any of which could have a material adverse effect on
our results of operations and financial condition. We may be forced to sell a significant portion
of our assets in order to meet near-term contractual requirements. We may not be able to sell
assets on terms that we consider advantageous to the Company and our stockholders.
We have significant near-term contractual obligations, which we may not be able to meet; our
working capital is currently a net deficit.
We have significant near-term contractual obligations, including, but not limited to, two drilling
contracts. Our net working capital position at December 31, 2009, is a deficit of $100.2 million,
which includes $91.7 million of amounts due under the Credit Facility and the rig note which have
been reclassified as current as a result of the defaults noted elsewhere herein. Our cash flow and
working capital have been significantly impacted by the precipitous decrease in the prices we
received for oil and natural gas in the second half of 2008, and continuing through 2009. If we are
not able to increase cash flow, our ability to meet these obligations may be impacted, which could
have a material adverse effect on our results of operations and financial condition.
If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, we
may be required to take further write-downs.
In 2009 and 2008, we recorded significant non-cash impairments, or ceiling test write-downs, to our
oil and natural gas properties of $63.5 million and $216.8 million, respectively. There is a risk
that we will be required to take additional write-downs in the future, which would reduce our
earnings and shareholders’ equity. A write-down could occur when oil and natural gas prices are low
or if we have substantial downward adjustments to our estimated proved reserves, increases in our
estimates of development costs or deterioration in our exploration and development results.
Downward adjustments to proved reserves may result from decreasing prices of oil and natural gas,
as expected development reserves become uneconomic under revised conditions.
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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 rules of the SEC for the
full cost method of accounting, the net carrying value of oil and natural gas properties, less
related deferred taxes, is limited to the sum of the present value (10% discount rate) of the
estimated future after-tax net cash flows from proved reserves, as adjusted for the Company’s cash
flow hedge positions, and on current costs, plus the lower of cost or estimated fair value of
unproved properties, adjusted for related income tax effects. Under new rules issued by the SEC,
the estimated future net cash flows as of December 31, 2009, were determined using average prices
for the most recent twelve months. The average is calculated using the first day of the month
price for each of the twelve months that make up the reporting period. As of December 31, 2008 and
2007, previous rules required that estimated future net cash flows from proved reserves be based on
period end prices.
We review our oil and natural gas properties for impairment quarterly or whenever events and
circumstances indicate that the carrying value may not be recoverable. Once incurred, a writedown
of oil and natural gas properties is not reversible at a later date even if natural gas or oil
prices increase. Given the complexities associated with oil and natural gas reserve estimates and
the history of price volatility in the oil and natural gas markets, events may arise that would
require us to record additional impairments of the recorded carrying values associated with our oil
and natural gas properties.
In addition, our undeveloped leases are subject to expiration and forfeiture if not drilled. Our
drilling plans for these areas are subject to the availability of funds for exploration, which is
in turn affected by the risk factors described above. The leases may also be sold or assigned, but
the oil and natural gas industry is currently undergoing significant market disruptions, which may
make it difficult for us to extract value from these assets before expiration. Such circumstances
increase the risk of the transfer of unevaluated oil and natural gas properties to the full cost
pool where they would be subject to amortization or impairment.
In addition to the impairment of our oil and natural gas properties, we recorded a $6.7 million
non-cash impairment of our drilling rig in 2008. The rig was purchased in 2007, with the intention
of securing access to an appropriate rig and crew for our exploration efforts. Although we utilized
the rig for our own drilling during 2008, it has been utilized by others since then based on
short-term arrangements. Due to the continued volatility in the prices of oil and natural gas, and
its negative effect on the drilling industry, we will continue to review this asset for additional
impairment. We cannot predict whether additional impairment will be necessary.
The oil and natural gas markets are volatile and expose us to financial risks.
Our profitability, cash flow and the carrying value of our oil and natural gas properties are
highly dependent on the market prices of oil and natural gas. Historically, the oil and natural gas
markets have proven cyclical and volatile as a result of factors that are beyond our control. These
factors include changes in tax laws, the level of consumer product demand, weather conditions, the
price and availability of alternative fuels, the price and level of imports and exports of oil and
natural gas, worldwide economic, political and regulatory conditions, and action taken by the
Organization of Petroleum Exporting Countries.
Any significant decline in oil and natural gas prices or any other unfavorable market conditions
could have a material adverse effect on our financial condition and on the carrying value of our
proved reserves. Consequently, we may not be able to generate sufficient cash flows from operations
to meet our obligations and to make planned capital expenditures. Price declines may also affect
the measure of discounted future net cash flows of our reserves, a result that could adversely
impact the borrowing base under our Credit Facility and may increase the likelihood that we will
incur additional impairment charges on our oil and natural gas properties for financial accounting
purposes.
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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 Credit Facility requires that only Lenders under that agreement
may act as counterparties. Due to our default, the Lenders have not allowed us to execute any new
hedging agreements, and all our previous hedging contracts have now expired.
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. Moreover, our future
profitability will depend on our ability to attract and retain qualified personnel. Our interim
Chief Executive Officer, Paul D. Ching, is only contractually committed to serve us on a
month-to-month basis. There can be no assurance that we will be able to attract a qualified
individual to succeed him.
We compete against significant players in the oil and natural gas industry, and our failure in the
long-term to complete future property acquisitions successfully and generate commercial exploration
and development drilling opportunities could reduce our earnings and cause revenues to decline.
The oil and natural gas industry is highly competitive. Our ability to acquire additional
properties and to discover additional reserves depends on our ability to consummate transactions in
this highly competitive environment. We compete with major oil companies, other independent oil and
natural gas companies, and individual producers and operators. Many of these competitors have
access to greater financial and personnel resources than those to which we have access. Moreover,
the oil and natural gas industry competes with other industries in supplying the energy and fuel
needs of industrial, commercial and other consumers. Increased competition causing oversupply or
depressed prices could materially adversely affect our revenues.
The oil and natural gas markets are heavily regulated.
We are subject to various federal, state and local laws and regulations. These laws and regulations
govern safety, exploration, development, taxation and environmental matters that are related to the
oil and natural gas industry. To conserve oil and natural gas supplies, regulatory agencies may
impose price controls and may limit our production. Certain laws and regulations require drilling
permits, govern the spacing of wells and the prevention of waste, and limit the total number of
wells drilled or the total allowable production from successful wells. Other laws and regulations
21
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 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
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from blowouts, cratering or explosions.
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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.
Our operations entail inherent casualty risks for which we may not have adequate insurance.
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.
22
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.
In addition, disruptions in financial markets have affected the credit standing of various
insurance companies. Our ability to collect on our current or future claims and to obtain insurance
at a price acceptable to us may be adversely affected by such general financial conditions, which
are beyond our control.
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 effectively market our oil and natural gas production.
We may encounter difficulties in the marketing of our oil and natural gas production. Effective
marketing depends on factors such as the existing market supply and demand for oil and natural gas
and the limitations imposed by governmental regulations. The proximity of our reserves to pipelines
and the available capacity of such pipelines and other transportation, processing and refining
facilities also affect our marketing efforts. Even if we discover hydrocarbons in commercial
quantities, a substantial period of time may elapse before we begin commercial production. If
pipeline facilities in an area are insufficient, we may have to wait for the construction or
expansion of pipeline capacity before we can market production from that area. Another risk lies in
our ability to negotiate commercially satisfactory arrangements with the owners and operators of
production platforms in close proximity to our wells. Also, natural gas wells may be shut in for
lack of market demand or because of the inadequate capacity or unavailability of natural gas
pipelines or gathering systems.
We are dependent on other operators who influence our productivity.
We have limited influence over the nature and timing of exploration and development on oil and
natural gas properties we do not operate, including limited control over the maintenance of both
safety and environmental standards. In 2009, 11% of our production and 13% of our reserves were
outside operated. The operators of those properties may 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, which 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 remain at present levels or decline further, 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
23
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 owner’s share of the project
costs.
Our 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 develop new exploration prospects will inhibit our growth.
From time to time, our business strategy has included acquisition and development of new
exploration prospects that complement or expand our prospect inventory. We may not be able to
identify attractive prospect opportunities. Even if we do identify attractive opportunities, we may
not have the capital to be able to complete the acquisition of the prospect or to do so on
commercially acceptable terms. If we do acquire additional prospects, we may not realize the
anticipated benefits of any such acquisition, due to lack of available capital.
Terrorist attacks and threats or actual war may negatively affect our business, financial condition
and results of operations.
Our business is affected by general economic conditions and fluctuations in consumer confidence and
spending, which can decline as a result of numerous factors outside of our control, such as
terrorist attacks and acts of war. Terrorist attacks against U.S. targets, as well as events
occurring in response to or in connection with them, rumors or threats of war, actual conflicts
involving the United States or its allies, or military or trade disruptions impacting our suppliers
or our customers, may adversely impact our operations. Strategic targets such as energy-related
assets may be at greater risk of future terrorist attacks than other targets in the United States.
These occurrences could have an adverse impact on energy prices, including prices for our natural
gas and crude oil production. In addition, disruption or significant increases in energy prices
could result in government-imposed price controls. It is possible that any or a combination of
these occurrences could have a material adverse effect on our business, financial condition and
results of operations.
Forward-Looking Information
From time to time, we may make certain statements that contain “forward-looking” information as
defined in the Private Securities Litigation Reform Act of 1995 and that involve risk and
uncertainty. These forward-looking statements may include, but are not limited to exploration and
seismic acquisition plans, anticipated results from current and future exploration prospects,
future capital expenditure plans, anticipated results from third party disputes and litigation,
expectations regarding compliance with our Credit Facility, the anticipated results of wells based
on logging data and production tests, future sales of production, earnings, margins, production
levels and costs, market trends in the oil and natural gas industry and the exploration and
development sector thereof, environmental and other expenditures and various business trends.
Forward-looking statements may be made by management orally or in writing including, but not
limited to, this Risk Factors section, the Management’s Discussion and Analysis of Financial
Condition and Results of
24
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.
Producing Properties
For information regarding Meridian’s properties, see “Item 1. Business” above.
|
|
|
|
|
Item 3.
|
|
Legal Proceedings
|
Default under Credit Agreement.
As described below under “Management’s Discussion and Analysis of
Financial Condition and Result of Operations-Liquidity and Capital Resources-Credit Facility and-
Rig Note,” the Company is in default under the terms of the Credit Facility and the rig note.
Defaults under the Credit Facility include a borrowing base deficiency, which was $27.5 million as
of December 31, 2009 ($23 million as of March 31, 2010) as well as defaults under certain
covenants. Default under the rig note is not due to payment deficiency, but to a cross-default
resulting from the defaults under the Credit Facility. The Company currently has in place
short-term forbearance agreements for each of these agreements in default and does not have
sufficient cash available to repay the shortfall under the Credit Facility. Should the forbearance
periods expire without extension or resolution of the deficiency and covenant defaults, the
remedies available to lenders under each of these agreements include acceleration of all principal
and interest payments. Accordingly, all debts noted above, including the rig note, have been
classified as current in the Consolidated Balance Sheets as of December 31, 2008 and 2009. The
Company is currently unable to predict what further actions the Lenders may pursue; therefore, the
Company has not provided for this matter in its financial statements at December 31, 2009, other
than to reclassify all outstanding debt as current.
H. L. Hawkins litigation
. In December 2004, the estate of H.L. Hawkins filed a claim against
Meridian for damages “estimated to exceed several million dollars” for Meridian’s alleged gross
negligence, willful misconduct and breach of fiduciary duty under certain agreements concerning
certain wells and property in the S.W. Holmwood and E. Lake Charles Prospects in Calcasieu Parish
in Louisiana, as a result of Meridian’s satisfying a prior adverse judgment in favor of Amoco
Production Company. Mr. James Bond 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. Bond’s employment ended
with Mr. Hawkins, Jr., and his companies, 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 Chief Operating Officer of the Company at the time. A
hearing was held before Judge Kay Bates on April 14, 2008. Judge Bates granted Hawkins’ Motion
finding that Meridian was estopped from arguing that it did not breach its contract with Hawkins as
a result of the United States Fifth Circuit’s decision in the
Amoco
litigation. Meridian disagrees
with Judge Bates’ ruling but the Louisiana First Court of Appeal declined to hear Meridian’s writ
requesting the court overturn Judge Bates’ ruling. Meridian filed a motion with Judge Bates asking
that the ruling be made a final judgment which would give Meridian the right to appeal immediately;
however, the Judge declined to grant the motion, allowing the case to proceed to trial. 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 Meridian’s
actions were not grossly negligent, but were within the business judgment rule. Since Mr. Bond’s
death, a pleading has been filed substituting the proper party for Mr. Bond. The Company is unable
to express
25
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, 2009.
Title/lease disputes.
Title and lease disputes may arise in the normal course of the Company’s
operations. These disputes are usually small but could result in an increase or decrease in
reserves once a final resolution to the title dispute is made.
Environmental litigation.
Various landowners have sued Meridian (along with numerous other oil
companies) in lawsuits concerning several fields in which the Company has had operations. The
lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and
punitive damages for alleged breaches of mineral leases and alleged failure to restore the
plaintiffs’ lands from alleged contamination and otherwise from the Company’s oil and natural gas
operations. In some of the lawsuits, Shell Oil Company and SWEPI LP (together, “Shell”) have
demanded contractual indemnity and defense from Meridian based upon the terms of the two
acquisition agreements 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 fields 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. On December 9, 2008 Shell sent Meridian a letter reiterating its demand for indemnity
and making claims of amounts which were substantial in nature and if adversely determined, would
have a material adverse effect on the Company. Shell initiated formal arbitration proceedings on
May 11, 2009, seeking relief only for the claimed costs and expenses arising from one of the two
acquisition agreements between Shell and Meridian. Meridian denies that it owes any indemnity under
either of the two acquisition agreements; however, the Company and Shell entered into a settlement
agreement on January 11, 2010. Under the terms of the settlement, the Company will pay Shell $5
million in five equal annual payments beginning in 2010 upon the closing of a sale of the assets or
equity interest in the Company to a third party (such as the merger with Alta Mesa), or at an
earlier date should Meridian be able. Meridian will also transfer title to certain land the
Company owns in Louisiana and an overriding royalty interest of minor value. In return, Shell will
release Meridian from any indemnity claim arising from any current or historical claim against
Shell, and will release Meridian’s indemnity obligation with respect to any future claim on all but
a small subset of the properties acquired pursuant to the acquisition agreements related to the
fields. The settlement agreement will terminate on May 1, 2010 if the first payment and the land
and overriding royalty interest transfer have not been made, or unless extended at the discretion
of Shell. The Company recorded $4.2 million in expense in the fourth quarter of 2009 to recognize
the estimated value of the proposed settlement, including the historical cost of the land and
discounting the cash payments to present value.
Other than with regard to the Shell matter, the Company is unable to express an opinion with
respect to the likelihood of an unfavorable outcome of the various environmental claims or to
estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, the
Company has not provided any amount for these claims in its financial statements at December 31,
2009.
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.
Property tax litigation.
In August, 2009, Gene P. Bonvillain, the tax assessor for Terrebonne
Parish, Louisiana, filed a lawsuit against the Company, alleging under-reporting and underpayment
of parish property taxes for the years 1998-2008. The claims, which are very similar to thirty
other cases filed by Bonvillain against other oil and natural gas companies, allege that certain
facilities or other property of the Company were improperly omitted from annual self-reporting tax
forms submitted to the parish for the years 1998-2008, and that the properties Meridian did report
on such forms were improperly undervalued and mischaracterized. The claims include recovery of
delinquent taxes in the amount
26
of $3.5 million, which the claimant advises may be revised upward, and general fraud charges
against the Company. All thirty-one similar cases have been consolidated in U. S. District Court
for the Eastern District of Louisiana.
Meridian denies the claims and expects to file a motion to dismiss the case, which it considers to
be without merit. Meridian asserts that Mr. Bonvillain has no legal basis for filing litigation to
collect what are, in essence, additional taxes based on reassessed property values. Furthermore,
Meridian asserts that the fraud element of the case is insufficiently supported. Meridian intends
to vigorously defend this action. 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, 2009.
Shareholder litigation
. On January 8, 2010 Mr. Eliezer Leider, a purported Company shareholder,
filed a derivative lawsuit filed on behalf of the Company,
Leider, derivatively on behalf of The
Meridian Resource Corporation v. Ching, et al.
in Harris County District Court
.
Defendants were
the Company’s directors, Alta Mesa Holdings, LP, and Alta Mesa Acquisition Sub, LLC. Leider
alleged that the Company’s directors breached their fiduciary duties in approving the merger
transaction with Alta Mesa and he requested, but was denied, a temporary restraining order against
the Company. This lawsuit was consolidated with another, similar one from Mr. Jeremy Rausch, which
was a class action lawsuit. Counsel for Leider was appointed lead counsel. On March 23, 2010, the
parties agreed in principle to settle the now-consolidated
Leider
action. The settlement is
conditioned on, among other things, approval of the merger by Meridian’s shareholders. Under the
terms of the proposed settlement, all claims relating to the Merger Agreement and the merger will
be dismissed on behalf of Meridian’s stockholders. As part of the proposed settlement, the defendants have
agreed not to oppose plaintiff’s counsel’s request to the court to be paid up to $164,000 for their
fees and expenses and up to $1,000 as an incentive award for plaintiff Leider. Any payment of fees,
expenses, and incentives is subject to final approval of the settlement and such fees, expenses,
and incentives by the court. The proposed settlement will not affect the amount of merger
consideration to be paid to Meridian’s shareholders in the merger or change any other terms of the
merger or Merger Agreement. Expenses of the proposed settlement are expected to be recorded in the first
quarter of 2010.
PART II
|
|
|
|
|
Item 5.
|
|
Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of
Equity Securities
|
Price Range of Common Stock and Dividend Policy
Our common stock is traded on the New York Stock Exchange under the symbol “TMR.” The following
table sets forth, for the periods indicated, the high and low sale prices per share for the common
stock as reported on the New York Stock Exchange:
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
|
Low
|
|
|
2009
:
|
|
|
|
|
|
|
|
|
|
First quarter
|
|
$
|
0.70
|
|
|
$
|
0.13
|
|
|
Second quarter
|
|
|
0.67
|
|
|
|
0.20
|
|
|
Third quarter
|
|
|
0.57
|
|
|
|
0.26
|
|
|
Fourth quarter
|
|
|
0.43
|
|
|
|
0.18
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
:
|
|
|
|
|
|
|
|
|
|
First quarter
|
|
$
|
1.88
|
|
|
$
|
1.32
|
|
|
Second quarter
|
|
|
3.30
|
|
|
|
1.45
|
|
|
Third quarter
|
|
|
3.29
|
|
|
|
1.66
|
|
|
Fourth quarter
|
|
|
1.90
|
|
|
|
.55
|
|
27
The closing sale price of the common stock on April 12, 2010, as reported on the New York Stock
Exchange Composite Tape, was $0.3075. As of April 12, 2010, we had approximately 679 shareholders
of record.
On December 4, 2008, we received notification from the New York Stock Exchange (“NYSE”) that the
Company had fallen below certain continued listing criteria that require a minimum average closing
price of $1.00 per share over 30 consecutive trading days. The NYSE temporarily suspended the
minimum average closing price requirement during part of the first half of 2009. We received
notification from the NYSE that our common stock would potentially be delisted if we were not in
compliance with that requirement by November 9, 2009. To date, we have not been delisted from the
NYSE.
In addition, we are currently monitoring the Company’s compliance with another listing criterion.
This criterion requires that average market capital over 30 consecutive trading days must be at
least $15 million. Based on shares outstanding at March 31, 2010, the Company’s average market
capital decreases below this level when the stock price drops below approximately $0.16 per share.
Some closing prices in the first half of 2009 have been below this price. If the Company becomes
non-compliant with this criterion, our common stock would be subject to the NYSE’s delisting
procedures.
The Company was also non-compliant with an NYSE listing criterion which requires that a majority of
our directors be independent. However, after the voluntary resignations of three non-independent
directors effective October 13, 2009, the Company is now in compliance with this listing criterion,
and the Company has been removed from the NYSE’s list of issuers non-compliant with corporate
governance listing standards on www.nyse.com. The resignations were not the result of any
disagreement with the Company on any matter relating to the Company’s operations, policies or
practices. Rather, the resigning directors agreed to resign to facilitate compliance with NYSE
rules for listed companies. The Company currently has seven directors, of which four are
independent.
In our communication with the NYSE they noted that we have not held a shareholders’ meeting in more
than 12 months, since August 6, 2008, and we are not in compliance with the NYSE rules in that
respect.
Finally, the NYSE also noted that it can take accelerated listing action in the event that our
common stock trades at levels viewed to be “abnormally low” over a sustained period of time, and
that it is continuing to evaluate the trading levels of our stock, including the price per share.
There can be no assurance that the stock of the Company will continue to be listed on the NYSE;
there can be no assurance that we will obtain listing on an alternate stock exchange or automated
quotation service in the event we are delisted from the NYSE. A delisting of our common stock could
materially and adversely affect, among other things, the liquidity and market price of our common
stock; the number of investors willing to hold or acquire our common stock; and our access to
capital markets to raise capital in the future.
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 repayment
of debt. We also are currently restricted under our Credit Facility from paying any cash dividends
on common stock, and from the purchase of shares of common stock. See “Item 7. Management’s
Discussion and Analysis of Financial Condition and Results Operations — Liquidity and Capital
Resources.”
28
The following stock price performance graph is intended to allow review of stockholder
returns, expressed in terms of the appreciation of the Company’s common stock relative to two
comparison stock performance indices. The graph compares the yearly percentage change in the
cumulative total stockholder return on the Company’s common stock with the cumulative total return
of the NYSE Composite Index and a peer group index from December 31, 2004 through December 31,
2009.
COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN AMONG THE MERIDIAN
RESOURCE CORPORATION, NYSE COMPOSITE INDEX AND PEER GROUP INDEX
ASSUMES $100 INVESTED ON DEC. 31, 2004
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR ENDING DEC. 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ending December 31,
|
|
|
Company/Index/Market
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
|
|
|
|
Meridian Resource Corporation
|
|
$
|
100.00
|
|
|
$
|
69.42
|
|
|
$
|
51.07
|
|
|
$
|
29.92
|
|
|
$
|
9.42
|
|
|
$
|
4.38
|
|
|
NYSE Composite Index
|
|
$
|
100.00
|
|
|
$
|
109.36
|
|
|
$
|
131.75
|
|
|
$
|
143.43
|
|
|
$
|
87.12
|
|
|
$
|
111.76
|
|
|
Peer Group Index
|
|
$
|
100.00
|
|
|
$
|
143.85
|
|
|
$
|
160.16
|
|
|
$
|
214.41
|
|
|
$
|
110.43
|
|
|
$
|
152.74
|
|
The Peer Group Index consists of the common stocks of the following companies:
Cabot Oil & Gas Corporation, Chesapeake Corporation, Comstock Resources, Inc., Denbury Resources,
Inc., Energy Partners, Ltd., Petroquest Energy, Inc., St. Mary Land & Exploration Company, Stone
Energy Corporation, and Swift Energy Company.
29
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth information as of December 31, 2009, with respect to our
compensation plans (including individual compensation arrangements) under which equity securities
are authorized for issuance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c)
|
|
|
|
|
(a)
|
|
|
|
|
|
|
Number of securities
|
|
|
|
|
Number of
|
|
|
(b)
|
|
|
remaining available
|
|
|
|
|
securities to
|
|
|
Weighted-
|
|
|
for
|
|
|
|
|
be issued upon
|
|
|
average
|
|
|
future issuance under
|
|
|
|
|
exercise
|
|
|
exercise price of
|
|
|
equity compensation
|
|
|
|
|
of outstanding
|
|
|
outstanding
|
|
|
plans
|
|
|
|
|
options,
|
|
|
options,
|
|
|
(excluding securities
|
|
|
|
|
warrants and
|
|
|
warrants and
|
|
|
reflected in column
|
|
|
Plan Category
|
|
rights
|
|
|
rights
|
|
|
(a))
|
|
|
Equity compensation plans approved by security holders
|
|
|
2,276,998
|
|
|
$
|
0.36
|
|
|
|
4,140,000
|
|
|
Equity compensation plans not approved by security holders
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,276,998
|
|
|
$
|
0.36
|
|
|
|
4,140,000
|
|
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,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
|
(In thousands, except prices and per share information)
|
|
|
A. Summary of Operating Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
834
|
|
|
|
765
|
|
|
|
838
|
|
|
|
859
|
|
|
|
882
|
|
|
Natural gas (MMcf)
|
|
|
7,549
|
|
|
|
9,369
|
|
|
|
13,239
|
|
|
|
18,170
|
|
|
|
20,490
|
|
|
Natural gas equivalent (MMcfe)
|
|
|
12,551
|
|
|
|
13,958
|
|
|
|
18,269
|
|
|
|
23,323
|
|
|
|
25,781
|
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
59.02
|
|
|
$
|
83.18
|
|
|
$
|
64.70
|
|
|
$
|
55.73
|
|
|
$
|
39.29
|
|
|
Natural gas ($/Mcf)
|
|
|
5.30
|
|
|
|
9.07
|
|
|
|
7.29
|
|
|
|
7.77
|
|
|
|
7.84
|
|
|
Natural gas equivalent ($/Mcfe)
|
|
|
7.11
|
|
|
|
10.65
|
|
|
|
8.25
|
|
|
|
8.11
|
|
|
|
7.57
|
|
|
B. Summary of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
89,254
|
|
|
$
|
149,165
|
|
|
$
|
152,178
|
|
|
$
|
190,957
|
|
|
$
|
195,696
|
|
|
Depletion and depreciation
|
|
|
37,102
|
|
|
|
72,072
|
|
|
|
77,076
|
|
|
|
106,067
|
|
|
|
97,354
|
|
|
Net earnings (loss)(1)(2)
|
|
|
(72,636
|
)
|
|
|
(209,886
|
)
|
|
|
7,137
|
|
|
|
(73,884
|
)
|
|
|
27,849
|
|
|
Net earnings (loss) per share:(1)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.79
|
)
|
|
$
|
(2.30
|
)
|
|
$
|
0.08
|
|
|
$
|
(0.84
|
)
|
|
$
|
0.33
|
|
|
Diluted
|
|
|
(0.79
|
)
|
|
|
(2.30
|
)
|
|
|
0.08
|
|
|
|
(0.84
|
)
|
|
|
0.31
|
|
|
Dividends per:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common share
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Redeemable preferred share
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2.60
|
|
|
Weighted average common shares outstanding — basic
|
|
|
92,465
|
|
|
|
91,382
|
|
|
|
89,307
|
|
|
|
87,670
|
|
|
|
84,527
|
|
|
C. Summary Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
183,130
|
|
|
$
|
304,575
|
|
|
$
|
483,775
|
|
|
$
|
467,895
|
|
|
$
|
555,802
|
|
|
Long-term obligations, inclusive of current maturities
|
|
|
93,666
|
|
|
|
103,849
|
|
|
|
75,000
|
|
|
|
75,000
|
|
|
|
75,000
|
|
|
Stockholders’ equity
|
|
|
40,744
|
|
|
|
122,511
|
|
|
|
325,430
|
|
|
|
320,797
|
|
|
|
377,565
|
|
|
|
|
|
|
(1)
|
|
Applicable to common stockholders.
|
|
|
|
(2)
|
|
Includes the impact (before tax) of impairments of long-lived assets of $63.5 million,
$223.5 million and $134.9 million, in 2009, 2008, and 2006 respectively.
|
30
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
Meridian is an independent oil and natural gas company that explores for, acquires and develops oil
and natural gas properties. 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. In
recent years, the Company’s goal has been to replace our reserves, and to strengthen our reserve
base with longer lived properties from our new areas of exploration.
However, economic developments in 2008 and 2009, most importantly the precipitous decrease in the
prices of oil and natural gas in the second half of 2008, significantly impacted the Company’s
financial position. At December 31, 2008, our current ratio failed to meet a covenant contained in
our Credit Facility, resulting in covenant default. In April 2009, our Lenders under the Credit
Facility reduced our borrowing base from $95 million, which was fully drawn at the time, to $60
million. As a result, after a 90 day period, the Company was unable to pay the $35 million deficit
and has been in payment default under the Credit Facility since July 29, 2009. The default under
the Credit Facility resulted in a cross-default under our other primary lending arrangement, the
fixed term rig note.
The following discussion points are organized around the issues upon which our management is most
highly focused, as well as the industry conditions that most influence our performance; the
discussion contains information relating to the past year’s performance as well as to our present
circumstances and expectations for the coming fiscal year. Following that discussion, we provide
the customary year to year analysis of our results of operations, and a review of our liquidity.
Industry and economic conditions
. The oil and gas industry has experienced significant volatility
in the past two years. After several years of rising demand, costs of exploration and development
had risen in tandem with the prices for energy products. These economic trends encouraged
exploration in more marginal areas at higher costs. However, in the second half of 2008, energy
prices dropped precipitously. West Texas Intermediate traded on the spot market at approximately
$145 per Bbl in July 2008; by December 31, 2008, the price was approximately $40 per Bbl. Natural
gas similarly reached a spot market high in July 2008 of over $13 per mmbtu, but by year-end was
trading at approximately $6 per mmbtu. In 2009, prices have experienced some strengthening, but
are still extremely volatile. Oil prices ranged from a low of $34 to a high of $81 for West Texas
Intermediate during the year. Gas futures prices ranged from $2.51 to $6.07 during 2009.
Global capital markets have experienced significant disruptions in 2008 and continuing in 2009,
resulting in the closing or restructuring of numerous large financial institutions. Extreme
uncertainty about creditworthiness, liquidity and interest rates, as well as the global economic
recession, continue to limit credit availability. Typically, as is the case with Meridian,
exploration and production companies borrow against the value of their proved reserves. When the
market value of those reserves decreases due to energy price fluctuations, their ability to borrow
declines; coupled with the recently tightened credit environment, exploration and production
companies are experiencing a significant loss of credit availability, and Meridian is no exception.
The decrease in oil and natural gas prices has also caused operating cash flows to decline across
the industry and at Meridian; coupled with the loss of credit access, Meridian’s cash resources
have been extremely stressed.
31
Credit agreements
. As noted above, since December 2008 we have been in default under both our
primary lending arrangements, the Credit Facility and the rig note. During 2009, management was
strongly focused on resolving these defaults. In September 2009, the Company successfully
negotiated forbearance agreements under each of the two debt agreements. The forbearance period
has been extended to May 31, 2010 to provide time to complete the merger with Alta Mesa. Under the
terms of the forbearance agreement, the Lenders have the right to terminate the agreement without
cause at any time after February 28, 2010, provided that all parties in the lending group
unanimously agree.
As of December 31, 2009, our net working capital reflects a deficit of approximately $100.2
million, which includes $91.7 million of amounts due under these two debt agreements which have
been reclassified as current as a result of the defaults noted above. The outstanding balances
under these debt agreements at December 31, 2009 are $87.5 million for the credit facility, and
$6.2 million for the rig note.
Proposed merger
. As described in Item 1 — Business — Proposed Merger, the board of directors has
approved a Merger Agreement, as amended, with Alta Mesa, under which shareholders will receive
$0.33 per share of common stock in cash and Alta Mesa will assume the liabilities of the Company,
including outstanding amounts under the debt agreements in default. The merger is subject to
approval by holders of two-thirds of our outstanding shares; a shareholder meeting and vote are
currently scheduled for April 28, 2010. The board of directors has recommended that shareholders
vote in favor of the merger. There can be no assurance that the shareholders will approve the
transaction. Some shareholders, in fact, filed litigation alleging that the Company’s directors
breached their fiduciary duties in approving the merger. To avoid the risk of the litigation
delaying or adversely affecting the merger and to minimize the expense of defending the Company
against the lawsuit, in March 2010 management agreed to a proposed settlement of the litigation (see Note 7 of the
accompanying Notes to Consolidated Financial Statements for further information). The offer from
Alta Mesa was the result of many months of effort to find an appropriate and sufficiently funded
buyer or partner for the Company, and a transaction which would allow the shareholders to receive
some value for their shares, in spite of the extreme difficulties posed by our credit defaults,
borrowing base deficiency, the tight credit market, and continuing low prices for oil and natural
gas.
Management believes the Alta Mesa merger is in the best interests of the Company and its
shareholders. Should that transaction fail, either due to shareholder vote or some other
circumstance, there can be no assurance the Company will be able to continue as a going concern.
Furthermore, under the terms of the bank forbearance agreement, the Lenders under the Credit
Facility have the right to terminate the forbearance period without cause on or after February 28,
2010, provided that all parties in the lending group unanimously agree. If the currently proposed
merger fails, the Lenders may choose to halt forbearance and accelerate all principal and interest
payments and we may be forced to liquidate or otherwise seek protection under federal bankruptcy
laws.
The Merger Agreement with Alta Mesa includes a reimbursement clause under which the Company will
pay Alta Mesa’s reasonable costs of the merger, not to exceed $1 million, in case of termination of
the agreement under various circumstances, including expiration of the term on May 31, 2010 without
consummation of the merger, and also including termination of the Merger Agreement due to
non-approval in the shareholder vote. In addition to reimbursement of Alta Mesa’s costs, the
Company would pay Alta Mesa a $3 million termination fee if, among other reasons, the Company
terminates the Alta Mesa agreement and accepts another offer for the Company, so long as the
definitive agreement related to the other offer is entered into within nine months after
termination of the Merger Agreement with Alta Mesa. The termination fee would be payable no later
than two business days after consummation of the transaction which triggered the fee.
Alta Mesa has the right to terminate the Merger Agreement at any time, whether before or after
approval by the Company’s shareholders, upon payment of a termination fee of $3 million to the
Company. The terms of the Company’s
Credit Facility forbearance agreement require any such termination payment received by Meridian to
be used to repay any outstanding balance under the Credit Facility.
32
Reserves
. Our management focuses on our reserve base, both the volume of proved reserves and the
value of our future net revenues, which we calculate following SEC rules using prices based on the
average of the prices for the twelve most recent months. During 2009, our total proved reserves
decreased 5.3 Bcfe, due to production which exceeded total reserves added through discoveries,
extensions, and positive revisions. We limited our drilling efforts in 2009 to two wells in the
East Texas Austin Chalk gas play in the first quarter, after which we ceased all but the most
essential capital expenditures and management concentrated on production and ongoing operations.
The opportunities for increases in reserves were accordingly reduced, and this is reflected in our
decreased reserves.
Prices for oil and natural gas.
Our revenues, operating profits, property impairment expense, and
access to credit are all significantly impacted by the price of oil and natural gas. Prices also
strongly influence our reserves, impacting the economic viability of reserves which are yet to be
developed.
While we received historically high average prices for oil and natural gas in 2008, by year-end
2008 our oil price had decreased approximately 52% from the average received in 2008. The natural
gas price we received in December 2008 was approximately 27% less than the average received in
2008. In 2009, energy prices continued to be extremely volatile, showing generally further
declines for natural gas and an increase for oil. Meridian’s reserves are approximately 70% gas.
Our estimated present value of future net revenues (before tax) from oil and natural gas at
December 31, 2009 is $139 million, a decrease of $40.5 million, or 23%, from the value one year
earlier. The decrease is due to both the 5.3 Bcfe decrease in reserves explained above, and the
decrease in prices used to compute the value of our reserves. At December 31, 2008, the price per
Mcfe used in computing future net revenues, over the life of the reserves, was $6.11. This price
reflects application of previous SEC rules requiring us to value our estimated proved oil and
natural gas using period end prices. At December 31, 2009 the future price used was $5.52 per
Mcfe, or 10% lower. This price reflects application of new SEC rules requiring us to value our
estimated proved oil and natural gas using average prices for the most recent twelve months.
Ceiling test.
The carrying value of our oil and natural gas properties are limited according to SEC
full cost accounting rules to the present value of our future net revenues from oil and natural gas
(the “ceiling test”). Due to the decrease in prices for natural gas during 2009, as well as to the
decrease in our reserves, we recorded significant non-cash impairments, or ceiling test
write-downs, to our oil and natural gas properties in the first and fourth quarters, totaling $63.5
million.
Based on the continued volatility of energy prices, Meridian may incur additional non-cash
impairments in the future.
Production
. Management closely monitors production. Results for 2009 reflect a decline in
production of 10% overall, consisting of a 19% decrease in natural gas production, partially offset
by a 9% increase in oil production. This is the result of natural production declines in our mature
south Louisiana properties.
Non-routine contract settlement expense.
On January 10, 2010, we entered into a settlement
agreement with Shell Oil Company and one of its subsidiaries (“Shell”). The settlement covered
indemnification for environmental claims related to oil and natural gas properties purchased from
Shell in 1998. The dispute had been submitted to arbitration prior to settlement, and Shell’s
claims against the Company were substantial in nature. We vigorously defended our position and
worked to resolve the matter for many months, as the uncertainty attached to this dispute
encumbered management’s efforts to find a suitable capital partner for the Company. Entry into the
settlement agreement was required under the terms of the Merger Agreement with Alta Mesa. We
recorded $4.2 million as indemnification settlement expense in the
fourth quarter of 2009 for the estimated present value of cash payments totaling $5 million which
the Company will make to Shell over a five year period; we will also transfer certain land and an
overriding royalty interest of minor value to
33
Shell, under the terms of the settlement. The
settlement becomes binding when Meridian makes the first annual payment of $1 million and executes
the land and overriding royalty transfer, which is due by May 1, 2010, unless extended at Shell’s
discretion. The settlement agreement will terminate if the initial payment and land and royalty
transfers are not made.
Expenses.
We took steps in 2009 to reduce our annual expenses, both in the field and in the
office. We reduced our staff significantly. A portion of the severance expense for the employees
was recorded in the first quarter of 2009, although a majority of it had been previously accrued in
2008. The reduction was primarily in our Houston office. The decrease in general and
administrative expenses was substantial; in 2008, general and administrative expenses were $36.5
million gross (before a portion of those expenses were capitalized to the full cost pool); in 2009,
gross general and administrative expenses were $20.7 million, a decrease of 43%. Although expenses
were decreased in nearly all categories, the majority of the decrease was in payroll and related
expenses. The decrease in net general and administrative expenses (after capitalization of a
portion to the full cost pool) is less dramatic, as we ceased capitalization of these expenses
after the first quarter of 2009, which resulted in 100% of such expenses flowing to the
statement of operations. However, the strong reduction in cash expenditures was the objective
achieved by management.
We also made changes to certain field operations to reduce costs. As a result, operating expenses
for 2009 decreased 28%, from $24.3 million to $17.6 million.
Drilling rig obligations.
Costs related to drilling obligations have continued to be significant in
2009. During 2007, in order to ensure access to a drilling rig with the technical specifications
appropriate to our drilling program, we committed to purchase a drilling rig. At the time, such
rigs were in high demand, and as a result of this demand, our drilling program was faced with
delays and increased costs. The purchased rig was largely constructed in 2007, and was placed in
service near the end of the first quarter of 2008.
We do not operate the rig; we lease the rig to Orion Drilling Company, LLC (“Orion”). Orion pays us
a monthly rental fee based on 50% of the monthly net profits of rig operation. The lease of the rig
to Orion runs concurrently with a dayrate contract we have entered, under which Orion operates the
rig. Each agreement was originally for twenty-four months, terminating in March, 2010. Pursuant to
our dayrate contract with Orion, we are obligated to pay the dayrate regardless of any inability to
use the rig which may arise. When the rig is not in use on our wells, Orion may contract it to
third parties, or the rig may be idled. Orion has credited our obligation when appropriate, based
on revenues from other parties who utilize the rig when the Company is unable to. The rig was used
continuously during 2008 in our East Texas drilling efforts, but beginning in the first quarter of
2009 it has been subleased to others, at rates which are less than the dayrate under our contract.
We are obligated for the difference in dayrates. We cannot predict whether such use by third
parties will be consistent, nor to what extent it may offset our obligations under the dayrate
contract.
We have an additional drilling rig commitment with Orion for a second rig, which we do not own;
this is also a dayrate contract, which will terminate in February, 2011. We used this rig
continuously in our East Texas drilling program through the end of the first quarter of 2009; since
then, it has been subleased to others at a rate which is less than the dayrate under our contract.
The total expense we recorded in 2009 as a result of underutilization of the two rigs, and net of
rental revenues from Orion for the rig owned by the Company, was $4.3 million. No similar expenses
were recorded in 2008 or 2007, as there was no underutilization of rigs during those periods.
We have continued to accrue this cost and have not yet expended cash to settle it. In September
2009, we entered into a forbearance agreement with Orion which may grant title to the company-owned
rig to Orion in exchange for release of all accrued and future liabilities under the rig contracts.
This would occur at termination and final payment of the related rig note, which is scheduled for
2013, if the Company continues to perform its obligations under the rig note and the rig is
free of any security interest at title transfer. Both the rig value and the net payable to Orion
would be written off at the time of such title transfer, if it were to occur. At December 31,
2009, the rig is included in equipment at a net book value
34
of $4.6 million. The forbearance
agreement also extends the term of the rig lease to Orion (but not the dayrate contract) to March
31, 2013. Alternatively, the terms of the forbearance agreement allow the Company an option to
settle all claims with Orion in cash at the end of the term of the rig note, and retain title to
the rig. So long as the forbearance agreement is not early terminated, the Company may continue to
accrue the liability for under-utilization of the two rigs, rather than settling in cash.
We cannot predict to what extent, if any, our obligation will continue to be mitigated by
utilization of the rigs by third parties, nor can we give assurance that the forbearance period
with Orion will not be early terminated. The forbearance agreement references termination of the
forbearance agreement provided to us by the creditor under the rig note, which is in turn dependent
on our forbearance agreement related to the Credit Facility.
The rig owned by the Company is subject to assessment for impairment on a quarterly basis. In
2008, we recorded a non-cash impairment expense of $6.7 million to write down the net book value of
the rig to $5.5 million. In 2009 there were no impairments of this asset; however, we cannot be
assured that the market for such rigs and for drilling services will not further soften, which may
necessitate additional write-downs in the future.
Tax Rate.
Our effective income tax rate has varied significantly in the past several years. During
periods of profitability, the effective rate was approximately 38-44%, which is greater than the
corporate income tax rate of 35% primarily due to state taxes and other permanent differences.
However, beginning in 2008, due to the uncertainties regarding our ability to generate net profits
in the near term, we have maintained a valuation allowance equal to the value of our net deferred
tax assets. This resulted in zero tax benefit recorded against our book net losses. Future
effective tax rates may be reduced by the exhaustion of the valuation allowance over time. The
total valuation allowance is $93.7 million.
Operations Overview
Production volumes for 2009 totaled 12.6 billion cubic feet of gas equivalent (“Bcfe”), or an
average of 34.4 million cubic feet of natural gas equivalent per day (“Mmcfe/d”) compared to 14.0
Bcfe or 38.1 Mmcfe per day for 2008. The reduction in production volumes between the two periods is
due to natural production declines. Currently, the overall average daily production for the
Company ranges between 27 and 29 Mmcfe per day.
During the first quarter, Meridian completed the Goodrich-Cocke No. 7 sidetrack and the Myles Salt
No. 27 recompletion, both in Weeks Island. The previously announced Weeks Bay No. 15 began
producing in the second quarter. In late April 2009, the outside operated Davis A-39 in East Texas
was completed as a producing well. We also completed the Company-operated Black Stone Minerals No.
A-278 well in East Texas.
As discussed elsewhere, we restricted our capital expenditures to only the most necessary
activities after the first quarter. We concentrated on reducing costs in the field, with
significant success; operating expenses decreased 28% from 2008 levels. Several marginal wells
were shut in, reducing our active well count, while also decreasing our expenses.
We carefully considered the elements of our lease portfolio and made the decision to monetize a
portion of our leasehold position in South Texas. These leases were recently acquired with the aim
of exploring the Austin Chalk and the Eagle Ford Shale formations. In 2009, we sold all of our
working interest in leases covering approximately 19,000 acres in Lavaca County, retaining an
overriding royalty interest. Also in 2009, we reduced our ownership in approximately 13,000 acres
of Karnes County leases by selling down our interest to a working interest participation option,
which may range from 17% to 25%, depending on the participation elections of others. We also
retained an overriding royalty interest, which is effective regardless of any election we may make
regarding our working interest participation. The first well in this area was recently drilled by
the outside operator to a total measured depth of approximately 17,340 feet (true vertical
depth of approximately 11,900’) and is currently being tested. The operator has obtained
permission from the regulatory agency for an extended test. Preliminary test results indicate it
will be completed as a producing oil well in the Eagle Ford
35
Shale formation. Our interest in this
unit is a 2% overriding royalty interest. There can be no assurance that we will have sufficient
liquidity to drill or participate as a working interest owner in future wells in this area should
they arise.
Results of Operations
Year Ended December 31, 2009, Compared to Year Ended December 31, 2008
Revenue.
Oil and natural gas revenues, which include oil and natural gas hedging activities (see Note 13 of
Notes to Consolidated Financial Statements included elsewhere herein), during the twelve months
ended December 31, 2009, decreased $59.4 million (40%) to $89.2 million, as compared to 2008
revenues of $148.6 million, due to a 10% decrease in production volumes primarily from natural
production declines, and by a 33% decrease in average commodity prices on a natural gas equivalent
basis. Our average daily production decreased to 34.4 MMcfe for 2009 from 38.1 MMcfe during 2008.
Oil and natural gas production volume totaled 12,551 MMcfe for 2009, compared to 13,958 MMcfe for
2008. During 2009, the Company’s drilling activity was limited to two wells in the East Texas
project area, one exploratory and one developmental, and both were completed as producing wells.
The following table summarizes Meridian’s operating revenues, production volumes and average sales
prices for the years ended December 31, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
December 31,
|
|
|
Increase
|
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
834
|
|
|
|
765
|
|
|
|
9
|
%
|
|
Natural gas (MMcf)
|
|
|
7,549
|
|
|
|
9,369
|
|
|
|
(19
|
%)
|
|
Natural gas equivalent (MMcfe)
|
|
|
12,551
|
|
|
|
13,958
|
|
|
|
(10
|
%)
|
|
Average Sales Price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
59.02
|
|
|
$
|
83.18
|
|
|
|
(29
|
%)
|
|
Natural gas (per Mcf)
|
|
|
5.30
|
|
|
|
9.07
|
|
|
|
(42
|
%)
|
|
Natural gas equivalent (per Mcfe)
|
|
|
7.11
|
|
|
|
10.65
|
|
|
|
(33
|
%)
|
|
Operating Revenues (000’s):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
49,222
|
|
|
$
|
63,636
|
|
|
|
(23
|
%)
|
|
Natural gas
|
|
|
40,023
|
|
|
|
84,998
|
|
|
|
(53
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
89,245
|
|
|
$
|
148,634
|
|
|
|
(40
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses.
Oil and natural gas operating expenses on an aggregate basis decreased $6.7 million (28%) to $17.6
million in 2009, compared to $24.3 million in 2008. On a unit basis, lease operating expenses
decreased $0.34 per Mcfe to $1.40 per Mcfe for the year 2009 from $1.74 per Mcfe for the year 2008.
Oil and natural gas operating expenses decreased between the periods primarily due to reduced labor
costs, salt water disposal fees, fuel and compression charges, platform facilities charges and
lower insurance costs. The decrease in the per Mcfe rate was attributable to the reduced expenses
partially offset by lower production in 2009.
Severance and Ad Valorem Taxes.
Severance and ad valorem taxes decreased $3.0 million (31%) to $6.7 million in 2009, compared to
$9.7 million in 2008, because of a decrease in the average price of oil as well as lower gas
36
production. Meridian’s oil and natural gas production is primarily from Louisiana and is therefore
subject to Louisiana severance tax. The severance tax rates for Louisiana are 12.5% of gross oil
revenues and $0.331 per Mcf (effective July 1, 2009) for natural gas. Generally in 2009, although
overall production was down, oil production was up slightly, and for this product, severance taxes
are computed on a percentage basis. Therefore the year to year reduction in oil prices strongly
impacted total severance taxes. Natural gas taxes in Louisiana are based on a per mcf rate which
increased slightly (from $0.288 to $0.331 per mcf). On an equivalent unit of production basis,
severance and ad valorem taxes decreased $0.17 to $0.53 per Mcfe for 2009 from $0.70 per Mcfe for
2008. This was primarily the result of the decrease in oil prices. The per-unit flat tax for gas
results in a severance tax rate that fluctuates as prices change, with the downward trend in prices
we experienced in 2009 producing a higher effective tax rate. In addition, the unit tax itself
increased in 2009. All these factors tended to increase taxes on a unit basis, offsetting the
decrease caused by the oil price decrease, and resulting in a decrease in severance tax expense
which is disproportionate to the decrease in revenues.
Depletion and Depreciation.
Depletion and depreciation expense decreased $35.0 million (49%) during 2009 to $37.1 million
compared to $72.1 million for 2008. The reduction is primarily due to a decrease in the rate per
unit produced, and secondarily to a 10% decrease in production volumes in 2009 compared to 2008.
This decrease in rate was caused by the reduction in the carrying value of oil and natural gas
properties which resulted from the significant impairment write-downs to oil and natural gas
properties recorded in December 2008 and March 2009. On a unit basis, depletion and depreciation
expenses decreased to $2.96 per Mcfe for 2009, compared to $5.16 per Mcfe for 2008.
Impairment of Long-Lived Assets.
In the first quarter of 2009, the Company recognized a non-cash impairment of $59.5 million to oil
and natural gas properties, based on March 31, 2009 pricing of $3.76 per Mcf of natural gas and
$49.66 per barrel of oil. In the fourth quarter of 2009, the Company recognized a non-cash
impairment of $4.0 million to oil and natural gas properties, based on December 31, 2009 pricing of
$3.87 per Mcf of natural gas and $61.18 per barrel of oil. The total impairment recorded in 2009
to oil and natural gas properties was $63.5 million.
In the fourth quarter of 2008, the Company recognized non-cash impairment expense of $216.8 million
($203.2 million after tax) to the Company’s oil and natural gas properties under the full cost
method of accounting, based on December 31, 2008 pricing of $5.79 per Mcf of natural gas and $44.04
per barrel of oil. In addition, we recorded impairment expense of $6.7 million on our drilling
rig. 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 Notes 2 and 19 of Notes to Consolidated Financial Statements included elsewhere
herein), decreased $0.9 million (5%) to $18.1 million in 2009 compared to $19.1 million for the
year 2008. Although the Company reduced headcount in the office and undertook other successful cost
cutting measures, the savings gained were offset in part by increased legal and professional fees,
primarily related to the negotiation of forbearance agreements with various creditors, and to
management’s ongoing efforts to locate a suitable candidate for a strategic transaction such as the
proposed merger with Alta Mesa.
However, overall general and administrative expense was also impacted by the decision to cease
capitalizing such expenses to the full cost pool after the first quarter of 2009, based on reduced
exploration and development activity.
Excluding capitalized amounts, gross general and administrative expenses decreased from $36.5
million in 2008 to $20.7 million in 2009, or 43%.
37
On an equivalent unit of production basis, general and administrative expenses increased $0.07 per
Mcfe to $1.44 per Mcfe for 2009 compared to $1.37 per Mcfe for 2008.
Contract and Indemnification Settlement Expenses.
In 2008, contract settlement expense of $9.9 million was recorded in the second quarter when the
employment contracts of certain executive officers were replaced and certain other agreements
governing other elements of their compensation packages were settled. See further information in
Note 12 of Notes to Consolidated Financial Statements.
Indemnification settlement expense of $4.2 million was recorded in the fourth quarter of 2009,
based on a settlement with Shell and its subsidiary, to resolve a dispute regarding responsibility
for environmental claims on oil and gas properties the Company purchased from Shell in 1998. See
further information in Note 7 of Notes to Consolidated Financial Statements.
Accretion Expense.
The Company records long-term liabilities representing the discounted present value of its
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 recorded accretion expense of $2.1 million and $2.1 million in 2009 and 2008,
respectively.
Hurricane Damage Repairs.
Hurricane damage repairs of $1.5 million were recorded in 2008 for hurricanes Ike and Gustav,
primarily related to the Company’s insurance deductibles for each storm. There were no hurricane
damage repairs recorded in 2009.
Interest Expense.
Interest expense increased $3.1 million (57%) to $8.5 million in 2009 compared to $5.4 million for
2008. The increase was a result of $1.4 million in forbearance fees included in the expense in
2009, and increased interest rates during 2009. Interest rates on both the Credit Facility debt
and the rig note increased under the terms of those agreements, which allow such increases when the
Company is in default. The increase in rates was partially offset by lower debt balances.
Taxes on Income.
Income tax benefit for 2009 was $120,000 as compared to a benefit of $8.5 million for 2008. Income
tax (benefit) is generally provided on book income (loss) after taking into account permanent
differences between book and taxable income (loss). The benefit for 2008 was primarily the result
of the impairment of long-lived assets recognized during the fourth quarter of 2008. The effective
tax rate of 4% in 2008 is the result of recording the impairment loss and the deferred tax asset
valuation allowance. When there is uncertainty as to the ability to recover a deferred tax asset
through future taxable income, no benefit can be recognized, and this was the case in both 2008 and
2009. The tax benefit recognized in 2009 relates to a tax refund.
Year Ended December 31, 2008, Compared to Year Ended December 31, 2007
Revenue.
38
Oil and natural gas revenues, which include oil and natural gas hedging activities (see Note 13 of
Notes to Consolidated Financial Statements included elsewhere herein), during the twelve months
ended December 31, 2008, decreased $2.1 million (1%) to $148.6 million, as compared to 2007
revenues of $150.7 million, due to a 24% decrease in production volumes primarily from natural
production declines, partially offset by a 29% 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 to 38.1 MMcfe for 2008 from 50.1 MMcfe during 2007. Oil and natural gas
production volume totaled 13,958 MMcfe for 2008, compared to 18,269 MMcfe for 2007. During 2008,
the Company’s drilling activity was primarily focused in the East Texas project area and the
Terrebonne Parish area of South Louisiana. During 2008, the Company drilled or participated in the
drilling of 22 wells of which 14 wells were completed, representing a 64% success rate. The
following table summarizes Meridian’s operating revenues, production volumes and average sales
prices for the years ended December 31, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
December 31,
|
|
|
Increase
|
|
|
|
|
2008
|
|
|
2007
|
|
|
(Decrease)
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
765
|
|
|
|
838
|
|
|
|
(9
|
%)
|
|
Natural gas (MMcf)
|
|
|
9,369
|
|
|
|
13,239
|
|
|
|
(29
|
%)
|
|
Natural gas equivalent (MMcfe)
|
|
|
13,958
|
|
|
|
18,269
|
|
|
|
(24
|
%)
|
|
Average Sales Price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
83.18
|
|
|
$
|
64.70
|
|
|
|
29
|
%
|
|
Natural gas (per Mcf)
|
|
|
9.07
|
|
|
|
7.29
|
|
|
|
24
|
%
|
|
Natural gas equivalent (per Mcfe)
|
|
|
10.65
|
|
|
|
8.25
|
|
|
|
29
|
%
|
|
Operating Revenues (000’s):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
63,636
|
|
|
$
|
54,218
|
|
|
|
17
|
%
|
|
Natural gas
|
|
|
84,998
|
|
|
|
96,491
|
|
|
|
(12
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
148,634
|
|
|
$
|
150,709
|
|
|
|
(1
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses.
Oil and natural gas operating expenses on an aggregate basis decreased $4.1 million (14%) to $24.3
million in 2008, compared to $28.3 million in 2007. On a unit basis, lease operating expenses
increased $0.19 per Mcfe to $1.74 per Mcfe for the year 2008 from $1.55 per Mcfe for the year 2007.
Oil and natural gas operating expenses decreased between the periods primarily due to lower
insurance and workover costs; in addition, some fields were shut-in during the third and fourth
quarters of 2008 due to hurricane damage. The increase in the per Mcfe rate was attributable to the
lower production between the two corresponding periods.
Severance and Ad Valorem Taxes.
Severance and ad valorem taxes increased $0.3 million (3%) to $9.7 million in 2008, compared to
$9.4 million in 2007, primarily because of an increase in the average price of oil. Meridian’s oil
and natural gas production is primarily from Louisiana and is therefore subject to Louisiana
severance tax. The severance tax rates for Louisiana are 12.5% of gross oil revenues and $0.288 per
Mcf (effective July 1, 2008) for natural gas. Generally in 2008, although total revenue was flat, a
larger proportion was generated from oil, for which severance taxes are computed on a percentage
basis. Natural gas taxes are based on a per mcf rate which on average did not significantly change.
On an equivalent unit of production basis, severance and ad valorem taxes increased to $0.70 per
Mcfe for 2008 from $0.52 per Mcfe for 2007. The effective
severance tax rate for oil is significantly higher than that for natural gas, particularly when
natural gas prices are trending
39
higher, as they were throughout a good portion of 2008; thus the
change in the mix of revenues and volumes toward more oil increased the effective tax rate, which
is reflected in the per unit costs.
Depletion and Depreciation.
Depletion and depreciation expense decreased $5.0 million (6%) during 2008 to $72.1 million
compared to $77.1 million for 2007. This was primarily the result of a 24% decrease in production
volumes in 2008 compared to 2007, partially offset by an increase in the depletion rate compared to
2007. On a unit basis, depletion and depreciation expenses increased to $5.16 per Mcfe for 2008,
compared to $4.22 per Mcfe for 2007. Depletion and depreciation expense on a per Mcfe basis
increased primarily due to capital costs.
Impairment of Long-Lived Assets.
A decline in oil and natural gas prices as of December 31, 2008, resulted in the Company
recognizing a non-cash impairment totaling $216.8 million of its oil and natural gas properties
under the full cost method of accounting. In addition, we recorded impairment expense of $6.7
million on our drilling rig. 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 Notes 2 and 19 of Notes to Consolidated Financial Statements included elsewhere
herein), increased $2.8 million (17%) to $19.1 million in 2008 compared to $16.2 million for the
year 2007, primarily due to the cost of a retention bonus program for employees, and to a contract
settlement with a former employee. (See Note 12 of Notes to Consolidated Financial Statements). On
an equivalent unit of production basis, general and administrative expenses increased $0.47 per
Mcfe to $1.36 per Mcfe for 2008 compared to $0.89 per Mcfe for 2007.
Contract Settlement Expense
.
Contract settlement expense of $9.9 million was recorded in the second quarter of 2008 when the
employment contracts of certain executive officers were replaced and certain other agreements
governing other elements of their compensation packages were settled. There was no contract
settlement expense recorded in 2007. See further information in Note 12 of Notes to Consolidated
Financial Statements.
Accretion Expense.
The Company records long-term liabilities representing the discounted present value of its
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 recorded accretion expense of $2.1 million and $2.2 million in 2008 and 2007,
respectively. The slight decrease in 2008 levels in comparison to 2007 is primarily the result of
revisions to estimated abandonment costs and actual abandonments, offset by additional wells
drilled and placed on production during the year.
Hurricane Damage Repairs.
Hurricane damage repairs of $1.5 million were recorded in 2008 for hurricanes Ike and Gustav,
primarily related to the Company’s insurance deductibles for each storm. There were no hurricane
damage repairs recorded in 2007.
Interest Expense.
40
Interest expense decreased $0.7 million (11%) to $5.4 million in 2008 compared to $6.1 million for
2007. The decrease was primarily a result of decreased interest rates during 2008, partially offset
by higher debt balances.
Taxes on Income.
Income tax benefit for 2008 was $8.5 million as compared to a provision of $5.7 million for 2007.
Income tax (benefit) is generally provided on book income (loss) after taking into account
permanent differences between book and taxable income (loss). The benefit for 2008 was primarily
the result of the impairment of long-lived assets recognized during the fourth quarter of 2008. The
effective tax rate of 44% in 2007 is typical of the rate experienced by the Company in a year
without unusual items. The 2007 rate differs from the statutory corporate tax rate of 35% due to
state income taxes, non-deductible expenses related to the basis of certain oil and natural gas
properties acquired in years past, and non-deductible expenses. The effective tax rate of 4% in
2008 is the result of recording the impairment loss and the deferred tax asset valuation allowance.
When there is uncertainty as to the ability to recover a deferred tax asset through future taxable
income, no benefit can be recognized, and this was the case in 2008.
Liquidity and Capital Resources
Cash Flows
.
Net cash flow provided by operating activities was $27.0 million for the year ended
December 31, 2009, as compared to $92.8 million for the year ended December 31, 2008, a decrease of
$65.8 million or 71%. The decrease was primarily due to lower crude oil and natural gas prices,
and lower natural gas production volumes, which reduced oil and natural gas revenues by a combined
$59.4 million. Interest expense increased $3.1 million. These reductions in cash flow were
partially offset by reduced cash-based operating expenses, severance taxes, general and
administrative expenses, and hurricane damage repair expense, totaling approximately $12.1 million;
in addition, 2008 included the funding of $9.9 million of contract settlement expenses for certain
Company officers. The remainder of the decrease in cash flow from operations is due to changes in
working capital account balances. The cash outflow from these working capital accounts primarily
reflects the paydown in 2009 of obligations to vendors and joint interest partners as we decreased
our drilling and other capital expenditures and established a lower base of payables related to
operations.
Net cash flows used in investing activities were $22.9 million for the year ended December 31,
2009, as compared to $116.9 million for the year ended December 31, 2008. This decrease was due to
the Company’s steep reduction in exploration and development activities after the first quarter of
2009, as management sought to address the credit default.
Net cash flows used by financing activities were $12.2 million for the year ended December 31,
2009, as compared to net cash flows provided by financing activities of $23.9 million for 2008.
Historically, the trend of our financing activities had been toward increasing use of our Credit
Facility and other new debt, until 2009 when credit under that facility became unavailable and we
began working to reduce the amount outstanding (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Cash provided by—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
27,017
|
|
|
$
|
92,767
|
|
|
$
|
96,991
|
|
|
Net drawdown under credit facility
|
|
|
—
|
|
|
|
20,000
|
|
|
|
—
|
|
|
New debt for drilling rig
|
|
|
—
|
|
|
|
10,000
|
|
|
|
—
|
|
|
Sales of property
|
|
|
2,432
|
|
|
|
7,171
|
|
|
|
3,060
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,449
|
|
|
|
129,938
|
|
|
|
100,051
|
|
|
Cash utilized in—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property and equipment
|
|
|
25,377
|
|
|
|
124,059
|
|
|
|
116,696
|
|
|
Repurchase of common stock
|
|
|
—
|
|
|
|
75
|
|
|
|
1,158
|
|
|
Net payments of credit facility debt
|
|
|
7,500
|
|
|
|
—
|
|
|
|
—
|
|
|
Reductions of drilling rig debt
|
|
|
2,683
|
|
|
|
1,150
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35,560
|
|
|
|
125,284
|
|
|
|
117,854
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other uses, net—
|
|
|
(1,970
|
)
|
|
|
(4,826
|
)
|
|
|
(95
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash—
|
|
$
|
(8,081
|
)
|
|
$
|
(172
|
)
|
|
$
|
(17,898
|
)
|
|
|
|
|
|
|
|
|
|
|
|
41
As noted above, we are in default under the terms of our Credit Facility, and our borrowing base is
limited to $60 million, which is less than the amount outstanding at December 31, 2009 of $87.5
million. The default under the Credit Facility has also triggered an event of default under our rig
note. Under both these debt agreements, the creditors may accelerate all payments of principal and
interest in response to an event of default, although the Company has obtained short-term
forbearance agreements for each. With credit markets extremely tight and the decrease in value of
our proved reserves due to decreased energy prices, it is unlikely that supplemental credit sources
will be available to us in the near term. In addition, the terms of our Credit Facility restrict
our ability to engage in other borrowing transactions. At present, cash flows from operations are
our primary source of cash.
We anticipate reduced cash from operations in 2010, due to expected natural production declines,
somewhat mitigated by the full-year impact of reductions in office and field expenses initiated in
2009. As described earlier, we have obligations under two long-term drilling contracts which may
significantly impact operational cash flows, but are also currently mitigated by a forbearance
agreement with the drilling contractor. If we are unable to effectively sublease the two rigs
continuously, or if the terms of any subleasing agreements do not completely cover the commitment
under our drilling contracts, we will continue to incur obligations under those contracts.
Management does not anticipate that any further significant reductions in expenses can be achieved.
As described above, management hopes to complete a merger of the Company with Alta Mesa, which
would provide a new foundation for financial position, but we can give no assurance that the merger
will be completed. Should the merger fail, and the forbearance
period under either of the two lending agreements and/or the drilling contracts end without
repayment, the Company would be exposed to the action of remedies available to its creditors, which
includes acceleration of all interest and principal. We would not have sufficient cash to meet
those obligations and in that event we may be forced to seek protection under federal bankruptcy
laws.
Cash Obligations
. The following summarizes the Company’s contractual obligations at December 31,
2009, 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
|
|
|
Debt
|
|
$
|
93,666
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
93,666
|
|
|
Interest (5)
|
|
|
3,379
|
|
|
|
—
|
|
|
|
—
|
|
|
|
3,379
|
|
|
Drilling rigs (1) (2)
|
|
|
12,385
|
|
|
|
899
|
|
|
|
—
|
|
|
|
13,284
|
|
|
Exploration contract settlement (3)
|
|
|
360
|
|
|
|
—
|
|
|
|
—
|
|
|
|
360
|
|
|
Settlement obligations (4)
|
|
|
2,383
|
|
|
|
3,200
|
|
|
|
1,000
|
|
|
|
6,583
|
|
|
Non-cancelable operating leases
|
|
|
2,099
|
|
|
|
1,601
|
|
|
|
—
|
|
|
|
3,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash obligations
|
|
$
|
114,272
|
|
|
$
|
5,700
|
|
|
$
|
1,000
|
|
|
$
|
120,972
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In addition to the obligations described above, the Company has a contingent obligation related to
the merger with Alta Mesa. The Merger Agreement with Alta Mesa includes a reimbursement clause
under which the Company will pay Alta Mesa’s reasonable costs of the merger, not to exceed $1
million, in case of termination of the agreement under various circumstances, including expiration
of the term on May 31, 2010 without consummation of the merger, and also including termination of
the Merger Agreement due to non-approval in the shareholder vote. In addition to reimbursement of
Alta Mesa’s costs, the Company would pay Alta Mesa a $3 million termination fee if, among other
reasons, the Company terminates the Alta Mesa agreement and accepts another offer for the Company,
so long as the definitive agreement related to the other offer is entered into within nine months after termination of the Merger
Agreement with Alta Mesa.
42
The termination fee would be payable no later than two business days
after consummation of the transaction which triggered the fee.
|
|
|
|
|
(1)
|
|
Commitments for drilling rigs include $1.8 million for a dayrate contract for operation of a
rig owned by Meridian. The rig is leased to the operator with whom we have the dayrate
contract. Offsetting this obligation for the dayrate contract, but not included above, are the
payments we receive from the operator for his lease of the rig, which are based on a
percentage of the monthly net profits of rig operation. The total rental income related to the
rig in 2009 was $1.1 million. We have a dayrate contract for an additional rig which we do not
own; the obligation under that dayrate contract is $10.6 million and $0.9 million in each of
the years 2010 and 2011, respectively.
|
|
|
|
(2)
|
|
Actual net cash outflow for rig obligations will be impacted by the outcome of events which
are currently uncertain. Under each of these contracts, when the rig is drilling for the
Company, the entire dayrate is payable, but can be expected to be partially recovered if other
working interest owners share costs of the well. When the Company is unable to utilize the
rig, the Company is liable for the entire dayrate. However, the operator has credited our
obligation to some extent, based on revenues from other parties who utilize the rig when the
Company is unable to. During 2009, both rigs have been effectively subleased to others under
short-term contracts. No such reduction in our net obligation has been included in the table
above.
|
|
|
|
(3)
|
|
This settlement obligation relates to an exploration commitment under a contract for
exploration in an area which management no longer believes has potential.
|
|
|
|
(4)
|
|
This obligation primarily relates to settlement of an indemnification dispute between the
Company and Shell Oil Company and one of its subsidiaries (“Shell”), relating to properties
the Company acquired from Shell some years ago. The settlement contract will become binding
when the first payment of $1.0 million is made; this payment is due by May 1, 2010, unless
extended at Shell’s discretion. Subsequent payments, should the contract become binding, are
required on January 4th of each succeeding year (2011 through 2014), for a total of $5.0
million. Although contingent, the obligation is included in the table above.
|
|
|
|
|
|
Also included in the first and second year projections are obligations for payments totaling
$1,481,000 and $200,000, respectively, under various settlement contracts.
|
|
|
|
(5)
|
|
Interest has been computed through the end of the forbearance period for both the debt under
the Company’s Credit Facility and the rig note. The forbearance period is anticipated to
terminate May 31, 2010; see below for further details.
|
Credit Facility
.
The Company has a credit facility with a group of banks (collectively, the
“Lenders,”) with a maturity date of February 21, 2012 (the “Credit Facility.”) The Credit Facility
is subject to borrowing base redeterminations and bears a floating interest rate based on LIBOR or
the prime rate of Fortis Capital Corp., the administrative agent of the Lenders. The borrowing base
and the interest formula have been redetermined or amended multiple times. As of December 31, 2008,
the borrowing base was $95 million and was fully drawn. The interest rate formula in effect at that
date was LIBOR plus 3.25% or prime plus 2.5%.
Obligations under the Credit Facility are to be secured by pledges of outstanding capital stock of
the Company’s subsidiaries and by a first priority lien on not less than 75% (95% in the case of an
event of default) of its present value of proved oil and natural gas properties. 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
43
stock, restrictions on incurrence of additional debt, and an unqualified audit report on the
Company’s consolidated financial statements.
As of December 31, 2008, the Company was in default of two of the covenants under the agreement,
including one that requires that the Company maintain a current ratio (as defined in the Credit
Facility) of one to one. The current ratio, as defined, was less than the required one to one at
December 31, 2008 and continued to be, through December 31, 2009. The Company is also in default of
the requirement that the Company’s auditors’ opinion for the current financial statements be
without modification. Both the Company’s 2008 and 2009 audit reports from its independent
registered public accounting firm included a “going concern” explanatory paragraph that expressed
substantial doubt about the Company’s ability to continue as a going concern. As a result of the
defaults, the outstanding Credit Facility balances of $95 million at December 31, 2008 and $87.5
million at December 31, 2009 have been classified as current in the accompanying consolidated
balance sheets. Also in response to the defaults, the Company provided additional security to the
Lenders, such that first priority liens cover in excess of 95% of the present value of proved oil
and natural gas properties.
The Credit Facility has been subject to semi-annual borrowing base redeterminations effective on
April 30 and October 31 of each year, with limited additional unscheduled redeterminations also
available to the Lenders or the Company. The determination of the borrowing base is subject to a
number of factors, including quantities of proved oil and natural gas reserves, the banks’ price
assumptions related to the price of oil and natural gas and other various factors unique to each
member bank. The Lenders can redetermine the borrowing base to a lower level than the current
borrowing base if they determine that the Company’s oil and natural gas reserves, at the time of
redetermination, are inadequate to support the borrowing base then in effect. In the event the
redetermined borrowing base is less than outstanding borrowings under the Credit Facility, the
Credit Facility requires repayment of the deficit within a specified period of time.
On April 13, 2009, the Lenders notified the Company that, effective April 30, 2009, the borrowing
base was reduced from its then-current and fully drawn $95 million to $60 million. As a result, a
$34.5 million payment to the Lenders for the borrowing base deficiency was due July 29, 2009, based
on the borrowings outstanding on that date. The Company did not have sufficient cash available to
repay the deficiency and, consequently, failed to pay such amount when due. Prior to July 29, 2009,
the Company was in covenant default under the terms of the Credit Facility; on and after that date
it was in covenant default and payment default as well.
Under the terms of the Credit Facility, the Lenders have various remedies available in the event of
a default, including acceleration of payment of all principal and interest.
On September 3, 2009, the Company entered into a forbearance agreement with the Lenders under the
Credit Facility (“Bank Forbearance Agreement”). The Bank Forbearance Agreement provided that the
Lenders would forbear from exercising any right or remedy arising as a result of certain existing
events of default under the Credit Facility until the earlier of December 3, 2009 or the date that
any default occurred under the Bank Forbearance Agreement. The terms of the Bank Forbearance
Agreement required the Company to consummate a capital transaction such as a capital infusion or a
sale or merger of the Company, before October 30, 2009. The deadlines for the capital transaction
and the forbearance period were extended several times by amendments to the Bank Forbearance
Agreement.
At origination of the Bank Forbearance Agreement, the Company paid the Lenders $2.0 million of
principal owed under the Credit Facility. Under the terms of the agreement the Company made a total
of $5.0 million in further principal payments through December 31, 2009, bringing the balance at
that date to $87.5 million. The Company also paid forbearance fees to the Lenders of $945,000,
charged to interest expense in the third quarter of 2009, and accrued an additional $476,000 in
forbearance fees, charged to interest expense in the fourth quarter of 2009. In addition, the
Company incurred approximately $2.3 million in legal and consulting fees recorded in general and
administrative expense, to originate and amend the Bank Forbearance Agreement and other related
agreements.
44
On December 22, 2009, the Company entered into an Agreement and Plan of Merger (the “Merger
Agreement”) with Alta Mesa Holdings, LP (“Alta Mesa”) and Alta Mesa Acquisition Sub, LLC, a direct
wholly owned subsidiary of Alta Mesa. The Eleventh Amendment to Forbearance and Amendment
Agreement (“11
th
Amendment”) provided the Lenders’ consent to the Merger Agreement and
extended the date for consummation of a capital transaction, such as the Alta Mesa merger, and the
forbearance period, to the earlier of the consummation of the merger with Alta Mesa, the
termination of the Merger Agreement, or May 31, 2010. However, the 11
th
Amendment also
allows the Lenders to terminate the forbearance period on or after February 28, 2010, without
cause, so long as the decision to terminate is unanimous among the Lenders. The 11
th
Amendment also requires the Company to repay $1 million in principal to the Lenders per month. As
of March 31, 2010, the outstanding balance under the Credit Facility is $83 million.
In accordance with the 11th Amendment, the Company has filed its shareholder proxy statement
regarding the merger and called a shareholder meeting currently scheduled for April 28, 2010 to
approve the transaction. There can be no assurance that shareholders will approve the transaction
or that the merger will be consummated within the time constraints specified in the 11
th
Amendment. Should the forbearance period terminate, the Company will be in default, unprotected
from the action of remedies available to the Lenders, which cannot be predicted. Such remedies
include acceleration of all outstanding principal and interest.
The Bank Forbearance Agreement placed other restrictions on the Company with respect to capital
expenditures, sales of assets, and incurrence and prepayments of other indebtedness and amended the
Credit Facility in certain respects. It contains covenants regarding the frequency of reporting of
financial and cash flow information to the Lenders, as well as cash account control agreements
which provide a secured lien over substantially all of the Company’s cash accounts.
Under the terms of the Bank Forbearance Agreement, as amended, the Credit Facility is amended such
that scheduled borrowing base redeterminations will occur quarterly rather than semi-annually, to
be effective January 31, April 30, July 31, and October 31 of each year. Outstanding amounts in
excess of the borrowing base must be repaid according to certain defined terms. The deficiency
could be paid in three equal installments over a maximum period of 100 days after the incurrence of
a borrowing base deficiency, or alternatively, the Company could provide additional sufficient
collateral to cover the deficiency. However, as the Company has already pledged in excess of 95% of
the value of all proved oil and natural gas reserves as security, such an alternative could apply
only to a small borrowing base deficiency. The Lenders have provided the Company with a limited
waiver postponing the next borrowing base redetermination to the end of the forbearance period. No
assurance can be given that further deficiencies will not be incurred at the next redetermination.
The Lenders exercised their right to increase the interest rate on outstanding borrowings by 2%
(“default interest,” under the terms of the Credit Facility) as of July 30, 2009. The floating
interest rate is based on the prime interest rate, currently 3.25%, plus 2.5%, plus the default
increment of 2%, resulting in a total rate of 7.75% at December 31, 2009 and continuing at that
rate currently
.
The additional default interest has been effective as to all outstanding borrowings
under the Credit Facility since the July 29, 2009 payment default, and the LIBOR alternative was
also eliminated. No interest payments are in arrears.
Rig Note
.
On May 2, 2008, the Company, through its wholly owned subsidiary TMRD, entered into a
financing agreement (“rig note”) with The CIT Group / Equipment Financing, Inc. (“CIT”). Under the
terms of the agreement, TMRD borrowed $10.0 million, at a fixed interest rate of 6.625%, which
increases in an event of default. The loan is collateralized by the drilling rig, as well as
general corporate credit. The term of the loan is five years, expiring on May 2, 2013.
Effective as of December 31, 2008, the Company was in default under the rig note. Under the terms
of the rig note, a default under the Credit Facility triggers a cross-default under the rig note.
The remedies available to CIT in the event of default include acceleration of all principal and
interest payments. Accordingly, all indebtedness under the rig note,
45
$8.8 million at December 31, 2008 and $6.2 million at December 31, 2009, has been classified as current
in the accompanying consolidated balance sheets.
On September 3, 2009, the Company also entered into a forbearance agreement with CIT (“CIT
Forbearance Agreement.”) The forbearance period under the CIT Forbearance Agreement has been
extended several times, most recently by the Fourth Amendment to Forbearance and Amendment
Agreement (“4
th
Amendment”). The forbearance period ends the earlier of the
consummation of the merger with Alta Mesa, the termination of the Merger Agreement, May 31, 2010,
or the date of any default under either the CIT Forbearance Agreement or the Bank Forbearance
Agreement. The 4
th
Amendment also provides CIT’s consent to the merger with Alta Mesa.
CIT retains the right to terminate the forbearance period if, in its sole determination, Alta Mesa
experiences changes to its financial condition that would adversely affect its ability to complete
the merger with the Company.
At origination of the CIT Forbearance Agreement, the Company prepaid, without penalty, $1.0 million
of principal on the rig note and began to pay “default interest” of an additional 4% effective
August 1, 2009, as allowed to CIT under the terms of the rig note, bringing the total monthly
payment to approximately $220,000. The Company also paid, and recorded in
general and administrative expense in the
third quarter, a forbearance fee of approximately $50,000. There can be no assurance that the
forbearance period under the CIT Forbearance Agreement will provide sufficient time to resolve the
cross-default under the rig note.
Capital Expenditures
.
Capital expenditures in 2009 consisted of $12.8 million (on an accrual basis)
for property and equipment additions related to exploration and development, including drilling and
workover activities, commitments under leases, and work on production facilities.
The Company anticipates the 2010 capital spending budget will be primarily used for any major lease
maintenance costs. We anticipate that the budget will be significantly lower than in past years,
including 2009, which included the drilling of two wells in the first quarter. We currently
anticipate funding the 2010 plan utilizing cash flow from operations and cash on hand, augmented by
proceeds from sales of assets as possible.
Dividends
. It is our policy to retain existing cash for reinvestment in our business, and
therefore, we do not anticipate that dividends will be paid with respect to the common stock in the
foreseeable future.
Off-Balance Sheet Arrangements
. None.
Share Repurchase Program.
In March 2007, the Company’s Board of Directors authorized a share
repurchase program; an amendment to the credit agreement at that time increased the available limit
for the Company’s repurchase of its common stock from $1.0 million to $5.0 million annually, so
long as the Company was in compliance with certain provisions of the Credit Facility. From March
2007, the inception of the share repurchase program, through December 31, 2009, the Company had
repurchased 535,416 common shares at a cost of $1,234,000, of which 501,300 shares have been
reissued for 401(k) contributions, for contract services and for compensation, and 34,116 have been
retired. The Bank Forbearance Agreement prohibits any further repurchase of Company stock. The
Company did not repurchase any shares during 2009 and does not expect to make share repurchases in
the foreseeable future.
Critical Accounting Policies and Estimates
The Company’s discussion and analysis of its financial condition and results of operation are based
upon consolidated financial statements, which have been prepared in accordance with accounting
principles generally accepted in the United States of America. The following summarizes several of
our critical accounting policies. See a complete list of significant accounting policies in Note 2
of the notes to the consolidated financial statements included herein.
46
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
2009, 2008, and 2007, capitalized general and administrative costs totaled $2.6 million, $17.4
million, and $16.5 million, respectively. General and administrative costs related to production
and general overhead are expensed as incurred. The Company discontinued capitalization of general
and administrative costs after the first quarter of 2009, based on its curtailment of exploration
and development activities; the Company will resume such capitalization if circumstances in the
future warrant.
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, are estimated
property by property based upon current economic conditions and are included in 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), excluding costs of unproved properties and reduced by estimated salvage values, are divided
by the total estimated units of proved oil and natural gas reserves at the beginning of the period
to determine the depletion rate. This rate is multiplied by the physical units of oil and natural
gas produced during the period.
Changes in the quantities of our reserves could significantly impact the Company’s expense of
depletion and amortization of oil and natural gas properties.
The cost of unevaluated oil and natural gas properties not subject to depletion 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, available geological and geophysical information, and actual
exploration and development plans. Any impairment assessed is added to the cost of proved
properties being amortized.
At December 31, 2009, we had $1.6 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
expense of depletion and amortization of oil and natural gas properties by less than 1% and a 10%
increase would have decreased our provision by less than 1% for the year ended December 31, 2009.
47
Full-Cost Ceiling Test
. At the end of each quarter, the unamortized cost of oil and natural gas
properties, net of related deferred income taxes, is limited to the sum of the estimated future
after-tax net revenues from proved properties, 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. This limitation is known as the “ceiling test,” and is based on SEC rules for
the full cost oil and gas accounting method. Prior to December 31, 2009, SEC rules prescribed that
future revenues from estimated reserves be calculated using period end prices. This method was
used in 2007 and 2008 to compute future revenues used in the ceiling test. As of December 31,
2009, the SEC requires that future revenues utilize prices based on the average of the most recent
twelve months. The average is calculated using the first day of the month price for each of the
twelve months making up the reporting period. This change in the method for estimating future
revenues from oil and natural gas reserves impacted the ceiling test in the fourth quarter of 2009.
In that quarter, we recorded a ceiling test write-down of $4.0 million; had we used the previous
pricing methodology, there would not have been a write-down.
The calculation of the ceiling test and depletion expense 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.
At March 31, 2009, and again at December 31, 2009, the unamortized cost of our oil and natural gas
properties, net of related deferred income taxes, exceeded the ceiling under the full cost method
of accounting for our oil and natural gas properties. In the first quarter of 2009, the Company
recognized a non-cash impairment of $59.5 million to oil and natural gas properties, based on March
31, 2009 pricing of $3.76 per Mcf of natural gas and $49.66 per barrel of oil. In the fourth
quarter of 2009, the Company recognized a non-cash impairment of $4.0 million to oil and natural
gas properties, based on December 31, 2009 pricing of $3.87 per Mcf of natural gas and $61.18 per
barrel of oil. The total impairment recorded in 2009 to oil and natural gas properties was $63.5
million (before and after tax). A non-cash impairment of $216.8 million ($203.2 million after tax)
was recognized in the fourth quarter of 2008, based on prices prevailing at that time.
Due to the imprecision in estimating oil and natural gas revenues as well as the potential
volatility in oil and natural gas prices and their effect on the carrying value of our proved oil
and natural gas reserves, there can be no assurance that write-downs in the future will not be
required as a result of factors that may negatively affect the present value of proved oil and
natural gas reserves and the carrying value of oil and natural gas properties, including volatile
oil and natural gas prices, downward revisions in estimated proved oil and natural gas reserve
quantities and unsuccessful drilling activities.
At December 31, 2009, we had no cushion (i.e., the excess of the ceiling over our capitalized
costs). Thus, any decrease in prices affecting the end of subsequent accounting periods, net of the
effect of our hedging positions, may require us to record additional impairment charges. Any future
impairment would be impacted by changes in the accumulated costs of oil and natural gas properties,
which may in turn be affected by sales or acquisitions of properties and additional capital
expenditures. Future impairment would also be impacted by changes in estimated future net revenues,
which are impacted by additions and revisions to oil and natural gas reserves. A 10% decrease in
prices would have increased our fourth quarter 2009 non-cash impairment expense by approximately
$28 million; a 10% increase in prices would have eliminated the need for a write-off.
Price Risk Management Activities
. The Company follows the guidance of Accounting Standards
Codification (“ASC”) Topic 815, “Derivatives and Hedging” (“ASC 815”) 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
48
and losses on derivatives to offset related results on the hedged item in the earnings statements
and requires that a company formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting.
The Company’s results of operations and operating cash flows are impacted by changes in market
prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes,
the Company has, in the past, entered into various derivative contracts. These contracts allowed
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 historical derivative instruments were found 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 ASC 815 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 losses of $6,000 and $18,000 during the years ended December 31, 2009 and 2008,
respectively, and a gain of $21,000 during the year ended December 31, 2007.
As of December 31, 2009 and 2008, the Company had unrealized gains of zero and $8.1 million
(pre-tax and net of tax) deferred in Accumulated Other Comprehensive Income, respectively. All of
the Company’s derivative agreements expired December 31, 2009.
Net settlements under these contract agreements increased (decreased) oil and natural gas revenues
by $11,745,000, ($4,663,000), and $3,252,000 for the years ended December 31, 2009, 2008, and 2007,
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. As of December 31, 2009 the Company
believes it is not practicable to estimate the fair value of its
outstanding debt under its Credit Facility in light of the payment default. The reduction in credit standing from this default would
certainly tend to reduce the fair value of the debt, but it is not practicable to estimate the
amount of such reduction. The carrying value of that debt is $87.5 million at December 31, 2009.
See “Liquidity and Capital Resources—Current Credit Facility” for further details on the Credit
Facility. The Company also has a smaller bank debt with a fixed rate, the rig note. The fair value
of the rig note at December 31, 2009 is estimated as approximately $4 million; the corresponding
carrying value is $6.2 million. The fair value was estimated based on the fair value of the
underlying collateral. The collateral is a drilling rig owned by the Company; see Notes 4 and 9 of
the accompanying notes to consolidated financial statements for further information on how fair
value for the rig was estimated. The Company’s oil and gas price risk hedging contracts are also
financial instruments, recorded at fair value; see Note 13 of the accompanying notes to
consolidated financial statements.
Deferred Tax Asset Valuation Allowance
. Under the liability method, deferred tax assets and
liabilities are recognized for the estimated future tax effects attributable to temporary
differences and carryforwards. Ultimately, realization of a deferred tax benefit depends on the
existence of sufficient taxable income within the carryback/carryforward period to absorb future
deductible temporary differences or a carryforward. In assessing the realizability of deferred tax
assets, we consider whether it is more likely than not that some portion or all of the deferred tax
assets will not be realized, including such evidence as the scheduled reversal of deferred tax
liabilities and projected future taxable income. As a result of the current assessment, in 2008 and
2009 we recorded a valuation allowance against deferred tax assets equal to the full amount of
those assets.
49
Rig Operations
. The Company has long-term drilling contracts for two rigs, both of which it has
been unable to utilize since early 2009. Although the drilling contractor has been able sublease
the rigs during the time Meridian is not utilizing them, the Company is obligated for the
difference if the third party sub-lessor’s dayrate is less than that provided under the Company’s
drilling contract, and for the full dayrate if the rig is idle. This cost related to the rigs when
they are not providing services to the Company have been included in the consolidated statements of
operations as “Rig operations, net.” The expense was $4.3 million in 2009 and zero in 2008.
The Company owns one of the two rigs, and leases it to the drilling contractor; rentals are based
on a percentage of the operating profits of the rig. The lease revenues for the period in which
the rigs have not been utilized by Meridian have been included in “Rig operations, net,”
effectively offsetting a portion of the expense of underutilization of that rig. Rig operations
expense for the year 2009 includes $1.1 million in lease revenue.
When the owned rig performs services for Meridian, the dayrate costs are capitalized to the full
cost pool, and any rental profits after ownership costs (primarily, depreciation and property
taxes) are also capitalized to the full cost pool. For the years ended 2009 and 2008, total rig
profits capitalized to the full cost pool were $180,000 and $1.1 million, respectively.
New Accounting Pronouncements
. In July 2009, the Financial Accounting Standards Board (“FASB”)
issued revised authoritative guidance regarding the hierarchy of generally accepted accounting
principles. Under this revised guidance, the FASB Accounting Standards Codification
(“Codification”), the FASB’s new web-based codification of accounting and reporting guidance, along
with guidance provided by the SEC, are the only “authoritative” sources of such guidance. All
guidance not contained in the Codification, other than SEC guidance, will be considered
“non-authoritative.” The Codification is designed to incorporate previously issued guidance from
sources such as the FASB, the American Institute of Certified Public Accountants, and the Public
Company Accounting Oversight Board, and is not intended to change GAAP for non-governmental
entities. The revised guidance on the hierarchy provides additional guidance on the selection,
interpretation, and application of accounting principles from the Codification and from
non-authoritative sources when necessary. The guidance is effective for financial statements issued
for interim and annual periods ending after September 15, 2009. The Company adopted the revised
guidance effective July 1, 2009; the adoption did not have a material impact on financial position
or results of operations.
In September 2006, the FASB issued Statement of Financial Accounting Standard (“SFAS”) No. 157,
“Fair Value Measurements,” codified in Accounting Standards Codification (“ASC”) Topic 820 (“ASC
820”). ASC 820 defines fair value, establishes a framework for measuring fair value in generally
accepted accounting principles and expands disclosure about fair value measurements. In accordance
with the effective dates provided in the guidance, the Company adopted the guidance for
measurements of the fair values of financial instruments and recurring fair value measurements of
non-financial assets and liabilities on January 1, 2008. Effective January 1, 2009, the Company
began applying the new guidance to non-recurring measurements of the fair values of non-financial
assets and liabilities, such as asset retirement obligations and impairments of long-lived assets
other than oil and natural gas properties. The adoptions had no material impact on financial
position or results of operations.
In January 2010, the FASB updated Topic 820 with Accounting Standards Update (“ASU”) 2010-06, “Fair
Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value
Measurements.” This ASU requires new disclosures and clarifies certain existing disclosure
requirements about fair value measurements. ASU 2010-06 requires a reporting entity to disclose
significant transfers in and out of Level 1 and Level 2 fair value measurements, to describe the
reasons for the transfers, and to present separately information about purchases, sales, issuances
and settlements for fair value measurements using significant unobservable inputs. ASU 2010-06 is
effective for interim and annual reporting periods beginning after December 15, 2009, except for
the disclosures about purchases, sales, issuances and settlements in the roll forward of activity
in Level 3 fair value measurements, which is effective for interim and annual reporting periods
beginning after December 15, 2010; early adoption is permitted. The Company does not expect that
the adoption of ASU 2010-06 will have a material impact on financial position, results of
operations or cash flows.
50
In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations,” codified in ASC
Topic 805 (“ASC 805”). ASC 805 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. ASC
805 was effective on a prospective basis for all business combinations completed on or after
January 1, 2009. The Company adopted the revised guidance effective January 1, 2009; the adoption
did not have a material impact on financial position or results of operations.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging
Activities,” codified in ASC Topic 815-10-50 (“ASC 815-10-50”). ASC 815-10-50 provides guidance
for additional disclosures regarding derivative contracts, including expanded discussions of risk
and hedging strategy, as well as new tabular presentations of accounting data related to derivative
instruments. The Company adopted the revised guidance effective January 1, 2009; the adoption did
not have a material impact on financial position or results of operations. The additional
disclosures are included in Note 13 of the accompanying notes to consolidated financial statements.
In June 2008, the FASB Emerging Task Force issued EITF Abstract Issue No. 07-05, “Determining
Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock” codified as ASC
Topic 815-40-15 (“ASC 815-40-15”). ASC 815-40-15 clarifies the determination of equity instruments
which may qualify for an exemption from the other provisions of ASC 815, “Derivatives and Hedging.”
Generally, equity instruments which qualify under the guidelines of ASC 815-40-15 may be accounted
for in equity accounts; those which do not qualify are subject to derivative accounting. The
Company adopted the guidance of ASC 815-40-15 on January 1, 2009. The effects of the adoption
included a revision in the carrying value of certain outstanding warrants, and recognition of a
related liability of $960,000 on January 1, 2009, as well as recognition of an unrealized gain of
$548,000 due to the change in fair value of those warrants during 2009, which is included in
general and administrative expense. See Note 10 in the accompanying notes to consolidated
financial statements, under the subheading “Warrants,” for further information.
In December 2008, the SEC published a Final Rule,
“Modernization of Oil and Gas Reporting
.
”
The new
rule permits the use of new technologies to determine proved reserves if those technologies have
been demonstrated to lead to reliable conclusions about reserves volumes. The new requirements also
allow companies to disclose their probable and possible reserves to investors. In addition, the new
disclosure requirements require companies to: (
a
) report the independence and qualifications of its
reserves preparer or auditor; (
b
) file reports when a third party is relied upon to prepare
reserves estimates or conducts a reserves audit; and (
c
) report oil and gas reserves using an
average price based upon the prior 12-month period rather than year-end prices. The use of average
prices affects impairment and depletion calculations. The new rule became effective for reserve
reports as of December 31, 2009; the FASB incorporated the new guidance into the Codification as
Accounting Standards Update 2010-03, effective also on December 31, 2009, ASC Topic 932,
“Extractive Activities — Oil and Gas.”
The Company adopted the new guidance effective December 31, 2009; information about the company’s
reserves has been prepared in accordance with the new guidance and is included in Note 19 of the
accompanying notes to consolidated financial statements; management has chosen not to provide
information on probable and possible reserves. The Company’s reserves were affected primarily by
the use of the average price rather than the year-end price required under the prior rules. As a
result of adopting the new guidance, we estimate that Meridian’s December 31, 2009 proven reserves
decreased approximately 1.4 Bcfe and prices used in the calculation decreased approximately 30%.
These changes in turn affected the results of the Company’s ceiling test for the fourth quarter,
which was a write-down of $4.0 million. Had the new rule using average pricing not been
implemented, the write-down in the fourth quarter of 2009 would not have been necessary. The
change in total reserves had only a negligible effect on depletion expense in the fourth quarter of
2009, as total proved reserves are the basis of depletion calculations.
51
In December 2009, the FASB issued revised authoritative guidance regarding consolidation of
variable interest entities (“VIE’s”) in ASU 2009-17, “Improvements to Financial Reporting by
Enterprises Involved with Variable Interest Entities,” codified as ASC 810-10-05-08. The ASU
(originally issued as SFAS No. 167 in June 2009) amends existing consolidation guidance for
variable interest entities. Variable interest entities generally are thinly-capitalized entities
which under previous guidance may not have been consolidated. The revised guidance requires a
company to perform a qualitative analysis to determine whether to consolidate a VIE, which includes
consideration of control issues other than the primarily quantitative considerations utilized prior
to this revision. In addition, the revised guidance requires ongoing assessments of whether to
consolidate VIE’s, rather than only when specific events occur. The revised guidance also requires
additional disclosures about consolidated and unconsolidated VIE’s, including their impact on the
company’s risk exposure and its financial statements. The revised guidance will be effective for
financial statements for annual and interim periods beginning after November 15, 2009. The Company
has not yet determined the impact of adoption on its financial position or results of operations.
In April 2009, the FASB issued new authoritative guidance regarding interim disclosures about the
fair value of financial instruments, which enhances consistency in financial reporting by
increasing the frequency of fair value disclosures. The guidance is effective for interim and
annual periods ending after June 15, 2009, with early adoption permitted for periods ending after
March 15, 2009. The Company adopted the new guidance effective April 1, 2009. The adoption did
not have a material impact on financial position or results of operations of the Company. The
disclosures are included in Note 2 of the accompanying notes to consolidated financial statements,
under the subheading “Fair Value of Financial Instruments.”
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 $87.5 million
remains borrowed under the Credit Facility, we estimate our annual interest expense will change by
$0.88 million for each 100 basis point change in the applicable interest rates utilized under the
Credit Facility.
Hedging Contracts
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
agreements 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. The Company’s Credit
Facility requires that counterparties in derivative transactions be limited to the Lenders,
including affiliates of the Lenders. The Company does not obtain collateral from the Company’s
counterparties to support counterparty obligations under the agreements. The master derivative
contracts with each counterparty allow the Company, so long as it is not a defaulting party, after
a default or the occurrence of a termination event, to set-off against the interest of the
counterparty in any outstanding balance under the
52
Credit Facility. In practice, no such set-off has been made, and all settlements have been made in
cash. As of December 31, 2009, however, the all of the Company’s derivative contracts have expired.
Due to our default under the Credit Facility, the Lenders have not allowed the Company to enter
into any additional hedging agreements. As a result, our oil and natural gas sales for periods
beyond December 2009 will more closely resemble prevailing market prices.
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
|
53
|
|
|
usually retains a royalty or reversionary interest in the lease. The interest received by an
assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”
|
|
|
|
“Field” An area consisting of a single reservoir or multiple reservoirs all grouped on or related
to the same individual geological structural feature or stratigraphic condition.
|
|
|
|
“Gross acres or gross wells” The total acres or wells, as the case may be, in which a working
interest is owned.
|
|
|
|
“Intangible Drilling and Development Costs” Expenditures made by an operator for wages, fuel,
repairs, hauling, supplies, surveying, geological works, etc., incident to and necessary for the
preparing for and drilling of wells and the construction of production facilities and pipelines.
|
|
|
|
“Lease Operating Expense” Recurring expenses incurred to operate wells and equipment on a
producing lease. Examples include pumping and gauging, chemicals, compression, fuel and water,
insurance and property taxes.
|
|
|
|
|
|
“MBbls” One thousand barrels of crude oil or other liquid hydrocarbons.
|
|
|
|
|
|
“Mcf” One thousand cubic feet.
|
|
|
|
|
|
“Mcfe” One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas
to one Bbl of crude oil, condensate or natural gas liquids.
|
|
|
|
|
|
“Mcfe/d” One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas
to one Bbl of crude oil, condensate or natural gas liquids, per day.
|
|
|
|
|
|
“MD” Measured depth.
|
|
|
|
|
|
“MMBls” One million barrels of crude oil or other liquid hydrocarbons.
|
|
|
|
|
|
“MMbtu” One million Btus.
|
|
|
|
|
|
“MMMbtu” One billion Btus.
|
|
|
|
|
|
“MMcf” One million cubic feet.
|
|
|
|
|
|
“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.
|
54
|
|
|
“Oil” Crude oil and condensate
|
|
|
|
|
|
“Present value or PV10 or SEC PV-10” 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 based on an average of the most
recent twelve months 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 analysis of geoscience 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.
|
55
|
|
|
“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.
|
56
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Below is an index to the financial statements and notes contained in Financial Statements and
Supplementary Data.
|
|
|
|
|
|
|
|
|
Page
|
|
|
|
|
59
|
|
|
|
|
|
60
|
|
|
|
|
|
61-62
|
|
|
|
|
|
63
|
|
|
|
|
|
64
|
|
|
|
|
|
65
|
|
|
|
|
|
66
|
|
|
|
|
|
66
|
|
|
|
|
|
67
|
|
|
|
|
|
75
|
|
|
|
|
|
76
|
|
|
|
|
|
77
|
|
|
|
|
|
79
|
|
|
|
|
|
80
|
|
|
|
|
|
84
|
|
|
|
|
|
85
|
|
|
|
|
|
87
|
|
|
|
|
|
92
|
|
|
|
|
|
93
|
|
|
|
|
|
94
|
|
|
|
|
|
97
|
|
|
|
|
|
97
|
|
|
|
|
|
99
|
|
|
|
|
|
100
|
|
|
|
|
|
100
|
|
|
|
|
|
101
|
|
57
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.
58
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
as of December 31, 2009 and 2008 and the related consolidated statements of operations,
comprehensive income (loss), stockholders’ equity and cash flows for each of the three years in the
period ended December 31, 2009. These financial statements are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States of America). 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 also includes examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the financial position of The Meridian Resource Corporation at December 31, 2009
and 2008, and the results of its operations and its cash flows for each of the three years in the
period ended December 31, 2009 in conformity with accounting principles generally accepted in the
United States of America.
The accompanying financial statements have been prepared assuming that the Company will continue as
a going concern. As discussed in Note 1 to the consolidated financial statements, at December 31,
2009, the Company was in violation of certain debt covenants resulting in the default on its
revolving credit and other debt agreements, which raise substantial doubt about the Company’s
ability to continue as a going concern. Management’s plans in regard to these matters are also
described in Note 1. The financial statements do not include any adjustments that might result from
the outcome of this uncertainty.
As discussed in Note 2 to the consolidated financial statements, effective December 31, 2009, the
Company changed its reserve estimates and related disclosures as a result of adopting new oil and
natural gas reserve estimation and disclosure requirements.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), The Meridian Resource Corporation’s internal control over financial
reporting as of December 31, 2009, 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 April 15, 2010 expressed an unqualified opinion thereon.
/s/ BDO Seidman, LLP
Houston, Texas
April 15, 2010
59
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
89,245
|
|
|
$
|
148,634
|
|
|
$
|
150,709
|
|
|
Price risk management activities
|
|
|
(6
|
)
|
|
|
(18
|
)
|
|
|
21
|
|
|
Interest and other
|
|
|
15
|
|
|
|
549
|
|
|
|
1,448
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
89,254
|
|
|
|
149,165
|
|
|
|
152,178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING COSTS AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas operating
|
|
|
17,550
|
|
|
|
24,280
|
|
|
|
28,338
|
|
|
Severance and ad valorem taxes
|
|
|
6,696
|
|
|
|
9,727
|
|
|
|
9,409
|
|
|
Depletion and depreciation
|
|
|
37,102
|
|
|
|
72,072
|
|
|
|
77,076
|
|
|
General and administrative
|
|
|
18,121
|
|
|
|
19,063
|
|
|
|
16,221
|
|
|
Rig operations, net
|
|
|
4,254
|
|
|
|
—
|
|
|
|
—
|
|
|
Contract settlement
|
|
|
—
|
|
|
|
9,894
|
|
|
|
—
|
|
|
Indemnification settlement
|
|
|
4,223
|
|
|
|
—
|
|
|
|
—
|
|
|
Accretion expense
|
|
|
2,083
|
|
|
|
2,064
|
|
|
|
2,230
|
|
|
Impairment of long-lived assets
|
|
|
63,495
|
|
|
|
223,543
|
|
|
|
—
|
|
|
Hurricane damage repairs
|
|
|
—
|
|
|
|
1,462
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
153,524
|
|
|
|
362,105
|
|
|
|
133,274
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS (LOSS) BEFORE OTHER EXPENSES &
INCOME TAXES
|
|
|
(64,270
|
)
|
|
|
(212,940
|
)
|
|
|
18,904
|
|
|
OTHER EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
8,486
|
|
|
|
5,408
|
|
|
|
6,090
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS (LOSS) BEFORE INCOME TAXES
|
|
|
(72,756
|
)
|
|
|
(218,348
|
)
|
|
|
12,814
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAX EXPENSE (BENEFIT):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
(120
|
)
|
|
|
(269
|
)
|
|
|
650
|
|
|
Deferred
|
|
|
—
|
|
|
|
(8,193
|
)
|
|
|
5,027
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(120
|
)
|
|
|
(8,462
|
)
|
|
|
5,677
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS (LOSS)
|
|
|
(72,636
|
)
|
|
|
(209,886
|
)
|
|
|
7,137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS (LOSS) APPLICABLE TO COMMON
STOCKHOLDERS
|
|
$
|
(72,636
|
)
|
|
$
|
(209,886
|
)
|
|
$
|
7,137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS (LOSS) PER SHARE:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.79
|
)
|
|
$
|
(2.30
|
)
|
|
$
|
0.08
|
|
|
Diluted
|
|
$
|
(0.79
|
)
|
|
$
|
(2.30
|
)
|
|
$
|
0.08
|
|
|
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
92,465
|
|
|
|
91,382
|
|
|
|
89,307
|
|
|
Diluted
|
|
|
92,465
|
|
|
|
91,382
|
|
|
|
94,944
|
|
See notes to consolidated financial statements.
60
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
CURRENT ASSETS:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
5,273
|
|
|
$
|
13,354
|
|
|
Restricted cash
|
|
|
35
|
|
|
|
9,971
|
|
|
Accounts receivable, less allowance for doubtful accounts of $110 [2009] and $210 [2008]
|
|
|
12,185
|
|
|
|
16,980
|
|
|
Prepaid expenses and other
|
|
|
2,195
|
|
|
|
3,292
|
|
|
Assets from price risk management activities
|
|
|
—
|
|
|
|
8,447
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
19,688
|
|
|
|
52,044
|
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, full cost method (including $1,647 [2009] and $39,927
[2008] not subject to depletion)
|
|
|
1,890,079
|
|
|
|
1,877,925
|
|
|
Land
|
|
|
—
|
|
|
|
48
|
|
|
Equipment and other
|
|
|
20,469
|
|
|
|
21,371
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,910,548
|
|
|
|
1,899,344
|
|
|
Less accumulated depletion and depreciation
|
|
|
1,747,274
|
|
|
|
1,647,496
|
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
163,274
|
|
|
|
251,848
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS:
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
168
|
|
|
|
683
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
168
|
|
|
|
683
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
183,130
|
|
|
$
|
304,575
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
61
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(continued)
(thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
6,133
|
|
|
$
|
15,097
|
|
|
Advances from non-operators
|
|
|
3
|
|
|
|
5,517
|
|
|
Revenues and royalties payable
|
|
|
4,890
|
|
|
|
6,267
|
|
|
Due to affiliates
|
|
|
542
|
|
|
|
8,145
|
|
|
Notes payable
|
|
|
—
|
|
|
|
1,775
|
|
|
Accrued liabilities
|
|
|
10,109
|
|
|
|
18,831
|
|
|
Liabilities from price risk management activities
|
|
|
—
|
|
|
|
311
|
|
|
Asset retirement obligations
|
|
|
4,570
|
|
|
|
1,457
|
|
|
Current income taxes payable
|
|
|
—
|
|
|
|
47
|
|
|
Current maturities of long-term debt
|
|
|
93,666
|
|
|
|
103,849
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
119,913
|
|
|
|
161,296
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM DEBT
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
OTHER:
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
19,253
|
|
|
|
20,768
|
|
|
Other
|
|
|
3,220
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,473
|
|
|
|
20,768
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES (Notes 5, 6, 7, 11, and 12)
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS’ EQUITY:
|
|
|
|
|
|
|
|
|
|
Common stock, $0.01 par value (200,000,000 shares authorized,
92,475,527 [2009] and 93,045,592 [2008] shares issued)
|
|
|
925
|
|
|
|
948
|
|
|
Additional paid-in capital
|
|
|
535,443
|
|
|
|
538,561
|
|
|
Accumulated deficit
|
|
|
(495,624
|
)
|
|
|
(422,028
|
)
|
|
Accumulated other comprehensive income
|
|
|
—
|
|
|
|
8,129
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,744
|
|
|
|
125,610
|
|
|
Less treasury stock, at cost, -0- [2009] and 1,712,114 [2008] shares
|
|
|
—
|
|
|
|
3,099
|
|
|
|
|
|
|
|
|
|
|
Total stockholders’ equity
|
|
|
40,744
|
|
|
|
122,511
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
$
|
183,130
|
|
|
$
|
304,575
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
62
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss)
|
|
$
|
(72,636
|
)
|
|
$
|
(209,886
|
)
|
|
$
|
7,137
|
|
|
Adjustments to reconcile net earnings (loss) to net cash
provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion and depreciation
|
|
|
37,102
|
|
|
|
72,072
|
|
|
|
77,076
|
|
|
Impairment of long-lived assets
|
|
|
63,495
|
|
|
|
223,543
|
|
|
|
—
|
|
|
Amortization of other assets
|
|
|
516
|
|
|
|
224
|
|
|
|
436
|
|
|
Non-cash compensation
|
|
|
153
|
|
|
|
1,728
|
|
|
|
2,549
|
|
|
Non-cash gain on change in fair value of outstanding warrants
|
|
|
(549
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Non-cash price risk management activities
|
|
|
6
|
|
|
|
18
|
|
|
|
(21
|
)
|
|
Accretion expense
|
|
|
2,083
|
|
|
|
2,064
|
|
|
|
2,230
|
|
|
Deferred income taxes
|
|
|
—
|
|
|
|
(8,193
|
)
|
|
|
5,027
|
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
9,936
|
|
|
|
(9,941
|
)
|
|
|
1,252
|
|
|
Accounts receivable
|
|
|
4,044
|
|
|
|
3,645
|
|
|
|
4,411
|
|
|
Prepaid expenses and other
|
|
|
1,191
|
|
|
|
1,246
|
|
|
|
(1,081
|
)
|
|
Accounts payable
|
|
|
(3,022
|
)
|
|
|
4,629
|
|
|
|
(946
|
)
|
|
Advances from non-operators
|
|
|
(5,514
|
)
|
|
|
(1,480
|
)
|
|
|
3,945
|
|
|
Due to (from) affiliates
|
|
|
(7,603
|
)
|
|
|
10,725
|
|
|
|
(1,910
|
)
|
|
Revenues and royalties payable
|
|
|
(1,377
|
)
|
|
|
(325
|
)
|
|
|
(1,341
|
)
|
|
Asset retirement obligations
|
|
|
(2,243
|
)
|
|
|
(613
|
)
|
|
|
(2,055
|
)
|
|
Other assets and liabilities
|
|
|
1,435
|
|
|
|
3,311
|
|
|
|
282
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
27,017
|
|
|
|
92,767
|
|
|
|
96,991
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property and equipment
|
|
|
(25,377
|
)
|
|
|
(124,059
|
)
|
|
|
(116,696
|
)
|
|
Proceeds from sale of property
|
|
|
2,432
|
|
|
|
7,171
|
|
|
|
3,060
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(22,945
|
)
|
|
|
(116,888
|
)
|
|
|
(113,636
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
|
—
|
|
|
|
48,000
|
|
|
|
3,000
|
|
|
Reductions in long-term debt
|
|
|
(10,183
|
)
|
|
|
(19,150
|
)
|
|
|
(3,000
|
)
|
|
Proceeds — Notes payable
|
|
|
2,232
|
|
|
|
5,684
|
|
|
|
9,540
|
|
|
Reductions — Notes payable
|
|
|
(4,007
|
)
|
|
|
(6,571
|
)
|
|
|
(9,632
|
)
|
|
Repurchase of common stock
|
|
|
—
|
|
|
|
(75
|
)
|
|
|
(1,158
|
)
|
|
Payment of taxes due on vested stock
|
|
|
(195
|
)
|
|
|
(3,035
|
)
|
|
|
—
|
|
|
Additions to deferred loan costs
|
|
|
—
|
|
|
|
(904
|
)
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(12,153
|
)
|
|
|
23,949
|
|
|
|
(1,253
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CHANGE IN CASH AND CASH EQUIVALENTS
|
|
|
(8,081
|
)
|
|
|
(172
|
)
|
|
|
(17,898
|
)
|
|
Cash and cash equivalents at beginning of year
|
|
|
13,354
|
|
|
|
13,526
|
|
|
|
31,424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT END OF YEAR
|
|
$
|
5,273
|
|
|
$
|
13,354
|
|
|
$
|
13,526
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of shares for contract services
|
|
$
|
—
|
|
|
$
|
144
|
|
|
$
|
(1,033
|
)
|
|
Capital expenditures
|
|
$
|
(12,585
|
)
|
|
$
|
(6,460
|
)
|
|
$
|
4,799
|
|
|
Rig depreciation capitalized to oil and natural gas properties
|
|
$
|
91
|
|
|
$
|
1,538
|
|
|
$
|
—
|
|
|
ARO Liability — new wells drilled
|
|
$
|
47
|
|
|
$
|
451
|
|
|
$
|
476
|
|
|
ARO Liability — changes in estimates
|
|
$
|
1,711
|
|
|
$
|
(3,160
|
)
|
|
$
|
24
|
|
See notes to consolidated financial statements.
63
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Years Ended December 31, 2007, 2008 and 2009
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
Accumulated
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
Paid-In
|
|
|
Earnings
|
|
|
Comprehensive
|
|
|
Treasury Stock
|
|
|
|
|
|
|
|
Shares
|
|
|
Par Value
|
|
|
Capital
|
|
|
(Deficit)
|
|
|
Income (Loss)
|
|
|
Shares
|
|
|
Cost
|
|
|
Total
|
|
|
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
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Company’s 401(k) plan contribution
|
|
|
42
|
|
|
|
1
|
|
|
|
155
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(157
|
)
|
|
|
390
|
|
|
|
546
|
|
|
Share-based compensation
|
|
|
—
|
|
|
|
—
|
|
|
|
294
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
294
|
|
|
Compensation expense
|
|
|
—
|
|
|
|
—
|
|
|
|
1,598
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,598
|
|
|
Accum. other comprehensive income
activity
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(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
|
|
|
Issuance of rights to common stock
|
|
|
—
|
|
|
|
4
|
|
|
|
(4
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Compensation expense—stock rights
|
|
|
—
|
|
|
|
—
|
|
|
|
968
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
968
|
|
|
Issuance of shares for rights to common
stock
|
|
|
3,515
|
|
|
|
17
|
|
|
|
3,082
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,712
|
|
|
|
(3,099
|
)
|
|
|
—
|
|
|
Reductions of rights to common stock
|
|
|
—
|
|
|
|
(10
|
)
|
|
|
(3,025
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(3,035
|
)
|
|
Company’s 401(k) plan contribution
|
|
|
103
|
|
|
|
1
|
|
|
|
240
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(99
|
)
|
|
|
181
|
|
|
|
422
|
|
|
Share-based compensation
|
|
|
—
|
|
|
|
—
|
|
|
|
193
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
193
|
|
|
Accum. other comprehensive income
activity
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
8,350
|
|
|
|
—
|
|
|
|
—
|
|
|
|
8,350
|
|
|
Issuance of shares for contract services
|
|
|
11
|
|
|
|
—
|
|
|
|
37
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(60
|
)
|
|
|
107
|
|
|
|
144
|
|
|
Shares repurchased and retired
|
|
|
(34
|
)
|
|
|
—
|
|
|
|
(75
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(75
|
)
|
|
Net loss
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(209,886
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(209,886
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
93,045
|
|
|
|
948
|
|
|
|
538,561
|
|
|
|
(422,028
|
)
|
|
|
8,129
|
|
|
|
1,712
|
|
|
|
(3,099
|
)
|
|
|
122,511
|
|
|
Effect of adoption of EITF Issue 07- 05
(to record outstanding warrants at fair
value)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(960
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(960
|
)
|
|
Distribution of shares from Rabbi Trust:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
From treasury shares
|
|
|
—
|
|
|
|
(17
|
)
|
|
|
(3,082
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(1,712
|
)
|
|
|
3,099
|
|
|
|
—
|
|
|
Repurchased in exchange for
payment of withholding tax on vested
stock
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
610
|
|
|
|
(195
|
)
|
|
|
(195
|
)
|
|
Retired
|
|
|
(610
|
)
|
|
|
(6
|
)
|
|
|
(189
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(610
|
)
|
|
|
195
|
|
|
|
—
|
|
|
Share-based compensation
|
|
|
40
|
|
|
|
—
|
|
|
|
153
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
153
|
|
|
Accum. other comprehensive income activity
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
(8,129
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(8,129
|
)
|
|
Net loss
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(72,636
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(72,636
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
92,475
|
|
|
$
|
925
|
|
|
$
|
535,443
|
|
|
$
|
(495,624
|
)
|
|
$
|
—
|
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
40,744
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
64
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Net earnings (loss) applicable to common stockholders
|
|
$
|
(72,636
|
)
|
|
$
|
(209,886
|
)
|
|
$
|
7,137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax, for unrealized
gains (losses) from hedging activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized holding gains (losses) arising during period (1)
|
|
|
3,616
|
|
|
|
3,806
|
|
|
|
(2,814
|
)
|
|
Reclassification adjustments on settlement of contracts (2)
|
|
|
(11,745
|
)
|
|
|
4,544
|
|
|
|
(2,114
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,129
|
)
|
|
|
8,350
|
|
|
|
(4,928
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income (loss)
|
|
$
|
(80,765
|
)
|
|
$
|
(201,536
|
)
|
|
$
|
2,209
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Net income tax (expense) benefit
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,515
|
|
|
(2) Net income tax (expense) benefit
|
|
$
|
—
|
|
|
$
|
(119
|
)
|
|
$
|
1,138
|
|
See notes to consolidated financial statements.
65
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION, BASIS OF PRESENTATION AND GOING CONCERN
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.
Since December 31, 2008, the Company has been in default of its credit facility, under which
borrowings were $87.5 million at December 31, 2009. The credit facility default gave rise to a
cross default under the Company’s $6.2 million term loan (“rig note”). As a result, the Company
faces substantial economic difficulties. Although operating cash flow has been positive and capital
expenditures have been very significantly reduced, the Company continues to be obligated for the
expense of drilling rigs it cannot fully utilize and continues to be impacted by prices for oil and
natural gas which have exhibited extreme volatility in the recent past. The Company’s default under
the debt agreements, which has been mitigated in the short term by certain forbearance agreements,
negatively impacts future cash flow and the Company’s access to credit or other forms of capital.
If the Company is unable to comply with the terms of the forbearance agreements, it will continue
to be in default under the credit facility and the rig note and will be subject to the exercise of
remedies by third parties on account of such defaults. The exercise of such remedies, which include
acceleration of all principal and interest payments, could potentially result in the Company
seeking protection under federal bankruptcy laws. Such relief could materially and adversely affect
the Company and its shareholders. Therefore, there is substantial doubt as to the Company’s ability
to continue as a going concern for a period longer than the next twelve months. In addition, the
accompanying report of the Company’s independent registered public accounting firm includes a
“going concern” explanatory paragraph that expresses substantial doubt as to the Company’s ability
to continue as a going concern.
For further information regarding bank debt and forbearance agreements, see Note 5. For further
information regarding the Company’s drilling rig contracts, and a forbearance agreement with the
rig operator, see Note 7.
Proposed Merger.
Management has actively pursued many avenues to strengthen the financial position
of the Company over the past year. As a result, on December 22, 2009, the Company entered into an
Agreement and Plan of Merger (“Merger Agreement”) with Alta Mesa Holdings, LP (“Alta Mesa”) and
Alta Mesa Acquisition Sub, LLC, a direct wholly owned subsidiary of Alta Mesa (“Merger Sub”).
Under the terms of the Merger Agreement, as amended, shareholders will receive $0.33 per share of
common stock, to be paid in cash, and Alta Mesa will assume the Company’s debts and obligations.
The Company would be merged into Alta Mesa Acquisition Sub, LLC with the Merger Sub as the
surviving entity. The Company’s stock would cease to be publicly traded. The merger is subject to
approval by holders of two thirds of the Company’s outstanding shares of common stock; a
shareholder meeting and vote are currently scheduled for April 28, 2010. The Company filed a proxy
statement regarding the proposed merger on February 8, 2010, in which the Company’s board
recommended that shareholders vote in favor of the merger. For further information on the proposed
merger, refer to the proxy statement.
The Company’s various forbearance agreements have been extended to allow for completion of the
merger, assuming shareholder approval is obtained. However, the most recent amendment to the bank
forbearance agreement also allows the lenders to terminate the forbearance period on or after
February 28, 2010, without cause, so long as the decision to terminate is unanimous among the
lenders.
66
The Merger Agreement may be terminated under various conditions, including the occurrence of an
event with a material adverse effect on Meridian (“Material Adverse Event,” as defined in the
Merger Agreement). Both Meridian and Alta Mesa must adhere to certain customary representations
and covenants contained in the Merger Agreement, including those that restrict Meridian’s conduct
of business primarily to current operations, and restrict Meridian from soliciting other offers for
the Company, although Meridian is entitled to consider any “superior proposal,” as defined in the
Merger Agreement. As a condition of the merger, Meridian was required to enter into a settlement
regarding certain indemnification claims, which it has done (see Note 7, “Environmental
litigation,” for further information).
The Merger Agreement with Alta Mesa includes a reimbursement clause under which the Company will
pay Alta Mesa’s reasonable costs of the merger, not to exceed $1 million, in case of termination of
the agreement under various circumstances, including expiration of the term on May 31, 2010 without
consummation of the merger, and also including termination of the Merger Agreement due to
non-approval in the shareholder vote. In addition to reimbursement of Alta Mesa’s costs, the
Company would pay Alta Mesa a $3 million termination fee if, among other reasons, the Company
terminates the Alta Mesa agreement and accepts another offer for the Company, so long as the
definitive agreement related to the other offer is entered into within nine months after
termination of the Merger Agreement with Alta Mesa. The termination fee would be payable no later
than two business days after consummation of the transaction which triggered the fee.
Alta Mesa has the right to terminate the Merger Agreement at any time, whether before or after
approval by the Company’s shareholders, upon payment of a termination fee of $3 million to the
Company. The terms of the Company’s Credit Facility forbearance agreement require any such
termination payment received by Meridian to be used to repay any outstanding balance under the
Credit Facility.
There can be no assurance that the proposed merger will be completed. Approval by the shareholders
is not assured. Litigation was filed by some shareholders claiming the Company’s directors
breached their fiduciary duties in approving the merger. To avoid the risk of the litigation
delaying or adversely affecting the merger and to minimize the expense of defending the Company
against the lawsuit, in March 2010 management agreed to a proposed settlement of the litigation (see Note 7). There
can be no assurance the bank forbearance period will not be terminated by the lenders before the
proposed merger can be completed. There can be no assurance that cash flow from operations and
other sources of liquidity, including asset sales, will be sufficient to meet contractual,
operating and capital obligations. The accompanying consolidated financial statements have been
prepared in accordance with generally accepted accounting principles applicable to a going concern,
which implies that the Company will continue to meet its obligations and continue its operations
for the next twelve months. No adjustments relating to the recoverability or classification of
recorded amounts have been made, other than to classify all bank debt as current.
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, 2009, was $35,000 and at December 31, 2008, was
$9,971,000. Restricted cash was increased by $9,894,000 in May 2008, when contractual obligations
to certain executives were funded by cash placed in a Rabbi Trust account. The obligations and
trust are more fully described in Note 12. The funds from the trust were disbursed in 2009.
Remaining restricted cash is related to a contractual obligation with respect to royalties payable.
67
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. Through March 2009, capitalized
costs included general and administrative costs directly related to acquisition, exploration and
development activities. Subsequent to that date, no general and administrative costs have been
capitalized, as such activities have significantly decreased. The Company may capitalize general
and administrative costs in the future, when costs related directly to the acquisition,
exploration, and development of oil and natural gas properties are incurred. Total general and
administrative costs capitalized for the years 2009 and 2008 were $2.6 million and $17.4 million,
respectively. 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, less related deferred taxes, is limited to the sum of the
present value (10% discount rate) of the estimated future net after-tax cash flows from proved
reserves, as adjusted for the Company’s cash flow hedge positions, and on current costs, plus the
lower of cost or estimated fair value of unproved properties adjusted for related income tax
effects. Under new rules issued by the SEC, the estimated future net cash flows as of December 31,
2009, were determined using average prices for the most recent twelve months. The average is
calculated using the first day of the month price for each of the twelve months that make up the
reporting period. As of December 31, 2008 and 2007, previous rules required that estimated future
net cash flows from proved reserves be based on period end prices. See Note 4.
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 subject to depletion include net
capitalized costs, and estimated future dismantlement, restoration, and abandonment costs and are
reduced by estimated salvage values. Estimated future abandonment, dismantlement and site
restoration costs include costs to dismantle, relocate and dispose of the Company’s offshore
production platforms, gathering systems, and wells and related structures. Capitalized costs
related to unproved oil and natural gas properties are excluded from the full cost pool until
proven or impaired in the judgment of management; such costs total $1.6 million and $39.9 million
as of December 31, 2009 and 2008, respectively. At December 31, 2009, excluded costs include no
exploratory well costs.
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. In 2009, gross asset retirements included $940,000 for
furniture and equipment retired, with related accumulated depreciation of $911,000.
Repairs and maintenance are charged to expense as incurred.
Rig Operations
The Company has a long-term dayrate contract to utilize a drilling rig from an unaffiliated service
company, Orion Drilling Company, LLC, (“Orion”). Although capital expenditure plans no longer
accommodate full use of this rig, the Company is obligated for the dayrate regardless of whether
the rig is working or idle. When the contracted rig is not in use on Meridian-operated wells, Orion
may contract it to third parties, or the rig may be idled. The Company is obligated for the
difference in dayrates if it is utilized by a third party at a lesser dayrate. The contracted rig
was utilized drilling a Meridian-operated well through the end of the first quarter of 2009, and
has subsequently been contracted to a third party at a lesser dayrate than the Company’s contracted
dayrate. The costs of the rig when it is not providing services to the Company have been included
in the consolidated statements of operations as “Rig operations, net.”
68
TMR Drilling Corporation (“TMRD”), a wholly owned subsidiary of the Company, owns a rig which was
also intended primarily to drill wells operated by the Company. In April 2008, Orion began leasing
the rig from TMRD, and operating it under a dayrate contract with the Company. When the rig drills
Company wells, drilling expenditures under the dayrate contract are capitalized as exploration
costs and all TMRD profits or losses related to lease of the rig, including any incidental profits
related to the share of drilling costs borne by joint interest partners, are offset against the
full cost pool. From April through December of 2008, the rig was utilized almost continuously on
Company wells and its profits were accordingly capitalized. For the years ended 2009 and 2008, the
rig profits capitalized to the full cost pool were $180,000 and $1.1 million, respectively.
When the rig is used by Orion for work on third party wells in which the Company has no economic or
management interest, TMRD’s profit or loss related to the lease of the rig is reflected in the
consolidated statements of operations. During 2009, the rig worked on third party wells. The
Company is obligated for the difference in dayrates if the rig is utilized by a third party at a
lesser dayrate, which has occurred during 2009. This loss on a contractual obligation is included
in “Rig Operations, net” in the consolidated statements of operations. The Company’s share of
profits on the lease of the rig to Orion partially offsets the loss on the drilling contract and is
included in “Rig operations, net” on the consolidated statements of operations. The total lease
revenue included in “Rig operations, net” for 2009 was $1.1 million.
Depreciation of the owned rig was $0.9 million and $1.5 million for 2009 and 2008, respectively, of
which $0.8 million and zero was included in depletion and depreciation expense on the consolidated
statements of operations, and the remainder was capitalized to the full cost pool. In addition,
impairment expense includes $6.7 million in 2008 for impairment of the value of the rig.
See Note 7 for additional information on the Company’s plans for potential disposition of the rig
and the obligations under the drilling contracts.
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 $7.9 million, $5.6 million, and $6.0 million in 2009,
2008 and 2007, respectively. Such payments include $1.2 million in forbearance fees in 2009, which
have been included in interest expense. Cash payments (refunds) for income taxes (federal and
state, net of receipts) were $(505,000), $385,000, and $61,000 for 2009, 2008, and 2007,
respectively.
Concentrations of Credit Risk
Substantially all of the Company’s receivables are due from oil and natural gas purchasers and
other oil and natural gas producing companies located in the United States. Accounts receivable are
generally not collateralized. Historically, credit losses incurred on receivables of the Company
have not been significant.
The Company maintains its cash in bank deposit accounts which, at times, may exceed federally
insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to
$250,000 as of December 31, 2009. As of December 31, 2008, the FDIC also provides an unlimited
guarantee for balances in non-interest bearing transactional accounts. At December 31, 2009, and
December 31, 2008, the Company had approximately $35,000 and $20,696,000, respectively, in excess
of FDIC insured limits, including cash in restricted cash accounts. The Company has not experienced
any losses in such accounts.
Revenue Recognition and Accounts Receivable
69
Meridian recognizes oil and natural gas revenue from its interests in producing wells as oil and
natural gas is produced and sold from those wells (the sales method). Oil and natural gas sold is
not significantly different from the Company’s share of production. Accounts receivable includes
accrued oil and natural gas revenue receivables of approximately $10.1 million and $10.2 million as
of December 31, 2009 and 2008, respectively.
Accounts receivable includes $1.1 million and $1.6 million in amounts due from joint interest
owners as of December 31, 2009 and 2008, respectively. As of December 31, 2008, accounts
receivable included $2.4 million for insurance proceeds related to hurricane damage.
The Company maintains an allowance for doubtful accounts for trade receivables equal to amounts
estimated to be uncollectible. This estimate is based upon historical collection experience,
combined with a specific review of each customer’s outstanding trade receivable balance. Management
believes that the allowance for doubtful accounts is adequate; however, actual write-offs may
exceed the recorded allowance.
Hurricane Damage Repairs
The expense of $1.5 million in 2008 is related to damages incurred from hurricanes Ike and Gustav
and is primarily related to the Company’s insurance deductible.
Capitalized Interest
Interest cost is capitalized as part of the historical cost of assets. During 2008 and 2007,
respectively, interest of approximately $191,000 and $323,000 was capitalized on the construction
of the Company’s drilling rig. The Company’s oil and natural gas properties did not include any
individual investments considered significant enough to qualify for interest capitalization under
our internal policies. Interest is capitalized using a weighted average interest rate based on the
Company’s outstanding borrowings. No interest was capitalized in 2009.
Earnings Per Share
Basic earnings per share amounts are calculated based on the weighted average number of shares of
common stock outstanding during each period. Diluted earnings per share is based on the weighted
average number of shares of common stock outstanding for the periods, including the dilutive
effects of stock options, warrants, and share rights granted. Dilutive options, warrants, and share
rights 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. Shares of
Company stock held by the trustee of the Rabbi Trust, although treated as treasury stock for
presentation on the Consolidated Balance Sheets, have been included in the computation of basic and
diluted earnings per share, as all conditions precedent to their issue, other than passage of time,
had been satisfied prior to distribution of the shares in 2009.
Stock Options
The Company follows the guidance in Accounting Standards Codification Topic 718 (“ASC 718”) to
account for share-based payment transactions in which the Company receives services in exchange for
equity instruments of the Company.
Compensation expense is recorded for stock options and other equity awards over the requisite
vesting periods based upon the fair value on the date of the grant.
Fair Value of Financial Instruments
70
The Company’s 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. As of December 31, 2009 the Company believes it is
not practicable to estimate the fair value of its outstanding debt under its credit facility in
light of the payment default. The reduction in credit standing from this default would certainly
tend to reduce the fair value of the debt, but it is not practicable to estimate the amount of such
reduction. The carrying value of that debt is $87.5 million at December 31, 2009. See Note 5 for
further details on the credit facility. The Company also has a smaller bank debt with a fixed rate.
The fair value of the rig note at December 31, 2009 is estimated as approximately $4 million; the
corresponding carrying value is $6.2 million. The fair value was estimated based on the fair value
of the underlying collateral. The collateral is a drilling rig owned by the Company; see Note 9 for
further information on how fair value for the rig was estimated. The Company’s oil and gas price
risk hedging contracts are also financial instruments, recorded at fair value; see Note 13.
Notes Payable
Notes payable are related to the financing of the Company’s insurance program. The weighted average
interest rate on the notes payable was 4.69%, as of December 31, 2008. There were no outstanding
notes payable as of December 31, 2009.
Lease Accounting
The Company amortizes the cost of leasehold improvements over the shorter of the life of the asset
or the term of the lease. Rent incentives, such as rent holidays, are also amortized over the life
of the lease.
Derivative Financial Instruments
The Company follows the guidance of Accounting Standards Codification Topic 815, “Derivatives and
Hedging” (“ASC 815”). The Company enters into derivative contracts to hedge the price risks
associated with a portion of anticipated future oil and natural gas production. The Company’s
derivative financial instruments have not been entered into for trading purposes and the Company
typically has the ability and intent to hold these instruments to maturity. Counterparties to the
Company’s derivative agreements are major financial institutions.
All derivatives are recognized on the balance sheet at their fair value. Derivatives are noted as
“Assets (or Liabilities) from price risk management activities” and are classified on the
Consolidated Balance Sheets as long-term or short-term based on the maturity date of the derivative
agreement. On the date the derivative contract is entered into, the Company designates the
derivative as either a hedge of the fair value of a recognized asset or liability or of an
unrecognized firm commitment (“fair value” hedge) or a hedge of a forecasted transaction or the
variability of cash flows to be received or paid related to a recognized asset or liability (“cash
flow” hedge). The Company formally documents all relationships between hedging instruments and
hedged items, as well as its risk management objective and strategy for undertaking various hedge
transactions. This process includes linking all derivatives that are designated as fair-value or
cash-flow hedges to specific assets and liabilities on the balance sheet or to specific firm
commitments or forecasted transactions. The Company also formally assesses, both at the hedge’s
inception and on an ongoing basis, whether the derivatives that are used in hedging transactions
are highly effective in offsetting changes in fair values or cash flows of hedged items.
Changes in the fair value of a derivative that is highly effective and that is designated and
qualifies as a cash-flow hedge are recorded in other comprehensive income, until earnings are
affected by the variability in cash flows of the designated hedged item, whereupon they are
recognized in oil or natural gas revenues. The Company recognized a loss of $6,000, a loss of
$18,000, and a gain of $21,000 related to hedge ineffectiveness during the years ended December 31,
2009, 2008,
71
and 2007, respectively. Gains and losses from hedge ineffectiveness are presented as “Price risk
management activities” in the Consolidated Statements of Operations.
The Company discontinues cash flow hedge accounting prospectively when it is determined that the
derivative is no longer effective in offsetting changes in the fair value or cash flows of the
hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is
redesignated as a hedging instrument because it is unlikely that a forecasted transaction will
occur, or management determines that designation of the derivative as a hedging instrument is no
longer appropriate.
When cash flow hedge accounting is discontinued because it is probable that a forecasted
transaction will not occur, the Company continues to carry the derivative on the balance sheet at
its fair value with subsequent changes in fair value included in earnings, and gains and losses
that were accumulated in other comprehensive income 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 reclassified into operations in the month in which the related
derivative contracts settle.
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, deferred tax assets and liabilities are recognized for the estimated
future tax effects attributable to temporary differences and carryforwards. Ultimately, realization
of a deferred tax benefit depends on the existence of sufficient taxable income within the
carryback/carryforward period to absorb future deductible temporary differences or a carryforward.
In assessing the realizability of deferred tax assets, management considers whether it is more
likely than not that some portion or all of the deferred tax assets will not be realized, including
such evidence as the scheduled reversal of deferred tax liabilities and projected future taxable
income. As a result of the current assessment, in both 2008 and 2009 the Company recorded a
valuation allowance equal to the net deferred tax assets.
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 Company’s
Consolidated Statements 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.
72
Recent Accounting Pronouncements
In July 2009, the Financial Accounting Standards Board (“FASB”) issued revised authoritative
guidance regarding the hierarchy of generally accepted accounting principles. Under this revised
guidance, the FASB Accounting Standards Codification (“Codification”), the FASB’s new web-based
codification of accounting and reporting guidance, along with guidance provided by the SEC, are the
only “authoritative” sources of such guidance. All guidance not contained in the Codification,
other than SEC guidance, will be considered “non-authoritative.” The Codification is designed to
incorporate previously issued guidance from sources such as the FASB, the American Institute of
Certified Public Accountants, and the Public Company Accounting Oversight Board, and is not
intended to change GAAP for non-governmental entities. The revised guidance on the hierarchy
provides additional guidance on the selection, interpretation, and application of accounting
principles from the Codification and from non-authoritative sources when necessary. The guidance is
effective for financial statements issued for interim and annual periods ending after September 15,
2009. The Company adopted the revised guidance effective July 1, 2009; the adoption did not have a
material impact on financial position or results of operations.
In September 2006, the FASB issued Statement of Financial Accounting Standard (“SFAS”) No. 157,
“Fair Value Measurements,” codified in Accounting Standards Codification (“ASC”) Topic 820 (“ASC
820”). ASC 820 defines fair value, establishes a framework for measuring fair value in generally
accepted accounting principles and expands disclosure about fair value measurements. In accordance
with the effective dates provided in the guidance, the Company adopted the guidance for
measurements of the fair values of financial instruments and recurring fair value measurements of
non-financial assets and liabilities on January 1, 2008. Effective January 1, 2009, the Company
began applying the new guidance to non-recurring measurements of the fair values of non-financial
assets and liabilities, such as asset retirement obligations and impairments of long-lived assets
other than oil and natural gas properties. The adoptions had no material impact on financial
position or results of operations.
In January 2010, the FASB updated Topic 820 with Accounting Standards Update (“ASU”) 2010-06, “Fair
Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value
Measurements.” This ASU requires new disclosures and clarifies certain existing disclosure
requirements about fair value measurements. ASU 2010-06 requires a reporting entity to disclose
significant transfers in and out of Level 1 and Level 2 fair value measurements, to describe the
reasons for the transfers and to present separately information about purchases, sales, issuances
and settlements for fair value measurements using significant unobservable inputs. ASU 2010-06 is
effective for interim and annual reporting periods beginning after December 15, 2009, except for
the disclosures about purchases, sales, issuances and settlements in the roll forward of activity
in Level 3 fair value measurements, which is effective for interim and annual reporting periods
beginning after December 15, 2010; early adoption is permitted. The Company does not expect that
the adoption of ASU 2010-06 will have a material impact on financial position, results of
operations or cash flows.
In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations,” codified in ASC Topic
805 (“ASC 805”). ASC 805 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, ASC
805 is effective on a prospective basis for all business combinations completed on or after January
1, 2009. The Company adopted the revised guidance effective January 1, 2009; the adoption did not
have a material impact on financial position or results of operations.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging
Activities,” codified in ASC Topic 815-10-50 (“ASC 815-10-50”). ASC 815-10-50 provides guidance
for additional disclosures regarding derivative contracts, including expanded discussions of risk
and hedging strategy, as well as new tabular presentations of accounting data related to derivative
instruments. The Company adopted the revised guidance effective
73
January 1, 2009; the adoption did not have a material impact on financial position or results of
operations. The additional disclosures are included in Note 13.
In June 2008, the FASB Emerging Task Force issued EITF Abstract Issue No. 07-05, “Determining
Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock” codified as ASC
Topic 815-40-15 (“ASC 815-40-15”). ASC 815-40-15 clarifies the determination of equity instruments
which may qualify for an exemption from the other provisions of ASC 815, “Derivatives and Hedging.”
Generally, equity instruments which qualify under the guidelines of ASC 815-40-15 may be accounted
for in equity accounts; those which do not qualify are subject to derivative accounting. The
Company adopted the guidance of ASC 815-40-15 on January 1, 2009. The effects of the adoption
included a revision in the carrying value of certain outstanding warrants, and recognition of a
related liability of $960,000 on January 1, 2009, as well as recognition of an unrealized gain of
$548,000 included in general and administrative expense, due to the change in fair value of those
warrants during 2009. See Note 10, “Warrants,” for further information.
In December 2008, the SEC published a Final Rule,
“
Modernization of Oil and Gas Reporting.
”
The new
rule permits the use of new technologies to determine proved reserves if those technologies have
been demonstrated to lead to reliable conclusions about reserves volumes. The new requirements also
allow companies to disclose their probable and possible reserves to investors. In addition, the new
disclosure requirements require companies to: (
a
) report the independence and qualifications of its
reserves preparer or auditor; (
b
) file reports when a third party is relied upon to prepare
reserves estimates or conducts a reserves audit; and (
c
) report oil and gas reserves using an
average price based upon the prior 12-month period rather than year-end prices. The use of average
prices affects impairment and depletion calculations. The new rule became effective for reserve
reports as of December 31, 2009; the FASB incorporated the new guidance into the Codification as
Accounting Standards Update 2010-03, effective also on December 31, 2009, ASC Topic 932,
“Extractive Activities — Oil and Gas.”
The Company adopted the new guidance effective December 31, 2009; information about the company’s
reserves has been prepared in accordance with the new guidance and is included in Note 19;
management has chosen not to provide information on probable and possible reserves. The Company’s
reserves were affected primarily by the use of the average prices rather than the period-end prices
required under the prior rules. As a result of adopting the new guidance, we estimate that
Meridian’s December 31, 2009 proven reserves decreased approximately 1.4 Bcfe and prices used in
the calculation decreased approximately 30%. This change in turn affected the results of the
Company’s ceiling test for the fourth quarter of 2009, which was a write-down of $4.0 million.
Had the new rule using average pricing not been implemented, the write down in the fourth quarter
of 2009 would not have been necessary. The change in total reserves using the new rules had a
negligible effect on depletion expense in the fourth quarter of 2009, as total proved reserves are
the basis of depletion calculations.
In December 2009, the FASB issued revised authoritative guidance regarding consolidation of
variable interest entities (“VIE’s”) in ASU 2009-17, “Improvements to Financial Reporting by
Enterprises Involved with Variable Interest Entities,” codified as ASC 810-10-05-08. The ASU
(originally issued as SFAS No. 167 in June 2009) amends existing consolidation guidance for
variable interest entities. Variable interest entities generally are thinly-capitalized entities
which under previous guidance may not have been consolidated. The revised guidance requires a
company to perform a qualitative analysis to determine whether to consolidate a VIE, which includes
consideration of control issues other than the primarily quantitative considerations utilized prior
to this revision. In addition, the revised guidance requires ongoing assessments of whether to
consolidate VIE’s, rather than only when specific events occur. The revised guidance also requires
additional disclosures about consolidated and unconsolidated VIE’s, including their impact on the
company’s risk exposure and its financial statements. The revised guidance will be effective for
financial statements for annual and interim periods beginning after November 15, 2009. The Company
has not yet determined the impact of adoption on its financial position or results of operations.
74
In April 2009, the FASB issued new authoritative guidance regarding interim disclosures about the
fair value of financial instruments, which enhances consistency in financial reporting by
increasing the frequency of fair value disclosures. The guidance is effective for interim and
annual periods ending after June 15, 2009, with early adoption permitted for periods ending after
March 15, 2009. The Company adopted the new guidance effective April 1, 2009. The adoption did
not have a material impact on financial position or results of operations of the Company. The
disclosures are included above, “Fair Value of Financial Instruments.”
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
The Company estimates the present value of future costs of dismantlement and abandonment of its
wells, facilities, and other tangible long-lived assets, recording them as liabilities in the
period incurred. Asset retirement obligations are calculated using an expected present value
technique. Salvage values are excluded from the estimation.
When the liability is initially recorded, the entity increases the carrying amount of the related
long-lived asset. 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, the
Company incurs a gain or loss based upon the difference between the estimated and final liability
amounts. The Company records gains or losses from settlements as adjustments to the full cost pool.
Accretion expenses were $2.1 million, $2.1 million and $2.2 million in 2009, 2008 and 2007,
respectively.
The following table describes the change in the Company’s asset retirement obligations for the
years ended December 31, 2009 and 2008 (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Asset retirement obligation at beginning of year
|
|
$
|
22,225
|
|
|
$
|
23,483
|
|
|
Additional retirement obligations incurred
|
|
|
47
|
|
|
|
451
|
|
|
Settlements
|
|
|
(2,243
|
)
|
|
|
(613
|
)
|
|
Revisions to estimates and other changes
|
|
|
1,711
|
|
|
|
(3,160
|
)
|
|
Accretion expense
|
|
|
2,083
|
|
|
|
2,064
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation at end of year
|
|
|
23,823
|
|
|
|
22,225
|
|
|
Less: current portion
|
|
|
4,570
|
|
|
|
1,457
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation, long-term
|
|
$
|
19,253
|
|
|
$
|
20,768
|
|
|
|
|
|
|
|
|
|
75
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.
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 present value (10% discount rate) of the
estimated future after-tax net revenues from proved properties after giving effect to cash flow
hedge positions, and the lower of cost or fair value of unproved properties adjusted for related
income tax effects. Under new rules issued by the SEC, the estimated future net cash flows as of
December 31, 2009, were determined using average prices for the most recent twelve months. The
average is calculated using the first day of the month price for each of the twelve months that
make up the reporting period. As of December 31, 2008 and 2007, previous SEC rules required that
estimated future net cash flows from proved reserves be based on period end prices.
The cost of unevaluated oil and natural gas properties not subject to depletion is also 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, available geological and geophysical information, and actual
exploration and development plans. Any impairment assessed is added to the cost of proved
properties being amortized.
In the first quarter of 2009, the Company recognized a non-cash impairment of $59.5 million to oil
and natural gas properties, based on March 31, 2009 pricing of $3.76 per Mcf of natural gas and
$49.66 per barrel of oil. In the fourth quarter of 2009, the Company recognized a non-cash
impairment of $4.0 million to oil and natural gas properties, based on December 31, 2009 pricing of
$3.87 per Mcf of natural gas and $61.18 per barrel of oil. The total impairment recorded in 2009
to oil and natural gas properties was $63.5 million.
In the fourth quarter of 2008, the Company recognized non-cash impairment expense of $216.8 million
($203.2 million after tax) to the Company’s oil and natural gas properties under the full cost
method of accounting, based on December 31, 2008 pricing of $5.79 per Mcf of natural gas and $44.04
per barrel of oil.
The Company also recorded a non-cash impairment of the value of its drilling rig in 2008, due to
uncertainties regarding utilization and dayrates for similar rigs, which decreased significantly
after the second quarter of 2008. The value of the rig was based on the present value of estimated
cash flows from the asset, using management’s best estimates of utilization and dayrates. The
estimated value was $5.5 million as of December 31, 2008. Accordingly, the Company recorded
non-cash impairment expense of $6.7 million to write down the net book value of the rig to $5.5
million. Management performs impairment testing of the drilling rig each quarter. No further
impairment has been recorded for the rig. At December 31, 2009, the carrying value of the rig
exceeded its estimated fair value (based on discounted cash flows) by approximately $0.9 million.
However, no impairment was necessary at that date as the undiscounted cash flows exceeded the
carrying value. Authoritative accounting guidance provides for impairment only when
carrying value exceeds undiscounted
cash flows.
Due to the substantial volatility in oil and natural gas prices and their effect on the carrying
value of the Company’s proved oil and natural gas reserves, there can be no assurance that future
write-downs will not be required as a result of factors that may negatively affect the present
value of proved oil and natural gas reserves and the carrying value of oil and natural gas
properties, including volatile oil and natural gas prices, downward revisions in estimated proved
oil and natural gas reserve quantities and unsuccessful drilling activities. Furthermore, due to
the related impact of volatile energy prices on the drilling industry, there can be no assurance
that future write-downs will not be required for the drilling rig as well.
76
5. DEBT
Credit Facility
.
The Company has a credit facility with a group of banks (collectively, the
“Lenders,”) with a maturity date of February 21, 2012 (the “Credit Facility.”) The Credit Facility
is subject to borrowing base redeterminations and bears a floating interest rate based on LIBOR or
the prime rate of Fortis Capital Corp., the administrative agent of the Lenders. The borrowing base
and the interest formula have been redetermined or amended multiple times. As of December 31, 2008,
the borrowing base was $95 million and was fully drawn. The interest rate formula in effect at that
date was LIBOR plus 3.25% or prime plus 2.5%.
Obligations under the Credit Facility are to be secured by pledges of outstanding capital stock of
the Company’s subsidiaries and by a first priority lien on not less than 75% (95% in the case of an
event of default) of its present value of proved oil and natural gas properties. 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, restrictions on incurrence of additional debt, and an unqualified
audit report on the Company’s consolidated financial statements.
As of December 31, 2008, the Company was in default of two of the covenants under the agreement,
including one that requires that the Company maintain a current ratio (as defined in the Credit
Facility) of one to one. The current ratio, as defined, was less than the required one to one at
December 31, 2008 and continued to be, through December 31, 2009. The Company is also in default of
the requirement that the Company’s auditors’ opinion for the current financial statements be
without modification. Both the Company’s 2008 and 2009 audit reports from its independent
registered public accounting firm included a “going concern” explanatory paragraph that expressed
substantial doubt about the Company’s ability to continue as a going concern. As a result of the
defaults, the outstanding Credit Facility balances of $95 million at December 31, 2008 and $87.5
million at December 31, 2009 have been classified as current in the accompanying consolidated
balance sheets. Also in response to the defaults, the Company provided additional security to the
Lenders, such that first priority liens cover in excess of 95% of the present value of proved oil
and natural gas properties.
The Credit Facility has been subject to semi-annual borrowing base redeterminations effective on
April 30 and October 31 of each year, with limited additional unscheduled redeterminations also
available to the Lenders or the Company. The determination of the borrowing base is subject to a
number of factors, including quantities of proved oil and natural gas reserves, the banks’ price
assumptions related to the price of oil and natural gas and other various factors unique to each
member bank. The Lenders can redetermine the borrowing base to a lower level than the current
borrowing base if they determine that the Company’s oil and natural gas reserves, at the time of
redetermination, are inadequate to support the borrowing base then in effect. In the event the
redetermined borrowing base is less than outstanding borrowings under the Credit Facility, the
Credit Facility requires repayment of the deficit within a specified period of time.
On April 13, 2009, the Lenders notified the Company that, effective April 30, 2009, the borrowing
base was reduced from its then-current and fully drawn $95 million to $60 million. As a result, a
$34.5 million payment to the Lenders for the borrowing base deficiency was due July 29, 2009, based
on the borrowings outstanding on that date. The Company did not have sufficient cash available to
repay the deficiency and, consequently, failed to pay such amount when due. Prior to July 29, 2009,
the Company was in covenant default under the terms of the Credit Facility; on and after that date
it was in covenant default and payment default as well.
Under the terms of the Credit Facility, the Lenders have various remedies available in the event of
a default, including acceleration of payment of all principal and interest.
77
On September 3, 2009, the Company entered into a forbearance agreement with the Lenders under the
Credit Facility (“Bank Forbearance Agreement”). The Bank Forbearance Agreement provided that the
Lenders would forbear from exercising any right or remedy arising as a result of certain existing
events of default under the Credit Facility until the earlier of December 3, 2009 or the date that
any default occurred under the Bank Forbearance Agreement. The terms of the Bank Forbearance
Agreement required the Company to consummate a capital transaction such as a capital infusion or a
sale or merger of the Company, before October 30, 2009. The deadlines for the capital transaction
and the forbearance period were extended several times by amendments to the Bank Forbearance
Agreement.
At origination of the Bank Forbearance Agreement, the Company paid the Lenders $2.0 million of
principal owed under the Credit Facility. Under the terms of the agreement the Company made a total
of $5.0 million in further principal payments through December 31, 2009, bringing the balance at
that date to $87.5 million. The Company also paid forbearance fees to the Lenders of $945,000,
charged to interest expense in the third quarter of 2009, and incurred an additional $476,000 in
forbearance fees, charged to interest expense in the fourth quarter of 2009. In addition, the
Company incurred approximately $2.3 million in legal and consulting fees, recorded in general and
administrative expense, to originate and amend the Bank Forbearance Agreement and other related
agreements.
On December 22, 2009, the Company entered into an Agreement and Plan of Merger (the “Merger
Agreement”) with Alta Mesa Holdings, LP (“Alta Mesa”) and Alta Mesa Acquisition Sub, LLC, a direct
wholly owned subsidiary of Alta Mesa. The Eleventh Amendment to Forbearance and Amendment
Agreement (“11
th
Amendment”) provided the Lenders’ consent to the Merger Agreement and
extended the date for consummation of a capital transaction, such as the Alta Mesa merger, and the
forbearance period, to the earlier of the consummation of the merger with Alta Mesa, the
termination of the Merger Agreement, or May 31, 2010. However, the 11
th
Amendment also
allows the Lenders to terminate the forbearance period on or after February 28, 2010, without
cause, so long as the decision to terminate is unanimous among the Lenders. The 11
th
Amendment also requires the Company to repay $1 million in principal to the Lenders per month. As
of March 31, 2010, the outstanding balance under the Credit Facility is $83 million.
In accordance with the 11th Amendment, the Company has filed its shareholder proxy statement
regarding the merger and called a shareholder meeting currently scheduled for April 28, 2010 to
approve the transaction. There can be no assurance that shareholders will approve the transaction
or that the merger will be consummated within the time constraints specified in the11th Amendment.
Should the forbearance period terminate, the Company will be in default, unprotected from the
action of remedies available to the Lenders, which cannot be predicted. Such remedies include
acceleration of all outstanding principal and interest.
The Bank Forbearance Agreement placed other restrictions on the Company with respect to capital
expenditures, sales of assets, and incurrence and prepayments of other indebtedness and amended the
Credit Facility in certain respects. It contains covenants regarding the frequency of reporting of
financial and cash flow information to the Lenders, as well as cash account control agreements
which provide a secured lien over substantially all of the Company’s cash accounts.
Under the terms of the Bank Forbearance Agreement, as amended, the Credit Facility is amended such
that scheduled borrowing base redeterminations will occur quarterly rather than semi-annually, to
be effective January 31, April 30, July 31, and October 31 of each year. Outstanding amounts in
excess of the borrowing base must be repaid according to certain defined terms. The deficiency
could be paid in three equal installments over a maximum period of 100 days after the incurrence of
a borrowing base deficiency, or alternatively, the Company could provide additional sufficient
collateral to cover the deficiency. However, as the Company has already pledged in excess of 95% of
the value of all proved oil and natural gas reserves as security, such an alternative could apply
only to a small borrowing base deficiency. The Lenders have provided the Company with a limited
waiver postponing the next borrowing base redetermination to the end of the forbearance period. No
assurance can be given that further deficiencies will not be incurred at the next redetermination.
78
The Lenders exercised their right to increase the interest rate on outstanding borrowings by 2%
(“default interest,” under the terms of the Credit Facility) as of July 30, 2009. The floating
interest rate is based on the prime interest rate, currently 3.25%, plus 2.5%, plus the default
increment of 2%, resulting in a total rate of 7.75% at December 31, 2009 and continuing at that
rate currently
.
The additional default interest has been effective as to all outstanding borrowings
under the Credit Facility since the July 29, 2009 payment default, and the LIBOR alternative was
also eliminated. No interest payments are in arrears.
Rig Note
.
On May 2, 2008, the Company, through its wholly owned subsidiary TMRD, entered into a
financing agreement (“rig note”) with The CIT Group / Equipment Financing, Inc. (“CIT”). Under the
terms of the agreement, TMRD borrowed $10.0 million, at a fixed interest rate of 6.625%, which
increases in an event of default. The loan is collateralized by the drilling rig, as well as
general corporate credit. The term of the loan is five years, expiring on May 2, 2013.
Effective as of December 31, 2008, the Company was in default under the rig note. Under the terms
of the rig note, a default under the Credit Facility triggers a cross-default under the rig note.
The remedies available to CIT in the event of default include acceleration of all principal and
interest payments. Accordingly, all indebtedness under the rig note, $8.8 million at December 31,
2008 and $6.2 million at December 31, 2009, has been classified as current in the accompanying
consolidated balance sheets.
On September 3, 2009, the Company also entered into a forbearance agreement with CIT (“CIT
Forbearance Agreement.”) The forbearance period under the CIT Forbearance Agreement has been
extended several times, most recently by the Fourth Amendment to Forbearance and Amendment
Agreement (“4
th
Amendment”). The forbearance period ends the earlier of the
consummation of the merger with Alta Mesa, the termination of the Merger Agreement, May 31, 2010,
or the date of any default under either the CIT Forbearance Agreement or the Bank Forbearance
Agreement. The 4
th
Amendment also provides CIT’s consent to the merger with Alta Mesa.
CIT retains the right to terminate the forbearance period if, in its sole determination, Alta Mesa
experiences changes to its financial condition that would adversely affect its ability to complete
the merger with the Company.
At origination of the CIT Forbearance Agreement, the Company prepaid, without penalty, $1.0 million
of principal on the rig note and began to pay “default interest” of an additional 4% effective
August 1, 2009, as allowed to CIT under the terms of the rig note, bringing the total monthly
payment to approximately $220,000. The Company also paid, and recorded in general and
administrative expense in the third quarter, a forbearance fee of approximately $50,000. There can
be no assurance that the forbearance period under the CIT Forbearance Agreement will provide
sufficient time to resolve the cross-default under the rig note.
Current Debt Maturities
Scheduled debt maturities for the next five years and thereafter, as of December 31, 2009,
including notes payable, are as follows: $93.7 million in 2010 and none thereafter. Absent the
assumed acceleration of principal under the Credit Facility and the rig note, scheduled maturities
would be: $29.5 million in 2010, $2.2 million in 2011, $62.0 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 Company’s office lease until September 30, 2011. As of December 31, 2009, the
remaining base rental payments will be $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 $1.8 million, $2.0 million, and $2.1 million in 2009, 2008, and
2007, respectively. Future minimum lease payments under all non-cancelable operating leases having
initial
79
terms of one year or more are $2.1 million for 2010, $1.6 million for 2011, and none thereafter. In
addition, over the next two years, the Company has contractual obligations for the use of two
drilling rigs. These obligations are $12.4 million in 2010 and $0.9 million in 2011. See Note 7
for further information.
Additional contractual obligations include: $1 million in 2010 to Shell Oil Company under the
settlement contract described in Note 7 below, if the contract is not terminated; and $1.5 million
in 2010 and $0.2 million in 2011 to be paid under various settlement contracts. The Shell Oil
Company obligation continues through 2014, with a payment of $1 million due each calendar year, for
a total of $5 million.
In addition to the obligations described above, the Company has a contingent obligation related to
the merger with Alta Mesa. The Merger Agreement with Alta Mesa includes a reimbursement clause
under which the Company will pay Alta Mesa’s reasonable costs of the merger, not to exceed $1
million, in case of termination of the agreement under various circumstances, including expiration
of the term on May 31, 2010 without consummation of the merger, and also including termination of
the Merger Agreement due to non-approval in the shareholder vote. In addition to reimbursement of
Alta Mesa’s costs, the Company would pay Alta Mesa a $3 million termination fee if, among other
reasons, the Company terminates the Alta Mesa agreement and accepts another offer for the Company,
so long as the definitive agreement related to the other offer is entered into within nine months
after termination of the Merger Agreement with Alta Mesa. The termination fee would be payable no
later than two business days after consummation of the transaction which triggered the fee.
7. COMMITMENTS AND CONTINGENCIES
Default under Credit Agreement
As described in Notes 1 and 5, the Company has been in default under the terms of the Credit
Facility and the rig note since December 31, 2008. Although forbearance has been provided by these
Lenders under short-term agreements, there can be no assurance that the Company will be able to
comply with the terms of the agreements. Among the default remedies available to the Lenders under
each of these debt agreements is acceleration of all principal and interest payments. Accordingly,
all such debt has been classified as current in the Consolidated Balance Sheets as of December 31,
2009 and 2008. The Company can give no assurance that the transactions contemplated by the Merger
Agreement will be completed (see Note 1) and failure to complete the merger will significantly
impact the credit defaults as well as the Company’s ability to continue as a going concern;
therefore, the Company has not provided for this matter as of December 31, 2009, in its financial
statements at December 31, 2009, other than to reclassify all outstanding debt as current at that
date and at December 31, 2008.
Proposed Merger Termination Fee
As described in Note 1, the Company’s board of directors has approved an offer of merger with Alta
Mesa, pending a shareholder vote. If the Merger Agreement is terminated by Meridian under various
scenarios, including lack of shareholder approval, the Company will be required to reimburse Alta
Mesa for their expenses of the merger, not to exceed $1 million. Acceptance of an alternative
offer for the Company and consummation of that transaction under certain circumstances could
obligate the Company to pay Alta Mesa a termination fee of $3 million (see Note 6 above).
Litigation
80
H. L. Hawkins litigation
. In December 2004, the estate of H.L. Hawkins filed a claim against
Meridian for damages “estimated to exceed several million dollars” for Meridian’s alleged gross
negligence, willful misconduct and breach of fiduciary duty under certain agreements concerning
certain wells and property in the S.W. Holmwood and E. Lake Charles Prospects in Calcasieu Parish
in Louisiana, as a result of Meridian’s satisfying a prior adverse judgment in favor of Amoco
Production Company. Mr. James Bond 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. Bond’s employment ended
with Mr. Hawkins, Jr., and his companies, 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 Chief Operating Officer of the Company at the time. A
hearing was held before Judge Kay Bates on April 14, 2008. Judge Bates granted Hawkins’ Motion
finding that Meridian was estopped from arguing that it did not breach its contract with Hawkins as
a result of the United States Fifth Circuit’s decision in the
Amoco
litigation. Meridian disagrees
with Judge Bates’ ruling but the Louisiana First Court of Appeal declined to hear Meridian’s writ
requesting the court overturn Judge Bates’ ruling. Meridian filed a motion with Judge Bates asking
that the ruling be made a final judgment which would give Meridian the right to appeal immediately;
however, the Judge declined to grant the motion, allowing the case to proceed to trial. 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 Meridian’s
actions were not grossly negligent, but were within the business judgment rule. Since Mr. Bond’s
death, a pleading has 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,
2009.
Title/lease disputes.
Title and lease disputes may arise in the normal course of the Company’s
operations. These disputes are usually small but could result in an increase or decrease in
reserves once a final resolution to the title dispute is made.
Environmental litigation.
Various landowners have sued Meridian (along with numerous other oil
companies) in lawsuits concerning several fields in which the Company has had operations. The
lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and
punitive damages for alleged breaches of mineral leases and alleged failure to restore the
plaintiffs’ lands from alleged contamination and otherwise from the Company’s oil and natural gas
operations. In some of the lawsuits, Shell Oil Company and SWEPI LP (together, “Shell”) have
demanded contractual indemnity and defense from Meridian based upon the terms of the two
acquisition agreements 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. On December 9, 2008 Shell sent Meridian a letter reiterating its demand for indemnity
and making claims of amounts which were substantial in nature and if adversely determined, would
have a material adverse effect on the Company. Shell initiated formal arbitration proceedings on
May 11, 2009, seeking relief only for the claimed costs and expenses arising from one of the two
acquisition agreements between Shell and Meridian. Meridian denies that it owes any indemnity under
either of the two acquisition agreements; however, the Company and Shell entered into a settlement
agreement on January 11, 2010. Under the terms of the settlement, the Company will pay Shell $5
million in five equal annual payments beginning in 2010 upon the closing of a sale of the assets or
equity interest in the Company to a third party (such as the merger with Alta Mesa described in
Note 1), or at an earlier date should Meridian be able. Meridian will also transfer title to
certain land the Company owns in Louisiana and an overriding royalty interest of minor value. In
return, Shell will release Meridian from any indemnity claim arising from any current or historical
claim against Shell, and will release Meridian’s indemnity obligation with respect to any future
claim on all but a small subset of the properties acquired pursuant to the acquisition agreements
related to the fields. The settlement agreement will terminate on May 1, 2010 if the first payment
and the land and overriding royalty interest transfer have not been made, or unless
81
extended at the discretion of Shell. The Company recorded $4.2 million in expense in the fourth
quarter of 2009 to recognize the estimated value of the proposed settlement, including the
historical cost of the land and discounting the cash payments to present value.
Other than the with regard to the Shell matter, the Company is unable to express an opinion with
respect to the likelihood of an unfavorable outcome of the various environmental claims or to
estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, the
Company has not provided any amount for these claims in its financial statements at December 31,
2009.
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.
Property tax litigation.
In August, 2009, Gene P. Bonvillain, the tax assessor for Terrebonne
Parish, Louisiana, filed a lawsuit against the Company, alleging under-reporting and underpayment
of parish property taxes for the years 1998-2008. The claims, which are very similar to thirty
other cases filed by Bonvillain against other oil and natural gas companies, allege that certain
facilities or other property of the Company were improperly omitted from annual self-reporting tax
forms submitted to the parish for the years 1998-2008, and that the properties Meridian did report
on such forms were improperly undervalued and mischaracterized. The claims include recovery of
delinquent taxes in the amount of $3.5 million, which the claimant advises may be revised upward,
and general fraud charges against the Company. All thirty-one similar cases have been consolidated
in U. S. District Court for the Eastern District of Louisiana.
Meridian denies the claims and expects to file a motion to dismiss the case, which it considers to
be without merit. Meridian asserts that Mr. Bonvillain has no legal basis for filing litigation to
collect what are, in essence, additional taxes based on reassessed property values. Furthermore,
Meridian asserts that the fraud element of the case is insufficiently supported. Meridian intends
to vigorously defend this action. 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, 2009.
Shareholder litigation
. On January 8, 2010 Mr. Eliezer Leider, a purported Company shareholder,
filed a derivative lawsuit filed on behalf of the Company,
Leider, derivatively on behalf of The
Meridian Resource Corporation v. Ching, et al.
in Harris County District Court
.
Defendants were
the Company’s directors, Alta Mesa Holdings, LP, and Alta Mesa Acquisition Sub, LLC. Leider
alleged that the Company’s directors breached their fiduciary duties in approving the merger
transaction with Alta Mesa and he requested, but was denied, a temporary restraining order against
the Company. This lawsuit was consolidated with another, similar one from Mr. Jeremy Rausch, which
was a class action lawsuit. Counsel for Leider was appointed lead counsel. On March 23, 2010, the
parties agreed in principle to settle the now-consolidated
Leider
action. The settlement proposed is
conditioned on, among other things, approval of the merger by Meridian’s shareholders. Under the
terms of the proposed settlement, all claims relating to the Merger Agreement and the merger will
be dismissed on behalf of Meridian’s stockholders. As part of the settlement, the defendants have
agreed not to oppose plaintiff’s counsel’s request to the court to be paid up to $164,000 for their
fees and expenses and up to $1,000 as an incentive award for plaintiff Leider. Any payment of fees,
expenses, and incentives is subject to final approval of the settlement and such fees, expenses,
and incentives by the court. The proposed settlement will not affect the amount of merger
consideration to be paid to Meridian’s shareholders in the merger or change any other terms of the
merger or Merger Agreement. Expenses of the proposed settlement are expected to be recorded in the first
quarter of 2010.
Other contingencies
82
Ceiling Test
. At the end of each quarter, the unamortized cost of oil and natural gas properties,
net of related deferred income taxes, is limited to the sum of the estimated future after-tax net
revenues from proved properties, 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. This limitation is known as the “ceiling test.” Under new rules issued by the SEC, the
estimated future net cash flows as of December 31, 2009, were determined using average prices for
the most recent twelve months. The average is calculated using the first day of the month price
for each of the twelve months that make up the reporting period. As of December 31, 2008 and 2007,
previous rules required that estimated future net cash flows from proved reserves be based on
period end prices. The Company recorded impairment charges against oil and natural gas properties
based on the results of the ceiling test in the fourth quarter of 2008 and again in the first and
fourth quarters of 2009.
At December 31, 2009, the Company had no cushion (i.e., the excess of the ceiling over capitalized
costs). Thus, any future decrease in the average price to be used for the ceiling test, net of the
effect of any hedging positions the Company may have, may necessitate additional impairment
charges. Any future impairment would be impacted by changes in the accumulated costs of oil and
natural gas properties, which may in turn be affected by sales or acquisitions of properties and
additional capital expenditures. Future impairment would also be impacted by changes in estimated
future net revenues, which are impacted by additions and revisions to oil and natural gas reserves,
as well as by sales and acquisitions of properties. A 10% decrease in prices would have increased
our fourth quarter 2009 non-cash impairment expense by approximately $28 million; a 10% increase in
prices would have eliminated the need for a write-off.
Due to the its default under lending agreements, should the proposed merger with Alta Mesa (see
Note 1) not be completed, the Company would be forced to consider sales of assets to generate cash
for repayment of debt. Sales of significant assets would impact future ceiling tests, as their
estimated future after-tax net revenues would be removed from the calculation. Proceeds from sales
of properties are generally credited to the full cost pool, reducing the carrying value of oil and
gas properties subject to the ceiling test. The Company cannot predict whether significant
property sales will cause additional ceiling test impairments, but it is possible that they will.
Drilling rigs.
As described in Note 2, “Rig Operations”, the Company has significant contractual
obligations for the use of two drilling rigs. The Company’s capital expenditure plans no longer
include full use of these rigs; however, the Company is obligated for the dayrate regardless of
whether the rigs are working or idle. The operator, Orion, has sought other parties to use the
rigs and agreed to credit the Company’s obligation, based on revenues from third parties who
utilize the rig(s) when the Company is unable to. Management cannot predict whether utilization of
the rigs by third parties will be consistent, nor to what extent it may offset obligations under
the dayrate contracts. The Company has not provided any amount for any future losses on these
drilling contracts in its financial statements at December 31, 2009. The two drilling contracts
will terminate in February 2011 (as to the rig not owned by the Company) and March 2010 (as to the
rig owned by the Company and operated by Orion).
The Company entered into a forbearance agreement with Orion which may grant title to the
company-owned rig to Orion, the operator under both the dayrate contracts, in exchange for release
of all accrued and future liabilities under the rig contracts. This would occur at termination and
final payment of the related rig note held by CIT, which is scheduled for 2013, if the Company
continues to perform its obligations under the rig note and the rig is free of any significant
security interest at title transfer. Both the rig value and the net payable to Orion would be
written off at the time of such title transfer, if it were to occur. Alternatively, the terms of
the forbearance agreement allow the Company an option to settle all claims with Orion in cash at
the end of the term of the rig note, and retain title to the rig. There can be no assurance that
the forbearance period under the CIT Forbearance Agreement will provide sufficient time to cure the
default under the rig note and ensure performance under the Orion forbearance agreement. All
accrued unpaid liabilities for rig expense through December 31, 2009 are classified in the
accompanying consolidated balance sheet as current.
83
At December 31, 2009, the rig is included in equipment at a net book value of $4.6 million, and
accounts payable includes a total of $4.3 million in accrued unpaid invoices from Orion for
underutilization of both rigs, which is net of a reduction of $1.1 million estimated as the
Company’s share of profits on the rig it owns. The Company performs impairment testing of the rig
each quarter; see Note 4.
8. TAXES ON INCOME
Provisions (benefits) for federal and state income taxes are as follows (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
(96
|
)
|
|
$
|
(304
|
)
|
|
$
|
560
|
|
|
State
|
|
|
(24
|
)
|
|
|
35
|
|
|
|
90
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
—
|
|
|
|
(7,984
|
)
|
|
|
4,470
|
|
|
State
|
|
|
—
|
|
|
|
(209
|
)
|
|
|
557
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit)
|
|
$
|
(120
|
)
|
|
$
|
(8,462
|
)
|
|
$
|
5,677
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) as reported is reconciled to the federal statutory rate (35%) as
follows (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Income tax provision (benefit) computed at
statutory rate
|
|
$
|
(25,465
|
)
|
|
$
|
(76,422
|
)
|
|
$
|
4,485
|
|
|
Nondeductible costs
|
|
|
2,005
|
|
|
|
1,956
|
|
|
|
577
|
|
|
State income tax, net of federal tax benefit
|
|
|
(2,864
|
)
|
|
|
(1,475
|
)
|
|
|
615
|
|
|
Tax on other comprehensive income
|
|
|
(2,846
|
)
|
|
|
2,846
|
|
|
|
—
|
|
|
Change in valuation allowance
|
|
|
29,050
|
|
|
|
64,633
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit)
|
|
$
|
(120
|
)
|
|
$
|
(8,462
|
)
|
|
$
|
5,677
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes reflect the net tax effects of net operating losses, depletion carryovers,
and temporary differences between the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts used for income tax purposes. Significant components of the
Company’s deferred tax assets and liabilities are as follows (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
|
Net operating tax loss carryforward
|
|
$
|
57,674
|
|
|
$
|
32,745
|
|
|
Statutory depletion carryforward
|
|
|
950
|
|
|
|
950
|
|
|
Tax credits
|
|
|
1,805
|
|
|
|
1,901
|
|
|
Deferred compensation
|
|
|
—
|
|
|
|
5,474
|
|
|
Tax basis in excess of book basis in property and equipment
|
|
|
31,717
|
|
|
|
25,655
|
|
|
Valuation allowance
|
|
|
(93,683
|
)
|
|
|
(64,633
|
)
|
|
Other
|
|
|
1,537
|
|
|
|
754
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
—
|
|
|
|
2,846
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
|
Unrealized hedge gain
|
|
|
—
|
|
|
|
2,846
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
—
|
|
|
|
2,846
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
84
As of December 31, 2009, the Company had approximately $164.8 million of tax net operating
loss carryforwards. The net operating loss carryforwards assume that certain items, primarily
intangible drilling 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 whether an election will be
made to capitalize all or part of these items for tax purposes.
A portion of the net operating loss carryforwards is subject to change in ownership limitations
that could restrict the Company’s ability to utilize such losses in the future.
As of December 31, 2009, the Company had net operating loss carryforwards for regular tax and
alternative minimum tax (AMT) purposes available to reduce future taxable income. These
carryforwards expire as follows (in thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
Year of
|
|
Net
|
|
|
AMT
|
|
|
Expiration
|
|
Operating Loss
|
|
|
Operating Loss
|
|
|
2018
|
|
$
|
10,549
|
|
|
$
|
13,820
|
|
|
2019
|
|
|
47,730
|
|
|
|
48,630
|
|
|
2020
|
|
|
31
|
|
|
|
31
|
|
|
2021
|
|
|
36
|
|
|
|
36
|
|
|
2022
|
|
|
3,719
|
|
|
|
6,232
|
|
|
2023
|
|
|
36,376
|
|
|
|
44,516
|
|
|
2025
|
|
|
42
|
|
|
|
11
|
|
|
2026
|
|
|
52
|
|
|
|
—
|
|
|
2027
|
|
|
77
|
|
|
|
1,369
|
|
|
2028
|
|
|
6,596
|
|
|
|
8,062
|
|
|
2029
|
|
|
59,574
|
|
|
|
61,896
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
164,782
|
|
|
$
|
184,603
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009, the Company had approximately $1.8 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 does not expect to fully realize its deferred
tax assets, and therefore recorded a valuation allowance in 2008 and 2009 to the full extent of all
net deferred tax assets.
|
|
|
|
|
9.
|
|
FAIR VALUE MEASUREMENT
|
Effective January 1, 2008, the Company adopted new authoritative guidance from the FASB regarding
fair value, contained in Accounting Standards Codification Topic 820 (“ASC 820”). ASC 820 provides
a hierarchy of fair value measurements, based on the inputs to the fair value estimation process.
It requires disclosure of fair values classified according to defined “levels,” which are based on
the reliability of the evidence used to determine fair value, with Level 1 being the most reliable
and Level 3 the least. Level 1 evidence consists of observable inputs, such as quoted prices in an
active market. Level 2 inputs typically correlate the fair value of the asset or liability to a
similar, but not identical item which is actively traded. Level 3 inputs include at least some
unobservable inputs, such as valuation models developed using the best information available in the
circumstances.
85
The Company adopted the provisions of ASC 820 as it applies to assets and liabilities measured at
fair value on a recurring basis on January 1, 2008. This included oil and natural gas derivatives
contracts, and as of January 1, 2009, certain outstanding warrants known as the General Partner
Warrants (see Notes 2 and 9).
In accordance with the deferred effective date provided by the FASB, on January 1, 2009, the
Company adopted the provisions of ASC 820 for non-financial assets and liabilities which are
measured at fair value on a non-recurring basis. This includes new additions to asset retirement
obligations, and any long-lived assets, other than oil and natural gas properties, for which an
impairment write-down is recorded during the period. There have been no such impairments of
long-lived assets since adoption. ASC 820 does not apply to oil and natural gas properties
accounted for under the full cost method, which are subject to impairment based on SEC rules.
The Company utilizes the modified Black-Scholes option pricing model to estimate the fair value of
oil and natural gas derivative contracts. Inputs to this model include observable inputs from the
New York Mercantile Exchange (NYMEX) for futures contracts, and inputs derived from NYMEX
observable inputs, such as implied volatility of oil and gas prices. The Company has classified
the fair values of all its derivative contracts as Level 2.
The fair value of the Company’s general partner warrants (see Notes 2 and 10) was calculated using
the Black-Scholes option pricing model.
Assets and liabilities measured at fair value on a recurring basis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2009
|
|
|
|
|
|
|
|
|
Using (thousands of dollars)
|
|
|
|
|
|
|
|
|
Quoted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Active
|
|
|
Significant
|
|
|
Significant
|
|
|
|
|
|
|
|
|
Markets for
|
|
|
Other
|
|
|
Other
|
|
|
|
|
|
|
|
|
Identical
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
|
December
|
|
|
Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Description
|
|
31, 2009
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Assets from price risk management activities
(1)
|
|
$
|
—
|
|
|
|
|
|
|
$
|
—
|
|
|
|
|
|
|
Liabilities from price risk management
activities
(1)
|
|
$
|
—
|
|
|
|
|
|
|
$
|
—
|
|
|
|
|
|
|
General partner warrants
(2)
|
|
$
|
412
|
|
|
|
|
|
|
$
|
412
|
|
|
|
|
|
86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2008
|
|
|
|
|
|
|
|
|
Using (thousands of dollars)
|
|
|
|
|
|
|
|
|
Quoted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Active
|
|
|
Significant
|
|
|
Significant
|
|
|
|
|
|
|
|
|
Markets for
|
|
|
Other
|
|
|
Other
|
|
|
|
|
|
|
|
|
Identical
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
|
December
|
|
|
Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Description
|
|
31, 2008
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Assets from price risk management activities
(1)
|
|
$
|
8,447
|
|
|
|
|
|
|
$
|
8,447
|
|
|
|
|
|
|
Liabilities from price risk management
activities
(1)
|
|
$
|
311
|
|
|
|
|
|
|
$
|
311
|
|
|
|
|
|
|
General partner warrants
(2)
|
|
$
|
—
|
|
|
|
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Assets and liabilities from price risk management activities are oil and natural gas
derivative contracts, primarily in the form of floor contracts to sell oil and natural gas within
specific future time periods. These contracts are more fully described in Note 12. As of December
31, 2009, all of the Company’s oil and natural gas derivative contracts had expired.
|
|
|
|
(2)
|
|
General partner warrants are more fully described in Note 10. The warrants were carried at
historical cost at December 31, 2008; historical cost was replaced with fair value upon adoption of
new accounting guidance on January 1, 2009 (see Note 2).
|
As noted above, ASC 820 also applies to new additions to asset retirement obligations, which must
be estimated at fair value when added. New additions result from estimations for new obligations
for new properties, and fair values for them are categorized as Level 3. Such estimations are
based on present value techniques which utilize company-specific information. The Company recorded
$47,000 in additions to asset retirement obligations measured at fair value during the year ended
December 31, 2009.
The Company estimates the fair value of its drilling rig quarterly (see Note 4), based on the
present value of estimated cash flows from the rig, using management’s best estimates of
utilization and dayrates. This is considered a Level 3 fair value.
Proposed Merger
As described in Note 1, the Company has proposed that it be merged with Alta Mesa, and the board of
directors has recommended that shareholders vote in favor of the merger, with the vote currently
scheduled for April 28, 2010. Under the terms of the Merger Agreement, as amended, shareholders
will receive $0.33 per share of common stock, to be paid in cash, and shares of the Company would
cease to be publicly traded. The Company would be merged into Alta Mesa Acquisition Sub, LLC with
the Merger Sub as the surviving entity.
87
Under the terms of the Merger Agreement, all the Company’s outstanding stock options will become
vested and exercisable. As all such options bear exercise prices in excess of the price of $0.33
per share to be received in the merger, the Company expects no additional consideration for the
options. Certain outstanding warrants (see below, “Warrants”) are expected to be settled for a
total of approximately $431,000 with two members of the Company’s Board of Directors, who are also
former officers.
Common Stock
In March 2007, the Company’s Board of Directors authorized a share repurchase program; an amendment
to the credit agreement at that time increased the available limit for the Company’s repurchase of
its common stock from $1.0 million to $5.0 million annually, so long as the Company was in
compliance with certain provisions of the Credit Facility. From March 2007, the inception of the
share repurchase program, through December 31, 2009, the Company had repurchased 535,416 common
shares at a cost of $1,234,000, of which 501,300 shares have been reissued for 401(k)
contributions, for contract services and for compensation, and 34,116 have been retired. The Bank
Forbearance Agreement prohibits any further repurchase of Company stock. The Company did not
repurchase any shares during 2009 and does not expect to make share repurchases in the foreseeable
future.
In 2008, the Company issued shares to certain former executives upon the discontinuation of its
deferred compensation plan (see Note 12). Shares sufficient to cover the value of these former
executives withholding taxes were withheld from issuance, and the Company made a cash payment for
the withholding tax. The total number of shares withheld was 1,001,511, at a value of approximately
$3,035,000. In 2009, the Company again withheld shares from a distribution in order to cover the
recipients’ personal withholding tax, which was paid in cash by the Company. The total shares
withheld in the 2009 transaction were 610,938 shares at a total cost of $195,000. These
transactions are considered an indirect repurchase and have been presented in the Consolidated
Statements of Cash Flows as a financing item.
Warrants
As of December 31, 2009, the Company had outstanding warrants (the “General Partner Warrants”) that
entitle Joseph A. Reeves, Jr. and Michael J. Mayell to purchase an aggregate of 1,872,998 shares of
common stock at an exercise price of $0.10 per share through December 31, 2015. Messrs. Reeves and
Mayell, respectively, were the Chief Executive Officer and Chief Operating Officer of the Company
for many years. Messrs. Reeves and Mayell both ceased to be employees of the Company on December
29, 2008.
The number of shares of common stock purchasable upon the exercise of the warrants 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 two
warrant arrangements permits the holder to purchase approximately 1% of the outstanding shares of
the common stock for an aggregate exercise price of $94,303. The General Partner Warrants were
issued to Messrs. Reeves and Mayell in conjunction with certain transactions with Messrs. Reeves
and Mayell that took place in anticipation of the Company’s consolidation in December 1990 and were
a component of the total consideration issued for various interests that Messrs. Reeves and Mayell
had as general partners in
TMR, Ltd., a predecessor entity of the Company. There are adequate authorized unissued common stock
shares that are required to be issued upon conversion of the General Partner Warrants. The Company
is not required to redeem the General Partner Warrants in cash.
88
The Company adopted new authoritative guidance from the FASB with regard to these warrants on
January 1, 2009. The provisions of the new guidance, which relate to equity securities indexed to
the price of a company’s own stock, were considered in regard to the General Partner Warrants and
it was determined that they were not indexed to the price of the Company’s own stock and should
therefore be subject to fair value accounting. Accordingly, a charge of $960,000 was recorded on
January 1, 2009 to retained earnings to reflect the cumulative effect of recording the 1,884,544
warrants outstanding at that date at fair value, with an offsetting entry to accrued liabilities.
Adjustments to fair value have been made on a prospective basis, beginning in 2009. For the year
ended December 31, 2009, the Company recorded a gain on the valuation of the warrants of $548,000,
which is included in general and administrative expense.
At December 31, 2009, 1,872,998 General Partner Warrants were outstanding and included in accrued
liabilities at a total fair value of $412,000. Fair value is based on the Black-Scholes model for
option pricing.
Share-based Compensation
Options to purchase the Company’s common stock have been granted to officers, employees,
nonemployee directors and certain key individuals, under various stock incentive plans. Options
generally become exercisable in 25% cumulative annual increments beginning with the date of grant
and expire at the end of ten years. The Company has also made grants of stock shares which vest
over time (typically, three years). The Company has also issued rights to shares of common stock
under its deferred compensation plan (see additional information for that plan below, “Deferred
Compensation.”) The Company typically utilizes newly issued stock shares when options are exercised
or shares vest.
Compensation expense is recorded for share-based awards over the requisite vesting periods based
upon the fair value of the award on the date of the grant. Share-based compensation expense for
grants of options and non-vested shares of approximately $153,000, $193,000, and $294,000 was
recorded in the years ended December 31, 2009, 2008, and 2007, respectively and is included in
general and administrative expense. In addition, general and administrative expense related to
issuance of shares in lieu of cash for services was zero, $144,000, and $1,144,000, for each of the
years ended December 31, 2009, 2008, and 2007, respectively. No portion of this expense has been
capitalized. At December 31, 2009, 2008, and 2007, 4,140,000, 3,970,000, and 3,850,000 shares,
respectively, were available for grant under the plans. Summaries of share-based awards
transactions follow:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
Number
|
|
|
Average
|
|
|
|
|
of Share Options
|
|
|
Exercise Price
|
|
|
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
|
|
|
Granted
|
|
|
115,000
|
|
|
|
2.34
|
|
|
Exercised
|
|
|
—
|
|
|
|
—
|
|
|
Canceled or Expired
|
|
|
(3,053,188
|
)
|
|
|
3.37
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
461,500
|
|
|
$
|
4.41
|
|
|
Granted
|
|
|
250,000
|
|
|
$
|
0.58
|
|
|
Exercised
|
|
|
—
|
|
|
|
—
|
|
|
Canceled or Expired
|
|
|
(307,500
|
)
|
|
$
|
5.01
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2009
|
|
|
404,000
|
|
|
$
|
1.59
|
|
|
|
|
|
|
|
|
|
|
|
Share options exercisable:
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
3,252,001
|
|
|
$
|
3.57
|
|
|
December 31, 2008
|
|
|
265,875
|
|
|
$
|
5.74
|
|
|
December 31, 2009
|
|
|
226,500
|
|
|
$
|
1.90
|
|
89
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
Number
|
|
|
Average
|
|
|
|
|
of Non-Vested
|
|
|
Grant Date
|
|
|
|
|
Shares
|
|
|
Fair Value
|
|
|
Outstanding non-vested at December 31, 2007
|
|
|
—
|
|
|
$
|
—
|
|
|
Granted
|
|
|
40,873
|
|
|
|
2.32
|
|
|
Vested
|
|
|
—
|
|
|
|
—
|
|
|
Forfeited
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Outstanding non-vested at December 31, 2008
|
|
|
40,873
|
|
|
$
|
2.32
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
—
|
|
|
|
—
|
|
|
Vested
|
|
|
(40,873
|
)
|
|
$
|
2.32
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Outstanding non-vested at December 31, 2009
|
|
|
—
|
|
|
|
—
|
|
Fair value of share options was estimated at the date of grant using the Black-Scholes option
pricing model. Certain assumptions were used in determining the fair value of share options using
this model. The Company calculated the estimated volatility of its stock by averaging the
historical daily price intervals for closing prices of the common stock. The risk-free interest
rate is based on observed U.S. Treasury rates at date of grant, appropriate for the expected lives
of the options. The expected life of options was determined based on the method provided in Staff
Accounting Bulletin 107, as we do not have an adequate exercise history to determine the average
life for the options with the characteristics of those granted.
Weighted averages of the assumptions used in the Black-Scholes option pricing model were as follows
for grants of options in the years ended December 31, 2009, 2008 and 2007, respectively: risk-free
interest rates of 1.5%, 3.0% and 4.54%; dividend yield of 0%; volatility factors of the expected
market price of the Company’s common stock of 0.58, 0.59, and 0.59; and weighted-average expected
lives of three years, four years, and five years. These assumptions resulted in weighted average
grant date fair values of $0.25, $1.14 and $1.36 for options granted in 2009, 2008, and 2007,
respectively.
The aggregate intrinsic value of share options exercised was zero in each of the years ended
December 31, 2009, 2008, and 2007, as no options were exercised. The aggregate intrinsic value of
non-vested shares which vested was $14,000, zero, and zero, for each of the years 2009, 2008, and
2007, respectively. No shares vested during 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
Options Exercisable
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Weighted
|
|
|
Range of
|
|
Outstanding at
|
|
|
Average
|
|
|
Exercisable at
|
|
|
Average
|
|
|
Exercisable Prices
|
|
December 31, 2009
|
|
|
Exercise Price
|
|
|
December 31, 2009
|
|
|
Exercise Price
|
|
|
$0.58 — $1.93
|
|
|
267,500
|
|
|
|
0.66
|
|
|
|
129,375
|
|
|
|
.62
|
|
|
$2.31 — $3.99
|
|
|
114,000
|
|
|
|
3.06
|
|
|
|
74,625
|
|
|
|
3.16
|
|
|
$4.42 — $5.32
|
|
|
22,500
|
|
|
|
5.11
|
|
|
|
22,500
|
|
|
|
5.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
404,000
|
|
|
|
1.59
|
|
|
|
226,500
|
|
|
|
1.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted average remaining contractual life of options outstanding at December 31, 2009, was
approximately four years.
90
The aggregate intrinsic value for all options outstanding and for all exercisable options at
December 31, 2009 was zero. The aggregate intrinsic value represents the total pre-tax value (the
difference between the Company’s closing stock price on the last trading day of 2009 and the
exercise price, multiplied by the number of in-the-money options) that would have been received by
the option holders had they exercised their options on December 31, 2009. The amount of aggregate
intrinsic value will change based on the fair market value of the Company’s common stock.
As of December 31, 2009, there was approximately $30,000 of total unrecognized compensation expense
related to stock-based compensation plans. This compensation expense is expected to be recognized
on a straight-line basis over the remaining vesting period of approximately 2 years.
Deferred Compensation
In July 1996, the Company through the Compensation Committee of the Board of Directors offered to
Messrs. Reeves and Mayell (at the time, the Company’s Chief Executive Officer and Chief Operating
Officer, respectively) the option to accept in lieu of an electable portion of their cash,
compensation rights to common stock pursuant to the Company’s Long Term Incentive Plan. Under the
terms of this deferred compensation plan, Messrs. Reeves and Mayell each deferred $160,000 for 2008
and $400,000 for 2007. In exchange for and in consideration of their accepting this option to
reduce the Company’s cash payments to each of Messrs. Reeves and Mayell, the Company granted to
each officer a matching deferral equal to 100% of the amount deferred, subject to a one-year
vesting period. Under the terms of the deferred compensation plan, the employee and matching
deferrals were allocated to a notional common stock account in which notional shares of common
stock were 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 with the deferred and matched funds. 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. Compensation costs related to the
amounts deferred by the officers and matched by the Company for these equity grants were $968,000
and $1,598,000 for 2008 and 2007, respectively. The costs are reflected in general and
administrative expense and in oil and natural gas properties for the years ended December 31, 2008
and 2007, respectively as follows: $484,000 and $799,000 in general and administrative expense, and
$484,000 and $799,000 capitalized to oil and natural gas properties.
The Company discontinued the deferred compensation plan provided to these officers, which resulted
in the issuance of a total of 1,803,291 shares of new common stock for Messrs. Reeves and Mayell
(combined) on July 2, 2008. The shares issued were net of a reduction of 1,001,511 shares withheld
in lieu of the executives’ personal withholding tax. The intrinsic value of all these shares on
date of issuance, including those withheld, was approximately $8.5 million at $3.03 per share. Also
due to termination of the plan, 1,712,114 new shares (856,057 shares for each of the two officers)
were issued and placed into a Rabbi Trust on October 2, 2008. The intrinsic value of these shares
on date of issuance to the trust was approximately $3.1 million at $1.81 per share. The shares were
distributed upon dissolution of the trust on June 26, 2009. The distribution was again issued net
of a reduction of shares withheld in lieu of personal withholding tax; the number of shares
withheld totaled 610,938. The intrinsic value of the 1,101,176 shares distributed and the 610,938
shares withheld was $352,000 and $195,000, respectively, at $0.32. See Note 12 for further
information.
91
Activity in the notional accounts for the years ended December 31, 2008 and 2007 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
Number
|
|
|
Grant Date
|
|
|
|
|
of Share Rights*
|
|
|
Fair Value
|
|
|
Outstanding at December 31, 2006
|
|
|
3,640,188
|
|
|
|
4.54
|
|
|
Granted
|
|
|
523,144
|
|
|
|
3.06
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
|
4,163,332
|
|
|
|
4.36
|
|
|
Granted
|
|
|
353,584
|
|
|
|
1.81
|
|
|
Converted to shares of common stock
|
|
|
(4,516,916
|
)
|
|
|
4.16
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
For simplicity, share rights vesting on a routine schedule are not separately shown; only the
original granting of the share rights is presented, and outstanding year-end balances include
both vested and unvested shares. As the Company matching portion of share rights vested
monthly over a one year period, each year’s activity actually included vesting of
approximately one-half of the prior year’s matching rights, and non-vesting of approximately
one-half of the current year’s matching rights. When the plan was discontinued in 2008, all
remaining unvested rights (approximately 180,478 rights) were vested on an accelerated basis,
then all rights were converted to shares of common stock. As of December 31, 2008, there were
no rights remaining in the notional accounts and no cost related to any rights granted which
had not yet been recognized.
|
The shares of common stock which would have been issuable upon distribution of deferrals and
matching grants during the time the plan was active (including 2007 and early 2008) have been
treated as common stock equivalents in computing earnings per share.
|
|
|
|
|
11.
|
|
PROFIT SHARING AND SAVINGS PLAN
|
|
|
|
The Company has a 401(k) profit sharing and savings plan (the “Plan”) that covers substantially all
employees and entitles them to contribute up to 15% of their annual compensation, subject to
maximum limitations imposed by the Internal Revenue Code. The Company matches 100% of each
employee’s contribution up to 6.5% of annual compensation subject to certain limitations as
outlined in the Plan. In addition, the Company may make discretionary contributions which are
allocable to participants in accordance with the Plan. Total expense related to the Company’s
401(k) plan was $382,000, $531,000, and $545,000, in 2009, 2008, and 2007, 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,” together with the Trust 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 $2.3 million, $5.0 million, and
$4.7 million, in 2009, 2008, and 2007, respectively. A portion of these amounts was capitalized
with regard to personnel engaged in activities associated with exploratory projects. The Executive
Committee of the Board of Directors, which was 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 participated in the
92
Management Plan. The participants in the Trust Plan generally will be employees of the Company that do not participate
in one of the other Well Bonus Plans. Effective March 2001, the participants in the Geoscientist
Plan were notified that no additional future wells would be placed into the Geoscientist Plan.
During 2002, the Executive Committee decided to modify this position and for certain key
geoscientists the Geoscientist Plan will include new wells.
Pursuant to the Well Bonus Plans, the Executive Committee designates, in its sole discretion, the
individuals and wells that will participate in each of the Well Bonus Plans. The Executive
Committee also determines the percentage bonus that will be paid under each well and the
individuals that will participate thereunder. The Well Bonus Plans cover all properties on which
the Company expends funds during each participant’s employment with the Company, with the
percentage bonus generally ranging from less than 0.1% to 0.5%, depending on the level of the
employee. It is intended that these well bonuses function similar to actual net profit interests,
except that the employee will not have a real property interest and will be subject to the general
credit of the Company. For certain employees covered under the Management Well Bonus Plan and the
Geoscientist Well Bonus Plan, 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 is based upon a variety of factors, including the Company’s current liquidity position
and the fair market value of the common stock at the time of issuance. In practice, most payments
have been made in cash, with some payments to ex-employees made in common stock.
In connection with the execution of their employment contracts in 1994, both Messrs. Reeves and
Mayell were granted a 2% net profit interest in the oil and natural gas production from the
Company’s properties to the extent the Company acquires a mineral interest therein. The net profits
interest for Messrs. Reeves and Mayell applies to all properties on which the Company expended
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, 2009, 2008, and 2007, compensation expense in the amounts of zero, $137,350, and $78,054 were
recorded for each Messrs. Reeves and Mayell. Grants made in 2009 were negligible. The net profit
interests represent real property rights not subject to vesting or continued employment with the
Company. Messrs. Reeves and Mayell did not participate in the Well Bonus Plans. The net profits
interest plan for Messrs. Reeves and Mayell was discontinued in April, 2008 as to new properties,
but continues to apply to all properties on which the Company had expended funds prior to
discontinuation. See Note 12 for further information.
|
|
|
|
|
12.
|
|
CONTRACT SETTLEMENTS, RABBI TRUST, EMPLOYEE RETENTION, AND INDEMNIFICATION SETTLEMENT
|
In April 2008 the Company made significant changes in the structure of the compensation of two
executives, Mr. Joseph A. Reeves and Mr. Michael J. Mayell, former Chief Executive Officer and
former Chief Operating Officer. Effective April 29, 2008, the employment contracts for Messrs.
Reeves and Mayell were replaced with new agreements. In addition, certain other agreements that
governed other elements of their compensation packages were also settled. As a result of the
agreements, the Company recorded $9.9 million in contract settlement expense in the second quarter
of 2008, and placed that amount of cash in a Rabbi Trust for the former officers. In June 2009,
pursuant to the contractual terms, the cash was distributed from the trust to the former officers.
Also in the third quarter of 2008, the Company recorded a $1.2 million non-cash expense due to
write-down of the deferred tax asset related to the stock rights; the write-down was the result of
the difference between the market value of the stock when the rights were issued and expensed, and
the market value at conversion of the rights into shares.
In addition, the Company discontinued the deferred compensation plan provided to these officers,
which resulted in the issuance of a total of 1,803,291 shares of new common stock for Messrs.
Reeves and Mayell (combined) on July 2, 2008. The shares issued were net of a reduction of
1,001,511 shares withheld from issuance in lieu of the former executives’ personal withholding tax.
An additional 1,712,114 new shares (856,057 shares to each of the two former officers) were
93
placed in the Rabbi Trust in the third quarter of 2008, and distributed to the former officers in June
2009. The shares were again issued net of shares withheld for personal withholding tax (a total of 610,938 shares were
withheld from distribution and retired). The total net shares distributed to the two officers was
1,101,176 (550,588 each). Substantially all of the compensation expense related to these shares
had been recognized historically, when the rights to such future shares were granted.
Prior to distribution, the cash in the Rabbi Trust was included on the Consolidated Balance Sheets
under “Restricted Cash,” and the shares in the trust were accounted for as treasury shares,
assigned a value based on the closing market price on the date they were issued, October 2, 2008.
Until distribution, the assets of the trust belonged to the Company, but were effectively
restricted due to the obligation to the former officers.
On July 29, 2008, the Company reached an agreement with a former employee to terminate a
compensation agreement. Under the terms of the termination agreement, the Company paid the former
employee $825,000 and repurchased from him, 34,116 shares of Company stock, which had been issued
to him in lieu of cash compensation. The total cost of repurchasing the shares was approximately
$75,000. The Company has no further obligation to this former employee. The termination payment was
recorded as general and administrative expense in the third quarter of 2008.
On July 3, 2008, the Company initiated the Meridian Resource & Exploration LLC Retention Incentive
Compensation Plan, and under the terms of the plan, distributed a total of $1.6 million in bonuses
to its employees. The purpose of the plan was to encourage the retention of valued employees for
the immediate term. The employment market for experienced personnel in the oil and gas industry had
been very strong for some time when the plan was initiated. Management’s intention for the
incentive program was to help equalize its employees’ compensation with current market conditions
and motivate them to continue their careers with Meridian. The terms of the plan included a second,
final bonus to those employees who continued their employment with the Company through March 31,
2009. The second payment, issued April 3, 2009, totaled approximately $2.9 million; the expense was
accrued ratably over the time period July 2008 through March 2009. The Company recognized $1.7
million in general and administrative expense, net of capitalization of a portion to the full cost
pool, through December 31, 2008, and approximately $0.5 million in general and administrative
expense for the retention bonus plan in 2009, net of capitalization.
As described in Note 7, in the fourth quarter of 2009 the Company recorded $4.2 million in expense
for a settlement with Shell regarding indemnification of environmental claims.
|
|
|
|
|
13.
|
|
RISK MANAGEMENT ACTIVITIES
|
Management of Financial Risk
The Company’s operating environment includes two primary financial risks which could be addressed
through derivatives and similar financial instruments: the risk of movement in oil and natural gas
commodity prices, which impacts revenue, and the risk of interest rate movements, which impacts
interest expense from floating rate debt.
The Company currently does not utilize derivative contracts or any other form of hedging against
interest rate risk.
The Company utilizes derivative contracts to address the risk of adverse oil and natural gas
commodity price fluctuations. While the use of derivative contracts limits the downside risk of
adverse price movements, it may also limit future gains from favorable movements. No derivative
contracts have been entered into for trading purposes, and the Company generally holds each
remaining instrument to maturity. The Company’s commodity derivative contracts are considered cash
flow hedges under generally accepted accounting principles.
Oil and Natural Gas Hedging Contracts
94
The Company has historically utilized derivative contracts to hedge the sale of a portion of its
future production. The Company’s objective is to reduce the impact of commodity price fluctuations
on both income and cash flow, as well as to protect future revenues from adverse price movements.
Management considers some exposure to market pricing to be desirable, due to the potential for
favorable price movements, but prefers to achieve a measure of stability and predictability over
revenues and cash flows by hedging some portion of production. All the Company’s hedging agreements
expired in December 2009. All of the Company’s hedging agreements are executed by affiliates of
the Lenders under the Credit Facility and are collateralized by the security interest the Lenders
have in the oil and natural gas assets of the Company. Due to the default under the Credit
Facility, the Lenders have not allowed the Company to enter into any additional hedging agreements.
As a result, the Company’s oil and natural gas sales for periods beyond December 2009 will more
closely resemble prevailing market prices.
Accounting and financial statement presentation for derivatives
The Company accounts for its derivative contracts under the provisions of ASC 815, “Derivatives and
Hedging.” Under ASC 815, the Company’s commodity derivatives are designated as cash-flow hedges
and are stated at fair value on the Consolidated Balance Sheets. See Note 9, “Fair Value
Measurements” for further information on how fair values of derivative instruments are determined.
Changes in the fair value of the contracts, which occur due to commodity price movements, are
offset in Accumulated Other Comprehensive Income. When the derivative contract or a portion of it
matures, the gain or loss is settled in cash and reclassified from Accumulated Other Comprehensive
Income to Revenues from Oil and Natural Gas. Net settlements under hedging agreements increased
(decreased) oil and natural gas revenues by $11.7 million, ($4.7 million) and $3.3 million for the
years ended December 31, 2009, 2008 and 2007, respectively. A gain or loss may be recorded to
earnings prior to contract maturity if a portion of the cash flow hedge becomes “ineffective” under
the guidelines provided under generally accepted accounting principles, or if the forecasted
transaction is no longer expected to occur. Although the Company periodically records gains or
losses from hedge ineffectiveness, there have been no losses recorded due to changes in
expectations regarding occurrence of the hedged transactions. The following two tables provide
information regarding assets, liabilities, gains, and losses related to derivative contracts, and
where these amounts are reflected within the Company’s financial statements (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Values of Derivative Contracts at
|
|
|
Description and location within
|
|
December 31,
|
|
|
December 31,
|
|
|
Consolidated Balance Sheet
|
|
2009
|
|
|
2008
|
|
|
Derivative contracts designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
Commodities Contracts
|
|
|
|
|
|
|
|
|
|
Current assets from price risk management activities
|
|
|
—
|
|
|
$
|
8,447
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-current assets from price risk management activities
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities from price risk management activities
|
|
|
—
|
|
|
$
|
311
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-current liabilities from price risk management
activities
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts not designated as hedging instruments
|
|
NONE
|
|
|
NONE
|
|
95
Effect of Derivative Contracts on the
Consolidated Balance Sheets and the Consolidated Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended
|
|
|
|
Location of Gain
|
|
|
|
|
|
|
|
(Loss) within
|
|
December 31,
|
|
December 31,
|
|
Description
|
|
Financial Statements
|
|
2009
|
|
2008
|
|
Derivative contracts designated as cash flow hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivative contracts recognized in Other Comprehensive Income (OCI)
|
|
|
|
|
|
|
|
|
|
|
|
Commodities Contracts
|
|
Accumulated Other Comprehensive Income
|
|
|
3,616
|
|
|
|
3,806
|
|
|
Gain (loss) on derivative contracts reclassified from OCI to earnings
|
|
|
|
|
|
|
|
|
|
|
|
Commodities Contracts
|
|
Oil and Natural Gas Revenues
|
|
|
11,745
|
|
|
|
(4,663
|
)
|
|
|
|
Gain (loss) due to hedging ineffectiveness reported in earnings
|
|
|
|
|
|
|
|
|
|
|
|
Commodities Contracts
|
|
Revenues from Price Risk Management
Activities
|
|
|
(6
|
)
|
|
|
(18
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of derivative contracts designated as cash flow hedging instruments,
excluded from effectiveness assessments
|
|
|
|
NONE
|
|
NONE
|
|
|
|
Derivative contracts not designated as hedging instruments
|
|
|
|
NONE
|
|
NONE
|
96
As of December 31, 2009 and 2008, the Company had unrealized gains of zero and $8.1 million
(pre-tax and net of tax) deferred in Accumulated Other Comprehensive Income, respectively. All of
the Company’s derivative agreements expired December 31, 2009.
Major customers for the years ended December 31, 2009, 2008, and 2007, were as follows (based on
sales exceeding 10% of total oil and natural gas revenues):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Customer
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Shell Trading (U.S.)
|
|
|
28
|
%
|
|
|
21
|
%
|
|
|
14
|
%
|
|
Stone Energy Corporation
|
|
|
17
|
%
|
|
|
8
|
%
|
|
|
8
|
%
|
|
Superior Natural Gas
|
|
|
11
|
%
|
|
|
17
|
%
|
|
|
23
|
%
|
|
Crosstex Gulfcoast Marketing
|
|
|
10
|
%
|
|
|
14
|
%
|
|
|
16
|
%
|
|
|
|
|
|
15.
|
|
RELATED PARTY TRANSACTIONS
|
Messrs. Joseph A. Reeves, Jr. and Michael J. Mayell, each of whom was an officer of the Company
until December 29, 2008 and is a current Director of Meridian, are working interest partners of the
Company. 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”) and JAR Resources LLC (“JAR”), entities controlled by Joseph A. Reeves,
Jr. and Sydson Energy, Inc. (“Sydson”), an entity controlled by Michael J. Mayell, have each
invested in Meridian drilling locations, where applicable, at a 1.5% to 4% working interest basis.
The maximum total percentage at which either officer was allowed to participate in any prospect was
a 4% working interest. The right to participate in “new oil and gas projects” was terminated as of
December 29, 2008, under the settlement agreements with Messrs. Reeves and Mayell described
immediately below and in Note 12. On a collective basis, TODD, JAR and Sydson invested $997,000,
$4,321,000, and $9,871,000, for the years ended December 31, 2009, 2008, and 2007, respectively, in
oil and natural gas drilling activities. The former officers continued to be offered participation
in new wells in 2009, from prospects initiated prior to December 29, 2008. Net amounts due to
(from) TODD, JAR, Matrix Petroleum LLC (see below) and Mr. Reeves were approximately $76,000 and
($1,981,000) as of December 31, 2009 and 2008, respectively. Net amounts due to Sydson and Mr.
Mayell were approximately $466,000 and $232,000 as of December 31, 2009 and 2008, respectively.
Messrs. Reeves and Mayell each entered into consulting agreements with the Company, commencing
December 30, 2008. Each provided professional services to the Company for a monthly fee; the
agreements terminated on April 30, 2009, with
97
a total of $217,000 paid to or on behalf of each of the two former officers during 2009.
During 2008, the Company settled certain compensation-related contracts with Messrs. Reeves and
Mayell, accruing a total of $9,894,000 for obligations under the settlements, included in “Due to
affiliates” in the accompanying Consolidated Balance Sheet for December 31, 2008. See Note 12 for
further details. As a result of this settlement, during the second quarter of 2009, the Company
paid $4,954,000 and $4,940,000 to Messrs. Reeves and Mayell, respectively. Funds for the payments
were provided from those previously set aside in the related Rabbi Trust. In addition to the cash
payment, each of the former officers received 550,588 shares of Company stock distributed from the
Rabbi Trust. Under the terms of other employment contracts entered into in 2008, Messrs. Reeves and
Mayell also continued to receive such employee benefits as medical insurance throughout 2009, as
well as other fringe benefits, primarily the maintenance of certain club memberships on their
behalf. The Company is obligated to continue these benefits to each of these two former officers
through October 2010.
Also under the terms of the 2008 settlement with Messrs. Reeves and Mayell, in 2009 the Company
transferred to them the furniture, equipment, and artwork from their Meridian executive offices.
During 2009, Matrix Petroleum LLC (“Matrix”), an entity controlled by Mr. Reeves, entered into a
lease of office space from Meridian. The Company has invoiced Matrix a total of $77,000 for rent
and minor charges for use of Meridian office support staff.
As described in Note 11, Messrs. Reeves and Mayell are entitled to certain grants of net profits
interests in properties initiated for development during their term of employment. As properties
develop from geological studies to executed mineral leases, Messrs. Reeves and Mayell receive
interests in the mineral leases. Such grants were valued by third party appraisal at $137,350 and
$78,054 for the years 2008 and 2007, respectively. Grants made in 2009 were negligible.
In December 2009, the Company reached a settlement agreement with Mr. Reeves, TODD, and JAR
(collectively, the “Reeves Parties”) regarding amounts the Reeves Parties claimed were owed to them
by the Company under various agreements, all of which involve the Company’s and the Reeves Parties’
ownership interests in various oil and natural gas properties. In settlement of these claims: 1)
the Company agreed to credit by $600,000 the balance owed by the Reeves Parties to the Company as
joint interest partners; 2) the Reeves Parties paid the Company $400,000 against their joint
interest accounts in December 2009 and agreed to bring their account balances current by May 2010;
3) the Company indemnified the Reeves Parties against claims arising prior to the settlement date
of December 22, 2009 in regard to the properties in which the Reeves Parties share an interest with
the Company; and 4) the Reeves Parties’ ownership in each property was clarified and listed,
including those potential properties included in areas of study performed during Mr. Reeves’ tenure
as an officer. Together with credits for the Reeves Parties’ share of fourth quarter revenues on
the properties, these transactions brought the balance between the Company and Reeves Parties to
the amount cited above, $76,000 owed by the Company to Reeves.
The Company also entered a settlement contract with Mr. Mayell and Sydson (together, “Mayell
Parties”) on December 17, 2009, clarifying and listing the Mayell Parties’ ownership in each oil
and natural gas property, including those potential properties included in areas of study performed
during Mr. Mayell’s tenure as an officer. The Company provided the Mayell Parties with
indemnifications as to claims arising before the date of settlement, with regard to the properties
in which the Mayell Parties share an interest with the Company.
Mr. Joe Kares, a former 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, 2009,
2008, and 2007 and received fees of approximately $150,000, $216,000, and $231,000, 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 $101,000 during 2009, $335,000 during 2008, and $275,000 during 2007. Mr. Kares
resigned from the Board of Directors effective October 13, 2009.
98
Mr. Gary A. Messersmith, a former 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, 2009, 2008, and 2007, and received fees of approximately $137,000,
$118,000, and $73,000, respectively. In addition, during 2007, the Company paid Gary A.
Messersmith, P.C. $8,333 per month relating to his services provided to the Company. The retainer
was paid through March, 2008, then discontinued. Mr. Messersmith also participated in the
Management Plan described in Note 11 above, pursuant to which he was paid approximately $159,000
during 2009, $527,000 during 2008, and $441,000 during 2007. Mr. Messersmith resigned from the
Board of Directors effective October 13, 2009.
During 2008, both Mr. Kares and Mr. Messersmith requested the Company discontinue their
participation in the Management Well Bonus Plan as to new wells drilled after mid-April 2008. Their
participation as to wells previously drilled is unchanged.
Mr. G. M. Larberg, a former Director of Meridian, is a petroleum industry consultant that provided
the Company with services for the years ended December 31, 2009, 2008, and 2007, and received
consulting fees of approximately $44,000, $210,000, and $223,000, respectively. Mr. Larberg
resigned from the Board of Directors effective October 13, 2009.
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 $218,000, $227,000, and $168,000, for the years 2009, 2008, and 2007,
respectively. Mr. Jeff Robinson is the son-in-law of Joseph A. Reeves, Jr. and is employed as the
Manager of the Company’s Information Technology Department and has been paid $198,000, $193,000,
and $164,000, for the years 2009, 2008, and 2007, respectively. Mr. J. Todd Reeves, the son of
Joseph A. Reeves, Jr., is a partner in the law firm of J. Todd Reeves and Associates, which
provides legal services to the Company and received fees of approximately $63,000 in 2009, $197,000
in 2008, and $371,000 in 2007. Such fees exceeded 5% of the gross revenues for the firm for those
respective years.
Mr. Michael W. Mayell, the son of Mr. Michael J. Mayell, an officer until December 29, 2008 and a
current Director of Meridian, is a staff member in the Production Department, and was paid
$174,000, $169,000, and $129,000 for the years 2009, 2008, and 2007, respectively. Mr. James T.
Bond, former Director of Meridian, was the father-in-law of Mr. Michael J. Mayell; he provided
consulting services to the Company and received fees in the amount of $48,000 for the year 2007.
Earnings during 2008 and 2009 noted above for related party employees include the impact of the
Retention Incentive Compensation Plan described in Note 12.
16. EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
(in thousands, except per share)
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) applicable to common stockholders
|
|
$
|
(72,636
|
)
|
|
$
|
(209,886
|
)
|
|
$
|
7,137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic earnings (loss) per share —
weighted-average shares outstanding
|
|
|
92,465
|
|
|
|
91,382
|
|
|
|
89,307
|
|
|
Effect of potentially dilutive common shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants and rights (a)
|
|
NA
|
|
NA
|
|
|
5,637
|
|
|
Employee and director stock options (b)
|
|
NA
|
|
NA
|
|
|
—
|
|
|
Denominator for diluted earnings (loss) per share —
weighted-average shares outstanding and assumed
conversions
|
|
|
92,465
|
|
|
|
91,382
|
|
|
|
94,944
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per share
|
|
$
|
(0.79
|
)
|
|
$
|
(2.30
|
)
|
|
$
|
0.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share
|
|
$
|
(0.79
|
)
|
|
$
|
(2.30
|
)
|
|
$
|
0.08
|
|
|
|
|
|
|
|
|
|
|
|
|
99
Warrants and stock options for which the exercise prices were greater than the average market price
of the Company’s common stock are excluded from the computation of diluted earnings per share.
Stock rights issued under the Company’s deferred compensation plan, which was discontinued in
2008, had no exercise price and are included in diluted earnings per share in all years during
which they were outstanding, unless there is a loss. All potentially dilutive shares, whether from
options, warrants, or rights, 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 1.9 million, 3.3 million, and 1.4
million, in 2009, 2008, and 2007, respectively.
|
|
|
|
(b)
|
|
The number of stock options excluded totaled approximately
0.4 million, 0.5 million, and 3.6
million, in 2009, 2008, and 2007, respectively.
|
17. ACCRUED LIABILITIES AND OTHER LIABILITIES
Below is the detail of accrued liabilities on the Company’s balance sheets as of December 31
(thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Capital expenditures
|
|
$
|
830
|
|
|
$
|
8,227
|
|
|
Operating expenses/taxes
|
|
|
4,072
|
|
|
|
4,452
|
|
|
Hurricane damage repairs
|
|
|
—
|
|
|
|
1,555
|
|
|
Compensation
|
|
|
918
|
|
|
|
2,478
|
|
|
Interest and accrued bank fees
|
|
|
353
|
|
|
|
261
|
|
|
General partner warrants
|
|
|
412
|
|
|
|
—
|
|
|
Shell settlement
|
|
|
1,003
|
|
|
|
—
|
|
|
Other
|
|
|
2,521
|
|
|
|
1,858
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10,109
|
|
|
$
|
18,831
|
|
|
|
|
|
|
|
|
|
The total Shell settlement obligation is $4,223,000, of which $3,220,000 is classified as “Other
Liabilities” in the long-term section of the accompanying Consolidated Balance Sheets at December
31, 2009. See Note 7 for further information. The balance is to be paid over a five year period.
18. QUARTERLY RESULTS OF OPERATIONS (Unaudited)
Results of operations by quarter for the year ended December 31, 2009 were (thousands of dollars,
except per share):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
|
2009
|
|
March 31
|
|
|
June 30
|
|
|
Sept. 30
|
|
|
Dec. 31
|
|
|
Revenues
|
|
$
|
22,109
|
|
|
$
|
22,710
|
|
|
$
|
21,950
|
|
|
$
|
22,476
|
|
|
Results of
operations from
exploration and
production
activities(1) (2)
|
|
|
(55,672
|
)
|
|
|
4,550
|
|
|
|
6,923
|
|
|
|
(851
|
)
|
|
Net (loss)
|
|
$
|
(60,961
|
)
|
|
$
|
(1,462
|
)
|
|
$
|
(768
|
)
|
|
$
|
(9,445
|
)
|
|
Net (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.66
|
)
|
|
$
|
(0.02
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.10
|
)
|
|
Diluted
|
|
$
|
(0.66
|
)
|
|
$
|
(0.02
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.10
|
)
|
100
Results of operations by quarter for the year ended December 31, 2008 were (thousands of dollars,
except per share):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
|
2008
|
|
March 31
|
|
|
June 30
|
|
|
Sept. 30
|
|
|
Dec. 31
|
|
|
Revenues
|
|
$
|
38,448
|
|
|
$
|
46,534
|
|
|
$
|
36,806
|
|
|
$
|
26,846
|
|
|
Results of operations from
exploration and production
activities(1) (3)
|
|
|
11,586
|
|
|
|
18,136
|
|
|
|
10,595
|
|
|
|
(224,406
|
)
|
|
Net earnings (loss)
|
|
$
|
3,563
|
|
|
$
|
839
|
|
|
$
|
699
|
|
|
$
|
(214,987
|
)
|
|
Net earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.04
|
|
|
$
|
0.01
|
|
|
$
|
0.01
|
|
|
$
|
(2.33
|
)
|
|
Diluted
|
|
$
|
0.04
|
|
|
$
|
0.01
|
|
|
$
|
0.01
|
|
|
$
|
(2.33
|
)
|
|
|
|
|
|
(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)
|
|
Includes impairments of long-lived assets of $59.5 million and $4.0 million in the
first and fourth quarters, respectively.
|
|
|
|
(3)
|
|
Includes impairment of long-lived assets of $223.5 million in the fourth quarter.
|
19. SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited)
In December 2008, the SEC published a Final Rule,
“Modernization of Oil and Gas Reporting
.
”
The new
rule permits the use of new technologies to determine proved reserves if those technologies have
been demonstrated to lead to reliable conclusions about reserves volumes. The new requirements also
allow companies to disclose their probable and possible reserves to investors. In addition, the new
disclosure requirements require companies to: (
a
) report the independence and qualifications of its
reserves preparer or auditor; (
b
) file reports when a third party is relied upon to prepare
reserves estimates or conducts a reserves audit; and (
c
) report oil and gas reserves using an
average price based upon the prior 12-month period rather than year-end prices. The use of average
prices affects impairment and depletion calculations. The new rule became effective for reserve
reports as of December 31, 2009; the FASB incorporated the new guidance into the Codification as
Accounting Standards Update 2010-03, effective also on December 31, 2009, ASC Topic 932,
“Extractive Activities — Oil and Gas.”
The Company adopted the new guidance effective December 31, 2009; information about the Company’s
reserves has been prepared in accordance with the new guidance; management has chosen not to
provide information on probable and possible reserves. The Company’s reserves were affected
primarily by the use of the average price rather than the year-end price required under the prior
rules. Under the new rules issued by the SEC, the estimated future net cash flows as of December
31, 2009, were determined using average prices for the most recent twelve months. The average is
calculated using the first day of the month price for each of the twelve months that make up the
reporting period. As of December 31, 2008 and 2007, previous rules required that estimated future
net cash flows from proved reserves be based on period end prices. As a result of adopting the new
guidance, we estimate that Meridian’s December 31, 2009 proven reserves decreased approximately 1.4
Bcfe and prices used in the calculation decreased approximately 30%. These changes in turn
affected the results of the Company’s ceiling test for the fourth quarter, which was a write-down
of $4.0 million. Had the new rule using average pricing not been implemented, the write-down in
the fourth quarter of 2009 would not have been
101
necessary. The change in total reserves had only a negligible effect on depletion expense in the
fourth quarter of 2009; total proved reserves are the basis of depletion calculations.
The reserve volumes and associated cash flows were prepared by T. J. Smith & Company, Inc.,
independent reservoir engineers. For further information on Mr. Smith’s qualifications and on the
methods and controls used in the process of estimating reserves, please see Part I, Item 1,
Business, Oil and Natural Gas Reserves.
The reserve information presented below is provided as supplemental information in accordance with
the provisions of ASC Topic 932-235.
Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities
(thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Costs incurred during the year:(1)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition costs
Unproved (3)
|
|
$
|
(2,136
|
)
|
|
$
|
21,879
|
|
|
$
|
9,589
|
|
|
Proved
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Exploration
|
|
|
5,838
|
|
|
|
51,752
|
|
|
|
92,320
|
|
|
Development
|
|
|
10,765
|
|
|
|
38,159
|
|
|
|
9,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
14,467
|
|
|
$
|
111,790
|
|
|
$
|
110,935
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Costs incurred during the years ended December 31, 2009, 2008 and 2007 include general and
administrative costs related to acquisition, exploration and development of oil and natural
gas properties, net of third party reimbursements, of $2,567,000, $17,390,000, and
$16,492,000, respectively.
|
|
|
|
(2)
|
|
Costs incurred during the years ended December 31, 2009 and 2008 include $180,000 and $1.1
million in net profit (loss) related to the lease of a drilling rig by TMRD. The rig was used
to drill wells which the Company owns and operates. The amount transferred to the full cost
pool represents the portion of profits (losses) on the lease related to services performed on
behalf of others, primarily our joint interest partners. Profits from the rig reduce the
costs incurred.
|
|
|
|
(3)
|
|
Property acquisition costs for unproved properties reflect a negative value for 2009, due to
the reimbursement of costs upon the partial sale of interests in various unproven leaseholds.
The Company retained an interest in the properties.
|
Capitalized Costs Relating to Oil and Natural Gas Producing Activities
(thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Capitalized costs
|
|
$
|
1,890,079
|
|
|
$
|
1,877,925
|
|
|
Accumulated depletion
|
|
|
1,732,112
|
|
|
|
1,632,622
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
157,967
|
|
|
$
|
245,303
|
|
|
|
|
|
|
|
|
|
At December 31, 2009 and 2008, unevaluated costs of $1,647,000 and $39,927,000, respectively, were
excluded from the depletion base. The costs excluded in 2009 are expected to be evaluated within
the next three years. These costs consist primarily of acreage acquisition costs at December 31,
2009, and acreage acquisition costs and related geological and geophysical costs at December 31,
2008.
102
Costs Not Being Amortized
The following table sets forth a summary of oil and natural gas property costs not being amortized
at December 31, 2009, by the year in which such costs were incurred. All the costs not being
amortized relate to one property, a group of leaseholds in south Texas under exploration with
another operator, and include no exploratory well costs.
(thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2009
|
|
|
2008
|
|
|
2007 & Prior
|
|
|
Leasehold acquisition costs
|
|
$
|
1,440
|
|
|
$
|
46
|
|
|
$
|
1,394
|
|
|
$
|
—
|
|
|
Capitalized general and
administrative costs
|
|
|
207
|
|
|
|
—
|
|
|
|
207
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,647
|
|
|
$
|
46
|
|
|
$
|
1,601
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations from Oil and Natural Gas Producing Activities
(thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
49,222
|
|
|
$
|
63,636
|
|
|
$
|
54,218
|
|
|
Natural Gas
|
|
|
40,023
|
|
|
|
84,998
|
|
|
|
96,491
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
89,245
|
|
|
|
148,634
|
|
|
|
150,709
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas operating costs
|
|
|
17,550
|
|
|
|
24,280
|
|
|
|
28,338
|
|
|
Severance and ad valorem taxes
|
|
|
6,696
|
|
|
|
9,727
|
|
|
|
9,409
|
|
|
Depletion
|
|
|
35,994
|
|
|
|
71,647
|
|
|
|
76,660
|
|
|
Accretion expense
|
|
|
2,083
|
|
|
|
2,064
|
|
|
|
2,230
|
|
|
Impairment of long-lived assets (1)
|
|
|
63,495
|
|
|
|
223,543
|
|
|
|
—
|
|
|
Hurricane damage repairs
|
|
|
—
|
|
|
|
1,462
|
|
|
|
—
|
|
|
Rig operations, net
|
|
|
4,254
|
|
|
|
—
|
|
|
|
—
|
|
|
Indemnification settlement
|
|
|
4,223
|
|
|
|
—
|
|
|
|
—
|
|
|
Income tax expense (benefit)
|
|
|
(120
|
)
|
|
|
(8,462
|
)
|
|
|
14,992
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
134,175
|
|
|
|
324,261
|
|
|
|
131,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations from oil and
natural gas producing activities
|
|
|
(44,930
|
)
|
|
|
(175,627
|
)
|
|
$
|
19,080
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion expense per Mcfe
|
|
$
|
2.87
|
|
|
$
|
5.13
|
|
|
$
|
4.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
For 2008, includes impairment of oil and natural gas properties of $216.8 million and
impairment of drilling rig of $6.7 million; for 2009, all impairments are to oil and natural
gas properties.
|
Estimated Quantities of Proved Reserves
The following table sets forth the net proved reserves of the Company as of December 31, 2009,
2008, and 2007, 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 prepared by T. J. Smith &
Company, Inc., independent reservoir engineers, for 2009, 2008, and 2007. Mr. T. J. Smith is the
person primarily responsible for overseeing the preparation of our annual reserve estimates. Mr.
Smith is a graduate of Mississippi State University with a Bachelor of
103
Science degree in Petroleum Engineering. He has over 40 years’ experience with approximately 35
years focused on reserve evaluation. He is a member of the Society of Petroleum Engineers and is a
Registered Professional Engineer in the states of Texas and Louisiana. All of the Company’s oil
and natural gas producing activities are located in the United States.
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
Total Proved Reserves:
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 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
|
|
|
Production during 2008
|
|
|
(765
|
)
|
|
|
(9,369
|
)
|
|
Sale of reserves in-place
|
|
|
(3
|
)
|
|
|
(170
|
)
|
|
Discoveries and extensions
|
|
|
1,934
|
|
|
|
3,817
|
|
|
Revisions of previous quantity estimates and other
|
|
|
(1,119
|
)
|
|
|
(4,711
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
4,903
|
|
|
|
50,896
|
|
|
Production during 2009
|
|
|
(834
|
)
|
|
|
(7,549
|
)
|
|
Sale of reserves in-place
|
|
|
—
|
|
|
|
—
|
|
|
Discoveries and extensions
|
|
|
516
|
|
|
|
3,666
|
|
|
Revisions of previous quantity estimates and other
|
|
|
(817
|
)
|
|
|
5,350
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
3,768
|
|
|
|
52,363
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2006
|
|
|
3,151
|
|
|
|
49,253
|
|
|
Balance at December 31, 2007
|
|
|
2,892
|
|
|
|
42,555
|
|
|
Balance at December 31, 2008
|
|
|
2,732
|
|
|
|
35,054
|
|
|
Balance at December 31, 2009
|
|
|
2,571
|
|
|
|
32,560
|
|
Proved Undeveloped Reserves
The total of the Company’s proved undeveloped reserves (“PUD’s”) is 27 Bcfe, or approximately 36%
of total proved reserves at December 31, 2009. The undeveloped properties are primarily in our
East Texas area and in two of our mature fields in Louisiana and are the same or similar properties
to those reported in 2008, which totaled 29 Bcfe. Reductions in PUD’s from the prior year include
a decrease of 5.6 Bcfe at the outside operated East Cameron 331/332 field offshore. We have
eliminated these non-operated reserves as there is substantial uncertainty as to their development
as the field has undergone numerous operator changes (again in 2009) and we have no firm plans to
develop them at this time. Other changes in PUD’s include a reduction of 3.7 Bcfe for several oil
wells that had been candidates for updip oil development; however, there is no certainty that these
updip locations will be oil. We have, for reserve purposes, estimated that the section will be
natural gas, and hence, the reserves are uneconomic and have been eliminated.
Increases to PUD’s were due primarily to upward revisions of estimates and the addition of several
new locations in East Texas totaling 5.8 Bcfe, based on new drilling and production information for
that area. Progress toward development of our portfolio of proved undeveloped reserves was
necessarily minimal during 2009, as we minimized capital spending due to our Credit Facility
defaults.
104
Approximately 11.5 Bcfe of our PUD’s at December 31, 2009 originated more than five years ago.
Certain PUD’s in our mature fields in Louisiana have been included for more than five years,
because they have been planned as sidetracks and cannot be developed until the current producing
well bores have been depleted and abandoned. We have been exploring and developing our East Texas
acreage since 2005, and now have a total of 14 producing wells in that area.
Standardized Measure of Discounted Future Net Cash Flows
The information that follows has been developed pursuant to ASC 932-235 and utilizes reserve and
production data prepared 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
historical 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.
The following table sets forth the components of the standardized measure of discounted future net
cash flows for the years ended December 31, 2009, 2008, and 2007 (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Future cash flows
|
|
$
|
414,043
|
|
|
$
|
490,602
|
|
|
$
|
842,986
|
|
|
Future production costs
|
|
|
(138,982
|
)
|
|
|
(168,160
|
)
|
|
|
(185,768
|
)
|
|
Future development costs
|
|
|
(85,898
|
)
|
|
|
(82,866
|
)
|
|
|
(80,656
|
)
|
|
Future taxes on income
|
|
|
—
|
|
|
|
—
|
|
|
|
(80,029
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
189,163
|
|
|
|
239,576
|
|
|
|
496,533
|
|
|
Discount to present value at 10 percent per annum
|
|
|
(50,208
|
)
|
|
|
(60,139
|
)
|
|
|
(105,069
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net
cash flows
|
|
$
|
138,955
|
|
|
$
|
179,437
|
|
|
$
|
391,464
|
|
|
|
|
|
|
|
|
|
|
|
|
The average expected realized price for natural gas in the above computations was $3.97, $5.79, and
$6.66 per Mcf at December 31, 2009, 2008, and 2007, respectively. The average expected realized
price used for crude oil in the above computations was $59.94, $44.04, and $95.54, per Bbl at
December 31, 2009, 2008, and 2007, respectively. No consideration was been given to the Company’s
hedged transactions.
Changes in Standardized Measure of Discounted Future Net Cash Flows
The following table sets forth the changes in standardized measure of discounted future net cash
flows for the years ended December 31, 2009, 2008, and 2007 (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Balance at Beginning of Period
|
|
$
|
179,437
|
|
|
$
|
391,464
|
|
|
$
|
327,899
|
|
|
Sales of oil and natural gas, net of production costs
|
|
|
(65,000
|
)
|
|
|
(114,626
|
)
|
|
|
(112,962
|
)
|
|
Changes in sales & transfer prices, net of
production costs
|
|
|
(12,019
|
)
|
|
|
(165,125
|
)
|
|
|
125,623
|
|
|
Revisions of previous quantity estimates
|
|
|
1,192
|
|
|
|
(32,842
|
)
|
|
|
25,751
|
|
|
Purchase of reserves-in-place
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Sale of reserves in-place
|
|
|
—
|
|
|
|
177
|
|
|
|
(2,233
|
)
|
|
Current year discoveries, extensions and improved
recovery
|
|
|
7,407
|
|
|
|
44,112
|
|
|
|
32,939
|
|
|
Changes in estimated future development costs
|
|
|
8,778
|
|
|
|
(1,417
|
)
|
|
|
(7,917
|
)
|
|
Development costs incurred during the period
|
|
|
979
|
|
|
|
8,298
|
|
|
|
8,526
|
|
|
Accretion of discount
|
|
|
17,944
|
|
|
|
39,146
|
|
|
|
32,790
|
|
|
Net change in income taxes
|
|
|
—
|
|
|
|
23,453
|
|
|
|
(14,451
|
)
|
|
Change in production rates (timing) and other
|
|
|
237
|
|
|
|
(13,203
|
)
|
|
|
(24,501
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change
|
|
|
(40,482
|
)
|
|
|
(212,027
|
)
|
|
|
63,565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Period
|
|
$
|
138,955
|
|
|
$
|
179,437
|
|
|
$
|
391,464
|
|
|
|
|
|
|
|
|
|
|
|
|
105
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
We conducted an evaluation under the supervision and with the participation of Meridian’s
management, including our Chief Executive Officer and Chief Accounting Officer, of the
effectiveness of the design and operation of our disclosure controls and procedures (as defined in
Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the fourth quarter of
2009. 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 2009 that could significantly affect these controls.
Management’s Annual Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining a system of adequate internal control
over the Company’s financial reporting, which is designed to provide reasonable assurance regarding
the preparation of reliable published consolidated financial statements. All internal control
systems, no matter how well designed, have inherent limitations. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to financial
statement preparation and presentation.
The Company’s management assessed the effectiveness of the Company’s system of internal control
over financial reporting as of December 31, 2009. In making this assessment, the Company’s
management used the criteria for effective internal control over financial reporting described in
“Internal Control — Integrated Framework” that the Committee of Sponsoring Organizations of the
Treadway Commission issued.
Based on its assessment using those criteria, management believes that, as of December 31, 2009,
the Company’s system of internal control over financial reporting was effective.
The Company’s independent registered public accounting firm has issued a report on the
effectiveness of the Company’s internal control over financial reporting, which report follows.
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial
Reporting
Board of Directors and Shareholders
106
The Meridian Resource Corporation
Houston, Texas
We have audited The Meridian Resource Corporation’s internal control over financial reporting as of
December 31, 2009, 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 Corporation’s management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of internal control
over financial reporting, included in the accompanying “Item 9A, Management’s Annual Report on
Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on the
Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance 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 company’s internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. A
company’s internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, The Meridian Resource Corporation maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2009, 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 as of
December 31, 2009 and 2008, and the related consolidated statements of operations, comprehensive
income (loss), stockholders’ equity and cash flows for each of the three years in the period ended
December 31, 2009 and our report dated April 15, 2010 included an explanatory paragraph that
expressed substantial doubt about the Company’s ability to continue as a going concern.
/s/ BDO Seidman, LLP
Houston, Texas
April 15, 2010
Item 9B. Other Information.
107
None.
PART III
The information required in Items 10, 11, 12, 13 and 14 is incorporated by reference to the
Company’s Form 10-K/A to be filed with the SEC on or before April 30, 2010.
PART IV
Item 15. Exhibits and Financial Statement Schedules
|
|
(a)
|
|
Documents filed as part of this report:
|
|
|
|
|
1.
|
|
Financial Statements included in Item 8:
|
|
|
(i)
|
|
Independent Registered Public Accounting Firm’s Report
|
|
|
|
|
(ii)
|
|
Consolidated Statements of Operations for each of the three years in the period
ended December 31, 2009
|
|
|
|
|
(iii)
|
|
Consolidated Balance Sheets as of December 31, 2009 and 2008
|
|
|
|
|
(iv)
|
|
Consolidated Statements of Cash Flows for each of the three years in the period
ended December 31, 2009
|
|
|
|
|
(v)
|
|
Consolidated Statements of Changes in Stockholders’ Equity for each of the three
years in the period ended December 31, 2009
|
|
|
|
|
(vi)
|
|
Consolidated Statements of Comprehensive Income (Loss) for each of the three
years in the period ended December 31, 2009
|
|
|
|
|
(vii)
|
|
Notes to Consolidated Financial Statements
|
|
|
|
|
(viii)
|
|
Supplemental Oil and Natural Gas Information (Unaudited)
|
|
|
2.
|
|
Financial Statement Schedules:
|
|
|
(i)
|
|
All schedules are omitted as they are not applicable, not required or the
required information is included in the consolidated financial statements or notes
thereto.
|
3. Exhibits:
2.1 Agreement and Plan of Merger, dated December 22, 2009, by and among Alta Mesa Holdings, LP, a
Texas limited partnership, Alta Mesa Acquisition Sub, LLC, a Texas limited liability company, and
The Meridian Resource Corporation, a Texas corporation (incorporated by reference to Exhibit 2.1 of
the Company’s Current Report on Form 8-K filed December 29, 2009).
2.2 First Amendment to Agreement and Plan of Merger, dated April 7, 2010, by and among Alta Mesa
Holdings, LP, a Texas limited partnership, Alta Mesa Acquisition Sub, LLC, a Texas limited
liability company, and The Meridian
108
Resource Corporation, a Texas corporation (incorporated by reference to Exhibit 2.1 of the
Company’s Current Report on Form 8-K filed April 12, 2010).
3.1 Third Amended and Restated Articles of Incorporation of the Company (incorporated by reference
to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the three months ended September
30, 1998).
3.2 Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the
Company’s Quarterly Report on Form 10-Q for the three months ended September 30, 1998).
3.3 Amendment No. 1 to Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 of the
Company’s Report on Form 8-K dated May 5, 1999).
3.5 Amendment No. 2 to Amended and Restated Bylaws of The Meridian Resource Corporation, adopted
April 29, 2008 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form
8-K filed May 2, 2008).
3.6 Amendment No. 3 to Amended and Restated Bylaws of The Meridian Resource Corporation, adopted
December 22, 2008 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form
8-K filed December 29, 2008).
4.1 Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of the Company’s
Registration Statement on Form S-1, as amended (Reg. No. 33-65504)).
*4.2 Common Stock Purchase Warrant of the Company dated October 16, 1990, issued to Joseph A.
Reeves, Jr. (incorporated by reference to Exhibit 10.8 of the Company’s Annual Report on Form 10-K
for the year ended December 31, 1991, as amended by the Company’s Form 8 filed March 4, 1993).
*4.3 Common Stock Purchase Warrant of the Company dated October 16, 1990, issued to Michael J.
Mayell (incorporated by reference to Exhibit 10.9 of the Company’s Annual Report on Form 10-K for
the year ended December 31, 1991, as amended by the Company’s Form 8 filed March 4, 1993).
*4.4 Registration Rights Agreement dated October 16, 1990, among the Company, Joseph A. Reeves, Jr.
and Michael J. Mayell (incorporated by reference to Exhibit 10.7 of the Company’s Registration
Statement on Form S-4, as amended (Reg. No. 33-37488)).
*4.5 The Meridian Resource Corporation Directors’ Stock Option Plan (incorporated by reference to
Exhibit 10.5 of the Company’s Annual Report on Form 10-K for the year ended December 31, 1991, as
amended by the Company’s Form 8 filed March 4, 1993).
*4.6 The Meridian Resource Corporation 2006 Non-Employee Directors’ Incentive Plan (incorporated by
reference to Exhibit A of the Company’s Proxy Statement on Schedule 14A filed May 19, 2006).
10.1 See exhibits 4.2 through 4.6 for additional material contracts.
*10.2 The Meridian Resource Corporation 1990 Stock Option Plan (incorporated by reference to
Exhibit 10.6 of the Company’s Annual Report on Form 10-K for the year ended December 31, 1991, as
amended by the Company’s Form 8 filed March 4, 1993).
109
*10.3 Form of Indemnification Agreement between the Company and its executive officers and
directors (incorporated by reference to Exhibit 10.6 of the Company’s Annual Report on Form 10-K
for the year ended December 31, 1994).
*10.4 Texas Meridian Resources Corporation 1995 Long-Term Incentive Plan (incorporated by reference
to the Company’s Annual Report on Form 10-K for the year ended December 31, 1996).
*10.5 Texas Meridian Resources Corporation 1997 Long-Term Incentive Plan (incorporated by reference
from the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 1997).
*10.6 The Meridian Resource Corporation TMR Employee Trust Well Bonus Plan (incorporated by
reference from the Company’s Annual Report on Form 10-K for the year ended December 31, 1998).
*10.7 The Meridian Resource Corporation Management Well Bonus Plan (incorporated by reference from
the Company’s Annual Report on Form 10-K for the year ended December 31, 1998).
*10.8 The Meridian Resource Corporation Geoscientist Well Bonus Plan (incorporated by reference
from the Company’s Annual Report on Form 10-K for the year ended December 31, 1998).
*10.9 Employment Agreement, dated April 29, 2008, by and between The Meridian Resources Corporation
and Joseph A. Reeves, Jr. (incorporated by reference to Exhibit 10.1 to the Company’s Annual Report
on Form 10-K/A for the year ended December 31, 2007).
*10.10 Employment Agreement, dated April 29, 2008, by and between The Meridian Resources
Corporation and Michael J. Mayell (incorporated by reference to Exhibit 10.2 to the Company’s
Annual Report on Form 10-K/A for the year ended December 31, 2007).
*10.11 Termination Agreement, dated April 29, 2008, by and between The Meridian Resources
Corporation and Joseph A. Reeves, Jr. (incorporated by reference to Exhibit 10.3 to the Company’s
Annual Report on Form 10-K/A for the year ended December 31, 2007).
*10.12 Termination Agreement, dated April 29, 2008, by and between The Meridian Resources
Corporation and Michael J. Mayell (incorporated by reference to Exhibit 10.4 to the Company’s
Annual Report on Form 10-K/A for the year ended December 31, 2007).
*10.13 Agreement (regarding Net Profits Interests), effective January 1, 1994, between Joseph A.
Reeves, Jr. and Texas Meridian Resources Corporation (n/k/a The Meridian Resource Corporation)
(incorporated by reference to Exhibit 10.5 to the Company’s Annual Report on Form 10-K/A for the
year ended December 31, 2007).
*10.14 Agreement (regarding Net Profits Interests), effective January 1, 1994, between Michael J.
Mayell and Texas Meridian Resources Corporation (n/k/a The Meridian Resource Corporation)
(incorporated by reference to Exhibit 10.6 to the Company’s Annual Report on Form 10-K/A for the
year ended December 31, 2007).
*10.15 Consulting Agreement, dated effective as of December 30, 2008, between the Company and
Joseph A. Reeves, Jr. (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on
Form 8-K filed December 29, 2008).
*10.16 Consulting Agreement, dated effective as of December 30, 2008, between the Company and
Michael J. Mayell (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on
Form 8-K filed December 29, 2008).
110
*10.17 The Meridian Resource & Exploration LLC Change in Control and Severance Plan (incorporated
by reference to Exhibit 10.1 to Amendment No. 1 to the Company’s Annual Report on Form 10-K/A for
the year ended December 31, 2008).
*10.18 Employment Agreement, dated effective as of December 30, 2008, by and between The Company
and Paul D. Ching (incorporated by reference to Exhibit 10.31 of the Company’s Report on Form 10-K
for the year ended December 31, 2008).
*10.19 Amendment to Employment Agreement, dated June 4, 2009, between The Meridian Resource
Corporation and Paul D. Ching. (incorporated by reference to Exhibit 10.1 of the Company’s Report
on Form 8-K filed June 5, 2009).
*10.20 Amendment No. 2 to Employment Agreement, dated February 22, 2010, between The Meridian
Resource Corporation and Paul D. Ching (incorporated by reference to Exhibit 10.1 of the Company’s
Current Report on Form 8-K filed February 26, 2010).
*10.21 Employment Agreement, dated effective as of December 17, 2008, by and between The Company
and Lloyd V. DeLano (incorporated by reference to Exhibit 10.32 of the Company’s Report on Form
10-K for the year ended December 31, 2008).
*10.22 Employment Agreement, dated effective as of December 17, 2008, by and between The Company
and Stephen G. Ives (incorporated by reference to Exhibit 10.33 of the Company’s Report on Form
10-K for the year ended December 31, 2008).
*10.23 Employment Agreement, dated effective as of December 17, 2008, by and between The Company
and Allen D. Breaux (incorporated by reference to Exhibit 10.34 of the Company’s Report on Form
10-K for the year ended December 31, 2008).
*10.24 Employment Agreement, dated effective as of December 17, 2008, by and between The Company
and Alan S. Pennington (incorporated by reference to Exhibit 10.35 of the Company’s Report on Form
10-K for the year ended December 31, 2008).
10.25 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 to Exhibit
10.1 of the Company’s Current Report on Form 8-K dated December 23, 2004).
10.26 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 (incorporated by reference to
Exhibit 10.21 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007).
10.27 Second Amendment to Credit Agreement, dated as of December 19, 2008, among the Company, the
several banks, financial institutions and other entities from time to time parties to the Credit
Agreement (collectively, the “Lenders”), and Fortis Capital Corp., as administrative agent for the
Lenders (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K
filed December 29, 2008).
111
10.28 Forbearance and Amendment Agreement, dated as of September 3, 2009, among The Meridian
Resource Corporation, certain of its subsidiaries, Fortis Capital Corp., as administrative agent,
and the several banks, financial institutions and other entities from time to time parties to
Amended and Restated Credit Agreement, dated as of December 23, 2004, as amended, among The
Meridian Resource Corporation, Fortis Capital Corp., as administrative agent, and the lenders party
thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K
filed September 10, 2009).
10.29 First Amendment to Forbearance and Amendment Agreement, dated as of September 30, 2009, among
The Meridian Resource Corporation, certain of its subsidiaries, Fortis Capital Corp., as
administrative agent, and the several banks, financial institutions and other entities from time to
time parties to the Amended and Restated Credit Agreement, dated as of December 23, 2004, as
amended, among The Meridian Resource Corporation, Fortis Capital Corp., as administrative agent,
and the lenders party thereto (incorporated by reference to Exhibit 10.2 of the Company’s Quarterly
Report on Form 10-Q for the three months ended September 30, 2009).
10.30 Second Amendment to Forbearance and Amendment Agreement, dated as of October 2, 2009, among
The Meridian Resource Corporation, certain of its subsidiaries, Fortis Capital Corp., as
administrative agent, and the several banks, financial institutions and other entities from time to
time parties to the Amended and Restated Credit Agreement, dated as of December 23, 2004, as
amended, among The Meridian Resource Corporation, Fortis Capital Corp., as administrative agent,
and the lenders party thereto (incorporated by reference to Exhibit 10.3 of the Company’s Quarterly
Report on Form 10-Q for the three months ended September 30, 2009).
10.31 Third Amendment to Forbearance and Amendment Agreement, dated as of October 20, 2009, among
The Meridian Resource Corporation, certain of its subsidiaries, Fortis Capital Corp., as
administrative agent, and the several banks, financial institutions and other entities from time to
time parties to the Amended and Restated Credit Agreement, dated as of December 23, 2004, as
amended, among The Meridian Resource Corporation, Fortis Capital Corp., as administrative agent,
and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s
Current Report on Form 8-K filed with the SEC on October 22, 2009).
10.32 Fourth Amendment to Forbearance and Amendment Agreement, dated as of November 13, 2009, among
The Meridian Resource Corporation, certain of its subsidiaries, Fortis Capital Corp., as
administrative agent, and the several banks, financial institutions and other entities from time to
time parties to the Amended and Restated Credit Agreement, dated as of December 23, 2004, as
amended, among The Meridian Resource Corporation, Fortis Capital Corp., as administrative agent,
and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current
Report on Form 8-K filed November 19, 2009).
10.33 Fifth Amendment to Forbearance and Amendment Agreement, dated as of November 20, 2009, among
The Meridian Resource Corporation, certain of its subsidiaries, Fortis Capital Corp., as
administrative agent, and the several banks, financial institutions and other entities from time to
time parties to the Amended and Restated Credit Agreement, dated as of December 23, 2004, as
amended, among The Meridian Resource Corporation, Fortis Capital Corp., as administrative agent,
and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current
Report on Form 8-K filed November 25, 2009).
10.34 Sixth Amendment to Forbearance and Amendment Agreement, dated as of November 30, 2009, among
The Meridian Resource Corporation, certain of its subsidiaries, Fortis Capital Corp., as
administrative agent, and the several banks, financial institutions and other entities from time to
time parties to the Amended and Restated Credit Agreement, dated as of December 23, 2004, as
amended, among The Meridian Resource Corporation, Fortis Capital Corp., as administrative agent,
and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current
Report on Form 8-K filed December 2, 2009).
112
10.35 Seventh Amendment to Forbearance and Amendment Agreement, dated as of December 2, 2009, among
The Meridian Resource Corporation, certain of its subsidiaries, Fortis Capital Corp., as
administrative agent, and the several banks, financial institutions and other entities from time to
time parties to the Amended and Restated Credit Agreement, dated as of December 23, 2004, as
amended, among The Meridian Resource Corporation, Fortis Capital Corp., as administrative agent,
and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current
Report on Form 8-K filed December 8, 2009).
10.36 Eighth Amendment to Forbearance and Amendment Agreement, dated as of December 4, 2009, among
The Meridian Resource Corporation, certain of its subsidiaries, Fortis Capital Corp., as
administrative agent, and the several banks, financial institutions and other entities from time to
time parties to the Amended and Restated Credit Agreement, dated as of December 23, 2004, as
amended, among The Meridian Resource Corporation, Fortis Capital Corp., as administrative agent,
and the lenders party thereto (incorporated by reference to Exhibit 10.2 of the Company’s Current
Report on Form 8-K filed December 8, 2009).
10.37 Ninth Amendment to Forbearance and Amendment Agreement, dated as of December 14, 2009, among
The Meridian Resource Corporation, certain of its subsidiaries, Fortis Capital Corp., as
administrative agent, and the several banks, financial institutions and other entities from time to
time parties to the Amended and Restated Credit Agreement, dated as of December 23, 2004, as
amended, among The Meridian Resource Corporation, Fortis Capital Corp., as administrative agent,
and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current
Report on Form 8-K filed December 17, 2009).
10.38 Tenth Amendment to Forbearance and Amendment Agreement, dated as of December 21, 2009, among
The Meridian Resource Corporation, certain of its subsidiaries, Fortis Capital Corp., as
administrative agent, and the several banks, financial institutions and other entities from time to
time parties to the Amended and Restated Credit Agreement, dated as of December 23, 2004, as
amended, among The Meridian Resource Corporation, Fortis Capital Corp., as administrative agent,
and the lenders party thereto (incorporated by reference to Exhibit 10.2 of the Company’s Current
Report on Form 8-K filed December 29, 2009).
10.39 Eleventh Amendment to Forbearance and Amendment Agreement, dated as of December 22, 2009,
among The Meridian Resource Corporation, certain of its subsidiaries, Fortis Capital Corp., as
administrative agent, and the several banks, financial institutions and other entities from time to
time parties to the Amended and Restated Credit Agreement, dated as of December 23, 2004, as
amended, among The Meridian Resource Corporation, Fortis Capital Corp., as administrative agent,
and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current
Report on Form 8-K filed December 29, 2009).
10.40 Forbearance Agreement, dated as of September 3, 2009, by and among Fortis Capital Corp.,
Fortis Energy Marketing & Trading GP and The Meridian Resource Corporation (incorporated by
reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed September 10, 2009).
10.41 First Amendment to Forbearance Agreement, dated as of December 4, 2009, among The Meridian
Resource Corporation, certain of its subsidiaries, Fortis Capital Corp. and Fortis Energy Marketing
& Trading GP (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K
filed December 8, 2009).
10.42 Second Amendment to Forbearance Agreement, dated as of December 14, 2009, among The Meridian
Resource Corporation, certain of its subsidiaries, Fortis Capital Corp. and Fortis Energy Marketing
& Trading GP (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K
filed December 17, 2009).
113
10.43 Third Amendment to Forbearance Agreement, dated as of December 16, 2009, among The Meridian
Resource Corporation, certain of its subsidiaries, Fortis Capital Corp. and Fortis Energy Marketing
& Trading GP (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K
filed December 29, 2009).
10.44 Forbearance and Amendment Agreement, dated as of September 3, 2009, by and among TMR Drilling
Corporation, The Meridian Resource Corporation, The Meridian Resource & Exploration LLC and The CIT
Group/Equipment Financing, Inc, as administrative agent and lender (incorporated by reference to
Exhibit 10.3 of the Company’s Current Report on Form 8-K filed September 10, 2009).
10.45 First Amendment to Forbearance and Amendment Agreement, dated as of December 4, 2009, among
The Meridian Resource Corporation, certain of its subsidiaries and The CIT Group/Equipment
Financing, Inc. (incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form
8-K filed December 8, 2009).
10.46 Second Amendment to Forbearance and Amendment Agreement, dated as of December 14, 2009, among
The Meridian Resource Corporation, certain of its subsidiaries and The CIT Group/Equipment
Financing, Inc. (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form
8-K filed December 17, 2009).
10.47 Third Amendment to Forbearance and Amendment Agreement, dated as of December 21, 2009, among
The Meridian Resource Corporation, certain of its subsidiaries and The CIT Group/Equipment
Financing, Inc. (incorporated by reference to Exhibit 10.5 of the Company’s Current Report on Form
8-K filed December 29, 2009).
10.48 Fourth Amendment to Forbearance and Amendment Agreement, dated as of December 22, 2009, among
The Meridian Resource Corporation, certain of its subsidiaries and The CIT Group/Equipment
Financing, Inc. (incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form
8-K filed December 29, 2009).
10.49 Forbearance and Amendment Agreement, dated as of September 3, 2009, by and among The Meridian
Resource Corporation, The Meridian Resource & Exploration LLC, TMR Drilling Corporation and Orion
Drilling Company LLC (incorporated by reference to Exhibit 10.4 of the Company’s Current Report on
Form 8-K filed September 10, 2009).
*10.50 Omnibus Agreement Relating to Assigned Interests, dated December 22, 2009, by and among
Joseph A. Reeves, Jr., Texas Oil Distribution & Development, Inc., JAR Resource Holdings, LLP, The
Meridian Resource Corporation, The Meridian Resource & Exploration LLC, Louisiana Onshore
Properties LLC, and Cairn Energy USA, Inc. (incorporated by reference to Exhibit 10.6 of the
Company’s Current Report on Form 8-K filed December 29, 2009).
*10.51 Settlement and Release Agreement, dated December 22, 2009, by and among Joseph A. Reeves,
Jr., Texas Oil Distribution & Development, Inc., JAR Resource Holdings, LLP, and The Meridian
Resource Corporation (incorporated by reference to Exhibit 10.7 of the Company’s Current Report on
Form 8-K filed December 29, 2009).
*10.52 Agreement with Cross-Release, dated December 17, 2009, by and among Michael J. Mayell,
Sydson Energy, Inc., The Meridian Resource Corporation, The Meridian Resource & Exploration LLC,
Louisiana Onshore Properties LLC, and Cairn Energy USA, Inc. (incorporated by reference to Exhibit
10.8 of the Company’s Current Report on Form 8-K filed December 29, 2009).
**10.53 Compromise and Settlement Agreement, dated January 11, 2010, among The Meridian Resource
Corporation, Shell Oil Company and SWEPI, LP.
**10.54 Amendment to Compromise and Settlement Agreement, dated March 30, 2010, among The Meridian
Resource Corporation, Shell Oil Company and SWEPI, LP.
114
21.1 Subsidiaries of the Company (incorporated by reference to Exhibit 2.1 of the Company’s Annual
Report on Form 10-K for the year ended December 31, 2007).
**23.1 Consent of BDO Seidman, LLP.
**23.2 Consent of T. J. Smith & Company, Inc.
**23.3 Report 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 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 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.
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*
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Management contract or compensatory plan.
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**
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Filed herewith.
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115
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:
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/s/ PAUL D. CHING
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Chief Executive Officer
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(Principal Executive Officer)
President Director and Chairman of the Board
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Date: April 15, 2010
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/ PAUL D. CHING
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Chief Executive Officer
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April 15, 2010
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Paul D. Ching
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(Principal Executive Officer)
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President Director and
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Chairman of the Board
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BY:
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/s/ LLOYD V. DELANO
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Senior Vice President
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April 15, 2010
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Lloyd V. DeLano
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(Chief Accounting Officer)
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BY:
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/s/ E. L. HENRY
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Director
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April 15, 2010
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E. L. Henry
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BY:
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/s/ MICHAEL J. MAYELL
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Director
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April 15, 2010
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Michael J. Mayell
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BY:
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/s/ C. MARK PEARSON
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Director
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April 15, 2010
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C. Mark Pearson
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BY:
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/s/ JOSEPH A. REEVES, JR.
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Director
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April 15, 2010
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Joseph A. Reeves, Jr.
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BY:
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/s/ JOHN B. SIMMONS
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Director
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April 15, 2010
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John B. Simmons
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BY:
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/s/ FENNER R. WELLER, JR.
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Director
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April 15, 2010
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Fenner R. Weller, Jr.
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116
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