e424b3
Filed
Pursuant to Rule 424(b)(3)
Registration No. 333-173751
ALTA MESA HOLDINGS,
LP
ALTA MESA FINANCE SERVICES
CORP.
Offer to Exchange
Up To $300,000,000 of
95/8% Senior
Notes due 2018
That Have Not Been Registered Under
The Securities Act of 1933
For
Up To $300,000,000 of
95/8% Senior
Notes due 2018
That Have Been Registered Under
The Securities Act of 1933
Terms of the New
95/8% Senior
Notes due 2018 Offered in the Exchange Offer:
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The terms of the new notes are identical to the terms of the old
notes that were issued on October 13, 2010, except that the
new notes will be registered under the Securities Act of 1933
and will not contain restrictions on transfer, registration
rights or provisions for additional interest.
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Terms of the Exchange Offer:
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We are offering to exchange up to $300,000,000 of our old notes
for new notes with materially identical terms that have been
registered under the Securities Act of 1933 and are freely
tradable.
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We will exchange all old notes that you validly tender and do
not validly withdraw before the exchange offer expires for an
equal principal amount of new notes.
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The exchange offer expires at 5:00 p.m., New York City
time, on August 11, 2011, unless extended.
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Tenders of old notes may be withdrawn at any time prior to the
expiration of the exchange offer.
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The exchange of new notes for old notes will not be a taxable
event for U.S. federal income tax purposes.
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Broker-dealers who receive new notes pursuant to the exchange
offer acknowledge that they will deliver a prospectus in
connection with any resale of such new notes.
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Broker-dealers who acquired the old notes as a result of
market-making or other trading activities may use the prospectus
for the exchange offer, as supplemented or amended, in
connection with resales of the new notes.
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There is no established trading market for the new notes or the
old notes.
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We do not intend to apply for listing of the new notes on any
national securities exchange or for quotation through any
quotation system.
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See Risk Factors beginning on page 12 for a
discussion of certain risks that you should consider before
participating in the exchange offer.
Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these
securities or determined if this prospectus is truthful or
complete. Any representation to the contrary is a criminal
offense.
The date of this prospectus is July 14, 2011
This prospectus is part of a registration statement we filed
with the Securities and Exchange Commission. In making your
investment decision, you should rely only on the information
contained in this prospectus and in the accompanying letter of
transmittal. We have not authorized anyone to provide you with
any other information. We are not making an offer to sell these
securities or soliciting an offer to buy these securities in any
jurisdiction where an offer or solicitation is not authorized or
in which the person making that offer or solicitation is not
qualified to do so or to anyone whom it is unlawful to make an
offer or solicitation. You should not assume that the
information contained in this prospectus is accurate as of any
date other than its date.
TABLE OF
CONTENTS
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F-1
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In this prospectus we refer to the notes to be issued in the
exchange offer as the new notes, new
Notes, or Exchange Notes, and we refer to the
$300 million principal amount of our
95/8% senior
notes due 2018 issued on October 13, 2010 as the old
notes or old Notes. We refer to the new notes
and the old notes collectively as the notes.
This prospectus incorporates important business and financial
information about us that is not included or delivered with this
prospectus. Such information is available without charge to
holders of old notes upon written or oral request made to Alta
Mesa Holdings, LP, 15415 Katy Freeway, Suite 800, Houston,
Texas, 77094, Attention: Chief Financial Officer (Telephone
(281) 530-0991).
To obtain timely delivery of any requested information, holders
of old notes must make any request no later than five business
days prior to the expiration of the exchange offer.
i
CAUTIONARY
STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
The information in this prospectus includes
forward-looking statements. All statements, other
than statements of historical fact included in this prospectus,
regarding our strategy, future operations, financial position,
estimated revenues and losses, projected costs, prospects, plans
and objectives of management are forward-looking statements.
When used in this prospectus, the words could,
should, will, play,
believe, anticipate, intend,
estimate, expect, project
and similar expressions are intended to identify forward-looking
statements, although not all forward-looking statements contain
such identifying words. These forward-looking statements are
based on our current expectations and assumptions about future
events and are based on currently available information as to
the outcome and timing of future events. When considering
forward-looking statements, you should keep in mind the risk
factors and other cautionary statements described under the
heading Risk Factors included in this prospectus.
These forward-looking statements are based on managements
current belief, based on currently available information, as to
the outcome and timing of future events.
Forward-looking statements may include statements about our:
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business strategy;
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reserves;
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financial strategy, liquidity and capital required for our
development program;
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realized oil and natural gas prices;
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timing and amount of future production of oil and natural gas;
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hedging strategy and results;
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future drilling plans;
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competition and government regulations;
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marketing of oil and natural gas;
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leasehold or business acquisitions;
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costs of developing our properties;
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general economic conditions;
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credit markets;
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liquidity and access to capital;
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uncertainty regarding our future operating results; and
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plans, objectives, expectations and intentions contained in this
prospectus that are not historical.
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We caution you that these forward-looking statements are subject
to all of the risks and uncertainties, most of which are
difficult to predict and many of which are beyond our control,
incident to the exploration for and development and production
of oil and natural gas. These risks include, but are not limited
to, commodity price volatility, inflation, lack of availability
of drilling and production equipment and services, environmental
risks, drilling and other operating risks, regulatory changes,
the uncertainty inherent in estimating oil and natural gas
reserves and in projecting future rates of production, cash flow
and access to capital, the timing of development expenditures,
and the other risks described under Risk Factors in
this prospectus.
Reserve engineering is a process of estimating underground
accumulations of oil and natural gas that cannot be measured in
an exact way. The accuracy of any reserve estimate depends on
the quality of available data, the interpretation of such data
and price and cost assumptions made by reservoir engineers. In
addition, the results of drilling, testing and production
activities may justify revisions of estimates that were made
previously. If significant, such revisions would change the
schedule of any further production and development drilling.
Accordingly, reserve estimates may differ significantly from the
quantities of oil and natural gas that are ultimately recovered.
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Should one or more of the risks or uncertainties described in
this prospectus occur, or should underlying assumptions prove
incorrect, our actual results and plans could differ materially
from those expressed in any forward-looking statements.
All forward-looking statements, expressed or implied, included
in this prospectus are expressly qualified in their entirety by
this cautionary statement. This cautionary statement should also
be considered in connection with any subsequent written or oral
forward-looking statements that we or persons acting on our
behalf may issue.
Except as otherwise required by applicable law, we disclaim any
duty to update any forward-looking statements, all of which are
expressly qualified by the statements in this section, to
reflect events or circumstances after the date of this
prospectus.
iii
PROSPECTUS
SUMMARY
This summary highlights certain information concerning our
business and this prospectus. Because this is a summary, it may
not contain all of the information that may be important to you
and to your investment decision. The following summary is
qualified in its entirety by the more detailed information and
financial statements and notes thereto included elsewhere in
this prospectus. You should read this prospectus carefully and
should consider, among other things, the matters set forth in
Risk Factors and the other cautionary statements
described in this prospectus.
In this prospectus, unless indicated otherwise, references to
Alta Mesa refer to Alta Mesa Holdings, LP.
References to the Company, our company,
we, our and us refer to Alta
Mesa and its subsidiaries and include the acquisition of
Meridian, which occurred on May 13, 2010. References to
Meridian are references to The Meridian Resource
Corporation and its subsidiaries prior to the acquisition.
References to Alta Mesa GP are references to Alta
Mesa Holdings GP, LLC, our general partner.
The estimates of our actual and pro forma proved reserves as
of December 31, 2010 included in this prospectus are based
on reserve reports prepared for us by T.J. Smith &
Company, Inc., independent petroleum engineers (T.J.
Smith), and W.D. Von Gonten & Co., independent
petroleum engineers (Von Gonten), and audited by
Netherland, Sewell & Associates, Inc., independent
petroleum engineers (Netherland Sewell). A copy of
the summary reports of T.J. Smith and Von Gonten and the audit
report of Netherland Sewell are filed as Exhibits 99.2,
99.3 and 99.4 to the registration statement, of which this
prospectus forms a part.
For the definitions of certain terms and abbreviations used
in the oil and natural gas industry, see Glossary of Oil
and Natural Gas Terms. Pro forma information contained
herein gives effect to the Meridian, Sydson, and TODD
acquisitions as if they had occurred on January 1, 2010.
See Recent Developments.
Our
Company
We are a privately held company primarily engaged in onshore oil
and natural gas acquisition, exploitation, exploration and
production whose focus is to maximize the profitability of our
assets in a safe and environmentally sound manner. We seek to
maintain a portfolio of lower risk properties in plays where we
identify a large inventory of drilling, development, and
enhanced recovery and exploitation opportunities in known
resources. We believe our balanced portfolio of
assets principally historically prolific fields in
South Louisiana, conventional liquids-rich gas and oil fields of
East Texas, shallow long-lived oil fields in Oklahoma, and
resource plays in the Deep Bossier of East Texas and Eagle Ford
Shale in South Texas has decades of future
development potential. We maximize the profitability of our
assets by focusing on advanced engineering analytics, enhanced
geological techniques including
3-D seismic
analysis, and proven drilling, stimulation, completion, and
production methods.
From December 2008 through December 2010, we increased
production at an annualized compounded rate of approximately 80%
through a focused program of drilling and field re-development
and strategic acquisitions. As of December 31, 2010, our
estimated total proved oil and natural gas reserves were
approximately 325 Bcfe, of which 66% were classified as
proved developed. Our proved reserve mix is approximately 74%
natural gas, 23% oil and 3% natural gas liquids with a pro forma
reserve life index of 9.3 years for the year ended
December 31, 2010. Excluding the Deep Bossier resource
play, which includes approximately 16% of the
PV-10 value
of our proved reserves and where EnCana Oil & Gas
(USA), Inc. (EnCana) is the principal operator, we
maintain operational control of approximately 83% of the
PV-10 value
of our proved reserves. Of this, we operate 68% directly and the
remainder is structured under operating arrangements with
minority interest holders where we contribute significantly to
the development of the assets through use of our internal
engineering and geologist staffs and we have the ability to
control the drilling schedule and remove the operator.
Our areas of focus are typically characterized by multiple
hydrocarbon pay zones, and because we are re-developing fields
and areas left behind by major oil and natural gas companies and
other previous operators,
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our assets are typically served by existing infrastructure. As a
result, our approach lowers geological, mechanical, and
market-related risks. We focus on properties within our core
operating areas that we believe have significant development and
exploration opportunities and where we can apply our technical
experience and economies of scale to increase production and
proved reserves while lowering lease operating and capital
costs. Additionally, we have consistently created value through
workovers and re-completions of existing wells, infill drilling,
operations improvements, secondary recovery and
3-D
seismic-driven drilling. We expect to continue production growth
in our core areas by exploiting known resources with continued
well workovers, development drilling and enhanced recovery
programs, and disciplined exploration.
Recent
Developments
Sydson
Acquisition
On April 21, 2011, we completed the purchase of certain oil
and natural gas assets primarily located in Texas and South
Louisiana in which we had shared interests from Sydson Energy
and certain of its related parties for $27.5 million. Total
net proved reserves acquired are estimated to be 800 MBOE
(5 Bcfe), 45% of which is oil. By virtue of this
acquisition, we increased our after payout net revenue interest
in the Eagle Ford Shale by over 50%. Funding for the acquisition
was provided through our credit facility. In addition,
litigation associated with a portion of the assets purchased was
resolved as a result of the transaction.
TODD
Acquisition
On June 17, 2011, we completed the purchase of certain oil
and natural gas assets primarily located in Texas and South
Louisiana in which we had shared interests from Texas Oil
Distribution & Development, Inc. and Matrix Petroleum LLC
(together, TODD) and certain other parties for
$22.5 million. Total net proved reserves acquired are
estimated to be 700 MBOE (4 Bcfe), 36% of which is
oil. By virtue of this acquisition, we increased our after
payout net revenue interest in the Eagle Ford Shale by another
15%. Funding for the acquisition was provided through our credit
facility. In addition, litigation associated with TODD was
resolved as a result of the transaction.
Amendment
to Senior Secured Revolving Credit Facility
On May 23, 2011, we amended our $500 million senior
secured revolving credit facility to, among other things,
increase the borrowing base limit and reduce applicable interest
rates provided thereunder, extend the maturity date, and
increase the amount of senior debt securities that we are
permitted to issue. The amended credit facility is currently
subject to a $260 million borrowing base limit with Wells
Fargo Bank, N.A. as the administrative agent.
Corporate
Partner and Structure
We began operations in 1987, and have funded development and
operating activities primarily through cash from operations,
capital raised from equity contributed by our founder, capital
contributed by a private equity partner, borrowings under our
bank credit facilities, and proceeds from the issuance in
October 2010 of $300 million principal amount of our senior
secured notes due October 15, 2018. Our private equity
partner, Alta Mesa Investment Holdings Inc. (AMIH),
is an affiliate of Denham Commodity Partners Fund IV LP
(DCPF IV). DCPF IV is advised by Denham Capital
Management LP, a private equity firm focused on energy and
commodities. Since investing in us as a limited partner in 2006,
AMIH has contributed $150 million in equity, which includes
a $50 million contribution as part of the Meridian
acquisition. In October 2010, AMIH received a $50 million
distribution from the proceeds of the offer and sale of the old
notes.
As a limited partnership, our operations and activities are
managed by the board of directors of our general partner, Alta
Mesa Holdings GP, LLC, and the officers of Alta Mesa Services,
LP (Alta Mesa Services), an entity wholly owned by
us. The sole member of Alta Mesa GP is Alta Mesa Resources, LP,
an entity owned by Michael E. Ellis, the founder of our company,
Chief Operating Officer, and Chairman of the Board of Directors
of Alta Mesa GP, and his spouse, Mickey Ellis.
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General
Corporate Information
Alta Mesa Holdings, LP is a Texas limited partnership founded in
1987 with principal offices at 15415 Katy Freeway,
Suite 800, Houston, Texas 77094. We can be reached at
(281) 530-0991
and our website address is www.altamesa.net. Information on the
website is not part of this prospectus. Alta Mesa Finance
Services Corp. is a Delaware corporation and a wholly owned
subsidiary of Alta Mesa that has no material assets and was
formed for the purpose of co-issuing the notes.
3
EXCHANGE
OFFER
On October 13, 2010, we completed a private offering of
$300 million principal amount of the old notes. We entered
into a registration rights agreement with the initial purchasers
in connection with the offering in which we agreed to deliver to
you this prospectus and to use commercially reasonable efforts
to complete an exchange offer of the old notes for new notes
with identical terms, except that the new notes will be
registered under the Securities Act of 1933 (the
Securities Act) and will not have restrictions on
transfer, registration rights or provisions for additional
interest, within 360 days after the date of the issuance of
the old notes.
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Exchange Offer |
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We are offering to exchange new notes for old notes. |
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Expiration Date |
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The exchange offer will expire at 5:00 p.m., New York City
time, on August 11, 2011, unless we decide to extend it. |
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Condition to the Exchange Offer |
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The registration rights agreement does not require us to accept
old notes for exchange if the exchange offer, or the making of
any exchange by a holder of the old notes, would violate any
applicable law or interpretation of the staff of the Securities
and Exchange Commission. The exchange offer is not conditioned
on a minimum aggregate principal amount of old notes being
tendered. |
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Procedures for Tendering Old Notes |
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To participate in the exchange offer, you must follow the
procedures established by The Depository Trust Company,
which we call DTC, for tendering notes held in
book-entry form. These procedures, which we call
ATOP, require that (i) the exchange agent
receive, prior to 5:00 p.m., New York City time, on the
expiration date of the exchange offer, a computer generated
message known as an agents message that is
transmitted through DTCs automated tender offer program,
and (ii) DTC confirms that: |
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DTC has received your instructions to exchange your
notes, and
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you agree to be bound by the terms of the letter of
transmittal.
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For more information on tendering your old notes, please refer
to the section in this prospectus entitled Exchange
Offer Terms of the Exchange Offer,
Procedures for Tendering, and
Description of New Notes Book-Entry; Delivery
and Form. |
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Guaranteed Delivery Procedures |
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None. |
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Withdrawal of Tenders |
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You may withdraw your tender of old notes at any time prior to
the expiration date. To withdraw, you must submit a notice of
withdrawal to the exchange agent using ATOP procedures before
5:00 p.m., New York City time, on the expiration date of
the exchange offer. Please refer to the section in this
prospectus entitled Exchange Offer Withdrawal
of Tenders. |
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Acceptance of Old Notes and Delivery of New Notes |
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If you fulfill all conditions required for proper acceptance of
old notes, we will accept any and all old notes that you
properly tender in the exchange offer before 5:00 p.m., New
York City time on the expiration date. We will return any old
notes that are late or not properly tendered, and therefore,
that we do not accept for exchange to you without expense
promptly after the expiration date and acceptance of the old
notes for exchange. Please refer to the section in this
prospectus entitled Exchange Offer Terms of
the Exchange Offer. |
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Fees and Expenses |
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We will bear expenses related to the exchange offer. Please
refer to the section in this prospectus entitled Exchange
Offer Fees and Expenses. |
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Use of Proceeds |
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The issuance of the new notes will not provide us with any new
proceeds. We are making this exchange offer solely to satisfy
our obligations under the registration rights agreement. |
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Consequences of Failure to Exchange Old Notes |
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If you do not exchange your old notes in this exchange offer,
you will no longer be able to require us to register the old
notes under the Securities Act except in limited circumstances
provided under the registration rights agreement. In addition,
you will not be able to resell, offer to resell or otherwise
transfer the old notes unless we have registered the old notes
under the Securities Act, or unless you resell, offer to resell
or otherwise transfer them under an exemption from the
registration requirements of, or in a transaction not subject
to, the Securities Act. |
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U.S. Federal Income Tax Consequences |
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The exchange of new notes for old notes in the exchange offer
will not be a taxable event for U.S. federal income tax
purposes. Please read Certain United States Federal Income
Tax Consequences. |
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Exchange Agent |
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We have appointed Wells Fargo Bank, N.A. as exchange agent for
the exchange offer. You should direct questions and requests for
assistance, requests for additional copies of this prospectus or
the letter of transmittal to the exchange agent as follows: |
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By registered & certified mail: |
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Wells Fargo Bank, N.A.
Corporate Trust Operations
MAC N9303-121
PO Box 1517 Minneapolis, Minnesota 55480 |
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By regular mail or overnight courier: |
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Wells Fargo Bank, N.A.
Corporate Trust Operations
MAC N9303-121
Sixth & Marquette Avenue
Minneapolis, Minnesota 55479 |
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In person by hand only: |
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Wells Fargo Bank, N.A.
12th Floor Northstar East Building
Corporate Trust Operations
608 Second Avenue South
Minneapolis, Minnesota 55480 |
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Eligible institutions may make requests by facsimile at
(612) 667-6282
and may confirm facsimile delivery by calling
(800) 344-5128 |
See Exchange Offer for more detailed information
concerning the terms of the exchange offer.
5
TERMS OF
THE NEW NOTES
The new notes will be identical to the old notes except that
the new notes will be registered under the Securities Act and
will not have restrictions on transfer or provisions for
additional interest. The new notes will evidence the same debt
as the old notes, and the same indenture will govern the new
notes and the old notes.
The following summary contains basic information about the
new notes and is not intended to be complete. For a more
complete understanding of the new notes, please refer to the
section entitled Description of New Notes in this
prospectus.
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Issuers |
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Alta Mesa Holdings, LP and Alta Mesa Finance Services Corp. Alta
Mesa Finance Services Corp. is our wholly owned direct
subsidiary incorporated in Delaware for the purpose of serving
as a co-issuer of the notes. Alta Mesa Finance Services Corp.
has no material assets and does not conduct any operations. |
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Securities Offered |
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$300,000,000 aggregate principal amount of
95/8% senior
notes due 2018. |
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Maturity Date |
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October 15, 2018. |
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Interest |
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Interest on the notes will accrue at the rate of
95/8%
per annum. |
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Interest Payment Dates |
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April 15 and October 15 of each year, beginning October 15,
2011. Interest on each new note will accrue from the last
interest payment date on which interest was paid on the old note
tendered in exchange thereof, or, if no interest has been paid
on the old note, from the date of the original issue of the old
note. |
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Guarantees |
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The notes will be guaranteed initially by all of our
subsidiaries, other than certain immaterial subsidiaries, and
will be guaranteed by our future domestic restricted
subsidiaries, other than certain immaterial subsidiaries. Our
current subsidiaries that will not guarantee the notes
represented in the aggregate less than 1% of each of our
consolidated total assets and consolidated pro forma revenues as
of and for the year ended December 31, 2010. |
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Ranking |
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The new notes and the related guarantees will be the unsecured
senior obligations of us, Alta Mesa Finance Services Corp. and
the guarantors. Accordingly, they will rank: |
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equal in right of payment with our existing and
future senior indebtedness, including our senior secured
revolving credit facility;
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senior in right of payment to all of our existing
and future indebtedness that is expressly subordinated to the
notes or the respective guarantees, including certain notes
payable to our founder, Michael E. Ellis;
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effectively subordinated to all of our existing and
future secured indebtedness to the extent of the value of the
collateral securing such indebtedness, including amounts
outstanding under our senior secured revolving credit facility;
and
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structurally subordinated to all existing and future
indebtedness and obligations of any of our subsidiaries that do
not guarantee the notes.
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As of March 31, 2011, we had $405.3 million of debt
outstanding, $87.3 million of which was secured
indebtedness and our non-guarantor subsidiaries had no
indebtedness outstanding except that |
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certain non-guarantor subsidiaries have guaranteed obligations
under our senior secured revolving credit facility. |
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Optional Redemption |
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Beginning on October 15, 2014, we may redeem some or all of
the new notes at the redemption prices listed under
Description of New Notes Optional
Redemption plus accrued and unpaid interest on the new
notes to the date of redemption. |
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At any time prior to October 15, 2013 we may redeem up to
35% of the aggregate principal amount of the new notes from the
proceeds of certain sales of our equity securities at 109.625%
of the principal amount, plus accrued and unpaid interest, if
any, to the date of redemption. We may make that redemption only
if, after the redemption, at least 65% of the aggregate
principal amount of the new notes remains outstanding and the
redemption occurs within 120 days of the closing of the
equity offering. |
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Before October 15, 2014, we may redeem some or all of the
new notes at the make-whole redemption price set
forth under Description of New Notes Optional
Redemption plus accrued and unpaid interest on the new
notes to the date of redemption. |
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Change of Control |
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Upon the occurrence of a change of control (as described under
Description of New Notes Change of
Control), we must offer to repurchase the new notes at
101% of their principal amount, plus accrued and unpaid interest
to the date of repurchase. |
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Covenants |
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The indenture governing the new notes contains certain covenants
limiting our ability and the ability of our restricted
subsidiaries to, under certain circumstances: |
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prepay subordinated indebtedness, pay distributions,
redeem stock or make certain restricted investments;
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incur indebtedness;
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create liens on our assets to secure debt;
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restrict dividends, distributions or other payments
from subsidiaries to us;
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enter into transactions with affiliates;
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designate subsidiaries as unrestricted subsidiaries;
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sell or otherwise transfer or dispose of assets,
including equity interests of restricted subsidiaries;
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effect a consolidation or merger; and
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change our line of business.
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These covenants are subject to important exceptions and
qualifications as described in this prospectus under the caption
Description of New Notes Certain
Covenants. |
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Transfer Restrictions; Absence of a Public Market for the New
Notes |
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The new notes generally will be freely transferable, but will
also be new securities for which there will not initially be a
market. There can be no assurance as to the development or
liquidity of any market for the new notes. We do not intend to
apply for a listing of the new notes on any securities exchange
or any automated dealer quotation system. |
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Risk Factors |
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Investing in the new notes involves risks. See Risk
Factors beginning on page 12 for a discussion of
certain factors you should consider in evaluating whether or not
to tender your old notes. |
7
Summary
Historical and Pro Forma Financial Data
The following table presents our summary consolidated historical
financial data giving effect to the Meridian acquisition from
the acquisition date of May 13, 2010, and summary pro forma
financial information for the Meridian, Sydson, and TODD
acquisitions for the year ended December 31, 2010 and for
the Sydson and TODD acquisitions for the three months ended
March 31, 2011. The summary historical financial data as of
December 31, 2010, 2009 and 2008 and for the years ended
December 31, 2010, 2009 and 2008 are derived from our
historical consolidated financial statements and are included
elsewhere in this prospectus. The historical financial data as
of March 31, 2011 and for the three months ended
March 31, 2011 and 2010 are derived from our unaudited
consolidated statements of operations included elsewhere in this
prospectus. The summary pro forma financial data for the year
ended December 31, 2010 and for the three months ended
March 31, 2011 has been derived from the unaudited pro
forma condensed consolidated financial statements included
elsewhere in this prospectus and gives effect to the Meridian,
Sydson, and TODD acquisitions as if they had occurred on
January 1, 2010. The unaudited pro forma financial
information, while helpful in illustrating the financial
characteristics of the consolidated company under one set of
assumptions, does not reflect the impact of possible revenue
enhancements, expense efficiencies and asset dispositions, among
other factors, that may result as a consequence of the merger
and, accordingly, does not attempt to predict or suggest future
results. It also does not necessarily reflect what the
historical results of the consolidated company would have been
had the companies been consolidated during these periods.
For further information that will help you better understand the
summary financial data, you should read this financial data in
conjunction with the Selected Historical Financial and
Other Data, and Managements Discussion and
Analysis of Financial Condition and Results of Operations
sections included elsewhere in this prospectus and the financial
statements and related notes and other financial information
included elsewhere in this prospectus. Our historical results of
operations are not necessarily indicative of results to be
expected for any future periods.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Year Ended
|
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended March 31,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
Year Ended December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
(Dollars in thousands)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, oil and natural gas liquids
|
|
$
|
72,733
|
|
|
$
|
246,376
|
|
|
$
|
70,631
|
|
|
$
|
38,065
|
|
|
$
|
208,537
|
|
|
$
|
102,263
|
|
|
$
|
98,983
|
|
Other revenue
|
|
|
469
|
|
|
|
1,544
|
|
|
|
469
|
|
|
|
21
|
|
|
|
1,475
|
|
|
|
1,558
|
|
|
|
3,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73,202
|
|
|
|
247,920
|
|
|
|
71,100
|
|
|
|
38,086
|
|
|
|
210,012
|
|
|
|
103,821
|
|
|
|
102,612
|
|
Unrealized gain (loss) oil and natural gas
derivative contracts
|
|
|
(19,184
|
)
|
|
|
10,088
|
|
|
|
(19,184
|
)
|
|
|
20,803
|
|
|
|
10,088
|
|
|
|
(26,258
|
)
|
|
|
60,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
54,018
|
|
|
|
258,008
|
|
|
|
51,916
|
|
|
|
58,889
|
|
|
|
220,100
|
|
|
|
77,563
|
|
|
|
163,224
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease and plant operating expense
|
|
|
13,711
|
|
|
|
47,651
|
|
|
|
13,331
|
|
|
|
8,078
|
|
|
|
41,905
|
|
|
|
23,871
|
|
|
|
20,658
|
|
Production and ad valorem taxes
|
|
|
5,401
|
|
|
|
13,661
|
|
|
|
5,401
|
|
|
|
1,613
|
|
|
|
11,141
|
|
|
|
4,755
|
|
|
|
6,954
|
|
Workover expense
|
|
|
1,626
|
|
|
|
7,561
|
|
|
|
1,626
|
|
|
|
1,959
|
|
|
|
7,409
|
|
|
|
8,988
|
|
|
|
8,113
|
|
Exploration expense
|
|
|
2,731
|
|
|
|
32,878
|
|
|
|
2,731
|
|
|
|
2,921
|
|
|
|
31,037
|
|
|
|
12,839
|
|
|
|
11,675
|
|
Depreciation, depletion, and amortization
|
|
|
19,652
|
|
|
|
71,176
|
|
|
|
19,468
|
|
|
|
8,622
|
|
|
|
59,090
|
|
|
|
48,659
|
|
|
|
49,219
|
|
Impairment expense
|
|
|
5,826
|
|
|
|
8,399
|
|
|
|
5,826
|
|
|
|
1,450
|
|
|
|
8,399
|
|
|
|
6,165
|
|
|
|
11,487
|
|
Accretion expense
|
|
|
470
|
|
|
|
2,168
|
|
|
|
470
|
|
|
|
145
|
|
|
|
1,370
|
|
|
|
492
|
|
|
|
729
|
|
Rig operations
|
|
|
|
|
|
|
2,088
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expense
|
|
|
5,751
|
|
|
|
26,431
|
|
|
|
5,751
|
|
|
|
2,223
|
|
|
|
20,135
|
|
|
|
8,738
|
|
|
|
6,401
|
|
Gain on sale of assets
|
|
|
|
|
|
|
(1,766
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,766
|
)
|
|
|
(738
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
55,168
|
|
|
|
210,247
|
|
|
|
54,604
|
|
|
|
27,011
|
|
|
|
178,720
|
|
|
|
113,769
|
|
|
|
115,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Year Ended
|
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended March 31,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
Year Ended December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
(Dollars in thousands)
|
|
|
Income (loss) from operations
|
|
|
(1,150
|
)
|
|
|
47,761
|
|
|
|
(2,688
|
)
|
|
|
31,878
|
|
|
|
41,380
|
|
|
|
(36,206
|
)
|
|
|
47,988
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(9,837
|
)
|
|
|
(30,066
|
)
|
|
|
(9,478
|
)
|
|
|
(4,199
|
)
|
|
|
(27,149
|
)
|
|
|
(13,831
|
)
|
|
|
(14,457
|
)
|
Gain on extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,349
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense)
|
|
|
(9,837
|
)
|
|
|
(30,066
|
)
|
|
|
(9,478
|
)
|
|
|
(4,199
|
)
|
|
|
(27,149
|
)
|
|
|
(13,831
|
)
|
|
|
(11,108
|
)
|
Benefit from (provision for) state income taxes
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
750
|
|
|
|
(250
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(10,987
|
)
|
|
$
|
17,693
|
|
|
$
|
(12,166
|
)
|
|
$
|
27,679
|
|
|
$
|
14,229
|
|
|
$
|
(49,287
|
)
|
|
$
|
36,630
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Supplementary Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX(1)
|
|
$
|
46,713
|
|
|
$
|
152,294
|
|
|
$
|
44,993
|
|
|
$
|
24,213
|
|
|
$
|
131,211
|
|
|
$
|
58,211
|
|
|
$
|
63,875
|
|
Ratio of senior debt to Adjusted EBITDAX(1)(2)
|
|
|
2.33
|
|
|
|
2.44
|
|
|
|
2.14
|
|
|
|
2.24
|
|
|
|
2.83
|
|
|
|
3.46
|
|
|
|
2.68
|
|
|
|
|
(1) |
|
Adjusted EBITDAX is a non-GAAP financial measure. See
Reconciliation of Non-GAAP Financial Measure
below. |
|
|
|
(2) |
|
Senior debt includes all of our debt other than the founder
notes. The founder notes are fully subordinated to the notes and
our senior secured revolving credit facility. See
Description of Certain Indebtedness. For all three
month periods, Adjusted EBITDAX is annualized in calculating the
ratio of senior debt to Adjusted EBITDAX. For the pro forma
three month period ended March 31, 2011, the ratio is
calculated using pro forma senior debt. See the unaudited pro
forma condensed consolidated financial statements and related
notes included elsewhere in this prospectus. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
March 31,
|
|
|
Year Ended December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
(Dollars in thousands)
|
|
|
Statement of Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
58,951
|
|
|
$
|
13,226
|
|
|
$
|
110,083
|
|
|
$
|
100,261
|
|
|
$
|
111,096
|
|
Net cash flow provided by operating activities
|
|
|
45,642
|
|
|
|
(1,351
|
)
|
|
|
61,120
|
|
|
|
34,343
|
|
|
|
20,300
|
|
Net cash used in investing activities(1)
|
|
|
(58,951
|
)
|
|
|
(13,226
|
)
|
|
|
(208,412
|
)
|
|
|
(86,573
|
)
|
|
|
(111,096
|
)
|
Net cash provided by financing activities
|
|
|
14,000
|
|
|
|
14,975
|
|
|
|
147,854
|
|
|
|
51,823
|
|
|
|
78,771
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalent
|
|
$
|
5,527
|
|
|
$
|
4,672
|
|
|
$
|
4,836
|
|
|
$
|
4,274
|
|
|
$
|
4,681
|
|
Property and equipment, net
|
|
|
469,314
|
|
|
|
243,493
|
|
|
|
456,264
|
|
|
|
236,196
|
|
|
|
201,327
|
|
Total assets
|
|
|
549,912
|
|
|
|
322,142
|
|
|
|
558,239
|
|
|
|
290,606
|
|
|
|
277,111
|
|
Senior debt(2)
|
|
|
385,341
|
|
|
|
216,500
|
|
|
|
371,276
|
|
|
|
201,500
|
|
|
|
171,089
|
|
Total debt
|
|
|
405,348
|
|
|
|
235,123
|
|
|
|
390,985
|
|
|
|
219,830
|
|
|
|
188,228
|
|
Total partners equity (deficit)
|
|
|
12,492
|
|
|
|
38,318
|
|
|
|
24,658
|
|
|
|
10,664
|
|
|
|
37,751
|
|
|
|
|
(1) |
|
Net cash used in investing activities includes
$101.4 million for the acquisition of Meridian in the year
ended December 31, 2010. |
|
|
|
(2) |
|
Senior debt includes all of our debt other than the founder
notes. The founder notes are fully subordinated to the notes and
our senior secured revolving credit facility. See
Description of Certain Indebtedness. The old notes
are carried on our balance sheet net of a discount of
$1.9 million and $2.0 million at March 31, 2011
and December 31, 2010, respectively. |
9
Reconciliation
of Non-GAAP Financial Measure
Adjusted EBITDAX is non-GAAP financial measure and as used
herein represents net income before interest expense,
exploration expense, depletion, depreciation and amortization,
impairment of oil and natural gas properties, accretion of asset
retirement obligations, deferred tax expense, and unrealized
gain/loss on oil and natural gas derivative contracts. We
present Adjusted EBITDAX because we believe it is an important
supplemental measure of our performance that is frequently used
by others in evaluating companies in our industry. Adjusted
EBITDAX is not a measurement of our financial performance under
GAAP and should not be considered as an alternative to net
income, operating income or any other performance measure
derived in accordance with GAAP or as an alternative to net cash
provided by operating activities as a measure of our
profitability or liquidity. Adjusted EBITDAX has significant
limitations, including that it does not reflect our cash
requirements for capital expenditures, contractual commitments,
working capital or debt service. In addition, other companies
may calculate Adjusted EBITDAX differently than we do, limiting
their usefulness as comparative measures.
The following table sets forth a reconciliation of net income
(loss) as determined in accordance with GAAP to Adjusted EBITDAX
for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Year Ended
|
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended March 31,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
Year Ended December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
(Dollars in thousands)
|
|
|
Net income (loss)
|
|
$
|
(10,987
|
)
|
|
$
|
17,693
|
|
|
$
|
(12,166
|
)
|
|
$
|
27,679
|
|
|
$
|
14,229
|
|
|
$
|
(49,287
|
)
|
|
$
|
36,630
|
|
Interest expense
|
|
|
9,837
|
|
|
|
30,066
|
|
|
|
9,480
|
|
|
|
4,199
|
|
|
|
27,172
|
|
|
|
13,835
|
|
|
|
14,497
|
|
Exploration expense
|
|
|
2,731
|
|
|
|
32,878
|
|
|
|
2,731
|
|
|
|
2,921
|
|
|
|
31,037
|
|
|
|
12,839
|
|
|
|
11,675
|
|
Depreciation, depletion and amortization
|
|
|
19,652
|
|
|
|
71,176
|
|
|
|
19,468
|
|
|
|
8,622
|
|
|
|
59,090
|
|
|
|
48,659
|
|
|
|
49,219
|
|
Impairment of oil and natural gas properties
|
|
|
5,826
|
|
|
|
8,399
|
|
|
|
5,826
|
|
|
|
1,450
|
|
|
|
8,399
|
|
|
|
6,165
|
|
|
|
11,487
|
|
Accretion of asset retirement obligations
|
|
|
470
|
|
|
|
2,168
|
|
|
|
470
|
|
|
|
145
|
|
|
|
1,370
|
|
|
|
492
|
|
|
|
729
|
|
Deferred tax (benefit) expense
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
(750
|
)
|
|
|
250
|
|
Unrealized (gain) loss on oil and natural gas derivative
contracts
|
|
|
19,184
|
|
|
|
(10,088
|
)
|
|
|
19,184
|
|
|
|
(20,803
|
)
|
|
|
(10,088
|
)
|
|
|
26,258
|
|
|
|
(60,612
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
|
|
$
|
46,713
|
|
|
$
|
152,294
|
|
|
$
|
44,993
|
|
|
$
|
24,213
|
|
|
$
|
131,211
|
|
|
$
|
58,211
|
|
|
$
|
63,875
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
Reserves and Operating Data
Proved
Reserves
The table below summarizes our estimated proved reserves as of
December 31, 2010.
|
|
|
|
|
Estimated Proved Reserves(1):
|
|
|
|
|
Natural gas (Bcf)
|
|
|
241.4
|
|
Oil (MMBbl)(2)
|
|
|
13.9
|
|
Total proved (Bcfe)
|
|
|
325.0
|
|
Proved developed producing (Bcfe)
|
|
|
119.7
|
|
Proved developed non-producing (Bcfe)
|
|
|
94.6
|
|
Proved undeveloped (Bcfe)
|
|
|
110.8
|
|
Percent natural gas
|
|
|
74.3
|
%
|
Percent proved developed
|
|
|
65.9
|
%
|
PV-10
(dollars in millions)(3)
|
|
$
|
705.2
|
|
|
|
|
(1) |
|
Our proved reserves as of December 31, 2010 were calculated
using oil and natural gas price parameters established by
current Securities and Exchange Commission (SEC)
guidelines and accounting rules |
10
|
|
|
|
|
based on average prices as of the first day of each of the
12 months ended on such date. These average prices were
$79.43 per Bbl for oil and $4.38 per MMBtu for natural gas.
Pricing was adjusted for basis differentials by field based on
our historical realized prices. |
|
(2) |
|
Oil reserves include natural gas liquids. |
|
(3) |
|
PV-10 was
calculated using oil and natural gas price parameters
established by current SEC guidelines and accounting rules based
on average oil and natural gas prices as of the first day of
each of the 12 months ended December 31, 2010. Because
we are a partnership and, as such, are not subject to income
taxes, our
PV-10 is the
same as our standardized measure of future net cash flows, the
most comparable measure under generally accepted accounting
principles, which is reduced for the discounted value of
estimated future income taxes. Calculation of
PV-10 does
not give effect to derivatives transactions. |
Operating
Data
The following table sets forth certain information regarding
production volumes, average prices and average production costs
associated with our sale of oil and natural gas for the periods
indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
Year Ended
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
Ended March 31,
|
|
December 31,
|
|
March 31,
|
|
Year Ended December 31,
|
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
2010
|
|
2009
|
|
2008
|
|
|
(Unaudited)
|
|
(Unaudited)
|
|
|
|
|
|
|
|
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
7,549
|
|
|
|
27,022
|
|
|
|
7,366
|
|
|
|
4,970
|
|
|
|
24,026
|
|
|
|
10,610
|
|
|
|
6,637
|
|
Oil (MBbls)
|
|
|
368
|
|
|
|
1,258
|
|
|
|
348
|
|
|
|
122
|
|
|
|
964
|
|
|
|
505
|
|
|
|
445
|
|
Natural gas liquids (MBbls)
|
|
|
62
|
|
|
|
201
|
|
|
|
58
|
|
|
|
13
|
|
|
|
147
|
|
|
|
47
|
|
|
|
47
|
|
Total (MMcfe)
|
|
|
10,129
|
|
|
|
35,776
|
|
|
|
9,803
|
|
|
|
5,783
|
|
|
|
30,694
|
|
|
|
13,919
|
|
|
|
9,593
|
|
Average sales price per unit before hedging effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
3.98
|
|
|
$
|
4.30
|
|
|
$
|
4.02
|
|
|
$
|
5.04
|
|
|
$
|
4.27
|
|
|
$
|
3.72
|
|
|
$
|
9.33
|
|
Oil (per Bbl)
|
|
|
95.64
|
|
|
|
77.94
|
|
|
|
96.70
|
|
|
|
76.02
|
|
|
|
78.86
|
|
|
|
59.23
|
|
|
|
99.17
|
|
Natural gas liquids (per Bbl)
|
|
|
51.62
|
|
|
|
45.11
|
|
|
|
52.88
|
|
|
|
54.26
|
|
|
|
46.58
|
|
|
|
36.05
|
|
|
|
52.24
|
|
Combined (per Mcfe)
|
|
|
6.76
|
|
|
|
6.24
|
|
|
|
6.77
|
|
|
|
6.07
|
|
|
|
6.05
|
|
|
|
5.10
|
|
|
|
11.31
|
|
Average sales price per unit after hedging effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
4.75
|
|
|
$
|
5.16
|
|
|
$
|
4.80
|
|
|
$
|
5.60
|
|
|
$
|
5.24
|
|
|
$
|
6.25
|
|
|
$
|
8.81
|
|
Oil (per Bbl)
|
|
|
91.60
|
|
|
|
77.76
|
|
|
|
92.44
|
|
|
|
77.97
|
|
|
|
78.63
|
|
|
|
67.94
|
|
|
|
85.45
|
|
Natural gas liquids (per Bbl)
|
|
|
51.62
|
|
|
|
45.11
|
|
|
|
52.88
|
|
|
|
54.26
|
|
|
|
46.58
|
|
|
|
36.05
|
|
|
|
52.24
|
|
Combined (per Mcfe)
|
|
|
7.18
|
|
|
|
6.89
|
|
|
|
7.21
|
|
|
|
6.58
|
|
|
|
6.79
|
|
|
|
7.35
|
|
|
|
10.32
|
|
Average costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease and plant operating expense
|
|
$
|
1.35
|
|
|
$
|
1.33
|
|
|
$
|
1.36
|
|
|
$
|
1.40
|
|
|
$
|
1.37
|
|
|
$
|
1.71
|
|
|
$
|
2.15
|
|
Production and ad-valorem taxes
|
|
|
0.53
|
|
|
|
0.38
|
|
|
|
0.55
|
|
|
|
0.28
|
|
|
|
0.36
|
|
|
|
0.34
|
|
|
|
0.72
|
|
Workover expense
|
|
|
0.16
|
|
|
|
0.21
|
|
|
|
0.17
|
|
|
|
0.34
|
|
|
|
0.24
|
|
|
|
0.65
|
|
|
|
0.85
|
|
Depreciation, depletion and amortization
|
|
|
1.94
|
|
|
|
1.99
|
|
|
|
1.99
|
|
|
|
1.49
|
|
|
|
1.93
|
|
|
|
3.50
|
|
|
|
5.13
|
|
General and administrative expense
|
|
|
0.57
|
|
|
|
0.74
|
|
|
|
0.59
|
|
|
|
0.38
|
|
|
|
0.66
|
|
|
|
0.63
|
|
|
|
0.67
|
|
11
RISK
FACTORS
An investment in the notes involves a significant degree of
risk. You should carefully consider each of the risks described
below, together with all of the other information contained in
this prospectus, before deciding to invest in the new notes and
participate in the exchange offer. If any of the following risks
develop into actual events, our business, financial condition or
results of operations could be materially adversely affected,
which in turn could adversely affect our ability to satisfy our
obligations under the notes and the guarantees of the notes.
Consequently, you may lose all or part of your investment.
Risks
Related to the Exchange Offer and New Notes
If you
do not properly tender your old notes, you will continue to hold
unregistered old notes and your ability to transfer old notes
will remain restricted and may be adversely
affected.
The co-issuers will only issue new notes in exchange for old
notes that you timely and properly tender. Therefore, you should
allow sufficient time to ensure timely delivery of the old notes
and you should carefully follow the instructions on how to
tender your old notes. Neither we nor the exchange agent is
required to tell you of any defects or irregularities with
respect to your tender of old notes.
If you do not exchange your old notes for new notes pursuant to
the exchange offer, the old notes you hold will continue to be
subject to the existing transfer restrictions. In general, you
may not offer or sell the old notes except under an exemption
from, or in a transaction not subject to, the Securities Act and
applicable state securities laws. We do not plan to register old
notes under the Securities Act unless our registration rights
agreement with the initial purchasers of the old notes require
us to do so. Further, if you continue to hold any old notes
after the exchange offer is consummated, you may have trouble
selling them because there will be fewer of the old notes
outstanding.
The
notes and the guarantees are unsecured and effectively
subordinated to the rights of our secured
indebtedness.
The notes and the guarantees are general unsecured senior
obligations ranking effectively junior to all of our, the
co-issuers and the guarantors existing and future
secured indebtedness, including obligations under our senior
secured revolving credit facility, to the extent of the value of
the collateral securing the indebtedness. The notes and the
guarantees are also effectively subordinated to any indebtedness
of any non-guarantor subsidiaries.
If we were unable to repay such indebtedness under our senior
secured revolving credit facility, the lenders under this
facility could foreclose on the pledged assets to the exclusion
of holders of the notes, even if an event of default exists
under the indenture governing the notes at such time.
Furthermore, if the lenders foreclose and sell the pledged
equity interests in any guarantor in a transaction permitted
under the terms of the indenture governing the notes, then such
guarantor will be released from its guarantee of the notes
automatically and immediately upon such sale. In any such event,
because the notes are not secured by any of such assets or by
the equity interests in any such guarantor, it is possible that
there would be no assets from which your claims could be
satisfied or, if any assets existed, they might be insufficient
to satisfy your claims in full.
If the co-issuers or any guarantor are declared bankrupt, become
insolvent or are liquidated or reorganized, any secured
indebtedness will be entitled to be paid in full from its assets
or the assets of any guarantor securing that indebtedness before
any payment may be made with respect to the notes or the
affected guarantees. Holders of the notes will participate
ratably in our remaining assets with all holders of any
unsecured indebtedness that does not rank junior to the notes,
based upon the respective amounts owed to each holder or
creditor. In any of the foregoing events, there may not be
sufficient assets to pay amounts due on the notes or the
guarantees. As a result, holders of the notes would likely
receive less, ratably, than holders of secured indebtedness.
As of December 31, 2010, we had total secured indebtedness
of approximately $73.3 million outstanding, and
$146.7 million of additional borrowing capacity under our
senior secured revolving credit facility.
12
We
have a substantial amount of indebtedness, which may adversely
affect our cash flows and ability to operate our business,
remain in compliance and repay our debt including the
notes.
As of March 31, 2011, we and the guarantors had
approximately $405.3 million of total debt outstanding. In
addition, the indenture for the notes permits us to incur
significant additional debt, some of which may be secured. Our
high level of indebtedness could have important consequences to
note holders, including the following:
|
|
|
|
|
it may make it difficult for us to satisfy our obligations under
the notes and our other indebtedness and contractual and
commercial commitments;
|
|
|
|
it may increase our vulnerability to adverse economic and
industry conditions;
|
|
|
|
it may require us to dedicate a substantial portion of our cash
flow from operations to payments on our indebtedness, thereby
reducing the availability of our cash flow to fund working
capital, capital expenditures and other general corporate
purposes;
|
|
|
|
it may limit our flexibility in planning for, or reacting to,
changes in our business and the industry in which we operate;
|
|
|
|
it may restrict us from making strategic acquisitions or
exploiting business opportunities;
|
|
|
|
it may place us at a competitive disadvantage compared to our
competitors that have less debt;
|
|
|
|
it may limit our ability to borrow additional funds;
|
|
|
|
it may prevent us from raising the funds necessary to repurchase
notes tendered to us if there is a change of control, which
would constitute a default under the indenture governing the
notes and under our senior secured revolving credit facility; and
|
|
|
|
it may decrease our ability to compete effectively or operate
successfully under adverse economic and industry conditions.
|
We may
not be able to generate sufficient cash flows to meet our debt
obligations.
We expect our earnings and cash flows to vary significantly from
year to year due to the cyclical nature of the oil and natural
gas industry. As a result, the amount of debt that we can manage
in some periods may not be appropriate for us in other periods.
In addition, our future cash flows may be insufficient to meet
our debt obligations and commitments, including the notes. Any
insufficiency could negatively impact our business. A range of
economic, competitive, business and industry factors will affect
our future financial performance, and, as a result, our ability
to generate cash flows from operations and to pay our debt,
including the notes. Many of these factors, such as oil and
natural gas prices, regulatory factors, economic and financial
conditions in our industry and the global economy or competitive
initiatives of our competitors, are beyond our control. If we do
not generate sufficient cash flows from operations to satisfy
our debt obligations, we may have to undertake alternative
financing plans, such as:
|
|
|
|
|
refinancing or restructuring our debt;
|
|
|
|
selling assets;
|
|
|
|
reducing or delaying capital investments; or
|
|
|
|
seeking to raise additional capital.
|
However, any alternative financing plans that we undertake, if
necessary, may not allow us to meet our debt obligations. Our
inability to generate sufficient cash flows to satisfy our debt
obligations, including our obligations under the notes, or to
obtain alternative financing, could materially and adversely
affect our business, financial condition, results of operations
and prospects.
Our ability to restructure or refinance our indebtedness will
depend on the condition of the capital markets and our financial
condition at such time. Any refinancing of our indebtedness
could be at higher
13
interest rates and could require us to comply with more onerous
covenants, which could further restrict our business operations.
The terms of existing or future debt instruments, including the
indenture governing the notes, may restrict us from adopting
some of these alternatives. In addition, any failure to make
payments of interest or principal on our outstanding
indebtedness on a timely basis would likely result in a
reduction of our credit rating, which could harm our ability to
incur additional indebtedness. In the absence of sufficient cash
flows and capital resources, we could face substantial liquidity
problems and might be required to dispose of material assets or
operations to meet our debt service and other obligations. We
may not be able to refinance our indebtedness, sell assets or
issue equity, or borrow more funds on terms acceptable to us, if
at all.
Our debt could have important consequences to you. For example,
it could:
|
|
|
|
|
increase our vulnerability to general adverse economic and
industry conditions;
|
|
|
|
limit our ability to fund future working capital and capital
expenditures, to engage in future acquisitions or development
activities, or to otherwise realize the value of our assets and
opportunities fully because of the need to dedicate a
substantial portion of our cash flows from operations to
payments of interest and principal on our debt or to comply with
any restrictive terms of our debt;
|
|
|
|
limit our flexibility in planning for, or reacting to, changes
in our business and the industry in which we operate;
|
|
|
|
impair our ability to obtain additional financing in the future;
and
|
|
|
|
place us at a competitive disadvantage compared to our
competitors that have less debt.
|
In addition, if we fail to comply with the covenants or other
terms of any agreements governing our debt, our lenders will
have the right to accelerate the maturity of that debt and
foreclose upon the collateral, if any, securing that debt.
Realization of any of these factors could adversely affect our
financial condition.
We may
be able to incur substantially more indebtedness, including
indebtedness ranking equal to the notes and the guarantees. This
could increase the risks associated with the
notes.
Subject to the restrictions in the indenture governing the notes
and in other instruments governing our other outstanding
indebtedness (including our senior secured revolving credit
facility), we may incur substantial additional indebtedness
(including secured indebtedness) in the future. Although the
indenture governing the notes and the instruments governing our
senior secured revolving credit facility contain restrictions on
the incurrence of additional indebtedness, these restrictions
are subject to waiver and a number of significant qualifications
and exceptions, and indebtedness incurred in compliance with
these restrictions could be substantial.
If the co-issuers or any guarantor incurs any additional
indebtedness that ranks equally with the notes (or with the
guarantee thereof), including trade payables, the holders of
that indebtedness will be entitled to share ratably with
noteholders in any proceeds distributed in connection with any
insolvency, liquidation, reorganization, dissolution or other
winding-up
of the co-issuers or such guarantor. This may have the effect of
reducing the amount of proceeds paid to noteholders in
connection with such a distribution.
The
notes are structurally subordinated in right of payment to the
indebtedness of those of any of our current and future
subsidiaries that do not guarantee the notes.
The notes will not be guaranteed by certain of our subsidiaries.
In addition, in the future, we may form unrestricted
subsidiaries that will not be subject to any of the covenants of
the indenture and will not guarantee the notes. In the case of
any subsidiaries that are not guarantors, the notes would be
effectively subordinated to all indebtedness and other
liabilities of such subsidiaries.
14
We may
not be able to fulfill our repurchase obligations with respect
to the notes upon a change of control.
If we experience certain specific change of control events, we
will be required to offer to repurchase all of our outstanding
notes at 101% of the principal amount of such notes plus accrued
and unpaid interest to the date of repurchase. We cannot assure
you that we will have available funds sufficient to pay the
change of control purchase price for any or all of the notes
that might be tendered in the change of control offer. The
definition of change of control in the indenture governing the
notes includes a phrase relating to the direct or indirect sale,
transfer, conveyance or other disposition of all or
substantially all of our and our restricted
subsidiaries assets, taken as a whole. Although there is a
limited body of case law interpreting the phrase
substantially all, there is no precise established
definition of the phrase under applicable law. Accordingly, the
ability of a holder of notes to require us to repurchase such
notes as a result of a sale, transfer, conveyance or other
disposition of less than all of our and our restricted
subsidiaries assets taken as a whole to another person or
group may be uncertain. Our limited partnership agreement
permits AMIH to cause our general partner to initiate a sale of
our company to a third-party after January 1, 2012, which
sale may be deemed to be a change of control. AMIH may exercise
this right at a time that we do not have sufficient capital or
are otherwise prohibited from repurchasing the notes. In
addition, our senior secured revolving credit facility contains,
and any future credit agreement likely will contain,
restrictions or prohibitions on our ability to repurchase the
notes under certain circumstances. If these change of control
events occur at a time when we are prohibited from repurchasing
the notes, we may seek the consent of our lenders to purchase
the notes or could attempt to refinance the borrowings that
contain these prohibitions or restrictions. If we do not obtain
our lenders consent or refinance these borrowings, we will
not be able to repurchase the notes. Accordingly, the holders of
the notes may not receive the change of control purchase price
for their notes in the event of a sale or other change of
control, which will give the trustee and the holders of the
notes the right to declare an event of default and accelerate
the repayment of the notes. See Description of New
Notes Change of Control.
Your
ability to transfer the notes may be limited by the absence of
an active trading market, and there is no assurance that any
active trading market will develop for the notes.
The old notes have not been registered under the Securities Act,
and may not be resold by holders thereof unless the old notes
are subsequently registered or an exemption from the
registration requirements of the Securities Act is available.
However, we cannot assure you that, even following registration
or exchange of the old notes for new notes, an active trading
market for the old notes or the new notes will exist, and we
will have no obligation to create such a market. At the time of
the private placements of the old notes, each book running
manager advised us that they intended to make a market in the
old notes and, if issued, the new notes. The book running
managers are not obligated, however, to make a market in the old
notes or the new notes and any market making may be discontinued
at any time at their sole discretion. No assurance can be given
as to the liquidity of or trading market for the old notes or
the new notes.
The liquidity of any trading market for the notes and the market
prices quoted for the notes depend upon the number of holders of
the notes, the overall market for high yield securities, our
financial performance or prospects or the prospects for
companies in our industry generally, the interest of securities
dealers in making a market in the notes and other factors.
An
adverse rating of the notes may cause the value of the notes to
fall.
If the rating agencies that rate the notes reduce their ratings
on the notes in the future or indicate that they have their
ratings on the notes under surveillance or review with possible
negative implications, the value of the notes could decline. In
addition, a ratings downgrade could adversely affect our ability
to access capital.
Our credit ratings are an assessment by rating agencies of our
ability to pay our debts when due. Consequently, real or
anticipated changes in our credit ratings will generally affect
the market value of the notes. These credit ratings may not
reflect the potential impact of risks relating to structure or
marketing of the notes. Agency ratings are not a recommendation
to purchase, hold or sell the notes and may be revised or
15
withdrawn at any time by the issuing organization. Each
agencys rating should be evaluated independently of any
other agencys rating.
A
financial failure by us or our subsidiaries may result in the
assets of any or all of those entities becoming subject to the
claims of all creditors of those entities.
A financial failure by us or our subsidiaries could affect
payment of the notes if a bankruptcy court were to substantively
consolidate us and our subsidiaries. If a bankruptcy court
substantively consolidated us and our subsidiaries, the assets
of each entity would be subject to the claims of creditors of
all entities. This would expose you not only to the usual
impairments arising from bankruptcy, but also to potential
dilution of the amount ultimately recoverable because of the
larger creditor base. Furthermore, forced restructuring of the
notes could occur through the cram-down provision of the
bankruptcy code. Under this provision, the notes could be
restructured over your objections as to their general terms,
primarily interest rate and maturity.
If the
subsidiary guarantees are deemed fraudulent conveyances or
preferential transfers, a court may subordinate or void
them.
Under various fraudulent conveyance or fraudulent transfer laws,
a court could subordinate or void our subsidiary guarantees.
Generally, a United States court may void or subordinate a
subsidiary guarantee in favor of the subsidiarys other
obligations if it finds that at the time the subsidiary entered
into a subsidiary guarantee it:
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intended to hinder, delay or defraud any present or future
creditor or contemplated insolvency with a design to favor one
or more creditors to the exclusion of others;
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did not receive fair consideration or reasonably equivalent
value for issuing the subsidiary guarantee;
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was insolvent or became insolvent as a result of issuing the
subsidiary guarantee;
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was engaged or about to engage in a business or transaction for
which the remaining assets of the subsidiary constituted
unreasonably small capital; or
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intended to incur, or believed that it would incur, debts beyond
its ability to pay those debts as they matured.
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The measures of insolvency for purposes of fraudulent transfer
laws vary depending upon the governing law. Generally, a
guarantor would be considered insolvent if:
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the sum of its debts, including contingent liabilities, were
greater than the fair saleable value of all its assets;
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the present fair saleable value of its assets is less than the
amount that would be required to pay its probable liability on
its existing debts, including contingent liabilities, as they
become absolute and mature; or
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it could not pay its debts as they become due.
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In addition, a guarantee may be voided based on the level of
benefits that the subsidiary guarantor received compared to the
amount of the subsidiary guarantee. If a subsidiary guarantee is
voided or held unenforceable, you would not have any claim
against that subsidiary and would be creditors solely of us and
any subsidiary guarantors whose guarantees are not held
unenforceable. After providing for all prior claims, there may
not be sufficient assets to satisfy claims of holders of notes
relating to any voided portions of any of the subsidiary
guarantees. In addition, the court might direct you to repay any
amounts that you already received from the subsidiary guarantor.
The
amount that can be collected under future subsidiary guarantees,
if any, will be limited.
Each subsidiary guarantee entered into after the closing date
will contain a provision intended to limit such guarantors
liability to the maximum amount that it could guarantee without
causing the incurrence of the obligations under its guarantee to
be a fraudulent transfer. This provision may not be effective to
protect subsidiary guarantees from being voided under applicable
fraudulent transfer laws or may reduce the
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guarantors obligation to an amount that effectively makes
the subsidiary guarantee worthless. In a recent Florida
bankruptcy case, this kind of provision was found to be
ineffective to protect the guarantees.
There is a risk of a preferential transfer if:
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a subsidiary guarantor declares bankruptcy or its creditors
force it to declare bankruptcy within 90 days (or in
certain cases, one year) after a payment on the guarantee; or
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a subsidiary guarantee was made in contemplation of insolvency.
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In addition, a court could require holders of notes to return
amounts received from the subsidiary guarantor during the
90-day (or,
in certain cases, one-year) period.
The
trading price of the new notes may be volatile.
There is no established market for the new notes, and we cannot
assure you that any active or liquid trading market will develop
for these notes. Historically, the market for non-investment
grade debt has been subject to disruptions that have caused
substantial volatility in the prices of securities similar to
the new notes. Any such disruptions could adversely affect the
prices at which the new notes may be sold. If a market for the
notes were to develop, the new notes could trade at prices that
may be higher or lower than reflected by their initial offering
price, depending on many factors, including, among other things:
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changes in the overall market for high yield securities;
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changes in our operating performance and financial condition or
prospects;
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the prospects for companies in our industry generally;
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the number of holders of the new notes;
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the market for similar securities;
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the interest of securities dealers in making a market for the
new notes; and
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prevailing interest rates.
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Risks
Related to Our Business and the Oil and Natural Gas
Industry
Our
exploration, exploitation, development and acquisition
operations will require substantial capital expenditures. We may
be unable to obtain needed capital or financing on satisfactory
terms, which could lead to a decline in our production and
reserves.
The oil and natural gas industry is capital intensive. We have
made and expect to continue to make substantial capital
expenditures in our business for the exploration, exploitation,
development and acquisition of oil and natural gas reserves. Our
capital expenditures for 2010 totaled $146 million. Our
budgeted capital expenditures for 2011 are currently expected to
be approximately $200 million, of which we have spent
$58.9 million through March 31, 2011. We have funded
development and operating activities primarily through equity
capital raised from a private equity partner, through borrowings
under our bank credit facilities and through internal operating
cash flows. We intend to finance our future capital expenditures
predominantly with cash flows from operations. If necessary, we
may also access capital through proceeds from potential asset
dispositions, borrowings under our senior secured revolving
credit facility and the future issuance of debt and/or equity
securities. Our cash flow from operations and access to capital
are subject to a number of variables, including:
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the estimated quantities of our oil and natural gas reserves;
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the amount of oil and natural gas we produce from existing wells;
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the prices at which we sell our production;
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take-away capacity; and
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our ability to acquire, locate and produce new reserves.
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If our revenues or the borrowing base under our senior secured
revolving credit facility decrease as a result of lower
commodity prices, operating difficulties, declines in reserves
or for any other reason, we may have limited ability to obtain
the capital necessary to conduct our operations at expected
levels. Our senior secured revolving credit facility may
restrict our ability to obtain new debt financing. If additional
capital is required, we may not be able to obtain debt and/or
equity financing on terms favorable to us, or at all. If cash
generated by operations or available under our senior secured
revolving credit facility is not sufficient to meet our capital
requirements, the failure to obtain additional financing could
result in a curtailment of our operations relating to
development of our prospects, which in turn could lead to a
decline in our reserves and production, and could adversely
affect our business, results of operation, financial conditions
and ability to make payments on our outstanding indebtedness.
External financing may be required in the future to fund our
growth. We may not be able to obtain additional financing, and
financing under our senior secured revolving credit facility may
not be available in the future. Without additional capital
resources, we may be unable to pursue and consummate acquisition
opportunities as they become available, and we may be forced to
limit or defer our planned oil and natural gas development
program, which will adversely affect the recoverability and
ultimate value of our oil and natural gas properties, in turn
negatively affecting our business, financial condition and
results of operations.
Oil
and natural gas prices are volatile and a decline in prices can
significantly affect our financial condition and results of
operations.
Our revenue, profitability and cash flow depend upon the prices
for oil and natural gas. The prices we receive for oil and
natural gas production are volatile and a decrease in prices can
significantly affect our financial results and impede our
growth, including our ability to maintain or increase our
borrowing capacity, to repay current or future indebtedness and
to obtain additional capital on attractive terms. Changes in oil
and natural gas prices have a significant impact on the value of
our reserves and on our cash flows. Prices for oil and natural
gas may fluctuate widely in response to relatively minor changes
in supply and demand, market uncertainty and a variety of
additional factors that are beyond our control, such as:
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the domestic and foreign supply of and demand for oil and
natural gas;
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the price and quantity of foreign imports of oil and natural gas;
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the level of consumer product demand;
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weather conditions;
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domestic and foreign governmental regulations and taxation;
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overall domestic and global economic conditions;
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the value of the dollar relative to the currencies of other
countries;
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overall domestic and global economic conditions;
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political and economic conditions and events in foreign oil and
natural gas producing countries, including embargoes, continued
hostilities in the Middle East and other sustained military
campaigns, conditions in South America, Central America, China
and Russia, and acts of terrorism or sabotage;
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the ability of members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and
production controls;
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the proximity and capacity of natural gas pipelines and other
transportation facilities to our production;
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technological advances affecting energy consumption;
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the price and availability of alternative fuels; and
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the impact of energy conservation efforts.
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Low oil or natural gas prices will decrease our revenues, and
may also reduce the volumetric amount of oil or natural gas that
we can economically produce. This may result in our having to
make substantial downward adjustments to our estimated proved
reserves. If this occurs, or if our estimates of development
costs increase, production data factors change or drilling
results deteriorate, accounting rules may require us to write
down, as a non-cash charge to earnings, the carrying value of
our oil and natural gas properties for impairments. We are
required to perform impairment tests on our assets whenever
events or changes in circumstances lead to a reduction of the
estimated useful life or estimated future cash flows that would
indicate that the carrying amount may not be recoverable or
whenever managements plans change with respect to those
assets. We may incur impairment charges in the future, which
could have a material adverse effect on our results of
operations in the period taken and our ability to borrow funds
under our senior secured revolving credit facility.
We
will depend on successful exploration, exploitation, development
and acquisitions to maintain reserves and revenue in the
future.
In general, the volume of production from oil and natural gas
properties declines as reserves are depleted, with the rate of
decline depending on each reservoirs characteristics.
Except to the extent that we conduct successful exploration and
development activities or acquire properties containing proved
reserves, or both, our proved reserves will decline as reserves
are produced. Our future oil and natural gas production is,
therefore, highly dependent on our level of success in finding
or acquiring additional reserves. Additionally, the business of
exploring for, developing, or acquiring reserves is capital
intensive. Recovery of our reserves, particularly undeveloped
reserves, will require significant additional capital
expenditures and successful drilling operations. To the extent
cash flow from operations is reduced and external sources of
capital become limited or unavailable, our ability to make the
necessary capital investment to maintain or expand our asset
base of oil and natural gas reserves would be impaired. In
addition, we are dependent on finding partners for our
exploratory activity. To the extent that others in the industry
do not have the financial resources or choose not to participate
in our exploration activities, we may be adversely affected.
Our
estimated oil and natural gas reserve quantities and future
production rates are based on many assumptions that may prove to
be inaccurate. Any material inaccuracies in these reserve
estimates or the underlying assumptions will materially affect
the quantities and present value of our reserves.
Numerous uncertainties are inherent in estimating quantities of
oil and natural gas reserves. The process of estimating oil and
natural gas reserves is complex, requiring significant decisions
and assumptions in the evaluation of available geological,
engineering and economic data for each reservoir, and these
reports rely upon various assumptions, including assumptions
regarding future oil and natural gas prices, production levels,
and operating and development costs. As a result, estimated
quantities of proved reserves and projections of future
production rates and the timing of development expenditures may
prove to be inaccurate. Over time, we may make material changes
to reserve estimates taking into account the results of actual
drilling and production. Any significant variance in our
assumptions and actual results could greatly affect our
estimates of reserves, the economically recoverable quantities
of oil and natural gas attributable to any particular group of
properties, the classifications of reserves based on risk of
recovery, and estimates of the future net cash flows. In
addition, changes in future production costs assumptions could
have a significant effect on our proved reserve quantities.
The
present value of future net revenues from our proved reserves or
PV-10,
will not necessarily be the same as the current market value of
our estimated oil and natural gas reserves.
You should not assume that the present value of future net
revenues from our proved reserves is the current market value of
our estimated oil and natural gas reserves. For the years prior
to 2009, we based the estimated discounted future net revenues
from our proved reserves on prices and costs in effect on the
day of the estimate. In accordance with more recent SEC
requirements, we currently base the estimated discounted future
net revenues from our proved reserves on the twelve-month
unweighted arithmetic average of the
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first-day-of-the-month
price for the preceding twelve months. Actual future net
revenues from our oil and natural gas properties will be
affected by factors such as:
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actual prices we receive for crude oil and natural gas;
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actual cost of development and production expenditures;
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the amount and timing of actual production;
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transportation and processing; and
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changes in governmental regulations or taxation.
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The timing of both our production and our incurrence of expenses
in connection with the development and production of oil and
natural gas properties will affect the timing and amount of
actual future net revenues from proved reserves, and thus their
actual present value. In addition, the 10% discount factor we
use when calculating discounted future net revenues may not be
the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with us or the oil
and natural gas industry in general. Actual future prices and
costs may differ materially from those used in the present value
estimate. If oil and gas prices decline by 10%, then our
PV-10 as of
December 31, 2010 would decrease approximately
$114 million.
Approximately
34% of our total estimated proved reserves at December 31,
2010 were proved undeveloped reserves requiring substantial
capital expenditures and may ultimately prove to be less than
estimated.
Recovery of proved undeveloped reserves requires significant
capital expenditures and successful drilling operations. At
December 31, 2010, approximately 111 Bcfe of our total
estimated proved reserves were undeveloped. The reserve data
included in our reserve reports assumes that substantial capital
expenditures will be made to develop non-producing reserves. The
calculation of our estimated net proved reserves as of
December 31, 2010 assumes that we will spend
$156 million to develop our estimated proved undeveloped
reserves, including an estimated $87 million in 2011.
Although cost and reserve estimates attributable to our natural
gas and oil reserves have been prepared in accordance with
industry standards, we cannot be sure that the estimated costs
are accurate. We may need to raise additional capital in order
to develop our estimated proved undeveloped reserves over the
next five years and we cannot be certain that additional
financing will be available to us on acceptable terms, if at
all. Further, our drilling efforts may be delayed or
unsuccessful, and actual reserves may prove to be less than
current reserve estimates, which could have a material adverse
effect on our financial condition, future cash flows and results
of operations. For a more detailed discussion of our current
liquidity and projected liquidity immediately following this
offering, please read Managements Discussion and
Analysis of Financial Condition and Results of
Operations Liquidity and Capital Resources.
We may
experience difficulty in achieving and managing future
growth.
Future growth may place strains on our resources and cause us to
rely more on project partners and independent contractors,
possibly negatively affecting our financial condition and
results of operations. Our ability to grow will depend on a
number of factors, including:
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the results of our drilling program;
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hydrocarbon prices;
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our ability to develop existing prospects;
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our ability to obtain leases or options on properties for which
we have 3-D
seismic data;
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our ability to acquire additional
3-D seismic
data;
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our ability to identify and acquire new exploratory prospects;
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our ability to continue to retain and attract skilled personnel;
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our ability to maintain or enter into new relationships with
project partners and independent contractors; and
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our access to capital.
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Our
use of 2-D
and 3-D
seismic data is subject to interpretation and may not accurately
identify the presence of hydrocarbons, which could adversely
affect the results of our drilling operations.
Even when properly used and interpreted,
2-D and
3-D seismic
data and visualization techniques are only tools used to assist
geoscientists in identifying subsurface structures and
hydrocarbon indicators and do not enable geoscientists to know
whether hydrocarbons are, in fact, present in those structures
and the amount of hydrocarbons. We are employing
3-D seismic
technology with respect to certain of our projects. The use of
2-D and
3-D seismic
and other advanced technologies requires greater pre-drilling
expenditures than traditional drilling strategies, and we could
incur greater drilling and testing expenses as a result of such
expenditures, which may result in a reduction in our returns or
losses. As a result, our drilling activities may not be
successful or economical, and our overall drilling success rate
or our drilling success rate for activities in a particular area
could decline.
We often gather
2-D and
3-D seismic
data over large areas. Our interpretation of seismic data
delineates those portions of an area that we believe are
desirable for drilling. Therefore, we may choose not to acquire
option or lease rights prior to acquiring seismic data, and, in
many cases, we may identify hydrocarbon indicators before
seeking option or lease rights in the location. If we are not
able to lease those locations on acceptable terms, we will have
made substantial expenditures to acquire and analyze
2-D and
3-D data
without having an opportunity to attempt to benefit from those
expenditures.
We
will rely on drilling to increase our levels of production. If
our drilling is unsuccessful, our financial condition will be
adversely affected.
The primary focus of our business strategy is to increase
production levels by drilling wells. Although we were successful
in drilling in the past, we cannot assure you that we will
continue to maintain production levels through drilling. Our
drilling involves numerous risks, including the risk that we
will not encounter commercially productive oil or natural gas
reservoirs. We must incur significant expenditures to drill and
complete wells. The costs of drilling and completing wells are
often uncertain, and it is possible that we will make
substantial expenditures on drilling and not discover reserves
in commercially viable quantities.
We may
be unable to make attractive acquisitions or successfully
integrate acquired businesses, and any inability to do so may
disrupt our business and hinder our ability to
grow.
In the future we may make acquisitions of businesses that
complement or expand our current business. We may not be able to
identify attractive acquisition opportunities. Even if we do
identify attractive acquisition opportunities, we may not be
able to complete the acquisition or do so on commercially
acceptable terms. No assurance can be given that we will be able
to identify additional suitable acquisition opportunities,
negotiate acceptable terms, obtain financing for acquisitions on
acceptable terms or successfully acquire identified targets.
The success of any completed acquisition will depend on our
ability to integrate effectively the acquired business into our
existing operations. The process of integrating acquired
businesses may involve unforeseen difficulties and may require a
disproportionate amount of our managerial and financial
resources. Our failure to achieve consolidation savings, to
incorporate the acquired businesses and assets into our existing
operations successfully or to minimize any unforeseen
operational difficulties could have a material adverse effect on
our financial condition and results of operations.
In addition, our partnership agreement, our senior secured
revolving credit facility and the indenture governing the notes
impose certain limitations on our ability to enter into mergers
or combination transactions. Our partnership agreement, our
senior secured revolving credit facility and the indenture
governing the notes
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also limit our ability to incur certain indebtedness, which
could indirectly limit our ability to engage in acquisitions of
businesses.
Our
business is subject to operational risks that will not be fully
insured, which, if they were to occur, could adversely affect
our financial condition or results of operations.
Our business activities are subject to operational risks,
including:
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damages to equipment caused by adverse weather conditions,
including tornadoes, hurricanes and flooding;
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facility or equipment malfunctions;
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pipeline ruptures or spills;
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surface fluid spills and salt water contamination;
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fires, blowouts, craterings and explosions; and
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uncontrollable flows of oil or natural gas or well fluids.
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In addition, a portion of our natural gas production is
processed to extract natural gas liquids at processing plants
that are owned by others. If these plants were to cease
operations for any reason, we would need to arrange for
alternative transportation and processing facilities. These
alternative facilities may not be available, which could cause
us to shut in our natural gas production. Further, such
alternative facilities could be more expensive than the
facilities we currently use.
Any of these events could adversely affect our ability to
conduct operations or cause substantial losses, including
personal injury or loss of life, damage to or destruction of
property, natural resources and equipment, pollution or other
environmental contamination, loss of wells, regulatory
penalties, suspension of operations, and attorneys fees
and other expenses incurred in the prosecution or defense of
litigation.
As is customary in the industry, we maintain insurance against
some but not all of these risks. Additionally, we may elect not
to obtain insurance if we believe that the cost of available
insurance is excessive relative to the perceived risks
presented. Losses could therefore occur for uninsurable or
uninsured risks or in amounts in excess of existing insurance
coverage. The occurrence of an event that is not fully covered
by insurance could have a material adverse impact on our
business activities, financial condition and results of
operations.
Our
hedging activities could result in financial losses or could
reduce our net income.
To achieve more predictable cash flows and to reduce our
exposure to fluctuations in the prices of oil and natural gas,
we have and may continue to enter into hedging arrangements for
a significant portion of our oil and natural gas production. As
of December 31, 2010, we hedged approximately 70% of our
forecasted PDP production through 2014 at average annual prices
ranging from $5.75 per MMBtu to $6.94 per MMBtu and $78.62 per
Bbl to $85.00 per Bbl. If we experience a sustained material
interruption in our production, we might be forced to satisfy
all or a portion of our hedging obligations without the benefit
of the cash flows from our sale of the underlying physical
commodity, resulting in a substantial diminution of our
liquidity. Lastly, an attendant risk exists in hedging
activities that the counterparty in any derivative transaction
cannot or will not perform under the instrument and that we will
not realize the benefit of the hedge.
Our ability to use hedging transactions to protect us from
future oil and natural gas price declines will be dependent upon
oil and natural gas prices at the time we enter into future
hedging transactions and our future levels of hedging, and as a
result our future net cash flows may be more sensitive to
commodity price changes.
Our policy has been to hedge a significant portion of our
near-term estimated oil and natural gas production. However, our
price hedging strategy and future hedging transactions will be
determined at our discretion. We are not under an obligation to
hedge a specific portion of our production. The prices at which
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we hedge our production in the future will be dependent upon
commodities prices at the time we enter into these transactions,
which may be substantially higher or lower than current oil and
natural gas prices. Accordingly, our price hedging strategy may
not protect us from significant declines in oil and natural gas
prices received for our future production. Conversely, our
hedging strategy may limit our ability to realize cash flows
from commodity price increases. It is also possible that a
substantially larger percentage of our future production will
not be hedged as compared with the next few years, which would
result in our oil and natural gas revenues becoming more
sensitive to commodity price changes.
Our
hedging transactions expose us to counterparty credit
risk.
Our hedging transactions expose us to risk of financial loss if
a counterparty fails to perform under a derivative contract.
Disruptions in the financial markets could lead to sudden
changes in a counterpartys liquidity, which could impair
their ability to perform under the terms of the derivative
contract. We are unable to predict sudden changes in a
counterpartys creditworthiness or ability to perform. Even
if we do accurately predict sudden changes, our ability to
negate the risk may be limited depending upon market conditions.
During periods of falling commodity prices, such as in late
2008, our hedge receivable positions increase, which increases
our exposure. If the creditworthiness of our counterparties
deteriorates and results in their nonperformance, we could incur
a significant loss.
The
adoption of derivatives legislation or regulations related to
derivative contracts could have an adverse impact on our ability
to hedge risks associated with our business.
On July 21, 2010, the President signed into law the
Dodd Frank Wall Street Reform and Consumer
Protection Act (the Act). Among other things, the
Act requires the Commodity Futures Trading Commission and the
SEC to enact regulations affecting derivative contracts,
including the derivative contracts we use to hedge our exposure
to price volatility within 360 days from the date of
enactment. We cannot predict the content of these regulations or
the effect that these regulations will have on our hedging
activities. Of particular concern, the Act does not explicitly
exempt end users (such as us) from the requirements to use
exchanges, which would require us to post margin in connection
with hedging activities. Even if we qualify for an exception,
there are other aspects of the Act that may make it more
expensive for other parties to offer these hedges to us. The
full effects of the Act will not be known until the regulations
have been enacted and the market for these hedges has adjusted.
It is possible the hedges will become more expensive, uneconomic
or unavailable, which could lead to increased costs or commodity
price volatility or a combination of both.
Certain
U.S. federal income tax preferences currently available with
respect to oil and natural gas production may be eliminated as a
result of future legislation.
Among the changes contained in President Obamas Budget
Proposal for Fiscal Year 2012 is the elimination of certain key
U.S. federal income tax incentives currently available to oil
and gas exploration and production. The Presidents budget
proposes to eliminate certain tax preferences applicable to
taxpayers engaged in the exploration or production of natural
resources. Specifically, the budget proposes to repeal the
deduction for percentage depletion with respect to wells, in
which case only cost depletion would be available. It is unclear
whether any such changes will be enacted or how soon any such
changes could become effective. The passage of any legislation
as a result of these proposals or any other similar changes in
U.S. federal income tax laws could negatively affect our
financial condition and results of operations.
We may
be unable to compete effectively with larger companies, which
may adversely affect our ability to generate sufficient
revenues.
The oil and natural gas industry is intensely competitive, and
we compete with other companies that have greater resources than
us. Our ability to acquire additional properties and to discover
reserves in the future will be dependent upon our ability to
evaluate and select suitable properties to consummate
transactions in a highly competitive market. Many of our larger
competitors not only drill for and produce oil and natural gas,
but also engage in refining operations and market petroleum and
other products on a regional, national or worldwide
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basis. These companies may be able to pay more for oil and
natural gas properties, and evaluate, bid for and purchase a
greater number of properties than our financial or human
resources permit. In addition, these companies may have a
greater ability to continue drilling activities during periods
of low oil and natural gas prices, to contract for drilling
equipment, to secure trained personnel, and to absorb the burden
of present and future federal, state, local and other laws and
regulations. The oil and natural gas industry has periodically
experienced shortages of drilling rigs, equipment, pipe and
personnel, which has delayed development drilling and other
exploitation activities and has caused significant price
increases. Competition has been strong in hiring experienced
personnel, particularly in the engineering and technical,
accounting and financial reporting, tax and land departments. In
addition, competition is strong for attractive oil and natural
gas producing properties, oil and natural gas companies, and
undeveloped leases and drilling rights. Our inability to compete
effectively with larger companies could have a material adverse
impact on our business activities, financial condition and
results of operations.
The oil and natural gas industry is characterized by rapid and
significant technological advancements and introductions of new
products and services using new technologies. As others use or
develop new technologies, we may be placed at a competitive
disadvantage or competitive pressures may force us to implement
those new technologies at substantial costs. In addition, other
oil and natural gas companies may have greater financial,
technical, and personnel resources that allow them to enjoy
technological advantages and may in the future allow them to
implement new technologies before we can. We may not be able to
respond to these competitive pressures and implement new
technologies on a timely basis or at an acceptable cost. If one
or more of the technologies we use now or in the future were to
become obsolete or if we are unable to use the most advanced
commercially available technology, our business, financial
condition, and results of operations could be materially
adversely affected.
Deficiencies
of title to our leased interests could significantly affect our
financial condition.
If an examination of the title history of a property reveals
that an oil or natural gas lease or other developed rights has
been purchased in error from a person who is not the owner of
the mineral interest desired, our interest would substantially
decline in value. In such cases, the amount paid for such oil or
natural gas lease or leases or other developed rights would be
lost. It is managements practice, in acquiring oil and
natural gas leases or undivided interests in oil and natural gas
leases or other developed rights, not to incur the expense of
retaining lawyers to examine the title to the mineral interest
to be acquired. Rather, we will rely upon the judgment of oil
and natural gas lease brokers or landmen who perform the
fieldwork in examining records in the appropriate governmental
or county clerks office before attempting to acquire a
lease or other developed rights in a specific mineral interest.
Prior to drilling an oil or natural gas well, however, it is the
normal practice in the oil and natural gas industry for the
person or company acting as the operator of the well to obtain a
preliminary title review of the spacing unit within which the
proposed oil or natural gas well is to be drilled to ensure
there are no obvious deficiencies in title to the well.
Frequently, as a result of such examinations, certain curative
work must be done to correct deficiencies in the marketability
of the title, such as obtaining affidavits of heirship or
causing an estate to be administered. Such curative work entails
expense, and it may happen, from time to time, that the operator
may elect to proceed with a well despite defects to the title
identified in the preliminary title opinion. Our failure to
obtain perfect title to our leaseholds may adversely impact our
ability in the future to increase production and reserves.
We are
vulnerable to risks associated with operating in the inland
waters region of South Louisiana.
Our operations and financial results could be significantly
impacted by unique conditions in the inland waters region of
South Louisiana because we explore and produce in that area. As
a result of this activity, we are vulnerable to the risks
associated with operating in the inland waters region of South
Louisiana, including those relating to:
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adverse weather conditions and natural disasters;
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availability of required performance bonds and insurance;
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oil field service costs and availability;
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compliance with environmental and other laws and regulations;
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matters arising from the 2010 BP Macondo well oil spill
including but not limited to new safety requirements, new
regulations, increased costs of services and rig mobilizations,
slowed issuance of permits for new wells and additional
insurance costs and requirements;
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remediation and other costs resulting from oil spills or
releases of hazardous materials; and
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failure of equipment or facilities.
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Further, production of reserves from reservoirs in the inland
waters region of South Louisiana generally decline more rapidly
than production of reservoirs from fields in many other
producing regions of the world. This results in recovery of a
relatively higher percentage of reserves from properties during
the initial years of production, and as a result, our reserve
replacement needs from new prospects may be greater in the
inland waters region of South Louisiana than for our operations
elsewhere. Also, our revenues and return on capital will depend
significantly on prices prevailing during these relatively short
production periods.
Our
ability to pursue our business strategies may be adversely
affected if we incur costs and liabilities due to a failure to
comply with environmental regulations or a release of hazardous
substances into the environment.
We may incur significant costs and liabilities as a result of
environmental requirements applicable to the operation of our
wells, gathering systems and other facilities. These costs and
liabilities could arise under a wide range of federal, state and
local environmental laws and regulations, including, for example:
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the Clean Air Act (CAA) and comparable state laws
and regulations that impose obligations related to air emissions;
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the Clean Water Act and Oil Pollution Act (OPA) and
comparable state laws and regulations that impose obligations
related to discharges of pollutants into regulated bodies of
water;
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the Resource Conservation and Recovery Act (RCRA),
and comparable state laws that impose requirements for the
handling and disposal of waste from our facilities;
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the Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA) and comparable state laws
that regulate the cleanup of hazardous substances that may have
been released at properties currently or previously owned or
operated by us or at locations to which we have sent waste for
disposal; and
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the Environmental Protection Agency (EPA) community
right to know regulations under the Title III of CERCLA and
similar state statutes require that we organize and/or disclose
information about hazardous materials used or produced in our
operations.
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Failure to comply with these laws and regulations may trigger a
variety of administrative, civil and criminal enforcement
measures, including the assessment of monetary penalties, the
imposition of remedial requirements, and the issuance of orders
enjoining future operations. Certain environmental statutes,
including RCRA, CERCLA, the federal OPA and analogous state laws
and regulations, impose strict joint and several liability for
costs required to clean up and restore sites where hazardous
substances or other waste products have been disposed of or
otherwise released. More stringent laws and regulations,
including any related to climate change and greenhouse natural
gases, may be adopted in the future. Moreover, it is not
uncommon for neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other waste
products into the environment. See Business
Environmental Matters & Regulation included
elsewhere herein.
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The
unavailability or high cost of drilling rigs, equipment,
supplies, personnel and oil field services could adversely
affect our ability to execute development and exploitation plans
on a timely basis and within budget, and consequently could
adversely affect our anticipated cash flow.
We utilize third-party services to maximize the efficiency of
our operation. The cost of oil field services typically
fluctuates based on demand for those services. While we
currently have excellent relationships with oil field service
companies, there is no assurance that we will be able to
contract for such services on a timely basis or that the cost of
such services will remain at a satisfactory or affordable level.
Shortages or the high cost of drilling rigs, equipment, supplies
or personnel could delay or adversely affect our development and
exploitation operations, which could have a material adverse
effect on our business, financial condition or results of
operations.
We are
subject to complex federal, state, local and other laws and
regulations that could adversely affect the cost, manner or
feasibility of conducting our operations.
Our oil and natural gas exploration and production operations
are subject to complex and stringent laws and regulations. In
order to conduct our operations in compliance with these laws
and regulations, we must obtain and maintain numerous permits,
approvals and certificates from various federal, state and local
governmental authorities. Failure or delay in obtaining
regulatory approvals or drilling permits could have a material
adverse effect on our ability to develop our properties, and
receipt of drilling permits with onerous conditions could
increase our compliance costs. In addition, regulations
regarding conservation practices and the protection of
correlative rights affect our operations by limiting the
quantity of oil and natural gas we may produce and sell.
We are subject to federal, state and local laws and regulations
as interpreted and enforced by governmental authorities
possessing jurisdiction over various aspects of the exploration,
production and transportation of oil and natural gas. The
possibility exists that new laws, regulations or enforcement
policies could be more stringent and significantly increase our
compliance costs. If we are not able to recover the resulting
costs through insurance or increased revenues, our financial
position could be adversely affected.
We
have limited control over activities on properties we do not
operate, which could reduce our production and
revenues.
We maintain operational control of approximately 70% of the
PV-10 value
of our proved reserves either through operating the properties
directly or entering into arrangements with local operators with
minority interests in our properties. We have limited control
over properties, especially those in Deep Bossier, which we do
not operate or do not otherwise control operations. If we do not
operate or otherwise control the properties in which we own an
interest, we do not have control over normal operating
procedures, expenditures or future development of the underlying
properties. The failure of an operator of our wells to
adequately perform operations or an operators breach of
the applicable agreements could reduce our production and
revenues. The success and timing of our drilling and development
activities on properties operated by others, therefore, depends
upon a number of factors outside of our control, including the
operators timing and amount of capital expenditures,
expertise and financial resources, inclusion of other
participants in drilling wells and use of technology.
AMIH,
as our Class B limited partner, has the ability to take
actions that conflict with your interests.
AMIH, an affiliate of a private equity fund focused on energy
and commodities, is the holder of our Class B limited
partner interest. Under our partnership agreement, the
Class B limited partner has certain significant rights,
including, without limitation:
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approval of material sales and acquisitions of properties and
assets, the incurrence of debt, the appointment of any successor
to our Chief Executive Officer and any other senior officers;
the entering into of partnerships and joint ventures; our merger
or consolidation with any entity; and the issuance of interests,
ownership interests, debentures, bonds and other securities of
the company;
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approval of our annual development plan and budget;
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the right to require us to implement measures to mitigate our
commodity price risks;
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the right to part of the proceeds of any future debt or equity
offering;
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the right to require the general partner, after January 1,
2012, to make distributions of net cash from
operations subject to our compliance with the covenants of
any senior debt, including the notes, or bank credit facility;
net cash from operations is defined as the gross
cash proceeds from our operations less amounts used to pay or
fund our costs, expenses, contract operating costs (including
operators general and administrative expenses), marketing
costs, debt payments, capital expenditures, reserve
replacements, tax distributions and agreed reserves (as agreed
upon by us and our Class B limited partner);
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the right to cause our general partner to initiate a sale of us
to a third party after January 1, 2012 or upon certain
events; and
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the right to remove the general partner for cause and replace
the general partner in the Class B limited partners
sole discretion.
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The interests of the Class B limited partner could conflict
with your interests as a holder of the notes. For example, if we
encounter financial difficulties or are unable to pay our debts
as they mature, the interests of the Class B limited
partner may conflict with your interests as a holder of the
notes. The Class B limited partner also may have an
interest in pursuing acquisitions, divestitures, financings or
other transactions that, in its judgment, could enhance its
investment, even though such transactions might involve risks to
you, as holders of the notes. We can provide no assurance that
any such conflicts will be resolved in the favor of the
interests of the holders of the notes.
Our
private equity partner and its affiliates are not limited in
their ability to compete with us for acquisition or drilling
opportunities. This could cause conflicts of interest and limit
our ability to acquire additional assets or
businesses.
Our partnership agreement with our private equity partner does
not prohibit it or its affiliates from owning assets or engaging
in businesses that compete directly or indirectly with us. For
instance, our private equity partner and its affiliates may
acquire, develop or dispose of additional oil or natural gas
properties or other assets in the future, without any obligation
to offer us the opportunity to purchase or develop any of those
assets. DCPF IV, an affiliate of our private equity partner, is
part of a larger family of funds, which has significantly
greater resources than we have, which may make it more difficult
for us to compete for acquisition candidates if our private
equity partner or its affiliates were to compete against us.
We
depend on key personnel, the loss of any of whom could
materially adversely affect future operations.
Our success will depend to a large extent upon the efforts and
abilities of our executive officers and key operations
personnel. The loss of the services of one or more of these key
employees could have a material adverse effect on us. We do not
maintain key-man life insurance with respect to any of our
employees. Our business will also be dependent upon our ability
to attract and retain qualified personnel. Acquiring and keeping
these personnel could prove more difficult or cost substantially
more than estimated. This could cause us to incur greater costs,
or prevent us from pursuing our development and exploitation
strategy as quickly as we would otherwise wish to do.
We may
encounter obstacles to marketing our oil and natural gas, which
could adversely impact our revenues.
The marketability of our production will depend in part upon the
availability and capacity of natural gas gathering systems,
pipelines and other transportation facilities owned by third
parties. Transportation space on the gathering systems and
pipelines we utilize is occasionally limited or unavailable due
to repairs or improvements to facilities or due to space being
utilized by other companies that have priority transportation
27
agreements. Our access to transportation options can also be
affected by U.S. federal and state regulation of oil and natural
gas production and transportation, general economic conditions
and changes in supply and demand. The availability of markets is
beyond our control. If market factors dramatically change, the
impact on our revenues could be substantial and could adversely
affect our ability to produce and market oil and natural gas.
We may
experience a temporary decline in revenues and production if we
lose one of our significant customers.
Historically, we have been dependent upon a few customers for a
significant portion of our revenue. To the extent any
significant customer reduces the volume of its oil or natural
gas purchases from us, we could experience a temporary
interruption in sales of, or a lower price for, our oil and
natural gas production and our revenues could decline.
If we
fail to maintain an effective system of internal controls, we
may not be able to accurately report our financial results or
prevent fraud.
Effective internal controls are necessary for us to provide
reliable financial reports, prevent fraud and operate
successfully. We cannot be certain that our efforts to maintain
our internal controls will be successful, that we will be able
to maintain adequate controls over our financial processes and
reporting in the future. Any failure to maintain effective
internal controls, or difficulties encountered in implementing
or improving our internal controls, could harm our operating
results and affect our ability to timely produce financial
results.
Climate
change legislation or regulations restricting emissions of
greenhouse gases (GHGs) could result in increased
operating costs and reduced demand for the oil and natural gas
we produce.
On December 15, 2009, the EPA officially published its
findings that emissions of carbon dioxide, methane and other
GHGs present an endangerment to public health and the
environment because emissions of such gases are, according to
the EPA, contributing to warming of the earths atmosphere
and other climatic changes. These findings allow the EPA to
adopt and implement regulations that would restrict emissions of
GHGs under existing provisions of the federal CAA. Accordingly,
the EPA has adopted rules regulating GHG emissions from motor
vehicles, thus triggering requirements to permit GHG emissions
from stationary sources under the Prevention of Significant
Deterioration and Title V permitting programs. EPA has
adopted the so-called Tailoring Rule, requiring that
the largest sources first obtain permit for GHG emissions. In
addition, on October 30, 2009, the EPA published a final
rule requiring the reporting of GHG emissions from specified
large GHG emission sources in the United States beginning in
2011 for emissions occurring in 2010. In November 2010, the EPA
expanded its GHG reporting rule to include onshore and offshore
oil and natural gas production, processing, transmission,
storage and distribution facilities. Reporting of GHG emissions
from such facilities is required on an annual basis, with
reporting beginning in 2012 for emissions occurring in 2011.
Although both houses of Congress have actively considered
legislation to reduce emissions of GHGs, no comprehensive
program has been enacted by Congress. Some members of Congress,
however, continue to indicate an intention to promote
legislation to curb EPAs authority to regulate GHGs. In
the absence of a comprehensive federal program, many states,
either individually or through multistate regional initiatives,
are considering or have begun implementing legal measures to
reduce emissions of GHGs. The adoption and implementation of any
regulations imposing reporting obligations on, or limiting
emissions of GHGs from, our equipment and operations could
require us to incur costs to reduce emissions of GHGs associated
with our operations or could adversely affect demand for the oil
and natural gas that we produce.
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Significant
physical effects of climatic change have the potential to damage
our facilities, disrupt our production activities and cause us
to incur significant costs in preparing for or responding to
those effects.
In an interpretative release on climate change disclosures, the
SEC indicates that climate change could have an effect on the
severity of weather (including hurricanes and floods), sea
levels, the arability of farmland, and water availability and
quality. If such effects were to occur, our development and
production operations have the potential to be adversely
affected. Potential adverse effects could include damages to our
facilities from powerful winds or rising waters in low lying
areas, disruption of our production activities either because of
climate related damages to our facilities in our costs of
operation potentially arising from such climatic effects, less
efficient or non-routine operating practices necessitated by
climate effects or increased costs for insurance coverage in the
aftermath of such effects. Significant physical effects of
climate change could also have an indirect effect on our
financing and operations by disrupting the transportation or
process-related services provided by midstream companies,
service companies or suppliers with whom we have a business
relationship. We may not be able to recover through insurance
some or any of the damages, losses or costs that may result from
potential physical effects of climate change.
Federal
legislation and state legislative and regulatory initiatives
relating to hydraulic fracturing could result in increased costs
and additional operating restrictions or delays.
Congress is currently considering the Fracturing Responsibility
and Awareness of Chemicals Act (FRAC Act) that would
amend the Safe Drinking Water Act (SDWA) to repeal
an exemption from regulation for hydraulic fracturing. If
enacted, the FRAC Act would amend the definition of
underground injection in the SDWA to encompass
hydraulic fracturing activities. If enacted, such a provision
could require hydraulic fracturing operations to meet permitting
and financial assurance requirements, adhere to certain
construction specifications, fulfill monitoring, reporting, and
recordkeeping obligations, and meet plugging and abandonment
requirements. The FRAC Act also proposes to require the
reporting and public disclosure of chemicals used in the
fracturing process, which could make it easier for third parties
opposing the hydraulic fracturing process to initiate legal
proceedings based on allegations that specific chemicals used in
the fracturing process could adversely affect groundwater. In
addition, the EPA has commenced a study of the potential adverse
effects that hydraulic fracturing may have on water quality and
public health, and a committee of the U.S. House of
Representatives has commenced its own investigation into
hydraulic fracturing practices. Additionally, many states and
other local regulatory authorities have enacted or are
considering regulations on hydraulic fracturing, including
regulations requiring disclosure of fracturing chemicals or
restricting hydraulic fracturing in certain circumstances. The
adoption of any future federal or state laws or implementing
regulations imposing reporting obligations on, or otherwise
limiting, the hydraulic fracturing process could make it more
difficult to complete oil and natural gas wells and increase our
costs of compliance and doing business.
The
obligations associated with being an SEC reporting company will
require significant resources and management attention, which
could have a material adverse effect on our business and
operating results.
Following the effectiveness of the registration statement of
which this prospectus forms a part, we will become subject to
certain of the reporting requirements of the Securities Exchange
Act of 1934, or the Exchange Act, and the Sarbanes-Oxley Act of
2002, or the Sarbanes-Oxley Act. Under the Exchange Act, we will
be required to file annual, quarterly and current reports with
respect to our business and financial condition. Under the
Sarbanes-Oxley Act, we will be required to, among other things,
establish and maintain effective internal controls and
procedures for financial reporting. As a result, we may incur
significant additional legal, accounting and other expenses that
we have not previously incurred. We anticipate that we may need
to upgrade our systems, implement additional financial and
management controls, reporting systems and procedures, implement
an internal audit function, and hire additional accounting and
internal audit staff. Furthermore, the need to establish the
corporate infrastructure demanded of a reporting company may
divert managements attention from implementing our growth
strategy, which could prevent us from improving our business,
results of operations and financial condition. We have made, and
will continue to make, changes to our internal controls and
procedures for financial reporting and accounting systems to
meet our reporting
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obligations as a stand-alone public company. However, the
measures we take may not be sufficient to satisfy our
obligations as a public company. In addition, we cannot predict
or estimate the amount of additional costs we may incur in order
to comply with these requirements. We anticipate that these
costs will materially increase our general and administrative
expenses.
Section 404 of the Sarbanes-Oxley Act requires annual
management assessments of the effectiveness of our internal
control over financial reporting, starting with the annual
report that we would expect to file with the SEC for the year
ending December 31, 2012. In connection with the
implementation of the necessary procedures and practices related
to internal control over financial reporting, we may identify
additional deficiencies. We may not be able to remediate any
future deficiencies in time to meet the deadline imposed by the
Sarbanes-Oxley Act for compliance with the requirements of
Section 404. In addition, failure to achieve and maintain
an effective internal control environment could have a material
adverse effect on our business.
Our
debt agreements contain restrictive covenants that may limit our
ability to respond to changes in market conditions or pursue
business opportunities.
Our senior secured revolving credit facility and the indenture
for the notes contain restrictive covenants that limit our
ability to, among other things:
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incur or guarantee additional debt;
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make distributions;
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repay subordinated debt prior to its maturity;
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grant additional liens on our assets;
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enter into transactions with our affiliates;
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repurchase equity securities;
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make certain investments or acquisitions of substantially all or
a portion of another entitys business assets; and
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merge with another entity or dispose of our assets.
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In addition, our senior secured revolving credit facility
requires us to maintain certain financial ratios and tests. The
requirement that we comply with these provisions may materially
adversely affect our ability to react to changes in market
conditions, take advantage of business opportunities we believe
to be desirable, obtain future financing, fund needed capital
expenditures or withstand a continuing or future downturn in our
business.
If we
are unable to comply with the restrictions and covenants in our
debt agreements, there could be a default under the terms of
such agreements, which could result in an acceleration of
repayment.
If we are unable to comply with the restrictions and covenants
in our debt agreements, there could be a default under the terms
of these agreements. Our ability to comply with these
restrictions and covenants, including meeting financial ratios
and tests, may be affected by events beyond our control. As a
result, we cannot assure that we will be able to comply with
these restrictions and covenants or meet such financial ratios
and tests. In the event of a default under these agreements,
lenders could terminate their commitments to lend or accelerate
the loans and declare all amounts borrowed due and payable.
Borrowings under other debt instruments that contain
cross-acceleration or cross-default provisions may also be
accelerated and become due and payable. If any of these events
occur, our assets might not be sufficient to repay in full all
of
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our outstanding indebtedness and we may be unable to find
alternative financing. Even if we could obtain alternative
financing, it might not be on terms that are favorable or
acceptable to us. Additionally, we may not be able to amend our
debt agreements or obtain needed waivers on satisfactory terms.
Our
borrowings under our senior secured revolving credit facility
expose us to interest rate risk.
Our earnings are exposed to interest rate risk associated with
borrowings under our senior secured revolving credit facility.
Our senior secured revolving credit facility carries a floating
interest rate based upon short-term interest rate indices. If
interest rates increase, so will our interest costs, which may
have a material adverse effect on our results of operations and
financial condition. We use interest rate hedges in an effort to
mitigate this risk, but those efforts may not prove successful.
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EXCHANGE
OFFER
Purpose
and Effect of the Exchange Offer
At the closing of the offering of the old notes, we entered into
a registration rights agreement with the initial purchasers
pursuant to which we agreed, for the benefit of the holders of
the old notes, at our cost, to do the following:
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file an exchange offer registration statement with the SEC with
respect to the exchange offer for the new notes, and
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use commercially reasonable efforts to have the exchange offer
completed by the
360th day
following the date of the initial issuance of the notes
(October 13, 2010).
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Upon the SECs declaring the exchange offer registration
statement effective, we agreed to offer the new notes in
exchange for surrender of the old notes. We agreed to use
commercially reasonable efforts to cause the exchange offer
registration statement to be effective continuously, and to keep
the exchange offer open for a period of not less than 20
business days.
For each old note surrendered to us pursuant to the exchange
offer, the holder of such old note will receive a new note
having a principal amount equal to that of the surrendered old
note. Interest on each new note will accrue from the last
interest payment date on which interest was paid on the
surrendered old note. The registration rights agreement also
contains agreements to include in the prospectus for the
exchange offer certain information necessary to allow a
broker-dealer who holds old notes that were acquired for its own
account as a result of market-making activities or other
ordinary course trading activities (other than old notes
acquired directly from us or one of our affiliates) to exchange
such old notes pursuant to the exchange offer and to satisfy the
prospectus delivery requirements in connection with resales of
new notes received by such broker-dealer in the exchange offer.
We agreed to use commercially reasonable efforts to maintain the
effectiveness of the exchange offer registration statement for
these purposes for a period ending on the earlier of (i) one
year from the date on which the exchange offer registration
statement is declared effective and (ii) the date on which a
broker-dealer
is no longer required to deliver a prospectus in connection with
market-making
or other trading activities.
The preceding agreement is needed because any broker-dealer who
acquires old notes for its own account as a result of
market-making activities or other trading activities is required
to deliver a prospectus meeting the requirements of the
Securities Act. This prospectus covers the offer and sale of the
new notes pursuant to the exchange offer and the resale of new
notes received in the exchange offer by any broker-dealer who
held old notes acquired for its own account as a result of
market-making activities or other trading activities other than
old notes acquired directly from us or one of our affiliates.
Based on interpretations by the staff of the SEC set forth in
no-action letters issued to third parties, we believe that the
new notes issued pursuant to the exchange offer would in general
be freely tradable after the exchange offer without further
registration under the Securities Act. However, any purchaser of
old notes who is an affiliate of ours or who intends
to participate in the exchange offer for the purpose of
distributing the related new notes:
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will not be able to rely on the interpretation of the staff of
the SEC,
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will not be able to tender its new notes in the exchange offer,
and
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must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with any sale
or transfer of the old notes unless such sale or transfer is
made pursuant to an exemption from such requirements.
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Each holder of the old notes (other than certain specified
holders) who desires to exchange old notes for the new notes in
the exchange offer will be required to make the representations
described below under Your Representations to
Us.
32
We further agreed to file with the SEC a shelf registration
statement to register for public resale of old notes held by any
holder who provides us with certain information for inclusion in
the shelf registration statement if:
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the exchange offer is not permitted by applicable law or SEC
policy, or
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the exchange offer is not for any reason completed by the
360th day
following the date of the initial issuance of the notes
(October 13, 2010), or
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upon completion of the exchange offer, any initial purchaser
shall so request in connection with any offering or sale of
notes.
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We have agreed to use commercially reasonable efforts to keep
the shelf registration statement continuously effective until
the earlier of one year following its effective date and such
time as all notes covered by the shelf registration statement
have been sold. We refer to this period as the shelf
effectiveness period.
The registration rights agreement provides that, in the event
that either the exchange offer is not completed or the shelf
registration statement, if required, is not declared effective
(or does not automatically become effective) on or prior to the
360th
calendar day following the date of the initial issuance of the
notes (October 13, 2010), the interest rate on the old
notes will be increased by 1.00% per annum until the exchange
offer is completed or the shelf registration statement is
declared effective (or automatically becomes effective) under
the Securities Act, at which time the increased interest shall
cease to accrue.
If the shelf registration statement has been declared effective
(or automatically becomes effective) and thereafter either
ceases to be effective or the prospectus contained therein
ceases to be usable for resales of the notes at any time during
the shelf effectiveness period, and such failure to remain
effective or usable for resales of the notes exists for more
than 45 calendar days in any three-month period (whether or not
consecutive) or 90 calendar days (whether or not consecutive) in
any 12-month
period, then the interest rate on the old notes will be
increased by 1.00% per annum commencing on the
46th day
or 91st
day, respectively, in such period and ending on such date that
the shelf registration statement has again been declared (or
automatically becomes) effective or the prospectus again becomes
usable, at which time the increased interest shall cease to
accrue.
Holders of the old notes will be required to make certain
representations to us (as described in the registration rights
agreement) in order to participate in the exchange offer and
will be required to deliver information to be used in connection
with the shelf registration statement and to provide comments on
the shelf registration statement within the time periods set
forth in the registration rights agreement in order to have
their old notes included in the shelf registration statement.
If we effect the registered exchange offer, we will be entitled
to close the registered exchange offer 20 business days after
its commencement as long as we have accepted all old notes
validly rendered in accordance with the terms of the exchange
offer.
This summary of the material provisions of the registration
rights agreement does not purport to be complete and is subject
to, and is qualified in its entirety by reference to, all the
provisions of the registration rights agreement, a copy of which
is filed as an exhibit to the registration statement which
includes this prospectus.
Except as set forth above, after consummation of the exchange
offer, holders of old notes which are the subject of the
exchange offer have no registration or exchange rights under the
registration rights agreement. See Consequences of
Failure to Exchange.
Terms of
the Exchange Offer
Subject to the terms and conditions described in this prospectus
and in the letter of transmittal, we will accept for exchange
any old notes properly tendered and not withdrawn prior to
5:00 p.m. New York City time on the expiration date. We
will issue new notes in principal amount equal to the principal
amount of old notes
33
surrendered in the exchange offer. Old notes may be tendered
only for new notes and only in minimum denominations of $2,000
and integral multiples of $1,000 in excess thereof.
The exchange offer is not conditioned upon any minimum aggregate
principal amount of old notes being tendered for exchange.
As of the date of this prospectus, $300,000,000 in aggregate
principal amount of the old notes is outstanding. This
prospectus and the letter of transmittal are being sent to all
registered holders of old notes. There will be no fixed record
date for determining registered holders of old notes entitled to
participate in the exchange offer.
We intend to conduct the exchange offer in accordance with the
provisions of the registration rights agreement, the applicable
requirements of the Securities Act and the Exchange Act and the
rules and regulations of the SEC. Old notes that the holders
thereof do not tender for exchange in the exchange offer will
remain outstanding and continue to accrue interest. These old
notes will continue to be entitled to the rights and benefits
such holders have under the indenture relating to the notes.
We will be deemed to have accepted for exchange properly
tendered old notes when we have given oral or written notice of
the acceptance to the exchange agent and complied with the
applicable provisions of the registration rights agreement. The
exchange agent will act as agent for the tendering holders for
the purposes of receiving the new notes from us.
If you tender old notes in the exchange offer, you will not be
required to pay brokerage commissions or fees or, subject to the
letter of transmittal, transfer taxes with respect to the
exchange of old notes. We will pay all charges and expenses,
other than certain applicable taxes described below, in
connecting with the exchange offer. It is important that you
read the section labeled Fees and Expenses
for more details regarding fees and expenses incurred in the
exchange offer.
We will return any old notes that we do not accept for exchange
for any reason without expense to their tendering holder
promptly after the expiration or termination of the exchange
offer.
Expiration
Date
The exchange offer will expire at 5:00 p.m., New York City
time, on August 11, 2011, unless, in our sole discretion,
we extend it.
Extensions,
Delays in Acceptance, Termination or Amendment
We expressly reserve the right, at any time or various times, to
extend the period of time during which the exchange offer is
open. We may delay acceptance of any old notes by giving oral or
written notice of such extension to their holders. During any
such extensions, all old notes previously tendered will remain
subject to the exchange offer, and we may accept them for
exchange.
In order to extend the exchange offer, we will notify the
exchange agent orally or in writing of any extension. We will
notify the registered holders of old notes of the extension no
later than 9:00 a.m., New York City time, on the first
business day following the previously scheduled expiration date.
If any of the conditions described below under
Conditions to the Exchange Offer have not been satisfied,
we reserve the right, in our sole discretion:
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to extend the exchange offer, or
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to terminate the exchange offer,
|
by giving oral or written notice of such delay, extension or
termination to the exchange agent. Subject to the terms of the
registration rights agreement, we also reserve the right to
amend the terms of the exchange offer in any manner.
Any extension, termination or amendment will be followed
promptly by oral or written notice thereof to the registered
holders of old notes. If we amend the exchange offer in a manner
that we determine to
34
constitute a material change, we will promptly disclose such
amendment by means of a prospectus supplement. The supplement
will be distributed to the registered holders of the old notes.
Depending upon the significance of the amendment and the manner
of disclosure to the registered holders, we may extend the
exchange offer. In the event of a material change in the
exchange offer, including the waiver by us of a material
condition, we will extend the exchange offer period if necessary
so that at least five business days remain in the exchange offer
following notice of the material change.
Conditions
to the Exchange Offer
We will not be required to accept for exchange, or exchange any
new notes for, any old notes if the exchange offer, or the
making of any exchange by a holder of old notes, would violate
applicable law or any applicable interpretation of the staff of
the SEC. Similarly, we may terminate the exchange offer as
provided in this prospectus before accepting old notes for
exchange in the event of such a potential violation.
In addition, we will not be obligated to accept for exchange the
old notes of any holder that has not made to us the
representations described under Purpose and Effect
of the Exchange Offer, Your Representations
to Us and Plan of Distribution and such other
representations as may be reasonably necessary under applicable
SEC rules, regulations or interpretations to allow us to use an
appropriate form to register the new notes under the Securities
Act.
We expressly reserve the right to amend or terminate the
exchange offer, and to reject for exchange any old notes not
previously accepted for exchange, upon the occurrence of any of
the conditions to the exchange offer specified above. We will
give prompt oral or written notice of any extension, amendment,
non-acceptance or termination to the holders of the old notes as
promptly as practicable.
These conditions are for our sole benefit, and we may assert
them or waive them in whole or in part at any time or at various
times in our sole discretion. If we fail at any time to exercise
any of these rights, this failure will not mean that we have
waived our rights. Each such right will be deemed an ongoing
right that we may assert at any time or at various times.
In addition, we will not accept for exchange any old notes
tendered, and will not issue new notes in exchange for any such
old notes, if at such time any stop order has been threatened or
is in effect with respect to the registration statement of which
this prospectus constitutes a part or the qualification of the
indenture relating to the notes under the Trust Indenture
Act of 1939.
Procedures
for Tendering
In order to participate in the exchange offer, you must properly
tender your old notes to the exchange agent as described below.
It is your responsibility to properly tender your notes. We have
the right to waive any defects. However, we are not required to
waive defects and are not required to notify you of defects in
your tender.
If you have any questions or need help in exchanging your notes,
please call the exchange agent, whose contact information is set
forth in Prospectus Summary The Exchange
Offer Exchange Agent.
All of the old notes were issued in book-entry form, and all of
the old notes are currently represented by global certificates
held for the account of DTC. We have confirmed with DTC that the
old notes may be tendered using the Automated Tender Offer
Program (ATOP) instituted by DTC. The exchange agent
will establish an account with DTC for purposes of the exchange
offer promptly after the commencement of the exchange offer and
DTC participants may electronically transmit their acceptance of
the exchange offer by causing DTC to transfer their old notes to
the exchange agent using the ATOP procedures. In connection with
the transfer, DTC will send an agents message
to the exchange agent. The agents message will state that
DTC has received instructions from the participant to tender old
notes and that the participant agrees to be bound by the terms
of the letter of transmittal.
By using the ATOP procedures to exchange old notes, you will not
be required to deliver a letter of transmittal to the exchange
agent. However, you will be bound by its terms just as if you
had signed it.
There is no procedure for guaranteed late delivery of the notes.
35
Determinations
Under the Exchange Offer
We will determine in our sole discretion all questions as to the
validity, form, eligibility, time of receipt, acceptance of
tendered old notes and withdrawal of tendered old notes. Our
determination will be final and binding. We reserve the absolute
right to reject any old notes not properly tendered or any old
notes our acceptance of which would, in the opinion of our
counsel, be unlawful. We also reserve the right to waive any
defect, irregularities or conditions of tender as to particular
old notes. Our interpretation of the terms and conditions of the
exchange offer, including the instructions in the letter of
transmittal, will be final and binding on all parties. Unless
waived, all defects or irregularities in connection with tenders
of old notes must be cured within such time as we shall
determine. Although we intend to notify holders of defects or
irregularities with respect to tenders of old notes, neither we,
the exchange agent nor any other person will incur any liability
for failure to give such notification. Tenders of old notes will
not be deemed made until such defects or irregularities have
been cured or waived. Any old notes received by the exchange
agent that are not properly tendered and as to which the defects
or irregularities have not been cured or waived will be returned
to the tendering holder, unless otherwise provided in the letter
of transmittal, promptly following the expiration date.
When We
Will Issue New Notes
In all cases, we will issue new notes for old notes that we have
accepted for exchange under the exchange offer only after the
exchange agent timely receives:
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a book-entry confirmation of such old notes into the exchange
agents account at DTC; and
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a properly transmitted agents message.
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Return of
Old Notes Not Accepted or Exchanged
If we do not accept any tendered old notes for exchange or if
old notes are submitted for a greater principal amount than the
holder desires to exchange, the unaccepted or non-exchanged old
notes will be returned without expense to their tendering
holder. Such non-exchanged old notes will be credited to an
account maintained with DTC. These actions will occur promptly
after the expiration or termination of the exchange offer.
Your
Representations to Us
By agreeing to be bound by the letter of transmittal, you will
represent to us that, among other things:
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any new notes that you receive will be acquired in the ordinary
course of your business;
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you have no arrangement or understanding with any person or
entity to participate in the distribution of the new notes;
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you are not our affiliate, as defined in
Rule 405 of the Securities Act; and
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if you are a broker-dealer that will receive new notes for your
own account in exchange for old notes, you acquired those notes
as a result of market-making activities or other trading
activities and you will deliver a prospectus (or to the extent
permitted by law, make available a prospectus) in connection
with any resale of such new notes.
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Withdrawal
of Tenders
Except as otherwise provided in this prospectus, you may
withdraw your tender at any time prior to 5:00 p.m. New
York City time on the expiration date. For a withdrawal to be
effective you must comply with the appropriate procedures of
DTCs ATOP system. Any notice of withdrawal must specify
the name and number of the account at DTC to be credited with
withdrawn old notes and otherwise comply with the procedures of
DTC.
We will determine all questions as to the validity, form,
eligibility and time of receipt of notice of withdrawal. Our
determination shall be final and binding on all parties. We will
deem any old notes so withdrawn not to have been validly
tendered for exchange for purposes of the exchange offer.
Any old notes that have been tendered for exchange but are not
exchanged for any reason will be credited to an account
maintained with DTC for the old notes. This crediting will take
place as soon as practicable
36
after withdrawal, rejection of tender or termination of the
exchange offer. You may retender properly withdrawn old notes by
following the procedures described under Procedures
for Tendering above at any time prior to 5:00 p.m.,
New York City time, on the expiration date.
Fees and
Expenses
We will bear the expenses of soliciting tenders. The principal
solicitation is being made by mail; however, we may make
additional solicitation by facsimile, telephone, electronic mail
or in person by our officers and regular employees and those of
our affiliates.
We have not retained any dealer-manager in connection with the
exchange offer and will not make any payments to broker-dealers
or others soliciting acceptances of the exchange offer. We will,
however, pay the exchange agent reasonable and customary fees
for its services and reimburse it for its related reasonable
out-of-pocket
expenses.
We will pay the cash expenses to be incurred in connection with
the exchange offer. They include:
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all registration and filing fees and expenses;
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all fees and expenses of compliance with federal securities and
state blue sky or securities laws;
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accounting fees, legal fees incurred by us, disbursements and
printing, messenger and delivery services, and telephone costs;
and
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related fees and expenses.
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Transfer
Taxes
We will pay all transfer taxes, if any, applicable to the
exchange of old notes under the exchange offer. The tendering
holder, however, will be required to pay any transfer taxes,
whether imposed on the registered holder or any other person, if
a transfer tax is imposed for any reason other than the exchange
of old notes under the exchange offer.
Consequences
of Failure to Exchange
If you do not exchange new notes for your old notes under the
exchange offer, you will remain subject to the existing
restrictions on transfer of the old notes. In general, you may
not offer or sell the old notes unless the offer or sale is
either registered under the Securities Act or exempt from the
registration under the Securities Act and applicable state
securities laws. Except as required by the registration rights
agreement, we do not intend to register resales of the old notes
under the Securities Act.
Accounting
Treatment
We will record the new notes in our accounting records at the
same carrying value as the old notes. This carrying value is the
aggregate principal amount of the old notes adjusted for any
bond discount or premium, as reflected in our accounting records
on the date of exchange. Accordingly, we will not recognize any
gain or loss for accounting purposes in connection with the
exchange offer.
Other
Participation in the exchange offer is voluntary, and you should
carefully consider whether to accept. You are urged to consult
your financial and tax advisors in making your own decision on
what action to take.
We may in the future seek to acquire untendered old notes in
open market or privately negotiated transactions, through
subsequent exchange offers or otherwise. We have no present
plans to acquire any old notes that are not tendered in the
exchange offer or to file a registration statement to permit
resales of any untendered old notes.
37
USE OF
PROCEEDS
The exchange offer is intended to satisfy our obligations under
the registration rights agreement. We will not receive any
proceeds from the issuance of the new notes in the exchange
offer. In consideration for issuing the new notes as
contemplated by this prospectus, we will receive old notes in a
like principal amount. The form and terms of the new notes are
identical in all respects to the form and terms of the old
notes, except the new notes will be registered under the
Securities Act and will not contain restrictions on transfer,
registration rights or provisions for additional interest. Old
notes surrendered in exchange for the new notes will be retired
and cancelled and will not be reissued. Accordingly, the
issuance of the new notes will not result in any change in our
outstanding indebtedness.
38
SELECTED
HISTORICAL FINANCIAL AND OTHER DATA
The following table presents our summary historical financial
data for the periods indicated, giving effect to the Meridian
acquisition from the acquisition date of May 13, 2010. The
data as of and for the years ended December 31, 2010, 2009,
2008, 2007 and 2006 have been derived from our audited
consolidated financial statements. The data as of and for the
three months ended March 31, 2011 and 2010 have been
derived from our unaudited consolidated financial statements.
For further information that will help you better understand the
summary data, you should read this financial data in conjunction
with Managements Discussion and Analysis of
Financial Condition and Results of Operations and the
consolidated financial statements and related notes and other
financial information included elsewhere in this prospectus.
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|
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Three Months Ended
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March 31,
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Year Ended December 31,
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2011
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2010
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2010
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|
2009
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|
2008
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|
2007
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|
2006
|
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|
(Unaudited)
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(Dollars in thousands)
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|
Statement of Operations Data:
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Revenues
|
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Natural gas, oil and natural gas liquids
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$
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70,631
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$
|
38,065
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$
|
208,537
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|
|
$
|
102,263
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|
|
$
|
98,983
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|
|
$
|
56,746
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|
|
$
|
40,902
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Other revenues
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|
469
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|
|
21
|
|
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|
1,475
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|
|
|
1,558
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|
|
|
3,629
|
|
|
|
12,036
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|
|
|
472
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
71,100
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|
|
|
38,086
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|
|
|
210,012
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|
|
|
103,821
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|
|
|
102,612
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|
|
|
68,782
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|
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|
41,374
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Unrealized gain (loss) oil and natural gas
derivative contracts
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|
|
(19,184
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)
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|
|
20,803
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|
|
10,088
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|
|
|
(26,258
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)
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|
60,612
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|
|
|
(14,457
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)
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|
17,867
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|
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|
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Total revenues
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|
$
|
51,916
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|
|
$
|
58,889
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|
|
$
|
220,100
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|
|
$
|
77,563
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|
|
$
|
163,224
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|
|
$
|
54,325
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|
|
$
|
59,241
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|
Costs and expenses:
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Lease and plant operating expense
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|
|
13,331
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|
|
|
8,078
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|
|
|
41,905
|
|
|
|
23,871
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|
|
|
20,658
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|
|
|
14,642
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|
|
|
12,046
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|
Production and ad valorem taxes
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|
|
5,401
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|
|
|
1,613
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|
|
|
11,141
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|
|
|
4,755
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|
|
|
6,954
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|
|
|
4,406
|
|
|
|
3,393
|
|
Workover expense
|
|
|
1,626
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|
|
|
1,959
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|
|
|
7,409
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|
|
|
8,988
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|
|
|
8,113
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|
|
|
7,825
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|
|
|
6,635
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|
Exploration expense
|
|
|
2,731
|
|
|
|
2,921
|
|
|
|
31,037
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|
|
|
12,839
|
|
|
|
11,675
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|
|
|
9,743
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|
|
|
1,303
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|
Depreciation, depletion, and amortization
|
|
|
19,468
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|
|
|
8,622
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|
|
|
59,090
|
|
|
|
48,659
|
|
|
|
49,219
|
|
|
|
31,298
|
|
|
|
11,340
|
|
Impairment expense
|
|
|
5,826
|
|
|
|
1,450
|
|
|
|
8,399
|
|
|
|
6,165
|
|
|
|
11,487
|
|
|
|
1,449
|
|
|
|
1,007
|
|
Accretion expense
|
|
|
470
|
|
|
|
145
|
|
|
|
1,370
|
|
|
|
492
|
|
|
|
729
|
|
|
|
627
|
|
|
|
538
|
|
General and administrative expense
|
|
|
5,751
|
|
|
|
2,223
|
|
|
|
20,135
|
|
|
|
8,738
|
|
|
|
6,401
|
|
|
|
5,321
|
|
|
|
3,617
|
|
Gain on sale of assets
|
|
|
|
|
|
|
|
|
|
|
(1,766
|
)
|
|
|
(738
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
54,604
|
|
|
|
27,011
|
|
|
|
178,720
|
|
|
|
113,769
|
|
|
|
115,236
|
|
|
|
75,311
|
|
|
|
39,879
|
|
Income (loss) from operations
|
|
|
(2,688
|
)
|
|
|
31,878
|
|
|
|
41,380
|
|
|
|
(36,206
|
)
|
|
|
47,988
|
|
|
|
(20,986
|
)
|
|
|
19,362
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(9,478
|
)
|
|
|
(4,199
|
)
|
|
|
(27,149
|
)
|
|
|
(13,831
|
)
|
|
|
(14,457
|
)
|
|
|
(10,792
|
)
|
|
|
(9,509
|
)
|
Gain on extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,349
|
|
|
|
4,302
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(9,478
|
)
|
|
|
(4,199
|
)
|
|
|
(27,149
|
)
|
|
|
(13,831
|
)
|
|
|
(11,108
|
)
|
|
|
(6,490
|
)
|
|
|
(9,509
|
)
|
(Provision) benefit for state income taxes
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
750
|
|
|
|
(250
|
)
|
|
|
(500
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(12,166
|
)
|
|
$
|
27,679
|
|
|
$
|
14,229
|
|
|
$
|
(49,287
|
)
|
|
$
|
36,630
|
|
|
$
|
(27,976
|
)
|
|
$
|
9,853
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
58,951
|
|
|
$
|
13,226
|
|
|
$
|
110,083
|
|
|
$
|
100,261
|
|
|
$
|
111,096
|
|
|
$
|
89,604
|
|
|
$
|
38,720
|
|
Net cash flow provided by operating activities
|
|
|
45,642
|
|
|
|
(1,351
|
)
|
|
|
61,120
|
|
|
|
34,343
|
|
|
|
20,300
|
|
|
|
38,618
|
|
|
|
868
|
|
Net cash used in investing activities(1)
|
|
|
(58,951
|
)
|
|
|
(13,226
|
)
|
|
|
(208,412
|
)
|
|
|
(86,573
|
)
|
|
|
(111,096
|
)
|
|
|
(98,604
|
)
|
|
|
(38,720
|
)
|
Net cash provided by financing activities
|
|
|
14,000
|
|
|
|
14,975
|
|
|
|
147,854
|
|
|
|
51,823
|
|
|
|
78,771
|
|
|
|
71,596
|
|
|
|
42,185
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
5,527
|
|
|
$
|
4,672
|
|
|
$
|
4,836
|
|
|
$
|
4,274
|
|
|
$
|
4,681
|
|
|
$
|
16,706
|
|
|
$
|
5,096
|
|
Property and equipment, net
|
|
|
469,314
|
|
|
|
243,493
|
|
|
|
456,264
|
|
|
|
236,196
|
|
|
|
201,327
|
|
|
|
132,719
|
|
|
|
74,672
|
|
Total assets
|
|
|
549,912
|
|
|
|
322,142
|
|
|
|
558,239
|
|
|
|
290,606
|
|
|
|
277,111
|
|
|
|
175,157
|
|
|
|
102,743
|
|
Total debt, including Notes to Founder
|
|
|
405,348
|
|
|
|
235,123
|
|
|
|
390,985
|
|
|
|
219,830
|
|
|
|
188,228
|
|
|
|
123,244
|
|
|
|
95,108
|
|
Total partners capital (deficit)
|
|
|
12,492
|
|
|
|
38,318
|
|
|
|
24,658
|
|
|
|
10,664
|
|
|
|
37,751
|
|
|
|
(11,661
|
)
|
|
|
(25,399
|
)
|
|
|
|
(1) |
|
Net cash used in investing activities includes
$101.4 million for acquisition of Meridian in the year
ended December 31, 2010. |
39
RATIO OF
EARNINGS TO FIXED CHARGES
The following table sets forth our ratios of earnings to fixed
charges for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended
|
|
Year Ended December 31,
|
|
|
March 31, 2011
|
|
2010
|
|
2009
|
|
2008
|
|
2007
|
|
2006
|
|
Ratio of earnings to fixed charges(1)
|
|
|
|
|
|
|
1.59
|
|
|
|
|
|
|
|
5.00
|
|
|
|
|
|
|
|
2.01
|
|
|
|
|
(1) |
|
The ratio of earnings to fixed charges is calculated by dividing
(i) earnings by (ii) fixed charges. Earnings consist
of pre-tax income from continuing operations before fixed
charges. Fixed charges consist of interest expense, including
amortization of discount on the notes, amortization of
capitalized costs related to debt, and an estimate of the
interest within rental expense. Earnings were inadequate to
cover fixed charges for the three months ended March 31,
2011 and for the years ended December 31, 2007 and 2009 by
$12 million, $27 million and $50 million,
respectively. |
40
MANAGEMENTS
DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in
conjunction with the Selected Historical Financial and
Other Data and the financial statements and related notes
included elsewhere in this prospectus. The following discussion
and analysis contains forward-looking statements that reflect
our future plans, estimates, beliefs and expected performance.
The forward-looking statements are dependent upon events, risks
and uncertainties that may be outside our control. Our actual
results could differ materially from those discussed in these
forward-looking statements. Factors that could cause or
contribute to such differences include, but are not limited to,
the volatility of oil and natural gas prices, production timing
and volumes, estimates of proved reserves, operating costs and
capital expenditures, economic and competitive conditions,
regulatory changes and other uncertainties, as well as those
factors discussed below and elsewhere in this prospectus,
particularly in Risk Factors and Cautionary
Statement Regarding Forward-Looking Statements, all of
which are difficult to predict. As a result of these risks,
uncertainties and assumptions, the forward-looking events
discussed may not occur. The historical financial information
discussed below in this Managements Discussion and
Analysis of Financial Condition and Results of Operations
represents Alta Mesas financial information for the
periods indicated, giving effect to the Meridian acquisition
from the acquisition date of May 13, 2010.
Overview
We currently generate significant amounts of our revenue,
earnings and cash flow from the production and sale of oil and
natural gas from our core properties in South Louisiana, East
Texas, Oklahoma, the Deep Bossier resource play of East Texas
and Eagle Ford Shale play in South Texas. We operate in one
industry segment, oil and natural gas exploration and
development, within one geographical segment, the United States.
The amount of cash we generate from our operations will
fluctuate based on, among other things:
|
|
|
|
|
the prices at which we will sell our production;
|
|
|
|
the amount of oil and natural gas we produce; and
|
|
|
|
the level of our operating and administrative costs.
|
In order to mitigate the impact of changes in oil and natural
gas prices on our cash flows, we are a party to hedging and
other price protection contracts, and we intend to enter into
such transactions in the future to reduce the effect of oil and
natural gas price volatility on our cash flows.
Substantially all of our oil and natural gas activities are
conducted jointly with others and, accordingly, amounts
presented reflect our proportionate interest in such activities.
Inflation has not had a material impact on our results of
operations and is not expected to have a material impact on our
consolidated results of operations in the future.
Significant
Acquisitions
On April 21, 2011, we completed the purchase of certain oil
and natural gas assets primarily located in Texas and South
Louisiana in which we had shared interests from Sydson Energy
and certain of its related parties for $27.5 million. Total
net proved reserves acquired are estimated to be 800 MBOE
(5 Bcfe), 45% of which is oil. By virtue of this
acquisition, we increased our after payout net revenue interest
in the Eagle Ford Shale by over 50%. Funding for the acquisition
was provided through our credit facility. In addition,
litigation associated with a portion of the assets purchased was
resolved as a result of the transaction.
On June 17, 2011, we completed the purchase of certain oil
and natural gas assets primarily located in Texas and South
Louisiana in which we had shared interests from TODD and certain
other parties for $22.5 million. Total net proved reserves
acquired are estimated to be 700 MBOE (4 Bcfe), 36% of
which is oil. By virtue of this acquisition, we increased our
after payout net revenue interest in the Eagle Ford Shale by
another 15%. Funding for the acquisition was provided through
our credit facility. In addition, litigation associated with
TODD was resolved as a result of the transaction.
41
On May 13, 2010, we acquired The Meridian Resource
Corporation, a public exploration and production company with
properties in or proximate to our own areas of operation and
with proved reserves of 75 Bcfe as of December 31, 2009,
for approximately $158 million. The acquisition was funded
with borrowings under our senior secured revolving credit
facility as well as a $50 million equity contribution from
our private equity partner, AMIH. As a result of the
acquisition, as of June 30, 2010, we increased total proved
reserves 36% and have achieved a more balanced portfolio mix by
increasing our total proved oil reserves by 69%. We also believe
the acquisition gives us significant growth potential by
increasing our proved undeveloped reserves by 51% as compared to
undeveloped reserves at December 31, 2009 and adding a
large library of
3-D and
2-D seismic
data, much of which we are reprocessing and utilizing for the
exploitation of known fields and identification and development
of new prospects in certain of our operating areas.
On July 23, 2009, we made a payment of $25.5 million
and took assignment of substantially all working interests that
had been held by Chesapeake Energy Corporation in an approximate
50,000 acre area of Leon and Robertson Counties, Texas in the
Deep Bossier play. We had exercised our preferential right to
purchase these interests from Gastar Exploration Ltd. in late
2005, but Gastar and Chesapeake had opposed this and Chesapeake
took record title until we finally and conclusively prevailed,
and in 2008 a Texas court of appeals directed that specific
performance take place. In early 2009, the Texas Supreme Court
denied the defendants request to hear the appeal. As a
result, we were able to take working interests in over 30
producing wells and participate in further development of the
area, primarily with EnCana, but also with Gastar. A subsequent
payment to EnCana of $15.2 million plus purchase accounting
adjustments of $3.8 million brought the total cost of the
acquisition to $44.5 million. While the ownership of these
interests has been decided by the courts, we are pursuing other
claims against Chesapeake; Chesapeake is claiming an additional
$36.5 million of past expenses from us.
Outlook
The U.S. and other world economies suffered a severe recession
lasting well into 2009 and economic conditions remain uncertain.
These uncertain economic conditions reduced demand for oil and
natural gas, resulting in a decline in oil and natural gas
prices received for our production in 2009 compared with years
prior to and including 2008. In response to these lower oil and
natural gas prices, we, along with many other oil and natural
gas companies, scaled back our drilling programs.
While oil and natural gas prices strengthened in 2010 and the
first quarter of 2011, they remain unstable and we expect them
to remain volatile in the future. Factors affecting the price of
oil include worldwide economic conditions, geopolitical
activities, worldwide supply disruptions, weather conditions,
actions taken by the Organization of Petroleum Exporting
Countries and the value of the U.S. dollar in international
currency markets. Factors affecting the price of natural gas
include industrial demand for natural gas, power generation
demand for natural gas, residential and commercial demand for
natural gas, each of which is influenced to some degree by the
U.S. and global economy as well as North American weather
conditions; storage levels of natural gas; the availability and
accessibility of natural gas deposits in North America; and the
effects of international natural gas demand on the import and
export of liquefied natural gas. If the global economic
instability continues, commodity prices may be depressed for an
extended period of time, which could alter our development plans
and adversely affect our growth strategy and our ability to
access additional funding in the capital markets.
The primary factors affecting our production levels are capital
availability, the effectiveness and efficiency of our production
operations, the success of our drilling program and our
inventory of drilling prospects. We inherently face the
challenge of natural production declines as reservoirs are
depleted, pressures decline, and the rate of production from a
given well decreases. We attempt to overcome the cumulative
effects of these natural declines primarily through developing
our existing undeveloped reserves through drilling, enhanced
completions and well recompletions, and other enhanced recovery
methods. Our future growth will depend on our ability to
continue to add reserves in excess of production. Our ability to
add reserves is dependent on our capital resources and can be
limited by many factors, including our ability to timely obtain
drilling permits and regulatory approvals. Any delays in
drilling, completing or connecting our new wells to gathering
lines
42
will negatively affect our production, which will have an
adverse effect on our revenues and, as a result, cash flow from
operations.
Results
of Operations: Three Months Ended March 31, 2011 v.
Three Months Ended March 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
|
|
|
|
|
|
|
Ended March 31,
|
|
|
Increase
|
|
|
|
|
|
|
2011
|
|
|
2010
|
|
|
(Decrease)
|
|
|
% Change
|
|
|
|
($ in thousands, except average sales price and unit
costs)
|
|
|
Summary Operating Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
7,366
|
|
|
|
4,970
|
|
|
|
2,396
|
|
|
|
48
|
%
|
Oil (MBbls)
|
|
|
348
|
|
|
|
122
|
|
|
|
226
|
|
|
|
185
|
%
|
Natural gas liquids (MBbls)
|
|
|
58
|
|
|
|
13
|
|
|
|
45
|
|
|
|
346
|
%
|
Total natural gas equivalent (MMcfe)
|
|
|
9,803
|
|
|
|
5,783
|
|
|
|
4,020
|
|
|
|
70
|
%
|
Average daily gas production (MMcfe per day)
|
|
|
108.9
|
|
|
|
64.3
|
|
|
|
44.6
|
|
|
|
70
|
%
|
Average Sales Price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) realized
|
|
$
|
4.80
|
|
|
$
|
5.60
|
|
|
$
|
(0.80
|
)
|
|
|
(14
|
)%
|
Natural gas (per Mcf) unhedged
|
|
|
4.02
|
|
|
|
5.04
|
|
|
|
(1.02
|
)
|
|
|
(20
|
)%
|
Oil (per Bbl) realized
|
|
|
92.44
|
|
|
|
77.97
|
|
|
|
14.47
|
|
|
|
19
|
%
|
Oil (per Bbl) unhedged
|
|
|
96.70
|
|
|
|
76.02
|
|
|
|
20.68
|
|
|
|
27
|
%
|
Natural gas liquids (per Bbl) realized(1)
|
|
|
52.88
|
|
|
|
54.26
|
|
|
|
(1.38
|
)
|
|
|
(3
|
)%
|
Combined (per Mcfe) realized
|
|
|
7.21
|
|
|
|
6.58
|
|
|
|
0.63
|
|
|
|
10
|
%
|
Hedging Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized natural gas revenue gain
|
|
$
|
5,791
|
|
|
$
|
2,749
|
|
|
$
|
3,042
|
|
|
|
111
|
%
|
Realized oil revenue gain (loss)
|
|
|
(1,484
|
)
|
|
|
237
|
|
|
|
(1,721
|
)
|
|
|
(726
|
)%
|
Summary Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
$
|
35,381
|
|
|
$
|
27,815
|
|
|
$
|
7,566
|
|
|
|
27
|
%
|
Oil
|
|
|
32,197
|
|
|
|
9,521
|
|
|
|
22,676
|
|
|
|
238
|
%
|
Natural gas liquids
|
|
|
3,053
|
|
|
|
729
|
|
|
|
2,324
|
|
|
|
319
|
%
|
Other revenues
|
|
|
469
|
|
|
|
21
|
|
|
|
448
|
|
|
|
2,133
|
%
|
Unrealized gain (loss) oil and natural gas
derivative contracts
|
|
|
(19,184
|
)
|
|
|
20,803
|
|
|
|
(39,987
|
)
|
|
|
(192
|
)%
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease and plant operating expense
|
|
|
13,331
|
|
|
|
8,078
|
|
|
|
5,253
|
|
|
|
65
|
%
|
Production and ad valorem taxes
|
|
|
5,401
|
|
|
|
1,613
|
|
|
|
3,788
|
|
|
|
235
|
%
|
Workover expense
|
|
|
1,626
|
|
|
|
1,959
|
|
|
|
(333
|
)
|
|
|
(17
|
)%
|
Exploration expense
|
|
|
2,731
|
|
|
|
2,921
|
|
|
|
(190
|
)
|
|
|
(7
|
)%
|
Depreciation, depletion, and amortization
|
|
|
19,468
|
|
|
|
8,622
|
|
|
|
10,846
|
|
|
|
126
|
%
|
Impairment expense
|
|
|
5,826
|
|
|
|
1,450
|
|
|
|
4,376
|
|
|
|
302
|
%
|
Accretion expense
|
|
|
470
|
|
|
|
145
|
|
|
|
325
|
|
|
|
224
|
%
|
General and administrative expense
|
|
|
5,751
|
|
|
|
2,223
|
|
|
|
3,528
|
|
|
|
159
|
%
|
Interest expense, net
|
|
|
9,478
|
|
|
|
4,199
|
|
|
|
5,279
|
|
|
|
126
|
%
|
(Benefit from) provision for state income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(12,166
|
)
|
|
$
|
27,679
|
|
|
$
|
(39,845
|
)
|
|
|
(144
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Unit Costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease and plant operating expense
|
|
$
|
1.36
|
|
|
$
|
1.40
|
|
|
$
|
(0.04
|
)
|
|
|
(3
|
)%
|
Production and ad valorem taxes
|
|
|
0.55
|
|
|
|
0.28
|
|
|
|
0.27
|
|
|
|
96
|
%
|
Workover expense
|
|
|
0.17
|
|
|
|
0.34
|
|
|
|
(0.17
|
)
|
|
|
(50
|
)%
|
Exploration expense
|
|
|
0.28
|
|
|
|
0.51
|
|
|
|
(0.23
|
)
|
|
|
(45
|
)%
|
Depreciation, depletion and amortization
|
|
|
1.99
|
|
|
|
1.49
|
|
|
|
0.50
|
|
|
|
34
|
%
|
General and administrative expense
|
|
|
0.59
|
|
|
|
0.38
|
|
|
|
0.21
|
|
|
|
55
|
%
|
43
|
|
|
(1) |
|
We do not utilize hedges for natural gas liquids. |
Revenues
Natural gas revenues for the three months ended
March 31, 2011 were $35.4 million, compared to
$27.8 million for the same period in 2010, representing a
$7.6 million or 27% increase. The increase in revenue was
attributable to increased production volumes partially offset by
a lower average realized price during the three months ended
March 31, 2011. Approximately $13.4 million of the
increase was due to an increase in production of 2.4 Bcf,
or 48%. This increase in turn was primarily due to the addition
of production from our Meridian acquisition acquired in May
2010, as well as the production attributable to drilling
activity during the second half of 2010. Natural gas production
attributable to the acquisition of Meridian for the first
quarter of 2011 was 1.6 Bcf. Production from our Deep
Bossier properties increased approximately 1 Bcf for the
first quarter of 2011 as compared to the corresponding prior
year period. The price of gas we received exclusive of hedging
decreased 20% in the first quarter of 2011, as did the overall
realized price (including hedging gains and losses), which
decreased from $5.60 per Mcf in the first quarter of 2010 to
$4.80 per Mcf for the same period in 2011, resulting in a
decrease in revenues of approximately $5.8 million.
Oil revenues for the three months ended March 31,
2011 increased $22.7 million, or 238%, to
$32.2 million from $9.5 million in the three months
ended March 31, 2010. The increase in revenue was due to
higher production volumes coupled with a higher realized average
price received. Oil production for the first quarter of 2011
increased to 348 MBbls from 122 MBbls for the same
period in 2010, an increase of 185%. Of this, 221 MBbls
were attributable to the acquisition of Meridian. During the
three months ended March 31, 2011, our average realized oil
price increased 19% to $92.44 per Bbl from $77.97 per Bbl in the
first quarter of 2010, primarily due to higher market prices
before hedging gains and losses. Market oil prices realized
exclusive of hedging activities increased 27%, from $76.02 per
Bbl to $96.70 per Bbl.
Natural gas liquids revenues increased during the first
quarter of 2011 to $3.1 million from $0.7 million for
the first quarter of 2010. The increase was primarily due to an
increase in volume sold, from 13 MBbls to 58 MBbls;
prices were relatively flat between the two periods, at $52.88
and $54.26 per Bbl for the three months ended March 31,
2011 and 2010, respectively.
Other revenues were $469,000 during the three months
ended March 31, 2011 as compared to $21,000 during the
three months ended March 31, 2010. The increase is
primarily the result of sales of prospect acreage.
Unrealized gain (loss) oil and natural gas
derivative contracts was a loss of $19.2 million during
the three months ended March 31, 2011 as compared to a gain
of $20.8 million during the same period in 2010. The
significant fluctuation from period to period is due to the
volatility of oil and natural gas prices and changes in our
outstanding hedging contracts during these periods.
Expenses
Lease and plant operating expense increased
$5.3 million in the first quarter of 2011 as compared to
the first quarter of 2010, due primarily to lease operating
costs of $4.1 million associated with production from the
Meridian acquisition, which was acquired in May 2010. On a unit
basis, lease and plant operating expense decreased from $1.40
per Mcfe to $1.36 per Mcfe.
Production and ad valorem tax expense increased
$3.8 million to $5.4 million, or 235%, for the first
quarter of 2011, as compared to $1.6 million for the first
quarter of 2010. The increase on a percentage basis follows the
increase in our revenues from products, which was 86%. On a per
unit basis, the expense increased to $0.55 per Mcfe for the
first quarter of 2011 from $0.28 per Mcfe for the first quarter
of 2010. The change in the mix of our sales toward a higher
percentage of revenues from oil impacts the average tax rate,
which increased from 5% to 9% as compared to total unhedged oil
and natural gas revenues. Tax rates on oil are higher than for
gas in Louisiana, where the majority of our oil is produced. Oil
as a percentage of product
44
revenues increased from 25% to 46% in the first quarter of 2011
as compared to 2010. In addition to the variance in severance
tax, an adjustment to ad valorem tax in the first quarter of
2011 increased this expense.
Workover expense decreased slightly from the first
quarter of 2010 as compared to the first quarter of 2011, from
$2.0 million to $1.6 million, respectively. This
expense varies depending on activities in the field.
Exploration expense includes the costs of our geology
departments, costs of geological and geophysical data, delay
rentals, expired leases, and dry holes. Exploration expense
decreased $0.2 million for the first quarter of 2011 to
$2.7 million from $2.9 million for the first quarter
of 2010. The decrease is primarily due to variations in spending
on seismic activities and delay rentals.
Depreciation, depletion and amortization increased
$10.8 million to $19.4 million for the first quarter
of 2011 as compared to an expense of $8.6 million for the
first quarter of 2010. On a per unit basis, this expense
increased from $1.49 to $1.99 per Mcfe. This is the result of
increased capitalized costs of proved properties for which the
corresponding increase in reserves was not proportional. For the
first quarter of 2011, Meridian properties, which were not
present in the corresponding period of the prior year, strongly
impacted the overall rate, contributing about a third of the
production and expense at a rate of approximately $2.32 per Mcfe.
Impairment expense increased from $1.5 million in
the first quarter of 2010 to $5.8 million in the first
quarter of 2011. This expense varies with the results of
exploratory drilling, as well as with price declines which may
render some projects uneconomic, resulting in impairment.
Accretion expense is related to our obligation for
retirement of oil and natural gas wells and facilities. We
record these liabilities when we place the assets in service,
using discounted present values of the estimated future
obligation. We then record accretion of the liabilities as they
approach maturity. Accretion expense was $0.5 million and
$0.1 million for the first quarter of 2011 and 2010,
respectively. The increase was due to the acquisition of
Meridian.
General and administrative expense increased
$3.5 million for the three months ended March 31, 2011
to $5.7 million from $2.2 million for the three months
ended March 31, 2010. The increase in general and
administrative expense resulted principally from increased
payroll and burden costs of $2.0 million, which are
predominately related to increased headcount due to the Meridian
acquisition, and the addition of other personnel. Other general
and administrative costs related to the acquisition of Meridian
also increased, including office rent, which increased
$0.4 million in the first quarter of 2011 as compared to
2010. Consulting expenses increased $0.8 million, primarily
for legal fees. On a unit basis, general and administrative
expense increased from $0.38 to $0.59 per Mcfe, the result of
the increases in expense, but partially reduced by the impact of
higher production.
Interest expense, net increased $5.3 million for the
three months ended March 31, 2011 to $9.5 million from
$4.2 million for the three months ended March 31,
2010, primarily due to interest on our
95/8% senior
notes issued in October 2010 ($7.2 million additional
interest), and to increased amortization of deferred loan costs
incurred in 2010 (approximately $0.8 million additional
interest), offset by decreased interest rate hedge losses
(approximately $0.8 million decrease in interest). These
items were further offset by a decrease in interest for bank
debt (decrease of $1.9 million) which in turn was due to a
decrease in the amount outstanding under our credit facility and
to retirement of our subordinated debt in October 2010; the
interest rate for the subordinated debt of $40 million was
comparatively high, at 12% for the three months ended
March 31, 2010.
45
Results
of Operations: Year Ended December 31, 2010 v. Year Ended
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
Increase
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
(Decrease)
|
|
|
% Change
|
|
|
|
($ in thousands, except average sales price and unit
costs)
|
|
|
Summary Operating Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
24,026
|
|
|
|
10,610
|
|
|
|
13,416
|
|
|
|
126
|
%
|
Oil (MBbls)
|
|
|
964
|
|
|
|
505
|
|
|
|
459
|
|
|
|
91
|
%
|
Natural gas liquids (MBbls)
|
|
|
147
|
|
|
|
47
|
|
|
|
100
|
|
|
|
213
|
%
|
Total natural gas equivalent (Mmcfe)
|
|
|
30,694
|
|
|
|
13,919
|
|
|
|
16,775
|
|
|
|
121
|
%
|
Average daily gas production (Mmcfe per day)
|
|
|
84.1
|
|
|
|
38.1
|
|
|
|
46.0
|
|
|
|
121
|
%
|
Average Sales Price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) realized
|
|
$
|
5.24
|
|
|
$
|
6.25
|
|
|
$
|
(1.01
|
)
|
|
|
(16
|
)%
|
Natural gas (per Mcf) unhedged
|
|
|
4.27
|
|
|
|
3.72
|
|
|
|
0.55
|
|
|
|
15
|
%
|
Oil (per Bbl) realized
|
|
|
78.63
|
|
|
|
67.94
|
|
|
|
10.69
|
|
|
|
16
|
%
|
Oil (per Bbl) unhedged
|
|
|
78.86
|
|
|
|
59.23
|
|
|
|
19.63
|
|
|
|
33
|
%
|
Natural gas liquids (per Bbl) realized(1)
|
|
|
46.58
|
|
|
|
36.05
|
|
|
|
10.53
|
|
|
|
29
|
%
|
Combined (per Mcfe) realized
|
|
|
6.79
|
|
|
|
7.35
|
|
|
|
(0.56
|
)
|
|
|
(8
|
)%
|
Hedging Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized natural gas revenue gain (loss)
|
|
$
|
23,206
|
|
|
$
|
26,835
|
|
|
$
|
(3,629
|
)
|
|
|
(14
|
)%
|
Realized oil revenue gain (loss)
|
|
|
(224
|
)
|
|
|
4,397
|
|
|
|
(4,621
|
)
|
|
|
(105
|
)%
|
Summary Financial Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
$
|
125,866
|
|
|
$
|
66,290
|
|
|
$
|
59,576
|
|
|
|
90
|
%
|
Oil
|
|
|
75,827
|
|
|
|
34,283
|
|
|
|
41,544
|
|
|
|
121
|
%
|
Natural gas liquids
|
|
|
6,844
|
|
|
|
1,690
|
|
|
|
5,154
|
|
|
|
305
|
%
|
Other revenues
|
|
|
1,475
|
|
|
|
1,558
|
|
|
|
(83
|
)
|
|
|
(5
|
)%
|
Unrealized gain (loss) oil and natural gas
derivative contracts
|
|
|
10,088
|
|
|
|
(26,258
|
)
|
|
|
36,346
|
|
|
|
138
|
%
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease and plant operating expense
|
|
|
41,905
|
|
|
|
23,871
|
|
|
|
18,034
|
|
|
|
76
|
%
|
Production and ad valorem taxes
|
|
|
11,141
|
|
|
|
4,755
|
|
|
|
6,386
|
|
|
|
134
|
%
|
Workover expense
|
|
|
7,409
|
|
|
|
8,988
|
|
|
|
(1,579
|
)
|
|
|
(18
|
)%
|
Exploration expense
|
|
|
31,037
|
|
|
|
12,839
|
|
|
|
18,198
|
|
|
|
142
|
%
|
Depreciation, depletion, and amortization
|
|
|
59,090
|
|
|
|
48,659
|
|
|
|
10,431
|
|
|
|
21
|
%
|
Impairment expense
|
|
|
8,399
|
|
|
|
6,165
|
|
|
|
2,234
|
|
|
|
36
|
%
|
Accretion expense
|
|
|
1,370
|
|
|
|
492
|
|
|
|
878
|
|
|
|
178
|
%
|
General and administrative expense
|
|
|
20,135
|
|
|
|
8,738
|
|
|
|
11,397
|
|
|
|
130
|
%
|
Gain on sale of assets
|
|
|
(1,766
|
)
|
|
|
(738
|
)
|
|
|
(1,028
|
)
|
|
|
(139
|
)%
|
Interest expense, net
|
|
|
27,149
|
|
|
|
13,831
|
|
|
|
13,318
|
|
|
|
96
|
%
|
(Benefit from) provision for state income taxes
|
|
|
2
|
|
|
|
(750
|
)
|
|
|
752
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
14,229
|
|
|
$
|
(49,287
|
)
|
|
$
|
63,516
|
|
|
|
129
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Unit Costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease and plant operating expense
|
|
$
|
1.37
|
|
|
$
|
1.71
|
|
|
$
|
(0.34
|
)
|
|
|
(20
|
)%
|
Production and ad valorem taxes
|
|
|
0.36
|
|
|
|
0.34
|
|
|
|
0.02
|
|
|
|
6
|
%
|
Workover expense
|
|
|
0.24
|
|
|
|
0.65
|
|
|
|
(0.41
|
)
|
|
|
(63
|
)%
|
Exploration expense
|
|
|
1.01
|
|
|
|
0.92
|
|
|
|
0.09
|
|
|
|
10
|
%
|
Depreciation, depletion, and amortization
|
|
|
1.93
|
|
|
|
3.50
|
|
|
|
(1.57
|
)
|
|
|
(45
|
)%
|
General and administrative expense
|
|
|
0.66
|
|
|
|
0.63
|
|
|
|
0.03
|
|
|
|
5
|
%
|
|
|
|
(1) |
|
We do not utilize hedging for natural gas liquids. |
46
Revenues
Natural gas revenues for the year ended December 31,
2010 were $125.9 million, compared to $66.3 million
for 2009, representing a $59.6 million or 90% increase. The
increase in revenue was attributable to increased production
volumes, which was partially offset by a lower average realized
price during 2010. Approximately $83.8 million of the
increase was due to an increase in production of 13.4 Bcf, or
126%. This increase in turn was primarily due to the addition of
production from our Meridian acquisition in May 2010, and the
full-year effect of the acquisition of our Deep Bossier
properties in July 2009. Natural gas production attributable to
the acquisition of Meridian for the year was 4.2 Bcf; the Deep
Bossier properties produced 12.3 Bcf in 2010, as compared to 4.0
Bcf in 2009. The price of gas we received exclusive of hedging
increased 15% in 2010; however, the overall realized price
(including hedging gains and losses), decreased 16% from $6.25
per Mcf in 2009 to $5.24 per Mcf in 2010, resulting in a
decrease in revenues of approximately $24.2 million.
Oil revenues for the year ended December 31, 2010
increased $41.5 million, or 121%, to $75.8 million
from $34.3 million in 2009. The increase in revenue was due
to higher production volumes coupled with a higher average
realized sales price. Oil production increased to 964 MBbls from
505 MBbls in 2009, an increase of 91%. Of this, 472 MBbls were
attributable to the acquisition of Meridian. During 2010, our
average realized oil price increased 16% to $78.63 per Bbl from
$67.94 per Bbl in 2009, primarily based on market increases to
prices before hedging gains and losses. Market oil prices
realized exclusive of hedging activities increased 33%, from
$59.23 per Bbl to $78.86 per Bbl.
Natural gas liquids revenues increased during 2010 to
$6.8 million from $1.7 million for 2009. The increase
was primarily due to an increase in volume sold, from 47 MBbls
to 147 MBbls; prices also increased between the two periods from
$36.05 per Bbl to $46.58 per Bbl.
Other revenues were $1.5 million during 2010 as
compared to $1.6 million during 2009. The decrease is
primarily the result of decreased income from investments, which
includes distributions from a drilling company we partially own
and do not consolidate.
Unrealized gain (loss) oil and natural gas
derivative contracts was a gain of $10.1 million for
2010 as compared to a loss of $26.3 million for 2009. The
significant fluctuation from period to period is due to the
volatility of oil and natural gas prices and changes in our
outstanding hedging contracts during these periods.
Expenses
Lease and plant operating expense increased
$18.0 million to $41.9 million in 2010 as compared to
$23.9 million in 2009, due primarily to lease operating
costs of $9.0 million associated with production from the
Meridian acquisition, which was acquired in May 2010. In
addition, the Deep Bossier properties, acquired in late July
2009, contributed $10.4 million in operating expenses in
2010, as compared to $1.1 million for 2009. The increase at
Deep Bossier included approximately $6.8 million in
additional gas gathering and marketing expenses, based on a
contract which originated in December 2009. Increased production
from the Deep Bossier properties, from 4.0 Bcf to 12.3 Bcf, as
well as increased production from other non-Meridian properties,
also impacted lease operating expense. On a unit basis, lease
and plant operating expense decreased from $1.71 per Mcfe to
$1.37 per Mcfe.
Production and ad valorem taxes increased
$6.3 million to $11.1 million, or 134%, for 2010, as
compared to $4.8 million for 2009. The increase on a
percentage basis follows the increase in our revenues from
products, which was 104%. On a per unit basis, the expense
increased to $0.36 for 2010 from $0.34 per Mcfe for 2009.
Workover expense decreased slightly from 2009 to 2010,
from $9.0 million to $7.4 million, respectively. This
expense varies depending on activities in the field.
Exploration expense includes the costs of our geology
departments, costs of geological and geophysical data, delay
rentals, expired leases, and dry holes. Exploration expense
increased $18.2 million for 2010 to $31.0 million from
$12.8 million for 2009. The increase is primarily due to an
exploratory dry hole in South
47
Louisiana which cost $4.8 million, two exploratory dry
holes in East Texas which cost a combined $10.2 million,
and increased seismic expenditures.
Depreciation, depletion and amortization increased
$10.4 million to $59.1 million for 2010 as compared to
an expense of $48.7 million for 2009. On a per unit basis,
this expense declined from $3.50 to $1.93 per Mcfe. This is the
result of the acquisition of the Meridian and Deep Bossier
properties.
Impairment expense increased $2.2 million to
$8.4 million in 2010 from $6.2 million in 2009. This
expense varies with the results of exploratory drilling, as well
as with price declines which may render some projects
uneconomic, resulting in impairment. See Critical
Accounting Policies and Estimates Impairment
below for more details related to impairment.
Accretion expense is related to our obligation for
retirement of oil and natural gas wells and facilities. We
record these liabilities when we place the assets in service,
using discounted present values of the estimated future
obligation. We then record accretion of the liabilities as they
approach maturity. Accretion expense was $1.4 million and
$0.5 million for 2010 and 2009, respectively. The increase
was due to the acquisition of Meridian.
General and administrative expense increased
$11.4 million for 2010 to $20.1 million from
$8.7 million for 2009. The increase in general and
administrative expense resulted principally from increased
payroll and burden costs of $8.8 million, which are
predominately related to increased headcount due to the Meridian
acquisition, the addition of other personnel, and to annual
bonuses paid in the third quarter of 2010. The increase in
payroll is partially offset by allocations to expense
categories. Other general and administrative costs related to
the acquisition of Meridian also increased, including office
rent, which increased $1.2 million in 2010 as compared to
2009. Consulting expenses such as legal, engineering and other
professional services increased a total of $2.0 million,
primarily due to increased costs of outside drilling and
reservoir engineers, and to services related to accounting and
tax work and to acquisition reviews, including the acquisition
of Meridian. On a unit basis, general and administrative expense
increased to $0.66 per Mcfe for 2010, from $0.63 per Mcfe, for
2009. The increase in total general and administrative expense
was largely mitigated on a unit basis by the increase in
production.
Interest expense, net increased $13.3 million for
2010 to $27.1 million from $13.8 million for 2009,
primarily due to new interest in the fourth quarter of 2010 from
our notes payable issued in October 2010 ($6.2 million
additional interest), to increases in the amount outstanding
under our credit facility (approximately $0.6 million
additional interest), to increased amortization of deferred loan
costs (approximately $3.5 million), to a prepayment penalty
on retirement of our subordinate credit facility
($0.8 million), to increased interest on our notes payable
to the founder of the company ($0.2 million) and to
increased interest rate hedge losses (approximately
$1.5 million).
48
Results
of Operations: Year Ended December 31, 2009 v. Year Ended
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
Increase
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
% Change
|
|
|
|
($ in thousands, except average sales price and unit
costs)
|
|
|
Summary Operating Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
10,610
|
|
|
|
6,637
|
|
|
|
3,973
|
|
|
|
60
|
%
|
Oil (MBbls)
|
|
|
505
|
|
|
|
445
|
|
|
|
60
|
|
|
|
13
|
%
|
Natural gas liquids (MBbls)
|
|
|
47
|
|
|
|
47
|
|
|
|
|
|
|
|
|
|
Total natural gas equivalent (MMcfe)
|
|
|
13,919
|
|
|
|
9,593
|
|
|
|
4,326
|
|
|
|
45
|
%
|
Average daily gas production (MMcfe per day)
|
|
|
38.1
|
|
|
|
26.2
|
|
|
|
11.9
|
|
|
|
45
|
%
|
Average Sales Price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) realized
|
|
$
|
6.25
|
|
|
$
|
8.81
|
|
|
$
|
(2.56
|
)
|
|
|
(29
|
)%
|
Natural gas (per Mcf) unhedged
|
|
|
3.72
|
|
|
|
9.33
|
|
|
|
(5.61
|
)
|
|
|
(60
|
)%
|
Oil (per Bbl) realized
|
|
|
67.94
|
|
|
|
85.45
|
|
|
|
(17.51
|
)
|
|
|
(20
|
)%
|
Oil (per Bbl) unhedged
|
|
|
59.23
|
|
|
|
99.17
|
|
|
|
(39.94
|
)
|
|
|
(40
|
)%
|
Natural gas liquids (per Bbl) realized(1)
|
|
|
36.05
|
|
|
|
52.24
|
|
|
|
(16.19
|
)
|
|
|
(31
|
)%
|
Combined (per Mcfe) realized
|
|
|
7.35
|
|
|
|
10.32
|
|
|
|
(2.97
|
)
|
|
|
(29
|
)%
|
Hedging Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized natural gas revenue gain (loss)
|
|
$
|
26,835
|
|
|
$
|
(3,446
|
)
|
|
$
|
30,281
|
|
|
|
879
|
%
|
Realized oil revenue gain (loss)
|
|
|
4,397
|
|
|
|
(6,112
|
)
|
|
|
10,509
|
|
|
|
172
|
%
|
Summary Financial Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
$
|
66,290
|
|
|
$
|
58,458
|
|
|
$
|
7,832
|
|
|
|
13
|
%
|
Oil
|
|
|
34,283
|
|
|
|
38,055
|
|
|
|
(3,772
|
)
|
|
|
(10
|
)%
|
Natural gas liquids
|
|
|
1,690
|
|
|
|
2,470
|
|
|
|
(780
|
)
|
|
|
(32
|
)%
|
Other revenues
|
|
|
1,558
|
|
|
|
3,629
|
|
|
|
(2,071
|
)
|
|
|
(57
|
)%
|
Unrealized gain (loss) oil and natural gas
derivative contracts
|
|
|
(26,258
|
)
|
|
|
60,612
|
|
|
|
(86,870
|
)
|
|
|
(143
|
)%
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease and plant operating expense
|
|
|
23,871
|
|
|
|
20,658
|
|
|
|
3,213
|
|
|
|
16
|
%
|
Production and ad valorem taxes
|
|
|
4,755
|
|
|
|
6,954
|
|
|
|
(2,199
|
)
|
|
|
(32
|
)%
|
Workover expense
|
|
|
8,988
|
|
|
|
8,113
|
|
|
|
875
|
|
|
|
11
|
%
|
Exploration expense
|
|
|
12,839
|
|
|
|
11,675
|
|
|
|
1,164
|
|
|
|
10
|
%
|
Depreciation, depletion, and amortization
|
|
|
48,659
|
|
|
|
49,219
|
|
|
|
(560
|
)
|
|
|
(1
|
)%
|
Impairment expense
|
|
|
6,165
|
|
|
|
11,487
|
|
|
|
(5,322
|
)
|
|
|
(46
|
)%
|
Accretion expense
|
|
|
492
|
|
|
|
729
|
|
|
|
(237
|
)
|
|
|
(33
|
)%
|
General and administrative expense
|
|
|
8,738
|
|
|
|
6,401
|
|
|
|
2,337
|
|
|
|
37
|
%
|
Gain on sale of assets
|
|
|
(738
|
)
|
|
|
|
|
|
|
(738
|
)
|
|
|
|
|
Interest expense, net
|
|
|
13,831
|
|
|
|
14,457
|
|
|
|
(626
|
)
|
|
|
(4
|
)%
|
Gain on extinguishment of debt
|
|
|
|
|
|
|
(3,349
|
)
|
|
|
3,349
|
|
|
|
|
|
(Benefit from) provision for state income taxes
|
|
|
(750
|
)
|
|
|
250
|
|
|
|
(1,000
|
)
|
|
|
(400
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(49,287
|
)
|
|
$
|
36,630
|
|
|
$
|
(85,917
|
)
|
|
|
(235
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Unit Costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease and plant operating expense
|
|
$
|
1.71
|
|
|
$
|
2.15
|
|
|
$
|
(0.44
|
)
|
|
|
(20
|
)%
|
Production and ad valorem taxes
|
|
|
0.34
|
|
|
|
0.72
|
|
|
|
(0.38
|
)
|
|
|
(53
|
)%
|
Workover expense
|
|
|
0.65
|
|
|
|
0.85
|
|
|
|
(0.20
|
)
|
|
|
(24
|
)%
|
Exploration expense
|
|
|
0.92
|
|
|
|
1.22
|
|
|
|
(0.30
|
)
|
|
|
(25
|
)%
|
Depreciation, depletion, and amortization
|
|
|
3.50
|
|
|
|
5.13
|
|
|
|
(1.63
|
)
|
|
|
(32
|
)%
|
General and administrative expense
|
|
|
0.63
|
|
|
|
0.67
|
|
|
|
(0.04
|
)
|
|
|
(6
|
)%
|
|
|
|
(1) |
|
We do not utilize hedging for natural gas liquids. |
49
Revenues
Natural gas revenues for 2009 increased $7.8 million
(13%) to $66.3 million as compared to $58.5 million in
2008. The revenue increase was due to a 60% increase in
production volumes, primarily related to the acquisition of the
Deep Bossier properties on July 23, 2009, partially offset
by a 29% decrease in our average natural gas prices realized
during the year.
Oil revenues decreased in 2009 $3.8 million (10%)
from 2008 revenues, primarily due to a 20% decrease in oil
prices realized during the year, partially offset by a
production volume increase of 13%.
Natural gas liquids revenues decreased by
$0.8 million (32%), due to the 31% decrease in prices
received during 2009 as compared to 2008. Production of NGLs was
flat over the two year period.
Other revenues were $1.6 million for 2009 as
compared to $3.6 million for 2008. The decrease is a result
of decreased income from investments and decreased income from a
drilling rig which was sold in 2009.
Unrealized gain (loss) oil and natural gas
derivative contracts was a loss of $26.3 million during
2009 as compared to a gain in 2008 of $60.6 million. The
significant fluctuation from period to period is due to the
extreme volatility of oil and gas prices and changes in our
outstanding hedging contracts during these periods.
Expenses
Lease and plant operating expense on an aggregate basis
increased $3.2 million (16%) to $23.9 million in 2009,
compared to $20.7 million in 2008, due to increases in
various expenses, including $1.1 million associated with
the acquisition of the Deep Bossier properties in July 2009. The
remainder of the increase was due primarily to the full-year
effect of wells acquired or drilled in 2008. On a per unit
basis, lease and plant operating expense decreased $0.44 per
Mcfe to $1.71 per Mcfe for the year 2009 from $2.15 per Mcfe for
the year 2008, due to higher production.
Production and ad valorem taxes decreased
$2.2 million (32%) to $4.8 million in 2009, compared
to $7.0 million in 2008. Total oil and gas revenues
increased slightly between the two periods. However, realized
hedging gains and losses, which we include with product
revenues, are not subject to production tax. Excluding such
realized gains and losses in revenue, total production and ad
valorem taxes were 7% and 6% of product revenues in 2009 and
2008, respectively.
Workover expense increased slightly from period to
period, to $9.0 million in 2009 from $8.1 million in
2008. This expense varies depending on activities in our various
fields.
Exploration expense includes the costs of our geology
departments, costs of geological and geophysical data, delay
rentals, expired leases, and dry holes. Exploration expense
increased $1.2 million for the year 2009 to
$12.8 million from $11.7 million for the same time
period 2008. The increase is primarily due to certain large
purchases of
3-D seismic
data during 2009.
Depreciation, depletion and amortization decreased by
$0.5 million during 2009 to $48.7 million compared to
$49.2 million for 2008. This was primarily a result of a
decrease in the depletion rate, largely offset by the 45%
increase in production volumes during the year 2009. The rate
decrease is the result of the acquisition of the Deep Bossier
properties, which were purchased at a unit cost which compared
very favorably with our historical finding and acquisition
costs. On a unit basis, depletion expenses decreased to $3.50
per Mcfe for 2009, compared to $5.13 per Mcfe for 2008.
Impairment expense for the year 2009 decreased
$5.3 million to $6.2 million from $11.5 million
for 2008. Commodity prices decreased sharply in the second half
of 2008, resulting in a comparatively larger impairment expense
for 2008. In 2009, prices partially recovered and impairment
expense declined. See Critical Accounting
Policies and Estimates Impairment below for
more details related to impairment.
Accretion expense is related to our obligation for
retirement of oil and gas wells and facilities. We record these
liabilities when we place the assets in service, using
discounted present values of the estimated future obligation. We
then record accretion of the liabilities as they approach
maturity. Accretion expense was comparable for the two periods,
at $0.5 million and $0.7 million in 2009 and 2008,
respectively.
50
General and administrative expense increased
$2.3 million to $8.7 million in 2009 from
$6.4 million in 2008. Increases included $0.9 million
in legal fees, a portion of which were related to the
acquisition of our Deep Bossier properties in 2009, and
$0.8 million in consulting fees related to increased
drilling and pre-drilling activities. Other fees increased as
well, primarily related to the redetermination of the borrowing
base under our senior revolving credit agreement. On a unit
basis, general and administrative expense decreased in 2009 to
$0.63 per Mcfe from $0.67 per Mcfe, due to increased production.
Interest expense, net decreased $0.6 million for the
year ended December 31, 2009 to $13.8 million from
$14.5 million for 2008, primarily due to a variance in
interest rate hedging gains and losses. In 2009, hedging losses
totaled $2.0 million, as compared to losses of
$5.4 million for 2008. Offsetting this, the Company
incurred $2.1 million additional interest expense in 2009
related to increased borrowings under our bank credit facility.
Amortization of loan costs also increased in 2009 based on
incremental loan costs incurred during the year.
Liquidity
and Capital Resources
Our principal requirements for capital are to fund our
day-to-day
operations, our exploration and development activities, and to
satisfy our contractual obligations, primarily for the repayment
of debt and any amounts owed during the period related to our
hedging positions.
Our 2010 capital budget was primarily focused on the development
of existing core areas through exploitation and development.
Currently, we anticipate a capital budget of approximately
$200 million for 2011, of which we have spent
$58.9 million as of March 31, 2011. Approximately 75%
of our 2011 capital budget is allocated to our properties in
Deep Bossier, East Texas, Eagle Ford, and South Louisiana. Our
future drilling plans, plans of our drilling operators and
capital budgets are subject to change based upon various
factors, some of which are beyond our control, including
drilling results, oil and natural gas prices, the availability
and cost of capital, drilling and production costs, availability
of drilling services and equipment, actions of our operators,
gathering system and pipeline transportation constraints and
regulatory approvals. Because a large percentage of our acreage
is held by production, we have the ability to materially
decrease our drilling and recompletion budget in response to
market conditions with minimal risk of losing significant
acreage.
In October 2010, we adjusted our capital structure by issuing
$300 million of
95/8%
senior notes due 2018. The old notes were issued at a discount
of $2.1 million, bringing the effective rate to
93/4%.
The net proceeds of the notes offering were used to repay in
full the $40 million drawn under our $150 million
second lien term loan facility with UnionBanCal Equities Inc.,
as the administrative agent, which was due to mature in March
2013, to repay $199.7 million of the borrowings outstanding
under our senior secured revolving credit facility, and to
provide a $50 million distribution to AMIH.
The old notes are unsecured senior general corporate
obligations, and effectively rank junior to any of our existing
or future secured indebtedness, which includes our credit
facility. The old notes are unconditionally guaranteed on a
senior unsecured basis by each of our material, wholly owned
subsidiaries. Pursuant to the terms of the exchange offer
described in this prospectus, we are offering to exchange the
old notes for an identical principal amount of new notes.
On May 23, 2011, we amended our senior secured revolving
credit facility (amended credit facility) such that
we currently have a $260 million borrowing base limit with
Wells Fargo Bank, N.A. as the administrative agent. The maturity
date was also extended to May 23, 2016. As of
March 31, 2011, we had approximately $87.3 million
outstanding under the amended credit facility. Our restricted
subsidiaries are guarantors of the amended credit facility. The
amended credit facility provides that we may not issue senior
unsecured debt securities in excess of $700 million,
including the notes. See Description of Certain
Indebtedness Senior Secured Revolving Credit
Facility.
The amended credit facility provides for two alternative
interest rate bases and margins. Eurodollar loans accrue
interest generally at the one-month London Interbank Offered
Rate plus a margin ranging from 2.00% to 2.75%, depending on the
utilization of our borrowing base. Reference rate
loans accrue interest at the prime rate of Wells Fargo Bank,
N.A., plus a margin ranging from 1.00% to 1.75%, depending on
the utilization of our borrowing base.
51
We expect to fund our 2011 capital budget predominantly with
cash flows from operations. If necessary, we may also access
capital through proceeds from potential asset dispositions,
borrowings under the credit facility and the future issuance of
debt and/or equity securities, subject to the distribution of
proceeds therefrom as set forth in our partnership agreement.
See The Partnership AgreementCash
Distributions and Note 15, Partners
Capital, in the accompanying Notes to Consolidated
Financial Statements for the years ended December 31, 2010,
2009 and 2008 for further information. We strive to maintain
financial flexibility and may access capital markets as
necessary to maintain substantial borrowing capacity under our
credit facility, facilitate drilling on our large undeveloped
acreage position, and permit us to selectively expand our
acreage position. In the event our cash flows are materially
less than anticipated and other sources of capital we
historically have utilized are not available on acceptable
terms, we may curtail our capital spending.
Cash
Flow Provided by Operating Activities
Operating activities provided cash of $61.1 million in
2010, as compared to $34.3 million for 2009. The
$26.8 million increase in operating cash flows was
primarily attributable to our increase in earnings. Cash-based
items of net income, including revenues (exclusive of unrealized
commodity gains or losses), operating expenses and taxes,
general and administrative expenses, and the cash portion of our
interest expense, provided a net increase of approximately
$58.2 million in earnings and a positive impact on cash
flow. However, partially offsetting these items were changes in
our working capital accounts, which used $30.2 million of
cash flows as compared to having provided $1.4 million in
cash in 2009. This reversal resulted in a total decrease of
$31.6 million in cash flow, which as noted above, partially
offset the positive effects of increased earnings. Although
accounts payable and accrued liabilities increased
$54.6 million in 2010, this was primarily due to the
acquisition of Meridian, and to an increase in accrued
liabilities for capital expenditures, which do not impact
operating cash flow. Underlying activity included a net use of
cash to meet working capital requirements.
Operating activities provided cash of $34.3 million in 2009
as compared to cash provided by operations of $20.3 million
in 2008. The increase in operating cash flows was principally
attributable to the timing of working capital requirements
resulting in higher 2008 payments for accounts payable and
accrued liabilities compared to 2009, partially offset by higher
production and exploration cash operating expenses in 2009
compared to 2008.
Cash
Flow Used in Investing Activities
Investing activities used cash of $208.4 million for the
year ended December 31, 2010 as compared to cash used in
investing of $86.6 million for the year ended
December 31, 2009. The increase in cash used in investing
activities was primarily related to the acquisition of Meridian,
for which cash expenditures were $101.4 million. Drilling
and development expenditures also increased by $10 million,
and proceeds from sales of properties decreased $11 million.
Investing activities used cash of $86.6 million in 2009 as
compared to cash used in investing of $111.1 million in
2008. The decrease in cash used in investing activities was
primarily related to a decrease in capital expenditure activity,
including the purchase of producing properties in each year, as
well as proceeds of $13.7 million from the sale of fixed
assets in 2009.
Cash
Flow Provided by Financing Activities
Financing activities provided cash of $147.9 million during
2010 as compared to cash provided by financing of
$51.8 million during 2009, an increase of
$96.1 million. The increase in cash flows provided by
financing activities was primarily due to the acquisition of
Meridian, which was financed by increased borrowing under our
credit facility, as well as a $50 million contribution from
our private equity partner, AMIH. The cash and debt retirement
paid for the Meridian acquisition was $101.4 million. The
proceeds from the issuance of the notes were used to retire
other debt and to provide a $50 million distribution to
AMIH, and had no net effect on cash flows from financing.
52
Financing activities provided cash of $51.8 million in 2009
as compared to cash provided by financing of $78.8 million
in 2008. The decrease in cash flows provided in financing
activities was primarily related to a decrease in capital
expenditure activity, resulting in fewer additions to the
outstanding balance under our credit facility.
Risk
Management Activities Commodity Derivative
Instruments
Due to the volatility of oil and natural gas prices, we
periodically enter into price-risk management transactions
(e.g., swaps, collars, puts, calls, and financial basis swap
contracts) for a portion of our oil and natural gas production.
This allows us to achieve a more predictable cash flow, as well
as to reduce exposure from price fluctuations. The commodity
derivative instruments apply to only a portion of our
production, and provide only partial price protection against
declines in oil and natural gas prices, and may partially limit
our potential gains from future increases in prices. At
March 31, 2011, commodity derivative instruments were in
place covering approximately 80% of our projected oil and
natural gas production from proved developed properties for
2011. See Note 6 to our consolidated financial statements
as of March 31, 2011, Derivative Financial
Instruments, for further information.
Contractual
Obligations
The following table summarizes our contractual obligations as of
December 31, 2010:
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|
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|
|
Year Ended December 31,
|
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|
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Total
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|
|
2011
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|
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2012-2013
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|
|
2014-2015
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|
|
Thereafter
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|
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(Dollars in thousands)
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|
|
Debt(1)
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|
$
|
392,999
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|
|
$
|
|
|
|
$
|
73,290
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|
|
$
|
|
|
|
$
|
319,709
|
|
Interest(1)
|
|
|
244,619
|
|
|
|
30,982
|
|
|
|
59,594
|
|
|
|
57,750
|
|
|
|
96,293
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|
Operating leases
|
|
|
16,068
|
|
|
|
2,881
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|
|
|
2,760
|
|
|
|
2,732
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|
|
|
7,695
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|
Drilling rigs
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|
928
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|
|
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928
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|
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|
Settlement obligations
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|
|
4,200
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|
|
|
1,200
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|
|
|
2,000
|
|
|
|
1,000
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|
|
|
|
|
Derivative contract premiums(2)
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|
|
6,233
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|
|
|
1,580
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|
|
|
4,653
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|
|
|
|
|
|
|
|
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Abandonment liabilities
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|
|
42,713
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|
|
|
1,617
|
|
|
|
4,837
|
|
|
|
6,481
|
|
|
|
29,778
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total
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$
|
707,760
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|
|
$
|
39,188
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|
|
$
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147,134
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|
|
$
|
67,963
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|
|
$
|
453,475
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|
|
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|
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|
(1) |
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Interest includes interest on the outstanding balance under our
revolving credit agreement maturing in 2012, payable quarterly;
on our senior notes due 2018, payable semiannually; and on the
debt to our founder, which is payable with principal, at
maturity in 2018. Projected obligation amounts are based on the
payment schedules for interest, and are not presented on an
accrual basis. |
|
(2) |
|
Derivative contract premiums relate to open derivative contracts
in place at December 31, 2010 and are due over time as the
contracts mature and settle. They are included on our
consolidated balance sheet with the related derivative
contracts. Amounts presented above are net of $2.8 million
for premiums due to us under derivative contracts from the same
counterparties. |
In addition to the items above, we have a contingent commitment
to pay an amount up to a maximum of approximately
$5 million for properties acquired in 2008 and prior years.
The additional purchase consideration will be paid only if
certain product price conditions are met. We cannot estimate the
amounts that will be paid in the future, if any, or the fiscal
years in which such amounts could become due.
We also have a remaining obligation under an acquisition
agreement totaling $411,000 as of December 31, 2010. This
obligation is paid monthly in varying amounts, depending on the
relationship of the commodity price received for production of
the acquired properties, to certain contractually specified
amounts. The obligation was reduced by approximately $392,000
during 2010.
53
Off-Balance
Sheet Arrangements
As of December 31, 2010 we had no guarantees of third party
obligations. Our off-balance sheet arrangements at
December 31, 2010 consist of bonds posted in the aggregate
amount of $8.8 million, primarily to cover future
abandonment costs.
We have no plans to enter into any off-balance sheet
arrangements in the foreseeable future.
Critical
Accounting Policies and Estimates
The discussion and analysis of our financial condition and
results of operations are based upon our consolidated financial
statements, which have been prepared in accordance with
accounting principles generally accepted in the United States
(GAAP). As used herein, the following acronyms have
the following meanings: FASB means the Financial
Accounting Standards Board; the Codification refers
to the Accounting Standards Codification, the collected
accounting and reporting guidance maintained by the FASB;
ASC means Accounting Standards Codification and is
generally followed by a number indicating a particular section
of the Codification; and ASU means Accounting
Standards Update, followed by an identification number, which
are the periodic updates made to the Codification by the FASB.
The preparation of our consolidated financial statements
requires us to make estimates and assumptions that affect our
reported results of operations and the amount of reported
assets, liabilities and proved oil and natural gas reserves.
Some accounting policies involve judgments and uncertainties to
such an extent that there is reasonable likelihood that
materially different amounts could have been reported under
different conditions, or if different assumptions had been used.
Actual results may differ from the estimates and assumptions
used in the preparation of our consolidated financial
statements. Described below are the most significant policies we
apply in preparing our consolidated financial statements, some
of which are subject to alternative treatments under accounting
principles generally accepted in the United States. We also
describe the most significant estimates and assumptions we make
in applying these policies.
Use of Estimates. The preparation of
consolidated financial statements in conformity with GAAP
requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the consolidated financial statements and the reported amounts
of revenues and expenses during the reporting period.
Reserve estimates significantly impact depreciation and
depletion expense and potential impairments of oil and natural
gas properties and are subject to change based on changes in oil
and natural gas prices and trends and changes in estimated
reserve quantities. We analyze estimates, including those
related to oil and natural gas reserves, the value of oil and
natural gas properties, oil and natural gas revenues, bad debts,
derivative contracts, income taxes and contingencies and
litigation. We base our estimates on historical experience and
various other assumptions that are believed to be reasonable
under the circumstances. Actual results may differ from these
estimates.
Property and Equipment. Oil and gas producing
activities are accounted for using the successful efforts method
of accounting. Under the successful efforts method, lease
acquisition costs and all development costs, including
unsuccessful development wells, are capitalized.
Unproved Properties. Acquisition costs
associated with the acquisition of leases are recorded as
unproved leasehold costs and capitalized as incurred. These
consist of costs incurred in obtaining a mineral interest or
right in a property, such as a lease in addition to options to
lease, broker fees, recording fees and other similar costs
related to activities in acquiring properties. Leasehold costs
are classified as unproved until proved reserves are discovered,
at which time related costs are transferred to proved oil and
gas properties.
Exploration Expense. Exploration expenses,
other than exploration drilling costs, are charged to expense as
incurred. These expenses include seismic expenditures and other
geological and geophysical costs, expired leases, and lease
rentals. The costs of drilling exploratory wells and
exploratory-type stratigraphic wells are initially capitalized
pending determination of whether the well has discovered proved
commercial reserves. If the exploratory well is determined to be
unsuccessful, the cost of the well is transferred to expense.
Exploratory well drilling costs may continue to be capitalized
if the reserve quantity is sufficient to justify
54
completion as a producing well and sufficient progress in
assessing the reserves and the economic and operating viability
of the project is being made.
Proved Oil and Gas Properties. Costs incurred
to obtain access to proved reserves and to provide facilities
for extracting, treating, gathering, and storing oil and gas are
capitalized. All costs incurred to drill and equip successful
exploratory wells, development wells, development-type
stratigraphic test wells, and service wells, including
unsuccessful development wells, are capitalized.
Impairment. The capitalized costs of proved
oil and gas properties are reviewed at least annually for
impairment in accordance with ASC
360-10-35,
Property, Plant and Equipment, Subsequent Measurement, whenever
events or changes in circumstances indicate that the carrying
amount of a long-lived asset or asset group exceeds its fair
market value and is not recoverable. The determination of
recoverability is based on comparing the estimated undiscounted
future net cash flows at a producing field level to the carrying
value of the assets. If the future undiscounted cash flows,
based on estimates of anticipated production from proved
reserves and future crude oil and natural gas prices and
operating costs, are lower than the carrying cost, the carrying
cost of the asset or group of assets is reduced to fair value.
For our proved oil and natural gas properties, we estimate fair
value by discounting the projected future cash flows at an
appropriate risk-adjusted discount rate.
Unproved leasehold costs are assessed at least annually to
determine whether they have been impaired. Individually
significant properties are assessed for impairment on a
property-by-property
basis, while individually insignificant unproved leasehold costs
may be assessed in the aggregate. If unproved leasehold costs
are found to be impaired, an impairment allowance is provided
and a loss is recognized in the statement of operations.
Depreciation, Depletion and
Amortization. Depreciation, depletion and
amortization (DD&A) of capitalized costs of
proved oil and gas properties is computed using the
unit-of-production
method based upon estimated proved reserves. Assets are grouped
for DD&A on the basis of reasonable aggregation of
properties with a common geological structural feature or
stratigraphic condition, such as a reservoir or field. The
reserve base used to calculate DD&A for leasehold
acquisition costs and the cost to acquire proved properties is
the sum of proved developed reserves and proved undeveloped
reserves. The reserve base used to calculate DD&A for lease
and well equipment costs, which include development costs and
successful exploration drilling costs, includes only proved
developed reserves.
Revenue Recognition. We recognize oil, gas and
natural gas liquids revenues when products are delivered at a
fixed or determinable price, title has transferred and
collectability is reasonably assured (sales method). Oil and
natural gas sold is not significantly different from the
Companys share of production. Revenue from drilling rigs
has been recorded when services are performed.
Derivative Financial Instruments. We use
derivative contracts to hedge the effects of fluctuations in the
prices of oil, natural gas and interest rates. We account for
such derivative instruments in accordance with ASC 815,
Derivatives and Hedging, which establishes accounting and
disclosure requirements for derivative instruments and requires
them to be measured at fair value and recorded as assets or
liabilities in the statements of financial position (see
Note 5 in the notes to our consolidated financial
statements at March 31, 2011 for further information on
fair value).
Under ASC 815, hedge accounting is used to defer recognition of
unrealized changes in the fair value of such financial
instruments, for those contracts which qualify as fair value or
cash flow hedges, as defined in the guidance. Historically, we
have not designated any of our derivative contracts as fair
value or cash flow hedges. Accordingly, the unrealized changes
in fair value of the contracts are included in net income in the
period of the change as Unrealized gain (loss)
oil and natural gas derivative contracts for oil and gas
contracts, and in interest expense for interest derivative
contracts. Realized gains and losses are recorded in income in
the period of settlement, and included in the related revenue
account or in interest expense. Cash flows from settlements of
derivative contracts are classified with the income or expense
item to which such settlements directly relate.
Income Taxes. We have elected under the
Internal Revenue Code provisions to be treated as individual
partnerships for tax purposes. Accordingly, items of income,
expense, gains and losses flow through to the
55
partners and are taxed at the partner level. Accordingly, no tax
provision for federal income taxes is included in the
consolidated financial statements.
We are subject to the Texas margin tax, which is considered a
state income tax, and is included in provision for state income
tax on the statement of operations. We record state income tax
(current and deferred) based on taxable income as defined under
the rules for the margin tax.
Acquisitions. Acquisitions are accounted for
as purchases and, accordingly, the results of operations are
included in our statement of operations from the closing date of
the acquisition. Purchase prices are allocated to acquired
assets and assumed liabilities based on their estimated fair
value at the time of the acquisition.
Asset Retirement Obligations. We estimate the
present value of future costs of dismantlement and abandonment
of our wells, facilities, and other tangible, long-lived assets,
recording them as liabilities in the period incurred. We follow
ASC 410, Asset Retirement and Environmental Obligations. ASC 410
requires that an asset retirement obligation (ARO)
associated with the retirement of a tangible long-lived asset be
recognized as a liability in the period in which it is incurred
or becomes determinable (as defined by the standard), with an
associated increase in the carrying amount of the related
long-lived asset. The cost of the tangible asset, including the
initially recognized asset retirement cost, is depreciated over
the useful life of the asset and accretion expense is recognized
over time as the discounted liability is accreted to its
expected settlement value. The fair value of the ARO is measured
using expected future cash outflows for abandonment discounted
generally at our cost of capital at the time of recognition.
Investment. Our investment consists of a 10%
ownership interest in a drilling company, Orion Drilling
Company, LP (Orion). The investment is accounted for
under the cost method. Under this method, our share of earnings
or losses of the investment are not included in the statements
of operations. Distributions from Orion are recognized in
current period earnings as declared.
Deferred Financing Costs. Deferred financing
costs are amortized using the straight-line method over the term
of the related debt, so long as this approximates the interest
rate method.
Quantitative
and Qualitative Disclosures about Market Risk
We are exposed to certain market risks that are inherent in our
consolidated financial statements that arise in the normal
course of business. We may enter into derivative instruments to
manage or reduce market risk, but do not enter into derivative
agreements for speculative purposes.
We do not designate these or future derivative instruments as
hedges for accounting purposes. Accordingly, the changes in the
fair value of these instruments are recognized currently in
earnings.
Commodity
Price Risk and Hedges
Our major market risk exposure is to prices for oil, natural gas
and natural gas liquids. These prices have historically been
volatile. As such, future earnings are subject to change due to
changes in these prices. Realized prices are primarily driven by
the prevailing worldwide price for oil and regional spot prices
for natural gas. We have used, and expect to continue to use,
oil and natural gas derivative contracts to reduce our exposure
to the risks of changes in the prices of oil and natural gas.
Pursuant to our risk management policy, we engage in these
activities as a hedging mechanism against price volatility
associated with pre-existing or anticipated sales of oil and
natural gas.
As of March 31, 2011, we have hedged approximately 80% of
our forecasted PDP production through 2015 at average annual
prices ranging from $4.98 per MMBtu to $6.91 per MMBtu and
$81.46 per Bbl to $86.60 per Bbl. Forecasted production from
proved reserves is estimated in our December 2010 reserve report
using prices, costs and other assumptions required by SEC rules.
Our actual production will vary from the amounts estimated in
the report, perhaps materially. Please read the disclosures
under Our estimated oil and natural gas reserve quantities
and future production rates are based on many assumptions that
may prove to be inaccurate. Any material inaccuracies in these
reserve estimates or the underlying assumptions will materially
affect the quantities and present value of our reserves in
the Risk Factors section above.
The fair value of our oil and natural gas derivative contracts
and basis swaps at December 31, 2010 was a net asset of
$24.6 million. A 10% increase or decrease in oil and
natural gas prices with all other factors held
56
constant would result in an unrealized loss or gain,
respectively, in the fair value (generally correlated to our
estimated future net cash flows from such instruments) of our
oil and natural gas commodity contracts of approximately
$23.2 million (unrealized loss) or $21.7 million
(unrealized gain), respectively.
Interest
Rates
We are subject to interest rate risk on our long-term fixed
interest rate debt and variable interest rate borrowings. We use
interest rate swaps to mitigate the effect of fluctuating
interest rates on interest expense. Floating to fixed rate swaps
hedge the variable interest rate under our amended credit
facility. We entered into a fixed to floating interest rate swap
which effectively reduces our fixed interest rate on half the
principal of our $300 million senior notes in the short
term, with an offsetting risk related to the floating rate over
the term of the contract, which is approximately four years. The
total fair value of our interest rate swaps at December 31,
2010 was a liability of $5.4 million. A 1% increase in
interest rates (100 LIBOR basis points) would increase the fair
value of our interest rate derivatives. However, such an
increase in interest rates would also increase interest expense
on our variable rate debt by approximately $0.7 million
annually, assuming the outstanding balance under our amended
credit facility were to remain at the December 31, 2010
balance of $73.3 million.
Recent
Accounting Pronouncements
In January 2010, the FASB updated Topic 820 with 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. We
adopted the new guidance effective January 1, 2010. We do
not expect the additional disclosure requirements will have any
material impact on our consolidated financial position or
results of operations.
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:
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|
|
report the independence and qualifications of its reserves
preparer or auditor;
|
|
|
|
file reports when a third party is relied upon to prepare
reserves estimates or conducts a reserves audit; and
|
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|
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 ASU
2010-03,
effective also on December 31, 2009, ASC Topic 932,
Extractive Activities Oil and Gas.
We adopted the new guidance effective December 31, 2009;
information about our reserves has been prepared in accordance
with the new guidance and is included in Note 19 of the
accompanying Notes to Consolidated Financial Statements. As of
December 31, 2009, our reserves were affected primarily by
the use of the average prices rather than the period-end prices
required under the prior rules. The changes resulting from the
new rules did not significantly impact our impairment testing,
depreciation, depletion and amortization expense, or other
results of operations.
In December 2009, the FASB issued revised authoritative guidance
regarding consolidation of variable interest entities
(VIEs) in ASU
2009-17,
Improvements to Financial Reporting by Enterprises
Involved with
57
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
VIEs, rather than only when specific events occur. The revised
guidance also requires additional disclosures about consolidated
and unconsolidated VIEs, including their impact on the
companys risk exposure and its financial statements. The
revised guidance is effective for financial statements for
annual and interim periods beginning after November 15,
2009. We adopted the new guidance effective January 1,
2010. The adoption had no material impact on consolidated
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 was effective for interim and annual periods ending
after June 15, 2009, with early adoption permitted for
periods ending after March 15, 2009. We adopted the new
guidance effective April 1, 2009. The adoption did not have
a material impact on consolidated financial position or results
of operations of the Company. The disclosures are included in
Note 2 of the notes to our consolidated financial
statements, under the subheading Financial
Instruments.
In May 2009, the FASB issued SFAS 165, Subsequent
Events, codified in ASC 855. ASC 855 defines the period
during which management should evaluate events or transactions
that occur after the balance sheet date for potential
recognition or disclosure in the financial statements, the
circumstances under which an entity should recognize events or
transactions occurring after the balance sheet date, and the
disclosures about such subsequent events. It did not
substantially change existing guidance, but added a new
disclosure of the date through which events have been evaluated
and whether that is the date of issuance of the financial
statements or an alternate date. The new guidance was effective
for interim or annual financial periods ending after
June 15, 2009. We adopted the new guidance effective
June 30, 2009; the adoption did not have a material impact
on consolidated financial position or results of operations of
the Company.
On May 12, 2011, the FASB issued ASU
No. 2011-04
to Topic 820, Fair Value Measurements, Amendments to
Achieve Common Fair Value Measurement and Disclosure
Requirements in U.S. GAAP and IFRS. The ASU changes
certain definitions of terms used its guidance regarding fair
value measurements, as well as modifying certain disclosure
requirements and other aspects of the guidance. We are reviewing
the ASU, which is effective for interim and annual periods
beginning after December 15, 2011. We do not expect
adoption of the guidance to have a material impact on our
consolidated financial position or results of operations.
On June 16, 2011, the FASB issued ASU
No. 2011-05,
Presentation of Comprehensive Income. This standard
eliminates the current option to report other comprehensive
income and its components in the statement of changes in equity.
Two presentation options remain. Changes in comprehensive income
may be reported in a continuous statement of comprehensive
income which presents the components of net income as well as
the components of comprehensive income. Alternatively, the
components of comprehensive income may be reported in a separate
statement of comprehensive income, which must immediately follow
the statement of net income. The ASU also creates a new
requirement that reclassifications from comprehensive income to
net income be presented on a gross basis on the face of the
financial statements (previously net presentation and footnoting
gross information was permitted). The ASU applies to interim and
year end reports and is effective for fiscal years beginning
after December 15, 2011, and is to be retrospectively
applied to all periods presented in such reports. Early adoption
is permitted. We do not expect adoption of the guidance to have
a material impact on our consolidated financial position or
results of operations.
58
BUSINESS
Our
Company
We are a privately held company primarily engaged in onshore oil
and natural gas acquisition, exploitation, exploration and
production whose focus is to maximize the profitability of our
assets in a safe and environmentally sound manner. We seek to
maintain a portfolio of lower risk properties in plays where we
identify a large inventory of drilling, development, and
enhanced recovery and exploitation opportunities in known
resources. We believe our balanced portfolio of
assets principally historically prolific fields in
South Louisiana, conventional liquids-rich gas and oil fields of
East Texas, shallow long-lived oil fields in Oklahoma, and
resource plays in the Deep Bossier of East Texas and Eagle Ford
Shale in South Texas has decades of future
development potential. We maximize the profitability of our
assets by focusing on advanced engineering analytics, enhanced
geological techniques including
3-D seismic
analysis, and proven drilling, stimulation, completion, and
production methods.
From December 2008 through December 2010, we increased
production at an annualized compounded rate of approximately 80%
through a focused program of drilling and field re-development
and strategic acquisitions. As of December 31, 2010, our
estimated total proved oil and natural gas reserves were
approximately 325 Bcfe, of which 66% were classified as proved
developed. Our proved reserve mix is approximately 74% natural
gas, 23% oil and 3% natural gas liquids with a pro forma reserve
life index of 9.3 for the year ended December 31, 2010.
Excluding the Deep Bossier resource play, which includes
approximately 16% of the
PV-10 value
of our proved reserves and where EnCana is the principal
operator, we maintain operational control of approximately 83%
of the PV-10
value of our proved reserves. Of this, we operate 68% directly
and the remainder is structured under operating arrangements
with minority interest holders where we contribute significantly
to the development of the assets through use of our internal
engineering and geologist staffs and we have the ability to
control the drilling schedule and remove the operator.
Our areas of focus are typically characterized by multiple
hydrocarbon pay zones, and because we are re-developing fields
and areas left behind by major oil and natural gas companies and
other previous operators, our assets are typically served by
existing infrastructure. As a result, our approach lowers
geological, mechanical, and market-related risks. We focus on
properties within our core operating areas that we believe have
significant development and exploration opportunities and where
we can apply our technical experience and economies of scale to
increase production and proved reserves while lowering lease
operating and capital costs. Additionally, we have consistently
created value through workovers and re-completions of existing
wells, infill drilling, operations improvements, secondary
recovery and
3-D
seismic-driven drilling. We expect to continue production growth
in our core areas by exploiting known resources with continued
well workovers, development drilling and enhanced recovery
programs, and disciplined exploration.
Meridian
Acquisition
On May 13, 2010, we acquired The Meridian Resource
Corporation, a public exploration and production company with
properties in or proximate to our own areas of operation and
proved reserves of 75 Bcfe as of December 31, 2009, for
$158 million. The acquisition was funded with borrowings
under our senior secured revolving credit facility as well as a
$50 million equity contribution from AMIH. As a result of
the acquisition, as of June 30, 2010, we increased total
proved reserves 36% and have achieved a more balanced portfolio
mix by increasing our total proved oil reserves by 69%. We also
believe the acquisition gives us significant growth potential by
increasing our proved undeveloped reserves by 51% as compared to
undeveloped reserves at December 31, 2009 and adding a
large library of
3-D and
2-D seismic
data, much of which we are reprocessing and utilizing for the
exploitation of known fields and identification and development
of new prospects in certain of our operating areas.
59
Deep
Bossier Acquisition
On July 23, 2009, Navasota Resources Ltd., LLP, a wholly
owned subsidiary of ours, made a payment of $25.5 million
and took assignment of substantially all working interests that
had been held by Chesapeake in an approximate 50,000 acre area
of Leon and Robertson Counties, Texas in the Deep Bossier play.
We had exercised our preferential right to purchase these
interests from Gastar in late 2005, but Gastar and Chesapeake
had opposed this and Chesapeake took record title of our assets.
We filed suit in late 2005 and after several years of litigation
in which we ultimately prevailed, in 2008 a Texas court of
appeals directed that specific performance take place. In early
2009, the Texas Supreme Court denied the defendants
request to hear the appeal. As a result, we took 25%-33% working
interests in over 30 producing wells and were able to
participate more significantly in further development of the
area, primarily with EnCana, but also with Gastar. Subsequent
payments and adjustments resulted in a final purchase price of
$44.5 million. The Deep Bossier properties contribute 93
Bcfe, or 29%, of our proved reserves as of December 31,
2010. The number of wells has increased from 30 at acquisition
to 48 as of December 31, 2010.
Our
Strategy
Our objective is to increase reserves and production by applying
advanced engineering analytics and enhanced geological
techniques in areas we have identified as under-developed and
over-looked.
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Exploit Known Resources in a Repeatable
Manner. The majority of our assets are in mature
fields previously developed by major oil and natural gas
companies or other independent producers. We seek to enhance
existing production in these properties by using our engineering
and geological expertise to convert PDNP and PUD reserves to the
PDP reserve category while creating repeatable efficiencies to
lower operating and capital costs. We intend to concentrate our
efforts in areas where we can leverage previous experience and
knowledge to continually improve our operations and guide our
future development and expansion.
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Maximize Development Opportunities with Sound Engineering and
Technology. We seek to exploit and redevelop
mature properties by using
state-of-the-art
technology including
2-D and
3-D seismic
imaging and advanced seismic modeling. We use various recovery
techniques, including recompletions, modern well log analysis,
advanced fracture stimulation design, and infill/step out
drilling to enhance oil and natural gas production. Our
geologists, geophysicists, engineers, and petrophysicists
systematically integrate reservoir performance data with
geologic and geophysical data, an approach that reduces drilling
risks, lowers finding costs and provides for more efficient
production of oil and natural gas from our properties.
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Create High-Potential, High-Impact Opportunities while
Mitigating Exploration Risk. We target high
impact prospects that offer an opportunity to significantly grow
reserves. We minimize exploration risk by amassing and
synthesizing engineering, geologic, and seismic data to create a
robust knowledge of producing zones in and around our
prospective areas. We seek multiple targets in a given
exploratory well to maximize and prolong the impact of our
capital spending, and seek exploration opportunities that will,
upon success, lead to multiple development wells. We diversify
our risk across a number of prospects and further mitigate risk
by typically bringing in industry partners to participate in our
exploration prospects.
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Optimize Production Mix Based on Market
Conditions. Our diversified asset base enables us
to adjust our development approach based on market price
differentials. Currently, we intend to take advantage of the
favorable oil price environment by continuing to exploit oil and
natural gas liquids opportunities within our portfolio. Oil and
natural gas liquids represent 22% of our 2010 production and 39%
of our oil and natural gas revenue for the year ended
December 31, 2010. For the second half of 2010, which
includes the full effect of the Meridian acquisition, oil and
natural gas liquids represent 28% of production and 45% of oil
and natural gas revenues. Oil and condensate-rich gas
opportunities represented approximately 60% of our 2010 capital
budget and represent approximately two thirds of our 2011
capital budget. Commodity mix will be a key consideration as we
evaluate future drilling and acquisition opportunities.
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60
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Pursue Value-Based Acquisitions that Leverage Current
Internal Knowledge. We continually review
opportunities to acquire producing properties, leasehold acreage
and drilling prospects. We pursue acquisition targets where our
own field exploitation methods can be profitably employed, and
identify lower-valued, non-strategic properties of other energy
companies. While we are biased toward acquisitions that leverage
our local knowledge and proprietary field exploitation methods
to obtain readily executable opportunities, we aim for
geographic and geological diversity to mitigate market, weather
and other risk. While we seek to control operations, we also
engage in partnerships with other operators and service
providers so we can capitalize on their data, knowledge and
access to equipment.
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Mitigate Commodity Price Risk. Due to the
volatility of oil and natural gas prices, we periodically enter
into and actively manage derivative transactions for a portion
of our oil and natural gas production. This allows us to reduce
exposure to price fluctuations and achieve more predictable cash
flows, while retaining commodity price upside potential through
future production and reserve growth. As of March 31, 2011,
we have hedged approximately 80% of our forecasted PDP
production through 2015 at average annual prices ranging from
$4.98 per MMBtu to $6.91 per MMBtu and $81.46 per Bbl to $86.60
per Bbl.
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Maintain Financial Flexibility. In order to
maintain our financial flexibility, we plan to fund our 2011
capital budget predominantly with cash flow from operations. Our
operational control enables us to manage the timing of a
substantial portion of our capital investments. At
March 31, 2011, under our senior secured revolving credit
facility, we had $87.3 million in borrowings outstanding
and $132.7 million available for borrowing.
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Our
Strengths
We believe that the following strengths provide us with
significant competitive advantages and position us to continue
to achieve our business objective and execute our strategies:
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Proven Track Record of Reserves and Production
Growth. From December 2008 through December 2010,
we increased production at an annualized compounded rate of
approximately 80% through a focused program of drilling and
field re-development and strategic acquisitions largely in our
core areas. Based on our long-term historical performance and
our business strategy, we believe we have the opportunities,
experience and knowledge to continue growing both our reserves
and production.
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High Quality Portfolio of Under-Exploited Properties and
Multi-Year, Low-Risk Drilling and Wellbore Utilization
Inventory. The bulk of our assets are producing
properties with significant opportunities for additional
exploitation and exploration. We have created and expect to
maintain a multi-year drilling inventory and a continuing
program of well recompletions, typically to shallower productive
zones as deeper formations deplete over time. As of
December 31, 2010, our inventory of proved reserve projects
consists of 234 PDNP opportunities, 105 of which are
recompletions in East Texas, and 125 PUD locations, including 20
PUD locations in the Deep Bossier resource play. By targeting
productive zones in multiple stacked pays we are able to
minimize exploration risk and costs.
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Geographically and Geologically Diverse Asset
Base. We have a balanced portfolio of low-risk
conventional and high-impact resource assets across various
historically productive basins. Our core assets are located in
South Louisiana, where the most significant field is Weeks
Island, a large oil field with multiple stacked pay sands; in
East Texas legacy fields with condensate-rich gas; in Oklahoma,
which are predominantly shallow-decline, long-lived oil fields;
in the Deep Bossier, a prolific natural gas sand formation in
East Texas; and in the Eagle Ford Shale in South Texas. Our core
properties are located in areas that benefit from an experienced
well-established service sector, efficient state regulation, and
readily available midstream infrastructure and services. In
addition, based on our estimated net proved reserves as of
December 31, 2010, approximately 50% of our future revenues
are expected to be generated from the production of proved oil
and NGL reserves. We believe our geographic and geologic
diversification enables us to allocate our capital more
profitably, manage market, weather and regulatory risks, and
capitalize on technological improvements.
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61
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Operational Control and Low Cost Structure. We
maintain operational control in properties holding approximately
83% of the
PV-10 value
of our proved reserves, excluding our Deep Bossier resource play
which includes approximately 16% of the
PV-10 value
of our proved reserves and where EnCana is the principal
operator. This control allows us to more effectively manage
production, control operating costs, allocate capital and
control the timing of field development. We have achieved low
average finding and development costs of $2.16 per Mcfe for the
three years ended December 31, 2010. Leases covering only
approximately 9% of the net acreage of our core properties are
set to expire through December 31, 2011, giving us greater
flexibility over our activities.
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Strong Management Team and Seasoned Technical
Expertise. We have an experienced and
technically-adept management team, averaging more than
25 years of industry experience among our top eight
executives. We have built a strong technical staff of geologists
and geophysicists, field operations managers, and engineers in
all relevant disciplines. Our engineers and operations staff
typically began their careers with major oil companies, large
independent producers, or leading service companies, and have
direct experience in our areas of operation. We believe our
engineers are among the best in their respective fields.
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Recent
Developments
Sydson
Acquisition
On April 21, 2011, we completed the purchase of certain oil
and natural gas assets primarily located in Texas and South
Louisiana in which we had shared interests from Sydson Energy
and certain of its related parties for $27.5 million. Total
net proved reserves acquired are estimated to be 800 MBOE
(5 Bcfe), 45% of which is oil. By virtue of this
acquisition, we increased our after payout net revenue interest
in the Eagle Ford Shale by over 50%. Funding for the acquisition
was provided through our credit facility. In addition,
litigation associated with a portion of the assets purchased was
resolved as a result of the transaction.
TODD
Acquisition
On June 17, 2011, we completed the purchase of certain oil
and natural gas assets primarily located in Texas and South
Louisiana in which we had shared interests from TODD and certain
other parties for $22.5 million. Total net proved reserves
acquired are estimated to be 700 MBOE (4 Bcfe), 36% of
which is oil. By virtue of this acquisition, we increased our
after payout net revenue interest in the Eagle Ford Shale by
another 15%. Funding for the acquisition was provided through
our credit facility. In addition, litigation associated with
TODD was resolved as a result of the transaction.
Amendment
to Senior Secured Revolving Credit Facility
On May 23, 2011, we amended our $500 million senior
secured revolving credit facility to, among other things,
increase the borrowing base limit and reduce applicable interest
rates provided thereunder, extend the maturity date, and
increase the amount of senior debt securities that we are
permitted to issue. The amended credit facility is currently
subject to a $260 million borrowing base limit with Wells
Fargo Bank, N.A. as the administrative agent.
62
Reserve
and Production Overview
The following table describes our reserves and production
profile as of December 31, 2010.
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Oil and
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NGLs
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Pro Forma
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Total
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as %
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Average
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Proved
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of Total
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PV-10
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Net
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Daily Net
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Reserve Life
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Reserves
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% Proved
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Proved
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($ in
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Net
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Producing
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Production
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Index
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Property
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(Bcfe)
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Developed(1)
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Reserves (1)
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(millions)(2)
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Acreage(3)
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Wells
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(MMcfe/d)(4)
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(Years)(5)
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South Louisiana
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75.7
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73.6
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%
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27.8
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%
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$
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229.2
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36,505
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34.7
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33.6
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6.8
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East Texas
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63.0
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83.7
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%
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26.3
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%
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153.9
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41,594
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51.4
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14.4
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12.2
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Oklahoma
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43.7
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61.8
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%
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53.7
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%
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129.2
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36,878
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152.7
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5.2
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23.0
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Deep Bossier
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93.2
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56.3
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%
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0.0
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%
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111.9
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16,998
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11.2
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33.6
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7.6
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Eagle Ford
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3.3
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52.3
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%
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87.1
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%
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13.2
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3,611
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0.6
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0.4
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9.0
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Other
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46.1
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53.2
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%
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42.5
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%
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67.8
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36,839
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61.6
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10.9
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11.6
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All Properties
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325.0
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65.9
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%
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25.7
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%
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$
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705.2
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172,425
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312.2
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98.1
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9.3
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(1) |
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Computed as a percentage of total reserves of the property. |
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(2) |
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Based on unweighted average prices as of the first of each month
during the 12 months ended December 31, 2010 of $79.43
per Bbl and $4.38 per MMBtu. |
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(3) |
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Includes developed and undeveloped acreage. |
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(4) |
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Pro forma for 2010 taking into account the Meridian, Sydson, and
TODD acquisitions as if they had occurred on January 1,
2010. See the unaudited pro forma condensed consolidated
financial statements and related notes included elsewhere in
this prospectus. |
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(5) |
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Calculated by dividing total pro forma proved reserves as of
December 31, 2010 by pro forma average daily net production
for 2010 taking into account the Meridian, Sydson, and TODD
acquisitions. Eagle Ford reserve life has been computed using
estimated annualized 2010 production, as these wells only began
producing late in 2010 and actual production is not
representative of a full year. |
Our
Properties
Our core properties are located in South Louisiana, East Texas,
Oklahoma, the Deep Bossier resource play of East Texas and the
Eagle Ford Shale play in South Texas. The majority of our assets
are producing properties located in mature fields characterized
by what we believe to be low geologic risk and a large inventory
of repeatable development opportunities with multiple pay zones.
South
Louisiana
We have four major areas of operation in South Louisiana, in
fields originally developed by major oil companies, where as of
December 31, 2010, we have working interests in 53
producing wells covering 59,017 gross acres (36,505 net acres).
These areas have multiple low-risk exploration and development
targets, potential for exploiting substantial bypassed and
overlooked oil pay zones, and opportunities to increase
profitability through facilities de-bottlenecking, production
enhancements and drilling. We have identified 35 PDNP
opportunities and 10 PUD locations in this area as of
December 31, 2010.
Weeks Island Field. Weeks Island, located in
Iberia Parish, is a historically-prolific oil field with 55
potential pay zones that are structurally trapped against a
piercement salt dome, which we believe offer significant future
opportunities for added production and reserves. The main field
pay zones are characterized by high, stable production rates due
to the predominant water-drive production mechanism and
high-porosity sands. The field was discovered in 1945 by Shell
and subsequently developed by Shell and Exxon. Shells
development activity peaked in the early 1950s with most of the
drilling completed by 1962. Meridian acquired Shells
interest in Weeks Island in 1998, and utilizing a 100 square
mile 3-D
survey in conjunction with subsurface data from 650 wellbores,
continued development of the field and increased reserves. We
operate all the wells in this field in which we have an
interest. As of December 31, 2010, we owned an
63
average 81% working interest in 18 producing wells with 18 PDNP
opportunities and seven PUD locations over approximately 5,294
net acres.
South Hayes Field. The South Hayes field is
located primarily in Cameron Parish, Louisiana. We own and
control operations with an average 44% working interest in the
South Hayes field as of December 31, 2010. South Hayes is
in the center of prolific fields originally developed by Shell,
Texaco, and Exxon, most notably the Chalkley and Thornwell
fields, and has been the focus of our geologic and geophysical
efforts for 15 years, including a
3-D survey
by Alta Mesa in 2009 of highly-prospective acreage. This
proprietary
3-D seismic
survey covered 90 square miles, of which the majority had never
been shot before, imaged key structures, and was seamlessly
integrated with over 300 square miles of previously-existing
3-D data. In
2010, we drilled our first prospect generated from this survey.
We have drilled five wells since 2006 with 100% success, one of
these being the Lacassane
26-1, the
highest-value single producing well in our company (based on
discounted future net revenues at December 31, 2010). We
have multiple low-risk exploration and development targets in
prospective pay zones that have historically produced at high,
stable rates. Additionally, we have invested in fluid gathering
and treating infrastructure that will facilitate future field
development. As of December 31, 2010, we have four
producing wells as well as four PDNP opportunities.
Bayou Biloxi Field. The Bayou Biloxi field is
located in St. Bernard Parish, Louisiana and was discovered by
Meridian as the result of a large
3-D seismic
survey. As of December 31, 2010, we owned and operated an
average 91% working interest in five producing wells. We have
one PDNP recompletion and no PUD locations as of
December 31, 2010. We have identified what we believe is
significant exploration potential in this field and are in
discussions to bring in industry partners to jointly pursue this
with us.
Ramos Field. The Ramos field is a multi-well,
multi-zone producing field located in Terrebonne Parish,
Louisiana acquired by us through the Meridian acquisition. As of
December 31, 2010, we owned and operated an average 73%
working interest in six producing wells and have four PDNP
recompletions and two PUD locations. We believe there is
additional opportunity to increase the profitability of Ramos
through facilities de-bottlenecking, production well and
facility enhancements, and drilling.
East
Texas
Our operations in this area are low-risk expansions of
well-established fields through a consistent, integrated,
multi-discipline technical approach to field re-development. Our
principal assets in the area are the Urbana and Cold Springs
fields, which are adjacent fields with similar geologic
formations producing condensate-rich gas principally from the
Wilcox formation. These fields were originally discovered in the
1950s and 1960s by major oil companies and were developed based
on technology available at the time. The area is served by a
robust pipeline and services infrastructure, and established
local operators familiar with the fields, wells, and facilities.
Wells are typically brought online relatively rapidly, and
production is long-lived as we progressively produce from
multiple pay zones. We have materially increased reserves and
extended the life of these fields by utilizing modern well log
and geochemical analyses, modern fracture stimulation
techniques, and the integration of
3-D seismic
for exploitation as well as exploration. Additionally, through
Meridian we acquired an interest in over 26,508 net acres in the
Austin Chalk and Wilcox formations, and have integrated these
field operations with those of the nearby Urbana field. We have
interests in 114 producing wells covering 41,594 net acres, and
have identified 105 PDNP opportunities and 21 PUD locations as
of December 31, 2010.
Urbana Field. We are the operator of the
Urbana field, located in San Jacinto County, Texas and have an
average 97% working interest in 23 producing wells as of
December 31, 2010. Urbana is a known structure with
multiple pay zones, and as many as 35 productive reservoirs from
7,200 feet to 11,600 feet deep. Advances in fracturing
techniques and low-resistivity log analyses have been the key to
identifying profitable drilling opportunities and additional
productive zones. The liquids/oil to natural gas ratio of
approximately 39 barrels per million cubic feet of natural gas
(based on 2010 production) from Urbana make our wells economic
even at low natural gas prices. We completed the first-ever
3-D survey
over the Urbana structure in late 2009, which has allowed us to
identify additional development of the main field structure,
deeper horizons, and additional nearby geologic features.
64
Cold Springs Field. The Cold Springs field is
located west of the Urbana field in San Jacinto County, Texas.
We are the largest working interest owner with an average 42%
working interest in 35 producing wells as of December 31,
2010. We acquired our interests from other working interest
owners in the field after we recognized the applicability of our
geologic analyses and production practices in the nearby Urbana
field and the potential to increase reserves at Cold Springs.
The Cold Springs field is a known structure with multiple pay
zones, similar to the Urbana field but larger and with greater
development and expansion potential. The liquids/oil to natural
gas makeup of our production in this field ranges from 50 to 80
barrels per million cubic feet of natural gas, and makes our
wells economic even at low natural gas prices. Since 2008, we
have identified additional field-wide pay zones and a western
structural extension to the field.
Austin Chalk. As part of the Meridian
transaction we acquired interests in the Anne Parsons field, an
Austin Chalk play located in Polk County, Texas. The Austin
Chalk is typically developed with horizontal wells, and
production is characterized by high initial rates, high
oil/liquids content, and attractive long-lived reserves. We have
nine PUD locations identified as of December 31, 2010. As
of December 31, 2010, we owned an average 41% working
interest in 17 producing wells in the field. Operators in this
field are the Company, Border to Border Exploration, LLC, and
Devon Energy Corporation.
Oklahoma
Our assets in Oklahoma are located in large fields with multiple
pay zones at depths from less than 2,000 feet to 7,500 feet. The
fields are located in the Sooner Trend area of the Anadarko
Basin and were initially developed by Conoco, Texaco and Exxon.
These assets are predominantly shallow-decline, long-lived oil
fields originally drilled on uniform,
80-acre
spacing and waterflooded to varying degrees. We own an 84%
interest in the Lincoln North Unit which consists of
approximately 74 unit producing wells and two
non-unit
producing wells. We had 12 PDNP opportunities and 30 PUD
locations as of December 31, 2010 in Lincoln North. We own
an 89% interest in the Lincoln SE Unit, which consists of 33
producing wells, 12 PDNP opportunities and no PUD locations, and
we own an 81% interest in the East Hennessey Unit, which
consists of 52 producing wells, six PDNP opportunities and three
PUD locations. Our other assets in this area are wells completed
in deeper formations in these fields, but which are not part of
the state-designated units, and are largely PDP. In the
aggregate, these Oklahoma areas represent approximately 18% of
the PV-10
value of our total proved reserves and 28% of our total proved
reserves for oil and natural gas liquids as of December 31,
2010. Our operations in these fields include infill drilling and
downspacing, waterflood expansion and new waterfloods in the
unit zones. Additionally, we will continue low-risk drilling
below unit formations and recompletions above unit formations.
Our Oklahoma properties have remaining exploitation potential in
down-spacing, production from
non-unit
intervals and exploration upside in the underlying Woodford
Shale.
Deep
Bossier
We believe our Deep Bossier assets provide us with a solid base
for future production and reserve growth through drilling,
advanced fracture stimulation, recompletions, and exploitation
of the Bossier sand, and other formations. The Deep Bossier is a
prolific natural gas formation under active development because
of attractive well qualities, including high production rates,
potential for multi-pay exploration and development and low unit
costs for finding, development, and operations. The region also
benefits from an experienced and well-established service
sector, efficient state regulation, and readily available
midstream infrastructure and services. The Deep Bossier play has
grown substantially over the past decade through the development
activities of Burlington Resources (now ConocoPhillips), EnCana,
Gastar, XTO Energy (now ExxonMobil), Chesapeake, and others.
Wells in this area target multiple natural gas formations and
are typically characterized by high initial production and
significant reserves.
We have a large, contiguous acreage position in the adjacent
Amoruso and Hilltop fields in Leon and Robertson Counties,
Texas, where we own participating interests in approximately
50,010 gross acres (16,998 net acres) as of December 31,
2010. EnCana is the primary operator, managing approximately
two-thirds of our production, with Gastar operating the
remainder. Our operating agreements with EnCana and Gastar allow
65
us substantial input related to operations and control of our
capital expenditures, including provisions that permit us to
either propose or non-consent individual wells. The primary
objective is the lower Bossier sand series at depths from 15,000
feet to greater than 20,000 feet, which we have historically
drilled vertically. There are also shallower horizons with
commercial production near our leasehold, including the Eagle
Ford, Woodbine, Travis Peak, Knowles, Glen Rose, and Buda
formations. Our interests in this area include 48 producing
wells, 12 PDNP opportunities and 20 PUD locations as of
December 31, 2010. We, EnCana, and Gastar have licensed a
3-D survey
covering this acreage and have regular technical collaboration
regarding drilling and completion plans, with an objective of
identifying additional PUD locations resulting from ongoing
drilling.
South
Texas Eagle Ford Shale
Our Eagle Ford Shale assets have increased in significance to
Alta Mesa, and we believe they will be a growing portion of our
portfolio in terms of oil production, oil reserves, and
investment for several years. As part of the Meridian
transaction, we acquired interests primarily in an area of
Karnes County, Texas, referred to as our Eagle Ford Shale play.
Our acreage position also includes portions of Goliad and DeWitt
Counties. The Eagle Ford is a shale typically developed with
horizontal wells, which produce a mix of oil, gas, and natural
gas liquids. We have six PUD locations identified as of
December 31, 2010. As of December 31, 2010, we owned
an average 20% working interest in three producing wells in the
field. The wells are operated by Murphy Oil Corporation.
Other
Assets
In addition to our core areas, we conduct operations in other
areas including the Blackjack Creek field in Florida, the
Marcellus Shale in West Virginia, and various fields in South
Texas. We have identified a total of 49 PDNP opportunities and
12 PUD locations in these areas as of December 31, 2010. We
continually evaluate the experience and data we gain from
operations in these areas to determine future development,
expansion and strategic divestiture plans. We own an approximate
98% working interest in Blackjack Creek, where we are operating
a waterflood in this shallow-decline field originally developed
by Exxon. We have a 1,307 net acre position (2,700 gross acres)
in West Virginia where we successfully drilled two vertical
wells in the Marcellus Shale in 2010.
In South Texas, other than the Eagle Ford, our most substantial
operations are in the Indian Point field where, as of
December 31, 2010, we operated six wells. In addition, we
partnered with EOG Resources on two Frio wells completed in
2010. In East Bay City, we have initiated a natural gas
co-production project to return a formerly-abandoned field to
production. In both Indian Point and other areas, our geologists
and geophysicists continue to use our proprietary seismic data
to identify additional potential.
Our Oil
and Natural Gas Reserves
The table below summarizes our estimated proved reserves as of
December 31, 2010.
|
|
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|
|
|
|
|
|
|
As of December 31, 2010
|
|
|
|
Oil and NGLs
|
|
|
Natural Gas
|
|
|
|
(MMBbls)
|
|
|
(Bcf)
|
|
|
Proved Reserves(1)
|
|
|
|
|
|
|
|
|
Developed
|
|
|
9.2
|
|
|
|
159.2
|
|
Undeveloped
|
|
|
4.7
|
|
|
|
82.2
|
|
|
|
|
|
|
|
|
|
|
Total Proved
|
|
|
13.9
|
|
|
|
241.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Our proved reserves as of December 31, 2010 were calculated
using oil and natural gas price parameters established by
current SEC guidelines and accounting rules based on average
prices as of the first day of each of the twelve months ended on
such date. These average prices were $79.43 per Bbl for oil and
$4.38 per MMBtu for natural gas. Pricing was adjusted for basis
differentials by field based on our historical realized prices.
See Note 19 Supplemental Oil and Natural
Gas Disclosures in the accompanying |
66
|
|
|
|
|
Notes to Consolidated Financial Statements included elsewhere in
this prospectus for information concerning proved reserves. |
The table above represents estimates only. Reserves estimates
are based upon various assumptions, including assumptions
required by the SEC relating to oil and natural gas prices,
drilling and operating expenses, capital expenditures, taxes and
availability of funds. The process of estimating reserves is
complex. This process requires significant decisions and
assumptions in the evaluation of available geological,
geophysical, engineering and economic data for each reservoir.
Furthermore, different reserve engineers may make different
estimates of reserves and cash flow based on the same available
data and these differences may be significant. Therefore, these
estimates are not precise. Actual future production, oil and
natural gas prices, revenues, taxes, development expenditures,
operating expenses and quantities of recoverable oil and natural
gas reserves will most likely vary from those estimated. In
addition, we may adjust estimates of proved reserves to reflect
production history, results of exploration and development,
prevailing oil and natural gas prices and other factors, many of
which are beyond our control.
Internal
Control and Qualifications
The reserve estimation process begins with our internal
engineering department, which prepares much of the data used in
estimating reserves. Working and net revenue interests are
cross-checked and verified by our land department. Cost data are
provided by our accounting department on a preliminary basis and
reviewed by the engineering department. Our Chief Operating
Officer is the technical person primarily responsible for
overseeing the preparation of our reserve estimates. His
qualifications include the following:
|
|
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|
|
over 30 years of practical experience in petroleum
engineering, including the estimation and evaluation of reserves;
|
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|
|
Bachelor of Science degree in Civil Engineering; and
|
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|
|
member in good standing of the Society of Petroleum Engineers.
|
We engaged two third-party engineering firms to prepare 100% of
our 2010 reserves estimates, using the data provided by our
engineering department, as well as other data. Their
methodologies include reviews of production trends, material
balance calculations, analogy to comparable properties, and/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.
We maintain internal controls including the following to ensure
the reliability of reserves estimations:
|
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|
|
|
no employees compensation is tied to the amount of
reserves booked;
|
|
|
|
we follow comprehensive SEC-compliant internal policies to
determine and report proved reserves;
|
|
|
|
reserves estimates are made by experienced reservoir engineers
or under their direct supervision; and
|
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|
|
each quarter, our Chief Operating Officer and Chief Executive
Officer review all significant reserves changes and all new
proved undeveloped reserves additions.
|
In addition, because of our recent growth and in anticipation of
filing reports with the SEC, we engaged a third-party
engineering firm to audit 100% of our 2010 reserve estimates.
The portion of our estimated proved reserves prepared or audited
by each of our third-party engineering firms as of
December 31, 2010 is presented below.
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|
%
|
|
|
|
|
(by Volume)
|
|
Principal Properties
|
|
Netherland, Sewell & Associates, Inc.
|
|
100% audited
|
|
All
|
T. J. Smith & Company, Inc.
|
|
96% prepared
|
|
All but those prepared by W. D. Von Gonten & Co.
|
W.D. Von Gonten & Co.
|
|
4% prepared
|
|
All properties in the Eagle Ford Shale play in Karnes County,
Texas; certain other properties in South Texas; and all
properties in the Marcellus Shale.
|
67
Copies of the reports issued by the engineering firms are filed
with this registration statement of which this prospectus forms
a part as Exhibits 99.2-99.4. The qualifications of the
technical person at each of these firms primarily responsible
for overseeing his firms preparation of our reserve
estimates are set forth below.
Netherland, Sewell & Associates, Inc.:
|
|
|
|
|
over 28 years of practical experience in petroleum
engineering and in the estimation and evaluation of reserves
|
|
|
|
a Registered Professional Engineer in the state of Texas
|
|
|
|
Bachelor of Science Degree in Petroleum Engineering
|
T. J. Smith & Company, Inc.:
|
|
|
|
|
over 40 years of practical experience in petroleum
engineering, with 35 years in the estimation and evaluation
of reserves
|
|
|
|
a Registered Professional Engineer in the states of Texas and
Louisiana
|
|
|
|
Member of the Society of Petroleum Engineers
|
|
|
|
Bachelor of Science Degree in Petroleum Engineering
|
W.D. Von Gonten & Co.:
|
|
|
|
|
over 22 years of practical experience in petroleum geology
and in the estimation and evaluation of reserves
|
|
|
|
a Registered Professional Engineer in the state of Texas
|
|
|
|
Member of the Society of Petroleum Engineers
|
|
|
|
Bachelor of Science Degree in Petroleum Engineering
|
The audit by Netherland, Sewell & Associates, Inc.
conformed to the meaning of reserves audit as
presented in the SECs
Regulation S-K,
Item 1202.
A reserves audit and a financial audit are separate activities
with unique and different processes and results. These two
activities should not be confused. As currently defined by the
SEC within
Regulation S-K,
Item 1202, a reserves audit is the process of reviewing
certain of the pertinent facts interpreted and assumptions
underlying a reserves estimate prepared by another party and the
rendering of an opinion about the appropriateness of the
methodologies employed, the adequacy and quality of the data
relied upon, the depth and thoroughness of the reserves
estimation process, the classification of reserves appropriate
to the relevant definitions used, and the reasonableness of the
estimated reserves quantities. A financial audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. A financial audit also
includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation.
Proved
Undeveloped Reserves
At December 31, 2010 we had PUDs of 111 Bcfe, or
approximately 34% of total proved reserves. The PUDs are
primarily in our Deep Bossier area, in South Louisiana, and in
our Blackjack Creek field in Florida. Total PUDs at
December 31, 2009 were 91 Bcfe, or 39% of our total
reserves. The acquisition of Meridian in 2010, including PUDs
booked post-acquisition for Meridian properties, accounts for
the majority of the increase in PUDs (25 Bcfe). In addition,
there were extensions at Blackjack Creek and certain fields in
East Texas, which added approximately 19 Bcfe, offset by a
downward revision at Deep Bossier (22 Bcfe).
In 2010, we converted 12.6 Bcfe, or 14% of total year end 2009
PUDs, to proved developed reserves. In addition, we converted
7.0 Bcfe, or 17%, of PUDs acquired in the Meridian acquisition,
to proved developed reserves. Costs relating to the development
of PUDs (including Meridian) were approximately
$28.4 million in 2010. Costs of PUD development in 2010 do
not represent the total costs of these conversions, as
additional costs may have been recorded in previous years.
Estimated future development costs relating to the
68
development of 2010 year-end PUDs are $156 million.
Our 2010 proved undeveloped reserves conversion rate is not
indicative of the planned pace of development of our proved
reserves at year-end 2010. All PUDs but one are scheduled to be
drilled by 2015. The basis for our development plans are
(i) allocation of capital to projects in our 2011 capital
budget and (ii) in subsequent years, on the basis of
capital allocation in our five-year business plan, each of which
generally is governed by our expectations of internally
generated cash flow. Reserve calculations at any
end-of-year
period are representative of our development plans at that time.
Changes in commodity pricing, oilfield service costs and
availability, and other economic factors may lead to changes in
development plans.
Approximately 7.6 Bcfe of our PUDs at December 31, 2010
originated more than five years ago. The most significant of
these is a 5.6 Bcfe waterflood expansion project at the East
Hennessey Unit in Oklahoma which has been underway for four
years and is proceeding in stages. We expect to reach full
implementation of the project over the next two to five years.
Production,
Price and Production Cost History
The following table sets forth certain information regarding the
production volumes, average prices received and average
production costs associated with our sale of oil and natural gas
for the periods indicated below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
24,026
|
|
|
|
10,610
|
|
|
|
6,637
|
|
Oil (MBbls)
|
|
|
964
|
|
|
|
505
|
|
|
|
445
|
|
Natural gas liquids (MBbls)
|
|
|
147
|
|
|
|
47
|
|
|
|
47
|
|
Total (MMcfe)
|
|
|
30,694
|
|
|
|
13,919
|
|
|
|
9,593
|
|
Average sales price per unit before hedging effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
4.27
|
|
|
$
|
3.72
|
|
|
$
|
9.33
|
|
Oil (per Bbl)
|
|
|
78.86
|
|
|
|
59.23
|
|
|
|
99.17
|
|
Natural gas liquids (per Bbl)
|
|
|
46.58
|
|
|
|
36.05
|
|
|
|
52.24
|
|
Combined (per Mcfe)
|
|
|
6.05
|
|
|
|
5.10
|
|
|
|
11.31
|
|
Average sales price per unit after hedging effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
5.24
|
|
|
$
|
6.25
|
|
|
$
|
8.81
|
|
Oil (per Bbl)
|
|
|
78.63
|
|
|
|
67.94
|
|
|
|
85.45
|
|
Natural gas liquids (per Bbl)
|
|
|
46.58
|
|
|
|
36.05
|
|
|
|
52.24
|
|
Combined (per Mcfe)
|
|
|
6.79
|
|
|
|
7.35
|
|
|
|
10.32
|
|
Average production costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease and plant operating expense
|
|
$
|
1.37
|
|
|
$
|
1.71
|
|
|
$
|
2.15
|
|
Production and ad-valorem taxes
|
|
|
0.36
|
|
|
|
0.34
|
|
|
|
0.72
|
|
Workover expense
|
|
|
0.24
|
|
|
|
0.65
|
|
|
|
0.85
|
|
Depreciation, depletion and amortization
|
|
|
1.93
|
|
|
|
3.50
|
|
|
|
5.13
|
|
General and administrative
|
|
|
0.66
|
|
|
|
0.63
|
|
|
|
0.67
|
|
Drilling
Activity
The following tables sets forth, for each of the three years
ended December 31, 2010, the number of net productive and
dry exploratory and developmental wells completed, regardless of
when drilling was initiated (all wells are located in the United
States). The information should not be considered indicative of
future performance, nor should it be assumed that there is
necessarily any correlation between the number of
69
productive wells drilled, quantities of reserves found or
economic value. We own one drilling rig which currently is under
contract to a third party.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Development wells (net):
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
17.69
|
|
|
|
12.2
|
|
|
|
14.0
|
|
Dry
|
|
|
|
|
|
|
0.6
|
|
|
|
0.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total development wells
|
|
|
17.69
|
|
|
|
12.8
|
|
|
|
14.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory wells (net):
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
3.82
|
|
|
|
2.7
|
|
|
|
5.1
|
|
Dry
|
|
|
4.30
|
|
|
|
0.3
|
|
|
|
2.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total exploratory wells
|
|
|
8.12
|
|
|
|
3.0
|
|
|
|
7.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present
Activities
As of December 31, 2010, we were drilling 27 gross (10.6
net) wells, which included 10 wells drilling and 17 awaiting
completion.
Productive
Wells
The following table sets forth information with respect to our
ownership interest in productive wells, all of which are located
in the United States, as of December 31, 2010:
|
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|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
|
Gross
|
|
|
Net
|
|
|
Oil wells:
|
|
|
|
|
|
|
|
|
South Louisiana
|
|
|
20
|
|
|
|
15.3
|
|
East Texas
|
|
|
25
|
|
|
|
5.2
|
|
Oklahoma
|
|
|
203
|
|
|
|
150.7
|
|
Deep Bossier
|
|
|
|
|
|
|
|
|
Eagle Ford
|
|
|
3
|
|
|
|
0.6
|
|
Other
|
|
|
26
|
|
|
|
18.6
|
|
|
|
|
|
|
|
|
|
|
All properties
|
|
|
277
|
|
|
|
190.4
|
|
|
|
|
|
|
|
|
|
|
Natural gas wells:
|
|
|
|
|
|
|
|
|
South Louisiana
|
|
|
33
|
|
|
|
19.4
|
|
East Texas
|
|
|
89
|
|
|
|
46.2
|
|
Oklahoma
|
|
|
7
|
|
|
|
2.0
|
|
Deep Bossier
|
|
|
48
|
|
|
|
11.2
|
|
Eagle Ford
|
|
|
|
|
|
|
|
|
Other
|
|
|
75
|
|
|
|
43.0
|
|
|
|
|
|
|
|
|
|
|
All properties
|
|
|
252
|
|
|
|
121.8
|
|
|
|
|
|
|
|
|
|
|
Of the total well count for 2010, one well (one net) is a
multiple completion.
70
Developed
and Undeveloped Acreage Position
The following table sets forth information with respect to our
gross and net developed and undeveloped oil and natural gas
acreage under lease as of December 31, 2010, all of which
is located in the United States:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed Acres
|
|
|
Undeveloped Acres
|
|
|
Total Acres
|
|
Property:
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
South Louisiana
|
|
|
34,127
|
|
|
|
26,046
|
|
|
|
24,890
|
|
|
|
10,459
|
|
|
|
59,017
|
|
|
|
36,505
|
|
East Texas
|
|
|
35,217
|
|
|
|
17,217
|
|
|
|
45,939
|
|
|
|
24,377
|
|
|
|
81,156
|
|
|
|
41,594
|
|
Oklahoma
|
|
|
56,597
|
|
|
|
36,878
|
|
|
|
|
|
|
|
|
|
|
|
56,597
|
|
|
|
36,878
|
|
Deep Bossier
|
|
|
16,000
|
|
|
|
5,332
|
|
|
|
34,010
|
|
|
|
11,666
|
|
|
|
50,010
|
|
|
|
16,998
|
|
Eagle Ford
|
|
|
2,111
|
|
|
|
396
|
|
|
|
19,092
|
|
|
|
3,215
|
|
|
|
21,203
|
|
|
|
3,611
|
|
Other
|
|
|
77,440
|
|
|
|
26,853
|
|
|
|
14,905
|
|
|
|
9,986
|
|
|
|
92,345
|
|
|
|
36,839
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All properties
|
|
|
221,492
|
|
|
|
112,722
|
|
|
|
138,836
|
|
|
|
59,703
|
|
|
|
360,328
|
|
|
|
172,425
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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As is customary in the oil and natural gas industry, we can
generally retain interest in undeveloped acreage through
drilling activity that establishes commercial production
sufficient to maintain the leases or by paying delay rentals
during the remaining primary term of leases. The oil and natural
gas leases in which we have an interest are for varying primary
terms and, if production under a lease continues from developed
lease acreage beyond the primary term, we are entitled to hold
the lease for as long as oil or natural gas is produced. The oil
and natural gas properties consist primarily of oil and natural
gas wells and interests in leasehold acreage, both developed and
undeveloped.
Undeveloped
Acreage Expirations
The following table sets forth information with respect to our
gross and net undeveloped oil and natural gas acreage under
lease as of December 31, 2010, all of which is located in
the United States, that will expire over the following three
years by region unless production is established within the
spacing units covering the acreage prior to the expiration dates:
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2011
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2012
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2013
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Property:
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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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South Louisiana
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14,992
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6,297
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9,898
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4,162
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East Texas
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16,775
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8,528
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9,619
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5,468
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19,545
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10,381
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Oklahoma
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Deep Bossier
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8,008
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2,722
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5,639
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1,942
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5,019
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1,750
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Eagle Ford
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10,112
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1,689
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4,012
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682
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3,798
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646
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Other
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8,023
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3,768
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951
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676
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5,931
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5,541
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All properties
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42,918
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16,707
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35,213
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15,065
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44,191
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22,480
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Corporate
Partner and Structure
We began operations in 1987, and have funded development and
operating activities primarily through cash from operations,
capital raised from equity contributed by our founder, capital
contributed by a private equity partner, borrowings under our
bank credit facilities, and proceeds from the issuance in
October 2010 of $300 million principal amount of our senior
secured notes due October 15, 2018. Our private equity
partner, AMIH, is an affiliate of DCPF IV. DCPF IV is advised by
Denham Capital Management LP, a private equity firm focused on
energy and commodities. Since investing in us as a limited
partner in 2006, AMIH has contributed $150 million in
equity, which includes a $50 million contribution as part
of the Meridian acquisition (described above). In October 2010,
AMIH received a $50 million distribution from the proceeds
of the offer and sale of the old notes.
71
As a limited partnership, our operations and activities are
managed by the board of directors of our general partner, Alta
Mesa GP, and the officers of Alta Mesa Services, an entity
wholly owned by us. The sole member of Alta Mesa GP is Alta Mesa
Resources, LP, an entity owned by Michael E. Ellis, the founder
of our company, Chief Operating Officer, and Chairman of the
Board of Directors of Alta Mesa GP, and his spouse, Mickey Ellis.
Marketing
and Customers
The market for our oil and natural gas production depends on
factors beyond our control, including the extent of domestic
production and imports of oil and natural gas, the proximity and
capacity of natural gas pipelines and other transportation
facilities, the demand for oil and natural gas, the marketing of
competitive fuels and the effect of state and federal
regulation. The oil and natural gas industry also competes with
other industries in supplying the energy and fuel requirements
of industrial, commercial and individual consumers. The prices
received for oil and natural gas sales are generally tied to
monthly or daily indices as quoted in industry publications.
Crude oil and natural gas purchasers vary by area. We market
substantially all our oil and natural gas production pursuant to
marketing contracts. We are not currently committed to provide a
fixed and determinable quantity of oil or gas in the near future
under our contracts.
For the year ended December 31, 2010, based on revenues
excluding hedging activities, one major customer, EnCana
Oil & Gas (USA), Inc., accounted for 10% or more of
those revenues individually, with a contribution of
$38.4 million. We believe that the loss of such customers
would not have a material adverse effect on us because
alternative purchasers are readily available.
Competition
We encounter intense competition from other oil and natural gas
companies in all areas of our operations, including the
acquisition of producing properties and undeveloped acreage. Our
competitors include major integrated oil and natural gas
companies, numerous independent oil and natural gas companies
and individuals. Many of our competitors are large,
well-established companies with substantially larger operating
staffs and greater capital resources and have been engaged in
the oil and natural gas business for a much longer time than us.
These companies may be able to pay more for productive oil and
natural gas properties, exploratory prospects and to define,
evaluate, bid for and purchase a greater number of properties
and prospects than our financial or human resources permit. Our
ability to acquire additional properties and to discover
reserves in the future will be dependent upon our ability to
evaluate and select suitable properties and to consummate
transactions in this highly competitive environment.
We are also affected by competition for drilling rigs and the
availability of related equipment. In the past, the oil and
natural gas industry has experienced shortages of drilling rigs,
equipment, pipe and personnel, which have delayed development,
exploitation and exploration activities. We are unable to
predict when, or if, such shortages may occur or how they would
affect our exploitation and development program.
72
Employees
As of December 31, 2010, we had 126 full-time employees. We
are not a party to any collective bargaining agreements and have
not experienced any strikes or work stoppages. We believe our
relationships with our employees are good. From time to time, we
utilize the services of independent contractors to perform
various field and other services. See Certain
Relationships and Related Party Transactions Land
Consulting Services.
Legal
Proceedings
We are party to various litigation matters arising in the
ordinary course of business. We do not believe the outcome of
such disputes or legal actions will have a material adverse
effect on our consolidated financial statements. Accruals for
losses associated with litigation are made when losses are
deemed probable and can be reasonably estimated.
On July 23, 2009, we made a payment of $25.5 million
and took assignment of substantially all working interests that
had been held by Chesapeake in an approximate 50,000 acre area
of Leon and Robertson Counties, Texas in the Deep Bossier play.
We had exercised our preferential right to purchase these
interests from Gastar in late 2005, but Gastar and Chesapeake
had opposed this and Chesapeake took record title until we
finally and conclusively prevailed, and in 2008 a Texas court of
appeals directed that specific performance take place. In early
2009, the Texas Supreme Court denied the defendants
request to hear the appeal. As a result, we were able to take
25% - 33% working interests in over 30 producing wells and
participate in further development of the area, primarily with
EnCana, but also with Gastar. A subsequent payment to EnCana of
$15.2 million plus purchase accounting adjustments of
$3.8 million brought the total cost of the acquisition to
$44.5 million. While the ownership of these interests has
been decided by the courts, we are pursuing other claims against
Chesapeake; Chesapeake is claiming an additional
$36.5 million of past expenses. We are 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, or potential gain should
the outcome be favorable. Therefore, we have not provided any
amount for this matter in our consolidated financial statements
at December 31, 2010.
In January 2011, Sydson Energy brought suit for declaratory
relief, breach of contract and tortious interference related to
certain assignments of oil and gas interests. On April 21,
2011, we completed the purchase of certain oil and natural gas
assets primarily located in Texas and South Louisiana in which
we had shared interests from Sydson Energy and certain of its
related parties. Total net proved reserves acquired are
estimated to be 800 MBOE (5 Bcfe), 45% of which is oil. By
virtue of this acquisition, we increased our net revenue
interest in the Eagle Ford Shale by over 50%. All claims related
to the suit filed in January 2011 by Sydson Energy were settled
in connection with the transaction.
In November, 2010, TODD filed a petition seeking declaratory
relief based on TODDs employment of Thomas Tourek, one of
our former independent contractors. On June 17, 2011, we
completed the purchase of certain oil and natural gas assets
primarily located in Texas and South Louisiana in which we had
shared interests from TODD and certain other parties for
$22.5 million. Total net proved reserves acquired are
estimated to be 700 MBOE (4 Bcfe), 36% of which is
oil. By virtue of this acquisition, we increased our after
payout net revenue interest in the Eagle Ford Shale by 15%. All
claims related to the suit filed in November 2010 by TODD were
settled in connection with the transaction.
Management has established a liability for soil contamination in
Florida of approximately $943,000 and $898,000 at
December 31, 2010 and 2009, respectively, based on our
engineering estimates. The obligations are included in other
long-term liabilities in the accompanying consolidated balance
sheets.
Various landowners have sued Meridian (along with numerous other
oil companies) in lawsuits concerning several fields in which
Meridian has had operations. The lawsuits seek injunctive relief
and other relief,
73
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 Meridians oil and natural
gas operations. We are 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, we
have not provided any amount for these claims in our
consolidated financial statements at December 31, 2010.
Environmental
Matters and Regulation
Our operations are subject to stringent and complex federal,
state and local laws and regulations that govern the protection
of the environment, as well as the discharge of materials into
the environment. These laws and regulations may, among other
things:
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require the acquisition of various permits before drilling
commences;
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require the installation of pollution control equipment in
connection with operations;
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place restrictions or regulations upon the use of the material
based on our operations;
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restrict the types, quantities and concentrations of various
substances that can be released into the environment or used in
connection with drilling, production and transportation
activities;
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limit or prohibit drilling activities on lands lying within
wilderness, wetlands and other protected areas; and
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require remedial measures to mitigate pollution from former and
ongoing operations, such as site restoration, pit closure and
plugging of abandoned wells.
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These laws, rules and regulations may also restrict the rate of
oil and natural gas production below the rate that would
otherwise be possible. The regulatory burden on the oil and
natural gas industry increases the cost of doing business in the
industry and consequently affects profitability. Additionally,
Congress and federal, state and local agencies frequently revise
environmental laws and regulations, and such changes could
result in increased costs for environmental compliance, such as
waste handling, permitting, or cleanup for the oil and natural
gas industry and could have a significant impact on our
operating costs.
The following is a summary of some of the existing laws, rules
and regulations to which our business operations are subject.
Solid
and Hazardous Waste Handling
The federal Resource Conservation and Recovery Act
(RCRA) and comparable state statutes regulate the
generation, transportation, treatment, storage, disposal and
cleanup of hazardous solid waste. Although oil and natural gas
waste generally is exempt from regulations as hazardous waste
under RCRA, we generate waste as a routine part of our
operations that may be subject to RCRA. Although a substantial
amount of the waste generated in our operations are regulated as
non-hazardous solid waste rather than hazardous waste, there is
no guarantee that the Environmental Protection Agency
(EPA) or individual states will not adopt more
stringent requirements for the handling of non- hazardous waste
or categorize some non-hazardous waste as hazardous in the
future. Any such change could result in an increase in our costs
to manage and dispose of waste, which could have a material
adverse effect on our results of operations and financial
position.
Comprehensive
Environmental Response, Compensation, and Liability Act
(CERCLA)
CERCLA imposes joint and several liability for costs of
investigation and remediation and for natural resource damages
without regard to fault or legality of the original conduct, on
certain classes of persons with respect to the release into the
environment of substances designated under CERCLA as hazardous
substances (Hazardous Substances). These classes of
persons, or so-called potentially responsible parties
(PRPs) include the current and past owners or
operators of a site where the release occurred and anyone who
disposed or arranged for the disposal of a hazardous substance
found at the site. CERCLA also authorizes the EPA and,
74
in some instances, third parties to take actions in response to
threats to public health or the environment and to seek to
recover from the PRPs the costs of such action. Many states have
adopted comparable or more stringent state statutes.
Although CERCLA generally exempts petroleum from the
definition of Hazardous Substance, in the course of our
operations, we have generated and will generate wastes that may
fall within CERCLAs definition of Hazardous Substances and
may have disposed of these wastes at disposal sites owned and
operated by others. We may also be the owner or operator of
sites on which Hazardous Substances have been released. To our
knowledge, neither we nor our predecessors have been designated
as a PRP by the EPA under CERCLA; we also do not know of any
prior owners or operators of our properties that are named as
PRPs related to their ownership or operation of such properties.
In the event contamination is discovered at a site on which we
are or have been an owner or operator or to which we sent
Hazardous Substances, we could be liable for the costs of
investigation and remediation and natural resources damages.
We currently own, lease, or operate numerous properties that
have been used for oil and natural gas exploration and
production for many years. Although we believe we have utilized
operating and waste disposal practices that were standard in the
industry at the time, Hazardous Substances, wastes or
hydrocarbons may have been released on or under the properties
owned or leased by us, or on or under other locations, including
offsite locations, where such materials have been taken for
disposal. In addition, some of these properties have been
operated by third parties or by previous owners or operators
whose treatment and disposal of Hazardous Substances, wastes, or
hydrocarbons were not under our control. These properties and
the materials disposed or released on them may be subject to
CERCLA or RCRA and analogous state laws. In the future, we could
be required to remediate property, including groundwater,
containing or impacted by previously disposed materials
(including wastes disposed or released by prior owners or
operators, or property contamination, including groundwater
contamination by prior owners or operators) or to perform
remedial plugging operations to prevent future or mitigate
existing contamination.
Clean
Water Act
The Federal Water Pollution Control Act (the Clean Water
Act) and analogous state laws impose restrictions and
strict controls with respect to the discharge of pollutants,
including spills and leaks of produced water and other oil and
natural gas wastes, into waters of the United States, a term
broadly defined. The discharge of pollutants into regulated
waters is prohibited, except in accordance with the terms of a
permit issued by EPA or an analogous state agency. The Clean
Water Act also prohibits the discharge of dredge and fill
material in regulated waters, including wetlands, unless
authorized by a permit issued by the U.S. Army Corps of
Engineers. Federal and state regulatory agencies can impose
administrative, civil and criminal penalties, as well as require
remedial or mitigation measures, for non-compliance with
discharge permits or other requirements of the Clean Water Act
and analogous state laws and regulations. In the event of an
unauthorized discharge of wastes, we may be liable for penalties
and costs.
Safe
Drinking Water Act (SDWA)
The SWDA regulates, among other things, underground injection
operations. Currently, most hydraulic fracturing activities are
regulated at the state level, as the SDWA exempts most hydraulic
fracturing. Recent legislative activity has occurred which, if
successful, would impose additional regulation under the SDWA
upon the use of hydraulic fracturing fluids. Congress is
considering two companion bills entitled the FRAC Act. If
enacted, the legislation would impose on our hydraulic
fracturing operations permit and financial assurance
requirements, requirements that we adhere to construction
specifications, fulfill monitoring, reporting and recordkeeping
obligations, and meet plugging and abandonment requirements. In
addition to subjecting the injection of hydraulic fracturing to
the SDWA regulatory and permitting requirements, the proposed
legislation would require the disclosure of the chemicals within
the hydraulic fluids, which could make it easier for third
parties opposing hydraulic fracturing to initiate legal
proceedings based on allegations that specific chemicals used in
the process could adversely affect ground water. Neither piece
of legislation has been passed. Many states and other local
regulatory authorities have enacted or are considering
regulations on hydraulic fracturing, including disclosure
requirements and regulations that could restrict hydraulic
fracturing
75
in certain circumstances. In addition, the EPA has commenced a
study of the potential adverse effects that hydraulic fracturing
may have on water quality and public health, and a committee of
the U.S. House of Representatives has commenced its own
investigation into hydraulic fracturing practices. If the
pending or similar legislation is enacted or other new
requirements or restrictions regarding hydraulic fracturing are
adopted as a result of these studies, we could incur substantial
compliance costs and the requirements could negatively impact
our ability to conduct fracturing activities on our assets.
Oil
Pollution Act
The primary federal law related to oil spill liability is the
Oil Pollution Act (the OPA) which amends and
augments oil spill provisions of the Clean Water Act and imposes
certain duties and liabilities on certain responsible
parties related to the prevention of oil spills and
damages resulting from such spills in or threatening United
States waters or adjoining shorelines. A liable
responsible party includes the owner or operator of
a facility, vessel or pipeline that is a source of an oil
discharge or that poses the substantial threat of discharge, or
in the case of offshore facilities, the lessee or permittee of
the area in which a discharging facility is located. OPA assigns
joint and several liability, without regard to fault, to each
liable party for oil removal costs and a variety of public and
private damages. Although defenses exist to the liability
imposed by OPA, they are limited. In the event of an oil
discharge or substantial threat of discharge, we may be liable
for costs and damages.
Air
Emissions
Our operations are subject to local, state and federal
regulations for the control of emissions from sources of air
pollution. Federal and state laws require new and modified
sources of air pollutants to obtain permits prior to commencing
construction. Major sources of air pollutants are subject to
more stringent, federally imposed requirements including
additional permits. Federal and state laws designed to control
hazardous air pollutants, might require installation of
additional controls. Administrative enforcement actions for
failure to comply strictly with air pollution regulations or
permits are generally resolved by payment of monetary fines and
correction of any identified deficiencies. Alternatively,
regulatory agencies could bring lawsuits for civil penalties or
require us to forego construction, modification or operation of
certain air emission sources.
National
Environmental Policy Act
Oil and natural gas exploration and production activities on
federal lands (including offshore leasing) may be subject to the
National Environmental Policy Act (the NEPA), which
requires federal agencies, including the Department of Interior,
to evaluate major agency actions having the potential to
significantly impact the environment. In the course of such
evaluations, an agency will prepare an Environmental Assessment
that assesses the potential direct, indirect and cumulative
impacts of a proposed project and, if necessary, will prepare a
more detailed Environmental Impact Statement that may be made
available for public review and comment. All of our current
exploration and production activities, as well as proposed
exploration and development plans, on federal lands require
governmental permits that are subject to the requirements of
NEPA. As a result of the events in the Gulf of Mexico, the NEPA
process is being reviewed and may become more stringent. This
process has the potential to delay or impose additional
conditions upon the development of oil and natural gas projects.
Climate
Change Regulation and Legislation
More stringent laws and regulations relating to climate change
and greenhouse gases (GHGs) may be adopted in the
future and could cause us to incur material expenses in
complying with them. Both houses of Congress have actively
considered legislation to reduce emissions of GHGs, but no
legislation has yet passed. In the absence of comprehensive
federal legislation on GHG emission control, the EPA has been
moving forward with rulemaking under the CAA to regulate GHGs as
pollutants under the CAA. The EPA has adopted regulations that
would require a reduction in emissions of GHGs from motor
vehicles, thus triggering permit requirements for GHGs from
certain stationary sources. In June 2010, EPA adopted the
Prevention of Significant Deterioration and Title V
Greenhouse Gas Tailoring Rule, which phases in permitting
requirements
76
for stationary sources of GHGs, beginning January 2, 2011.
This rule tailors these permitting programs to apply
to certain stationary sources of GHG emissions in a multi-step
process, with the largest sources first subject to permitting.
We do not believe our operations currently are subject to
subject to these permitting requirements, but if our operations
become subject to these or other similar requirements, we could
incur significant costs to control our emissions and comply with
regulatory requirements. In addition, the EPA has adopted a
mandatory GHG emissions reporting program that imposes reporting
and monitoring requirements on various types of facilities and
industries. In November 2010, the EPA expanded its GHG reporting
rule to include onshore and offshore oil and natural gas
production, processing, transmission, storage, and distribution
facilities, requiring reporting of GHG emissions from such
facilities on an annual basis, with reporting beginning in 2012
for emissions occurring in 2011. We do not believe our
operations to be subject to GHG reporting requirements, but
there is no guarantee that the EPA will not further expand the
program to additional sources and facilities. Should we be
required to report GHG emissions, it could require us to incur
costs to monitor, keep records of, and report emissions of GHGs.
Because of the lack of any comprehensive legislative program
addressing GHGs, there is a great deal of uncertainty as to how
and when federal regulation of GHGs might take place. Some
members of Congress have expressed the intention to promote
legislation to curb EPAs authority to
regulation GHGs. In addition to possible federal
regulation, a number of states, individually and regionally,
also are considering or have implemented GHG regulatory
programs. These potential regional and state initiatives may
result in so-called cap and trade programs, under which overall
GHG emissions are limited and GHG emissions are then allocated
and sold, and possibly other regulatory requirements, that could
result in our incurring material expenses to comply, e.g., by
being required to purchase or to surrender allowances for GHGs
resulting from our operations. The federal, regional and local
regulatory initiatives also could adversely affect the
marketability of the oil and natural gas we produce. The impact
of such future programs cannot be predicted, but we do not
expect our operations to be affected any differently than other
similarly situated domestic competitors.
OSHA
and Other Laws and Regulation
We are subject to the requirements of the federal Occupational
Safety and Health Act (OSHA) and comparable state
statutes. These laws and the implementing regulations strictly
govern the protection of the health and safety of employees. The
OSHA hazard communication standard, the EPA community
right-to-know
regulations under the Title III of CERCLA and similar state
statutes require that we organize and/or disclose information
about hazardous materials used or produced in our operations. We
believe that we are in substantial compliance with these
applicable requirements and with other OSHA and comparable
requirements.
We believe that we are in substantial compliance with all
existing environmental laws and regulations applicable to our
current operations and that our continued compliance with
existing requirements will not have a material adverse impact on
our financial condition and results of operations. We did not
incur any material capital expenditures for remediation or
pollution control activities for the years ended
December 31, 2010, 2009 and 2008. Additionally, we are not
aware of any environmental issues or claims that will require
material capital expenditures during 2011 or that will otherwise
have a material impact on our financial position or results of
operations in the future. However, we cannot assure you that the
passage of more stringent laws and regulations in the future
will not have a negative impact our business activities,
financial condition or results of operations.
Other
Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by
numerous federal, state and local authorities. Legislation
affecting the oil and natural gas industry is under constant
review for amendment or expansion, frequently increasing the
regulatory burden. Also, numerous departments and agencies, both
federal and state, are authorized by statute to issue rules and
regulations binding on the oil and natural gas industry and its
individual members, some of which carry substantial penalties
for failure to comply. Although the regulatory burden on the oil
and natural gas industry increases our cost of doing business
and, consequently, affects our
77
profitability, these burdens generally do not affect us any
differently or to any greater or lesser extent than they affect
other companies in the industry with similar types, quantities
and locations of production.
Legislation continues to be introduced in Congress and
development of regulations continues in the Department of
Homeland Security and other agencies concerning the security of
industrial facilities, including oil and natural gas facilities.
Our operations may be subject to such laws and regulations.
Presently, it is not possible to accurately estimate the costs
we could incur to comply with any such facility security laws or
regulations, but such expenditures could be substantial.
Drilling
and Production
Our operations are subject to various types of regulation at the
federal, state and local levels. These types of regulation
include requiring permits for the drilling of wells, drilling
bonds and reports concerning operations. Most states and some
counties and municipalities in which we operate also regulate
one or more of the following:
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the location of wells;
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the method of drilling and casing wells;
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the surface use and restoration of properties upon which wells
are drilled; and
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the plugging and abandoning of wells.
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State laws regulate the size and shape of drilling and spacing
units or proration units governing the pooling of oil and
natural gas properties. Some states allow forced pooling or
integration of tracts to facilitate exploitation while other
states rely on voluntary pooling of lands and leases. In some
instances, forced pooling or unitization may be implemented by
third parties and may reduce our interest in the unitized
properties. In addition, state conservation laws establish
maximum rates of production from oil and natural gas wells,
generally prohibit the venting or flaring of natural gas and
impose requirements regarding the ratability of production.
These laws and regulations may limit the amount of oil and
natural gas we can produce from our wells or limit the number of
wells or the locations at which we can drill. Moreover, each
state generally imposes a production, ad valorem or severance
tax with respect to the production and sale of oil, natural gas
and natural gas liquids within its jurisdiction.
In addition, 11 states have enacted surface damage statutes
(SDAs). These laws are designed to compensate for
damage caused by mineral development. Most SDAs contain entry
notification and negotiation requirements to facilitate contact
between operators and surface owners/users. Most also contain
bonding requirements and specific expenses for exploration and
producing activities. Costs and delays associated with SDAs
could impair operational effectiveness and increase development
costs.
We do not control the availability of transportation and
processing facilities used in the marketing of our production.
For example, we may have to shut-in a productive natural gas
well because of a lack of available natural gas gathering or
transportation facilities.
If we conduct operations on federal, state or Indian oil and
natural gas leases, these operations must comply with numerous
regulatory restrictions, including various non-discrimination
statutes, royalty and related valuation requirements, and
certain of these operations must be conducted pursuant to
certain
on-site
security regulations and other appropriate permits issued by the
Bureau of Land Management, Minerals Management Service or other
appropriate federal or state agencies.
Federal
Natural Gas Regulation
The availability, terms and cost of transportation significantly
affect sales of natural gas. The interstate transportation and
sale for resale of natural gas is subject to federal regulation,
including regulation of the terms, conditions and rates for
interstate transportation, storage and various other matters,
primarily by the Federal Energy Regulatory Commission
(FERC). Federal and state regulations govern the
price and terms for access to natural gas pipeline
transportation. FERCs regulations for interstate natural
gas transmission in
78
some circumstances may also affect the intrastate transportation
of natural gas. FERC regulates the rates, terms and conditions
applicable to the interstate transportation of natural gas by
pipelines under the Natural Gas Act as well as under
Section 311 of the Natural Gas Policy Act.
Since 1985, FERC has implemented regulations intended to
increase competition within the natural gas industry by making
natural gas transportation more accessible to natural gas buyers
and sellers on an open-access, nondiscriminatory basis. FERC has
announced several important transportation related policy
statements and rule changes, including a statement of policy and
final rule issued February 25, 2000, concerning
alternatives to its traditional
cost-of-service
rate-making methodology to establish the rates interstate
pipelines may charge for their services. The final rule revises
FERCs pricing policy and current regulatory framework to
improve the efficiency of the market and further enhance
competition in natural gas markets.
FERC has also issued several other generally pro-competitive
policy statements and initiatives affecting rates and other
aspects of pipeline transportation of natural gas. On
May 31, 2005, FERC generally reaffirmed its policy of
allowing interstate pipelines to selectively discount their
rates in order to meet competition from other interstate
pipelines. On June 15, 2006, the FERC issued an order in
which it declined to establish uniform standards for natural gas
quality and interchangeability, opting instead for a
pipeline-by-pipeline
approach. Four days later, on June 19, 2006, in order to
facilitate development of new storage capacity, FERC established
criteria to allow providers to charge market-based (i.e.
negotiated) rates for storage services. On June 19, 2008,
the FERC removed the rate ceiling on short-term releases by
shippers of interstate pipeline transportation capacity.
Although natural gas prices are currently unregulated, Congress
historically has been active in the area of natural gas
regulation. We cannot predict whether new legislation to
regulate natural gas might be proposed, what proposals, if any,
might actually be enacted by Congress or the various state
legislatures, and what effect, if any, the proposals might have
on the operations of the underlying properties. Sales of
condensate and natural gas liquids are not currently regulated
and are made at market prices.
State
Natural Gas Regulation
Various states regulate the drilling for, and the production,
gathering and sale of, natural gas, including imposing severance
taxes and requirements for obtaining drilling permits. States
also regulate the method of developing new fields, the spacing
and operation of wells and the prevention of waste of natural
gas resources. States may regulate rates of production and may
establish maximum daily production allowables from natural gas
wells based on market demand or resource conservation, or both.
States do not regulate wellhead prices or engage in other
similar direct economic regulation, but there can be no
assurance that they will not do so in the future. The effect of
these regulations may be to limit the amounts of natural gas
that may be produced from our wells and to limit the number of
wells or locations we can drill.
Other
Regulation
In addition to the regulation of oil and natural gas pipeline
transportation rates, the oil and natural gas industry generally
is subject to compliance with various other federal, state and
local regulations and laws. Some of those laws relate to
occupational safety, resource conservation and equal employment
opportunity.
79
MANAGEMENT
As is the case with many partnerships, we do not directly employ
officers, directors or employees. Our operations and activities
are managed by the board of directors of our general partner,
Alta Mesa Holdings GP, LLC, and the officers and directors of
Alta Mesa Services, LP, an entity wholly owned by us. Prior to
the offering of the old notes in October 2010, Alta Mesa
Services was owned by Michael E. and Mickey Ellis. References to
our directors are references to the directors of Alta Mesa GP.
References to our officers and employees are references to the
officers and employees of Alta Mesa Services.
All of our executive management personnel are employees of Alta
Mesa Services and devote all of their time to our business and
affairs. We also utilize a significant number of employees of
Alta Mesa Services to operate our properties and provide us with
certain general and administrative services. Under the shared
services and expenses agreement, we reimburse Alta Mesa Services
for its operational personnel who perform services for our
benefit. See Certain Relationships and Related Party
Transactions Shared Services and Expenses
Agreement.
Board
Leadership Structure
Our Chairman is Michael E. Ellis, our Chief Operating Officer
and founder of the Company. Our Board of Directors has no policy
regarding the separation of the positions of Chief Executive
Officer and Chairman. We also do not have a lead independent
director.
Board
Oversight of Risk
Like all businesses, we face risks in our business activities.
Many of these risks are discussed under the caption Risk
Factors elsewhere in this prospectus. The board of
directors has delegated to management the primary responsibility
of risk management, while it has retained oversight of
management in that regard.
In addition, our Board of Directors considers our practices
regarding risk assessment and risk management, reviews our
contingent liabilities, reviews our oil and natural gas reserve
estimation practices, as well as major legislative and
regulatory developments that could affect us. Our Board reviews
and attempts to mitigate risks which may result from our
compensation policies.
Executive
Officers and Directors
The following table sets forth the names, ages and offices of
our present directors and executive officers as of May 31,
2011. Members of our Board of Directors are elected for one-year
terms.
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Director
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Name
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Age
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Since
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Position
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Harlan H. Chappelle
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54
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2005
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President, Chief Executive Officer and Director
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Michael E. Ellis
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54
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1987
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Founder, Chairman, Vice President of Engineering and Chief
Operating Officer
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Mickey Ellis
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53
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1987
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Director
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Michael A. McCabe
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55
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Vice President and Chief Financial Officer
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F. David Murrell
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49
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Vice President, Land and Business Development
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The following is a biographical summary of the business
experience of these directors and executive officers:
Harlan H. Chappelle joined Alta Mesa as President and CEO
in November 2004, and has led the company in a period of
significant growth, building a strong management and technical
team, focusing the company on its greatest opportunities, making
strategic acquisitions, and restructuring its financing.
Mr. Chappelle has over 25 years in field operations,
engineering, management, marketing and trading, acquisitions and
divestitures, and field re-development in collaboration with
majors including Exxon and Chevron. He has worked for Louisiana
Land & Exploration Company, Burlington Resources,
Southern Company, and Mirant. Mr. Chappelle retired as a
Commander from the U.S. Navy Reserve. He has a Bachelor
80
of Chemical Engineering from Auburn University and a Master of
Science in Petroleum Engineering from The University of Texas at
Austin.
Michael E. Ellis founded Alta Mesa in 1987 after
beginning his career with Amoco, and is our Chairman and Chief
Operating Officer, as well as Vice President of Engineering.
Mr. Ellis manages all
day-to-day
engineering and field operations of Alta Mesa. He built the
companys asset base by starting with small earn-in
exploitation projects, then progressively growing the company
with successive acquisitions of fields from major oil companies,
and consistent success in exploration and development drilling.
He has over 30 years experience in management,
engineering, exploration, and acquisitions and divestitures in
the Gulf Coast, Midcontinent and West Texas regions.
Mr. Ellis holds a Bachelor of Science in Civil Engineering
from West Virginia University.
Mickey Ellis has served as a Director since the
companys inception in 1987. Ms. Ellis is actively
involved in the leadership of charitable organizations, as a
Board Member of Houston Area Respite Care and The Confessing
Movement of the United Methodist Church, Treasurer of the
National Charity League Star Chapter, Committee Member on
several committees within Mission Bend United Methodist Church,
and Building Relocation Coordinator for Mission Bend Christian
Academy. She is a major fundraiser for the Susan G. Komen
Foundation, and an active volunteer for CanCare. Ms. Ellis
is the spouse of Michael E. Ellis.
Michael A. McCabe, our Chief Financial Officer, joined
Alta Mesa in September 2006. Mr. McCabe has over
25 years of corporate finance experience, with a focus on
the energy industry. From 2004 until 2006, Mr. McCabe
served as President and sole owner of Bridge Management Group,
Inc., a private consulting firm primarily providing advisory
services to us and to MultiFuels, Inc., a Houston based
developer of natural gas storage facilities. He has served in
senior positions with Bank of Tokyo, Bank of New England, and
Key Bank. Mr. McCabe holds a Bachelor of Science in
Chemistry and Physics from Bridgewater State University, a
Masters of Science in Chemical Engineering from Purdue
University and a Masters of Business Administration in Financial
Management from Pace University.
David Murrell has served as our Vice President, Land and
Business Development since 2006. Mr. Murrell has over
25 years of experience in Gulf Coast leasing, exploration
and development programs, contract management and acquisitions
and divestitures. He created a structured land management system
for Alta Mesa, and built a team of lease analysts, landmen, and
field representatives that has facilitated our companys
growth. Mr. Murrell earned a Bachelor of Business
Administration in Petroleum Land Management from the University
of Oklahoma.
Qualifications
of Directors
Mr. Chappelles experience as our Chief Executive
Officer since 2004, combined with his significant equity
ownership of us, uniquely qualify him to serve as a director of
our general partner.
Mr. Ellis is our founder; his experience in that capacity
and as one of our executive officers since 1987 provide him
intimate knowledge of our operations, finances and strategy and
uniquely qualify him to serve as the Chairman of our general
partner.
Ms. Ellis role in working with us since our inception
in 1987 provides her with valuable knowledge of our business and
operations.
Executive
Compensation and Other Information
Compensation
Discussion and Analysis
Because we are a partnership, we do not directly employ any of
the persons responsible for managing our business. Our
operations and activities are managed by the Board of Directors
of our general partner, Alta Mesa GP, and the officers of Alta
Mesa Services, our wholly owned subsidiary. References to our
officers and employees are references to the officers and
employees of Alta Mesa Services. We refer to the Board of
Directors of Alta Mesa GP as our Board or our
Board of Directors.
81
Prior to our offering of the old notes in October 2010, Alta
Mesa Services was owned by an affiliate of our general partner
and it provided services, including accounting, corporate
development, finance, land administration and engineering, to us
pursuant to an administrative services agreement. Pursuant to
the administrative services agreement, expenses were allocated
to us based on the portion of time that the employees allocated
to our business. During 2010, all of Alta Mesa Services
expenses were allocated to us under the above formula.
In connection with the note offering, we acquired Alta Mesa
Services. All of our executive officers are employees of Alta
Mesa Services and devote all of their time to our business and
affairs.
Prior to the note offering, Alta Mesa Services had the ultimate
decision-making authority with respect to our compensation
program for our executive officers. The board of Alta Mesa
Services was comprised of Michael E. Ellis, our Chief Operating
Officer, Mickey Ellis, his wife, and Harlan H. Chappelle, our
President and Chief Executive Officer. After the offering, our
Board of Directors assumed responsibility for overseeing our
executive remuneration programs and the fair and competitive
compensation of our executive officers. Our Board consists of
Michael E. Ellis, Mickey Ellis and Harlan H. Chappelle and meets
each year to review our compensation program and to determine
compensation levels for the ensuing fiscal year.
In this Compensation Discussion and Analysis, we discuss our
compensation objectives, our decisions and the rationale behind
those decisions relating to 2010 compensation for our named
executive officers.
Objectives
of Our Compensation Program
Our executive compensation program is intended to motivate our
executive officers to achieve strong financial and operating
results for us. In addition, our program is designed to achieve
the following objectives:
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attract and retain talented executive officers by providing
reasonable total compensation levels competitive with that of
executives holding comparable positions in similarly situated
organizations;
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provide total compensation that is justified by individual
performance; and
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provide performance-based compensation that is tied to both
individual and our performance.
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What
Our Compensation Program is Designed to Reward
Our strategy is to increase reserves and production by applying
advanced engineering analytics and enhanced geological
techniques in areas we have identified as under-developed and
over-looked. Our compensation program is designed to reward
performance that contributes to the achievement of our business
strategy. In addition, we reward qualities that we believe help
achieve our strategy such as teamwork; individual performance in
light of general economic and industry specific conditions;
performance that supports our core values; resourcefulness; the
ability to manage our existing corporate assets; the ability to
explore new avenues to increase oil and gas production and
reserves; level of job responsibility; and tenure with the
company.
Elements
of Our Compensation Program and Why We Pay Each
Element
To accomplish our objectives, our compensation program is
comprised of three elements: base salary, cash bonus and
benefits. We currently do not offer equity-based compensation.
We pay base salary in order to recognize each executive
officers unique value and historical contributions to our
success in light of salary norms in the industry and the general
marketplace; to match competitors for executive talent; to
provide executives with sufficient, regularly-paid income; and
to reflect an executives position and level of
responsibility.
We include an annual cash bonus as part of our compensation
program because we believe this element of compensation helps to
motivate executives to achieve key corporate objectives by
providing annual recognition of achievement. The annual cash
bonus also allows us to be competitive from a total remuneration
standpoint.
82
We offer benefits such as a 401(k) plan and payment of insurance
premiums in order to provide a competitive remuneration package
as well as a measure of financial security to our employees.
How We
Determine Each Element of Compensation
In determining the elements of compensation, we consider our
ability to attract and retain executives as well as various
measures of company and industrial performance including debt
levels, revenues, cash flow, capital expenditures, reserves of
oil and gas and costs. We did not retain a consultant with
respect to determining 2010 compensation.
Messrs. Ellis, Chappelle, McCabe and Murrell are parties to
employment agreements with Alta Mesa Services. The employment
agreements automatically renew annually, subject to prior notice
of cancellation by either Alta Mesa Services or the executive.
These employment agreements establish set minimum base salaries
for each officer of $400,000, $400,000, $300,000 and $190,000
per annum, respectively, which we believe are competitive with
other independent oil and gas companies with whom we compete for
managerial talent. In addition, the employment agreements
provide that the executives are each entitled to an annual bonus
equal to a percentage of his respective annual base salary if
performance criteria set by the board for the applicable period
are met. The agreements also provide for benefits such as
reimbursement of business expenses, participation in employee
benefit plans and key man life insurance.
Base Salary. In reviewing base salaries, the
board takes into account a combination of subjective factors,
primarily relying on their own personal judgment and experience.
Subjective factors the board considers include individual
achievements, our performance, level of responsibility,
experience, leadership abilities, increases or changes in duties
and responsibilities and contributions to our performance.
Mr. Ellis and Mr. Chappelle participate in and are
present during the boards review and determination of
their respective base salaries. For 2010, the Board set the base
salaries for Messrs. Ellis, Chappelle, McCabe and Murrell
at $450,000, $450,000, $350,000 and $275,000, respectively.
Bonus. A portion of each executives
total compensation may be paid as bonus compensation. The board
takes into consideration the companys achievements during
the year and each executives contribution toward such
achievements. While performance criteria may be set, the board
takes into account subjective factors in determining if these
criteria were met. Bonuses for any one year are usually
determined and paid in the second or third quarter of the
following year. Bonus compensation for our executive officers
for 2010 has not yet been determined. However, bonuses paid in
2010 for 2009 performance ranged from approximately 55% to 100%
of base salary.
Benefits. We provide company benefits or
perquisites that we believe are standard in the industry to all
of our employees. These benefits consist of a group medical and
dental insurance program for employees and their qualified
dependents and a 401(k) employee savings and protection plan.
The costs of these benefits are paid for entirely by the
company. We do not provide employee life insurance amounts
surpassing the Internal Revenue Service maximum. We make
matching contributions to the 401(k) contribution of each
qualified participant. The company pays all administrative costs
to maintain the plan. In addition, we provide Messrs. Ellis
and Chappelle with company automobiles.
Other Compensation. As part of his employment
agreement, we reimburse Mr. McCabe for the rental cost of
an apartment near our headquarters and pay his commuting
expenses to and from his permanent home to Houston. In 2010,
these housing and commuting expenses totaled $77,599. We agreed
to provide these benefits to Mr. McCabe because our Board
believed it was necessary to retain Mr. McCabes
services despite the fact that his permanent residence is
outside of the Houston area. The Board considered the value of
this additional compensation in evaluating
Mr. McCabes total compensation package.
How
Elements of Our Compensation Program are Related to Each
Other
We view the various components of compensation as related but
distinct and emphasize pay for performance with a
portion of total compensation reflecting a risk aspect tied to
our financial and strategic goals. We determine the appropriate
level for each compensation component based in part, but not
exclusively,
83
on our view of internal equity and consistency, and other
considerations we deem relevant, such as rewarding extraordinary
performance.
Assessment
of Risk
Our Board takes risk into account when making compensation
decisions and has concluded that the executive compensation
program as it is currently structured does not encourage
excessive risk or unnecessary risk-taking.
Accounting
and Tax Considerations
We have structured our compensation program to comply with
Internal Revenue Code Section 409A. If an executive is
entitled to nonqualified deferred compensation benefits that are
subject to Section 409A, and such benefits do not comply
with Section 409A, then the benefits are taxable in the
first year they are not subject to a substantial risk of
forfeiture. In such case, the service provider is subject to
regular federal income tax, interest and an additional federal
income tax of 20% of the benefit includible in income.
Summary
Compensation
The following table summarizes, with respect to our named
executive officers, information relating to the compensation
earned for services rendered in all capacities during the fiscal
year ended December 31, 2010. There was no compensation
awarded to, earned by or paid to any of the named executive
officers related to option awards or non-equity incentive
compensation plans. In addition, none of the named executive
officers participate in a defined benefit pension plan.
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All Other
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Name and Principal Position
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Year
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Salary
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Bonus(1)
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Compensation
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Total
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Harlan H. Chappelle
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2010
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$
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450,000
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18,639
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(2)
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$
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468,639
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President, Chief Executive Officer
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Michael E. Ellis
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2010
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$
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450,000
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26,429
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(3)
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$
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476,429
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Chief Operating Officer, Vice President of Engineering, and
Chairman of the Board
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Michael A. McCabe
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2010
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$
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350,000
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88,016
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(4)
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$
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438,016
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Vice President, Chief Financial Officer
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David Murrell
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2010
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$
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273,750
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(5)
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8,250
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(6)
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$
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282,000
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Vice President of Land and Business Development
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(1) |
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Bonuses for 2010 have not yet been determined. We expect these
bonuses will be determined before the end of the third quarter
of 2011. Bonuses paid in 2010 for 2009 performance were $450,000
for Mr. Chappelle, $350,000 for Mr. McCabe, and
$150,000 for Mr. Murrell. Mr. Ellis declined to
receive a bonus paid in 2010. |
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(2) |
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Mr. Chappelles other compensation consists of $8,250
in matching funds to his 401(k) account and $10,389 in auto
expenses. |
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(3) |
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Mr. Ellis other compensation consists of $8,250 in
matching funds to his 401(k) account and $18,179 in auto
expenses. |
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(4) |
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Mr. McCabes other compensation consists of $10,417 in
matching funds to his 401(k) account, and $77,599 in travel and
living expenses, which includes $20,239 for an apartment in
Houston and $57,360 for travel, which consists primarily of
airfare and the cost of rental cars and parking. |
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(5) |
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Mr. Murrells salary was raised to $275,000 during
2010. |
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(6) |
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Mr. Murrells other compensation consists of $8,250 in
matching funds to his 401(k) account. |
84
Narrative
Disclosure to Summary Compensation Table
Mr. Chappelle
Mr. Chappelle entered into an employment agreement on
August 31, 2006 that provides that he will act as President
and Chief Executive Officer until August 31, 2010, subject
to automatic one year renewals of the term if neither party
submits a notice of termination at least 60 days prior to
the end of the then-current term. In accordance with the
provisions of the employment agreement, in 2010, the agreement
was automatically renewed for an additional one-year term. This
agreement may be terminated by either party, at any time,
subject to severance obligations in the event Mr. Chappelle
is terminated by us without cause or he dies or is disabled.
Mr. Chappelles employment agreement provides for a
minimum base salary of $400,000 and an annual bonus equal to a
percentage of his base salary paid during each such annual
period, such percentage to be established by our Board of
Directors in the Boards sole discretion.
Mr. Ellis
Mr. Ellis entered into an employment agreement on
August 31, 2006 that provides that he will act as Vice
President and Chief Operating Officer until August 31,
2010, subject to automatic one year renewals of the term if
neither party submits a notice of termination at least
60 days prior to the end of the then-current term. In
accordance with the provisions of the employment agreement, in
2010, the agreement was automatically renewed for an additional
one-year term. This agreement may be terminated by either party,
at any time, subject to severance obligations in the event
Mr. Ellis is terminated by us without cause or he dies or
is disabled.
Mr. Ellis employment agreement provides for a minimum
base salary of $400,000 and an annual bonus equal to a
percentage of his base salary paid during each such annual
period, such percentage to be established by our Board of
Directors in the Boards sole discretion.
Mr. McCabe
Mr. McCabe entered into an employment agreement on
August 31, 2006 that provides that he will act as Vice
President and Chief Financial Officer until August 31,
2010, subject to automatic one year renewals of the term if
neither party submits a notice of termination at least
60 days prior to the end of the then-current term. In
accordance with the provisions of the employment agreement, in
2010, the agreement was automatically renewed for an additional
one-year term. This agreement may be terminated by either party,
at any time, subject to severance obligations in the event
Mr. McCabe is terminated by us without cause or he dies or
is disabled.
Mr. McCabes employment agreement provides for a
minimum base salary of $300,000 and an annual bonus equal to a
percentage of his base salary paid during each such annual
period, such percentage to be established by our Board of
Directors in the Boards sole discretion.
Mr. McCabes employment agreement also provides that
he is allowed to work from his residence in Massachusetts as
well as in our Houston office so long as he is capable of
performing his duties assigned to him. In his employment
agreement, we also agree to provide Mr. McCabe with
suitable housing (or a housing allowance) and an automobile or
reimbursement for the lease of an automobile while he is in
Houston.
Mr. Murrell
Mr. Murrell entered into an employment agreement on
October 1, 2006 that provides that he will act as Vice
President of Land and Business Development until October 1,
2007, subject to automatic one year renewals of the term if
neither party submits a notice of termination at least
60 days prior to the end of the then-current term. In
accordance with the provisions of the employment agreement, in
2010, the agreement was automatically renewed for an additional
one-year term. This agreement may be terminated by either party,
85
at any time, subject to severance obligations in the event
Mr. Murrell is terminated by us without cause or he dies or
is disabled.
Mr. Murrells employment agreement provides for a
minimum base salary of $190,000 and an annual bonus equal to
0.5% of the after-tax profits of Alta Mesa Holdings, LP, subject
to a minimum bonus of $50,000 and a maximum bonus such that his
combined salary plus bonus does not exceed $1,000,000.
Grants
of Plan-Based Awards for Fiscal Year 2010
There were no grants of plan-based awards to our named executive
officers during the fiscal year ended December 31, 2010.
Outstanding
Equity Awards Value at 2010 Fiscal Year-End
There were no outstanding equity awards for our named executive
officers as of December 31, 2010.
Option
Exercises and Equity Awards Vested in Fiscal Year
2010
There were no exercises of equity awards and no vesting of
equity awards for our named executive officers during fiscal
2010.
Pension
Benefits
We do not provide pension benefits for our named executive
officers.
Nonqualified
Deferred Compensation
We do not have a nonqualified deferred compensation plan and, as
such, no compensation has been deferred by our named executive
officers.
Termination
of Employment and Change-in-Control Provisions
Messrs. Chappelle, Ellis, McCabe and Murrell are parties to
employment agreements which provide them with post-termination
benefits in a variety of circumstances. The amount of
compensation payable in some cases may vary depending on the
nature of the termination, whether as a result of
retirement/voluntary termination, involuntary not-for-cause
termination, termination following a change of control and in
the event of disability or death of the executive. The
discussion below describes the varying amounts payable in each
of these situations. It assumes, in each case, that the
officers termination was effective as of December 31,
2010. In presenting this disclosure, we describe amounts earned
through December 31, 2010 and, in those cases where the
actual amounts to be paid out can only be determined at the time
of such executives separation from us, our estimates of
the amounts which would be paid out to the executives upon their
termination.
Provisions
Under the Employment Agreements
Under the employment agreements, if the executives
employment with us terminates, the executive is entitled to
unpaid salary for the full month in which the termination date
occurred. However, if the executive is terminated for cause, the
executive is only entitled to receive accrued but unpaid salary
through the termination date. In addition, if the
executives employment terminates, the executive is
entitled to unpaid vacation days for that year which have
accrued through the termination date, reimbursement of
reasonable business expenses that were incurred but unpaid as of
the termination date, a pro rata portion of the annual bonus for
that year and COBRA coverage as required by law. Salary and
accrued vacation days are payable in cash lump sum less
applicable withholdings. Business expenses are reimbursable in
accordance with normal procedures.
If the executives employment is involuntarily terminated
by us (except for cause or due to the death of the executive) or
if the executives employment is terminated due to
disability or retirement or by the executive for good reason, we
are obligated to pay as additional compensation an amount in
cash equal to two
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years, except in the case of Mr. Murrell, in which case it
is six months, of the executives base salary in effect as
of the termination date. Under the terms of
Mr. Murrells employment agreement, upon such
involuntary termination, he would also be paid 50% of the annual
bonus then in effect. Assuming termination as of
December 31, 2010, for both Messrs. Chappelle and
Ellis, the termination benefit would have been $900,000; for
Mr. McCabe, $700,000; and for Mr. Murrell, $212,500.
In addition, the executive is entitled to continued group health
plan coverage following the termination date for the executive
and the executives eligible spouse and dependents for the
maximum period for which such qualified beneficiaries are
eligible to receive COBRA coverage. The executive shall not be
required to pay more for COBRA coverage than officers who are
then in active service for us and receiving coverage under the
plan. Assuming termination as of December 31, 2010, the
total cost to the Company of providing this benefit would have
been $22,689 for Mr. Chappelle, $33,918 for Mr. Ellis,
$26,915 for Mr. McCabe, and $33,918 for Mr. Murrell.
Cause means:
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the executives conviction by a court of competent
jurisdiction of a crime involving moral turpitude or a felony,
or entering the plea of nolo contendere to such crime by
the executive;
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the commission by the executive of a demonstrable act of fraud,
or a misappropriation of funds or property, of or upon us or any
affiliate;
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the engagement by the executive without approval of us and the
board of directors in any material activity which directly
competes with the business of us or any affiliate or which would
directly result in a material injury to the business or
reputation of us or any affiliate (including the partners of
Alta Mesa); or
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the breach by the executive of any material provision of the
employment agreement, and the executives continued failure
to cure such breach within a reasonable time period set by us
but in no event less than twenty calendar days after the
executives receipt of such notice.
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Good reason means the occurrence of any of the
following, if not cured and correct by us or our successor,
within 60 days after written notice thereof is provided by
the executive to us or our successor:
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the demotion or reduction in title or rank of the executive, or
the assignment to the executive of duties that are materially
inconsistent with the executives current positions,
duties, responsibilities and status with us, or any removal of
the executive from, or any failure to re-elect the executive to,
any of such positions (other than a change due to the
executives disability or as an accommodation under the
Americans with Disabilities Act), except for any such demotion,
reduction, assignment, removal or failure that occurs in
connection with (i) the executives termination of
employment for cause, disability or death, or (ii) the
executives prior written consent;
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the reduction of the executives annual base salary or
bonus opportunity as effective immediately prior to such
reduction without the prior written consent of the executive; or
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a relocation of the executives principal work location to
a location in excess of 50 miles from its then current location.
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Retirement means the termination of the
executives employment for normal retirement at or after
attaining age 70, provided that the executive has been with
us for at least five years.
The employment agreements do not separately provide for benefits
upon a change of control.
Compensation
of Directors
The employee and non-employee members of the Board of Directors
do not receive compensation for their services as directors.
However, our directors may be reimbursed for their expenses in
attending board meetings.
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Corporate
Governance Matters
Audit
and Compensation Committee
We do not have a formal compensation committee and our full
Board serves as our audit committee. Because the registration
statement of which this prospectus forms a part registers only
debt securities and because we do not have and are not seeking
to list any securities on a national securities exchange or on
an inter-dealer quotation system, we are not subject to a number
of the corporate governance requirements of the SEC or of any
national securities exchange or inter-dealer quotation system.
For example, we are not required to have a board of directors
comprised of a majority of independent directors or to have an
audit committee comprised of independent directors. Accordingly,
our Board of Directors has not made any determination as to
whether any of the members of our Board of Directors or
committees thereof would qualify as independent under the
listing standards of any national securities exchange or any
inter-dealer quotation system or under any other independence
definition. Additionally, for the same reason, we have not yet
determined whether any of our directors is an audit committee
financial expert.
Code
of Ethics
The Board of Directors has adopted a Code of Ethics for Senior
Financial Officers. The Code of Ethics is posted on the investor
relations section of our website at www.altamesa.net and is
available free of charge upon written request to 15415 Katy
Freeway, Suite 800, Houston, Texas 77094.
Compensation
Committee Interlocks and Insider Participation
We do not currently have a compensation committee. None of our
executive officers has served as a director or member of the
compensation committee of any other entity whose executive
officers served as a director or member of our compensation
committee.
88
THE
PARTNERSHIP AGREEMENT
The following is a summary of the material provisions of our
partnership agreement, as amended.
Organization
and Duration
Our partnership was organized in September 2005 and will have a
perpetual existence.
Purpose
Our purpose under the partnership agreement is
(a) exploring, developing, operating, investing in,
acquiring, expanding, selling, managing and financing, directly
or indirectly, oil and gas properties, including those
properties held by the partnership as of the effective date and
after the effective date and (b) taking all such other
actions incidental to any of the foregoing as may be necessary
or desirable and for which a Texas limited partnership may
legally engage.
Our general partner is authorized in general to perform all acts
it determines to be necessary or appropriate to carry out our
purposes and to conduct our business.
Capital
Contributions
Our general partner and Class A limited partners have no
obligation to make additional capital contributions. Our
Class B limited partner is obligated to make additional
capital contributions in the amounts set forth in the
partnership agreement and contribution agreement, which are
referred to as the Class B Commitment. In the
event the Class B limited partner defaults in making
additional capital contributions required under the partnership
agreement, the general partner may extinguish certain of the
Class B limited partners rights under the partnership
or withhold distributions to the Class B limited partner.
Cash
Distributions
Our partnership agreement specifies the manner in which we will
make cash distributions to our general and limited partners.
Net Cash from Operations. Except for tax
distributions and as the general partner and the Class B
limited partner otherwise agree, prior to January 1, 2012,
net cash from operations is otherwise to be retained by the
company to fund the activities of the company and the
subsidiaries, including development, exploration and acquisition
activities. After January 1, 2012, the Class B limited
partner may require the general partner to make distributions of
net cash from operations upon notice to the general partner,
provided, however, that such distributions are subject to our
compliance with the covenants set forth in any senior debt,
including the notes, and our bank credit facility. Net
cash from operations means the gross cash proceeds from
operations (including sales and dispositions of properties in
the ordinary course of business) less the portion thereof used
to pay or fund our costs, expenses, contract operating costs
(including operators general and administrative expenses),
marketing costs, debt payments, capital expenditures, reserve
replacements, tax distributions to the partners and Agreed
Reserves (as defined below). Subject to the foregoing, net cash
from operations is to be distributed:
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first, 85% to the Class B limited partner and 15% to the
general partner and the Class A limited partners until the
Class B limited partner has received aggregate
distributions since September 1, 2006 equal to the
Class B limited partners aggregate capital
contributions since the effective date (the 1x Return
Amount);
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second, 85% to the Class B limited partner and 15% to the
general partner and the Class A limited partners until the
cumulative amount of distributions to the Class B limited
partner results in the Class B limited partner achieving a
15% internal rate of return;
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third, 65% to the Class B limited partner and 35% to the
general partner and the Class A limited partners until the
cumulative amount of distributions to the Class B limited
partner result in the Class B limited partner achieving a
27.5% internal rate of return; and
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thereafter, 25% to the Class B limited partner and 75% to
the general partner and the Class A limited partners.
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Net Cash from Liquidity Events. Except as
otherwise agreed upon by the general partner and the
Class B limited partners, net cash from a liquidity event
is to be distributed to the partners, subject to the retention
of agreed reserves:
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if the liquidity event occurs prior to January 1, 2012, net
cash from a liquidity event shall generally be distributed in
the same manner as net cash from operations provided that such
distributions provide the Class B limited partner aggregate
distributions from the company since September 1, 2006
equal to at least 200% of the Class B limited
partners aggregate capital contributions since
September 1, 2006 (the 2x Return Amount); or
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if the liquidity event occurs on or after January 1, 2012,
net cash from a liquidity event is to be distributed to the
partners as follows:
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(i) first, 100% to the Class B limited partner until
the Class B limited partner receives aggregate
distributions equal to the 1x Return Amount;
(ii) second, 85% to the Class B limited partner and
15% to the general partner and the Class A limited partners
until the cumulative amount of distributions to the Class B
limited partner result in the Class B limited partner
achieving a 10% internal rate of return;
(iii) third, 100% to the general partner and the
Class A limited partners until the aggregate distributions
have been distributed 85% to the Class B limited partner
and 15% to the general partner and Class A limited partners;
(iv) fourth, 85% to the Class B limited partner and
15% to the general partner and the Class A limited partners
until the cumulative amount of distributions to the Class B
limited partner result in the Class B limited partner
achieving a 15% internal rate of return;
(v) fifth, 65% to the Class B limited partner and 35%
to the general partner and the Class A limited partners
until the cumulative amount of distributions to the Class B
limited partner result in the Class B limited partner
achieving a 27.5% internal rate of return ; and
(vi) thereafter, 25% to the Class B limited partner
and 75% to the general partner and the Class A limited
partners.
All distributions made to the general partner and the
Class A limited partners are pro rata to such partners.
A liquidity event is any event in which the
company receives cash proceeds outside the ordinary course of
the companys business, including (a) a sale of the
company and its subsidiaries, whether structured as a merger or
consolidation, share exchange, sale of interests or the equity
of the subsidiaries, or a sale of all or substantially all of
the assets of the company and the subsidiaries outside the
normal course of business, (b) a public or private offering
of the interests or other public or private sale of debt or
equity securities of the company or a subsidiary; and (c) a
financing transaction or leveraged recapitalization of the
company or a subsidiary.
Agreed reserves are a reserve of cash to pay
reasonably anticipated future costs and liabilities of the
company, as agreed upon by the general partner and the
Class B limited partner.
Amounts due by the company in respect of (i) certain
related party subordinated debt and (ii) indemnity
obligations under the Contribution Agreement are to be made by
the company exclusively from the general partners and the
Class A limited partners allocable share of
distributions of net cash from operations and of net cash from a
liquidity event.
Distributions for Payment of Taxes. In
addition, in each fiscal year, the general partner is to
distribute to the partners, to the extent of available cash, in
proportion to the taxable income allocated to them, such amount
as the general partner reasonably determines is necessary to
enable the partners who were allocated
90
taxable income during that fiscal year to pay their income taxes
on their distributive shares of the companys taxable
income.
Management
by General Partner; Approval Rights of Class B Limited
Partner
Our business and affairs are managed by our general partner,
which has full and exclusive power and authority on our behalf
to manage, control, administer and operate our properties,
business and affairs. Without the written consent of the
Class B limited partner, however, our general partner
cannot cause:
(a) any sale of any property or asset of the company or a
subsidiary (in a single transaction or a series of related
transactions) having a value in each case in excess of
$10,000,000 or any sales of properties or assets of the company
or its subsidiaries during any 12 month period having an
aggregate value in excess of ten percent (10%) of the proved
reserves value of the properties as reflected under the most
recent engineering report delivered under Section 8.2
(c) of the partnership agreement;
(b) except in connection with the senior credit facility,
the incurrence by the company or any subsidiary of indebtedness
for borrowed money in excess of amounts drawn under a company
credit facility that was approved by the Class B limited
partner;
(c) the guaranty by the company or any subsidiary of the
payment of money or the performance of any contract or other
obligation of any person other than the company or any
subsidiary, except in connection with indebtedness permitted
under (a) above;
(d) the grant of liens on any assets of the company or its
subsidiaries, except in connection with the indebtedness
permitted under (a) above or for customary liens contained
in joint operating agreements;
(e) the adoption of the development plan and budget
pursuant to the terms of the partnership agreement, and making
any material amendments to thereto;
(f) the acquisition of properties and other assets (whether
in one or in a series of related transactions) having a purchase
price or, if not a cash transaction, a fair market value, which
exceeds $10,000,000 and which acquisition is not expressly
budgeted for in the approved budget;
(g) the appointment of any successor to the Chief Executive
Officer or any other senior officer and the payment of any
executive compensation to the senior officers;
(h) the approval of any policy of director and officers
liability insurance;
(i) entering into a partnership or joint venture with any
other party for the purpose of carrying on any business other
than in the ordinary course of business;
(j) creating any subsidiary other than in the ordinary
course of business;
(k) any amalgamation, reconstruction, liquidation,
dissolution, commencement of bankruptcy, or similar proceedings
with respect to the company or any subsidiary, or compromise
with a creditor;
(l) the merger or consolidation of the company with any
entity, the conversion of the company into any other
organizational form, or the exchange of interests with any other
person or entity;
(m) any issuance of interests, ownership interests,
debentures, bonds or any other security, including issuances of
securities in connection with any employee incentive plan or as
consideration in any acquisition (whether by purchase of
ownership interests, asset purchase or merger);
(n) any transaction or series of related transactions (not
otherwise expressly permitted) between the company or any
subsidiary, on the one hand, and any partner or affiliate of any
partner, on the other hand;
(o) pursuant to the partnership agreement, any amendment to
the partnership agreement, any adoption of or amendment to the
partnership agreement, memorandum and articles of association,
certificate and articles of incorporation, bylaws, or other
organizational documents, of the company or any subsidiary;
91
(p) except for the exercise of certain warrants, any
redemption or other change in the interests or ownership
interest, or options or other rights to acquire such interests,
in the company or the subsidiaries;
(q) the initiation, compromise or settlement of any
lawsuit, administrative matter or other dispute where the amount
the company may recover or might be obligated to pay, as
applicable, is in excess of $100,000;
(r) the extension of any loans by the company to any third
party (including the general partner or any affiliate thereof);
(s) the grant of any approval by the company under
Section 6 of the Shared Services Agreement by and among
Alta Mesa Services, LP, on the one hand, and the general
partner, the company and certain of the subsidiaries of the
company, on the other hand, or
(t) the amendment or modification of the terms of certain
warrants, the waiver of any material right of the company under
the warrants or the making of any material determination or
election by the company under the warrants.
Additional
Class B Rights
Development Plan and Operating Budget. The
general partner is to prepare and submit to the Class B
limited partner a proposed development plan and budget annually,
on or before the 60th day prior to the end of each fiscal year,
which shall set forth, for the next following fiscal year, the
proposed operations, time schedule for implementing operations,
estimated revenues, operating expenditures, and capital
expenditures for the company and each of its subsidiaries. All
development plans and budgets are subject to the prior written
approval of the Class B limited partner.
Price Risk Mitigation. Subject to any
restrictions contained in any credit facility or other agreement
to which the company or its subsidiaries are parties or any of
their respective properties are subject, the Class B
limited partner can require the company and its subsidiaries to
implement reasonable measures to mitigate commodity price risks.
Initiation of Liquidity Event. Following the
earlier of (i) January 1, 2012, and (b) a breach
of or default by the company under any representation, warranty,
covenant or agreement contained in any loan or credit agreement
to which the company is a party or by which its assets are
bound, following the expiration of any cure periods, the
Class B limited partner can, without consent of any other
partner, upon notice to the general partner and Class A
partners, request that the general partner take such actions to
cause the company and its subsidiaries, or the assets of the
company and the subsidiaries to be sold to one or more third
parties, subject to a Class A partners right of right
of first offer to purchase the Class B limited
partners interests.
Conflicts of Interest. The general partner and
its affiliates may transact business with the company and the
subsidiaries provided that the terms of such transaction are
fair and reasonable to the company and the subsidiaries and no
less favorable to the company and the subsidiaries than those
the company and the subsidiaries could obtain from unrelated
third parties. In connection with any such transaction, the
general partner must provide prompt written notice to the
Class B limited partner of such transaction.
Meetings of Partners. The Class B limited
partner, by notice to the other partners, may call a meeting of
partners at such times and places inside the State of Texas as
the Class B limited partner may determine upon not less
than two business days prior to the date of such meeting.
Business Opportunities. The Class B
limited partner has no duty to disclose to the company business
opportunities, whether or not competitive with the
companys business whether or not the company might be
interested in such business opportunity for itself.
Removal of General Partner. The Class B
limited partner may remove our general partner with cause and
select a new general partner to operate and carry on our
business and affairs. With cause includes the
commission by the general partner of fraud, willful or
intentional misconduct or gross negligence in the performance of
its duties hereunder; a default by the general partner in the
performance or observation of any material agreement, covenant,
term, condition or obligation under the partnership agreement; a
false material
92
representation or warranty made by the general partner in the
partnership agreement or by the general partner or any of its
officers in any writing furnished in connection with or pursuant
to the partnership agreement; and the dissolution (or other
similar event) of the general partner.
Issuance
of Additional Securities
In accordance with Texas law and the provisions of our
partnership agreement, we may issue additional partnership
securities in the future.
Amendment
of the Partnership Agreement
Except as otherwise provided in the partnership agreement, the
partnership agreement may be amended, or any provision waived,
only with the written consent of each of the general partner,
those Class A limited partners holding percentage interests
in the aggregate equal to or greater than
662/3%
of percentage interests held by all Class A limited
partners, and the Class B limited partner; provided that no
amendment or waiver can materially and adversely affect
disproportionately the rights of any limited partner when
compared with its effect on any other limited partner without
the prior written approval of such disadvantaged limited partner.
Termination
and Dissolution
We will continue as a limited partnership until terminated under
our partnership agreement. We will dissolve upon:
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the consent in writing signed by all the partners;
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the sale or other disposition of all or substantially all of the
our assets;
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the entry of a final judgment, order or decree of a court of
competent jurisdiction adjudicating the company to be bankrupt
and the expiration without appeal of the period, if any, allowed
by applicable law in which to appeal;
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the entry of a judicial order dissolving the company in
accordance with Section 8.02 of the Act;
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any withdrawal or retirement from the company by the general
partner;
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the election of the Class B limited partner by written
notice to the general partner if at the time such notice is
given (i) the general partner has committed fraud, willful
or intentional misconduct or gross negligence in the performance
of its duties hereunder, (ii) subject to Section 5.13,
the general partner is in default in the performance or
observation of any material agreement, covenant, term, condition
or obligation under the partnership agreement, which default is
not cured, or (iii) a material representation or warranty
made by the general partner in the partnership agreement or by
the general partner or any of its officers in any writing
furnished in connection with or pursuant to the partnership
agreement shall be false in any respect on the date as of which
made; or
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the election of the Class B limited partner by written
notice to the general partner upon (i) the dissolution (or
other similar event) of the general partner; or (ii) the
death, insanity, legal disability, bankruptcy or insolvency of a
key person, or the resignation, retirement or removal of a key
person or a key person is not otherwise actively involved in the
day-to-day
management of the business and operations of the general partner
and the company and such key person is not replaced by another
officer reasonably acceptable to Class B limited partner.
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Withdrawal
of General Partner
Upon the withdrawal or retirement from the company of the
general partner, the business of the company will be continued
if within 90 calendar days the Class B limited partner
elects by written action to continue the business of the company
and designate a replacement general partner. If the Class B
limited partner fails to continue the companys business,
the company will be liquidated.
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Reimbursement
of Expenses
Our partnership agreement requires us to reimburse our general
partner for all direct and indirect expenses it incurs or
payments it makes on our behalf and all other expenses allocable
to us or otherwise incurred by our general partner in connection
with operating our business.
Books and
Reports
We keep books of account and records in accordance with GAAP.
Such books and records are maintained at our principal office.
The Class B limited partner and any Class A limited
partner have the right to audit any and all financial and
operational records with respect to the properties, the company
and its subsidiaries and their respective operations. The
calendar year is the accounting year of the company, and the
books of account are maintained on an accrual basis.
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SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the limited partnership interests
in Alta Mesa beneficially owned as of May 31, 2011 by:
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all persons who, to the knowledge of our management team,
beneficially own more than 5% of our outstanding limited
partnership interests;
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each current director of Alta Mesa GP, our general partner;
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each principal officer of Alta Mesa GP; and
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all current directors and principal officers of Alta Mesa GP as
a group.
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Percentage of
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Percentage of
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Class A Limited
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Class B Limited
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Partnership
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Partnership
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Interests
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Interests
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Beneficially
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Beneficially
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Name of Beneficial Owner(1)
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Owned
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Owned
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Alta Mesa Investment Holdings Inc.(2)
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100.0
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%
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Macquarie Bank Limited(3)
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5.0
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%
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RBS Equity Corporation(4)
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5.0
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%
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Michael E. Ellis(5)
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84.5
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%
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Mickey Ellis(6)
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Harlan H. Chappelle
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5.0
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%
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Michael A. McCabe
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David Murrell
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Directors and principal officers as a group (5 persons)
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89.5
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%
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(1) |
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Unless otherwise indicated, the address for all beneficial
owners in this table is at 15415 Katy Freeway, Suite 800,
Houston, Texas 77094. |
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(2) |
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The address of Alta Mesa Investment Holdings Inc. is c/o Denham
Capital Management LP, 600 Travis, Suite 2310, Houston,
Texas 77002. For more information on the ability of our
Class B Limited Partner to cause a liquidity event, see
The Partnership Agreement. |
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(3) |
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The address of Macquarie Bank Limited is 333 Clay Street, Suite
4200, Houston, Texas 77002. |
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(4) |
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The address of RBS Equity Corporation is c/o The Royal Bank of
Scotland plc, 600 Travis, Suite 6500, Houston, Texas 77002. |
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(5) |
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Mr. Ellis does not own directly any partnership interests.
Includes limited partner interests held by Alta Mesa Resources,
LP, Galveston Bay Resources Holdings, LP, Petro Acquisition
Holdings, LP and Petro Operating Company Holdings, Inc., all
entities owned and controlled by Mr. Ellis. |
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(6) |
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Mickey Ellis is the spouse of Michael E. Ellis. Ms. Ellis
may be deemed to be the beneficial owner of the partnership
interests owned by Mr. Ellis. |
Additionally, our general partner, Alta Mesa GP, is owned by Mr.
and Ms. Ellis. For further information regarding the manner
in which we make cash distributions to our general and limited
partners, see The Partnership Agreement Cash
Distributions.
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CERTAIN
RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Ownership
in Us and Our General Partner by Founder
Michael E. Ellis, our Chairman and Chief Operating Officer, and
his spouse Mickey Ellis, one of our directors, own 84.5% of our
Class A interests. Our general partner, Alta Mesa GP, is
owned 100% by Alta Mesa Resources, LP, an entity owned by
Michael E. Ellis and Mickey Ellis. Our general partner has a
0.1% interest in us.
Shared
Services and Expenses Agreement
Through a Shared Services and Expenses Agreement with us, our
general partner and our subsidiaries, Alta Mesa Services, LP, an
entity owned by us, conducts our business and operations and, in
addition to the board of directors of our general partner, makes
decisions on our behalf. In addition, Alta Mesa Services agrees
to make available its personnel, including our chief operating
officer, chief executive officer and chief financial officer,
which permits us to carry on our business. Prior to the offering
of the notes in October 2010, Alta Mesa Services was owned by
Michael E. and Mickey Ellis.
During the years ended December 31, 2010, 2009 and 2008, we
and our subsidiaries reimbursed Alta Mesa Services an aggregate
of $14.6 million, $5.9 million and $6.1 million,
respectively, under the Shared Services and Expenses Agreement.
No fees are paid to Alta Mesa Services pursuant to the
agreement. Our consolidated financial statements include the
activity of Alta Mesa Services for the years ended
December 31, 2010, 2009, and 2008, respectively. We expect
that Alta Mesa Services will continue to provide services to our
non-wholly owned subsidiaries.
Founder
Notes
We were founded in 1987 by Michael E. Ellis and we or our
subsidiaries have over time entered into promissory notes to
repay Mr. Ellis for contributions of working capital and
other amounts. See Description of Certain
Indebtedness Founder Notes.
Land
Consulting Services
David Murrell, our Vice President, Land and Business
Development, is the principal of David Murrell and Associates,
which provides land consulting services to us. The primary
employee of David Murrell & Associates is his spouse,
Brigid Murrell. Services are provided at a pre-negotiated hourly
rate based on actual time employed by the company. Payments for
the years ended December 31, 2010, 2009 and 2008 were
approximately $146,000, $131,000 and $119,000, respectively. The
contract may be terminated by either party without penalty upon
30 days notice.
Employee
David McClure, the
son-in-law
of our CEO, Harlan H. Chappelle, is employed by us as a senior
engineer. He received total compensation during 2010 of $95,031.
Additionally, his position provides him with the use of a
company vehicle, similar to our other engineers whose duties
include field oversight.
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DESCRIPTION
OF CERTAIN INDEBTEDNESS
Senior
Secured Revolving Credit Facility
On May 23, 2011, we amended our $500 million senior
secured revolving credit facility. The amended credit facility
is currently subject to a $260 million borrowing base limit
with Wells Fargo Bank, N.A. as the administrative agent. As of
March 31, 2011, we had approximately $87.3 million
outstanding under the senior facility. Each of our material
operating subsidiaries is a guarantor of the senior secured
revolving credit facility. Our senior secured revolving credit
facility provides that we may not issue senior debt securities
in excess of $700.0 million, including the
$300.0 million of notes issued in October 2010. The
borrowing base under the senior facility will be automatically
reduced by 25 cents per dollar of any additional notes issued in
the future.
The amended credit facility matures on May 23, 2016, and
principal amounts borrowed are payable on the maturity date with
such borrowings bearing interest, payable quarterly. We have a
choice of borrowing in Eurodollars or at the base rate.
Eurodollar loans bear interest at a rate per annum equal to the
rate appearing on the Reuters Reference LIBOR1 page as the
London Interbank Offered Rate, for deposits in Dollars at
11:00 a.m. (London, England time) for one, three, or six
months plus an applicable margin ranging from 200 to 275 basis
points, depending on the percentage of our borrowing base
utilized. Base rate loans bear interest at a rate per annum
equal to the greatest of (i) the agent banks
reference rate, (ii) the federal funds effective rate plus
50 basis points and (iii) the rate for one month Eurodollar
loans plus 1%, plus an applicable margin ranging from 100 to 175
basis points, depending on the percentage of our borrowing base
utilized. The next redetermination of our borrowing base is
scheduled to be on or about November 1, 2011. Following the
next scheduled borrowing base redetermination, we may be subject
to restrictions on our ability to incur indebtedness or our
borrowing base may be reduced. The amount outstanding under the
amended credit facility is secured by first priority liens on
substantially all of our oil and natural gas properties and
associated assets. Our amended credit facility contains
restrictive covenants that may limit our ability to, among other
things:
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incur additional indebtedness;
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sell assets;
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guarantee or make loans to others;
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make investments;
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enter into mergers;
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make certain payments and distributions;
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enter into hedge agreements;
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incur liens; and
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engage in certain other transactions without the prior consent
of the lenders.
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The senior secured revolving credit facility also requires us to
maintain the following three financial ratios:
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a current ratio, tested quarterly, of our consolidated current
assets to our consolidated current liabilities (other than
current assets and obligations under hedge agreements and
excluding current asset retirement obligations) of not less than
1.0 to 1.0 as of the end of each fiscal quarter (for purposes of
the current ratio test, current assets are increased by the
amount of any unused borrowing base);
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a leverage ratio, tested quarterly, of our consolidated debt as
of the end of such fiscal quarter to our consolidated EBITDAX
over the four quarter period then ended of not greater than 4.0
to 1.0.
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an interest coverage ratio, tested quarterly, of our
consolidated EBITDAX to interest expense, to be at least 3.00 to
1.00.
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Founder
Notes
We were founded in 1987 by Michael E. Ellis and we or our
subsidiaries have over time entered into promissory notes to
repay Mr. Ellis for contributions of working capital and
other amounts. The loans bear interest at 10.0%
paid-in-kind
and mature on December 31, 2018 and are subordinated to the
notes. The aggregate amount payable under the notes as of
December 31, 2010 was $19.7 million. During the years
ended December 31, 2010, 2009 and 2008, no amounts were
paid in principal or interest. Interest on the notes payable is
not compounded and amounted to $1.4 million during 2010,
and $1.2 million during each of 2009 and 2008. Such amounts
have been added to the balance of the notes.
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DESCRIPTION
OF NEW NOTES
We will issue the new Notes under an indenture dated as of
October 13, 2010 (the Indenture), among the
Issuers, the Subsidiary Guarantors and Wells Fargo Bank, N.A.,
as trustee (the Trustee). On October 13, 2010,
the Issuers issued $300.0 million principal amount of old
Notes under the Indenture. The terms of the new Notes include
those expressly set forth in the Indenture and those made part
of the Indenture by reference to the Trust Indenture Act of
1939, as amended (the Trust Indenture Act).
References in this Description of New Notes to
Issue Date mean October 13, 2010.
The Issuers may issue an unlimited principal amount of
additional notes having identical terms and conditions as the
Notes (the Additional Notes). The Issuers will only
be permitted to issue such Additional Notes in compliance with
the covenant described under the subheading
Certain Covenants Limitation on
Indebtedness and Preferred Stock. Any Additional Notes
will be part of the same series as the Notes and will vote on
all matters with the holders of the Notes. Unless the context
otherwise requires, for all purposes of the Indenture and this
Description of New Notes, references to the Notes
include the new Notes, the old Notes and any Additional Notes
actually issued.
This Description of New Notes is intended to be a
useful overview of the material provisions of the Notes and the
Indenture. Since this description is only a summary, you should
refer to these documents for a complete description of the
obligations of the Issuers and the Subsidiary Guarantors and
your rights. A copy of the Indenture has been filed as an
exhibit to the registration statement of which the prospectus is
a part.
You will find the definitions of capitalized terms used in this
description under the heading Certain
Definitions. For purposes of this description, references
to the Co-Issuer refer only to Alta Mesa Finance
Services Corp., the co-issuer of the Notes, and references to
the Company, we, our and
us refer only to Alta Mesa Holdings, LP and not to
any of its subsidiaries. The Co-Issuer and the Company are
referred to jointly as the Issuers.
The registered holder of a new Note will be treated as the owner
of it for all purposes. Only registered holders of the Notes
have rights under the Indenture, and all references to
holders in this Description of New Notes
are to registered holders of the Notes.
If the exchange offer contemplated by this prospectus is
consummated, holders of old Notes who do not exchange those
Notes for new Notes in the exchange offer will vote together
with holders of new Notes for all relevant purposes under the
Indenture. In that regard, the Indenture requires that certain
actions by the holders thereunder must be taken, and certain
rights must be exercised, by specified minimum percentages of
the aggregate principal amount of the outstanding securities
issued under the Indenture. In determining whether holders of
the requisite percentage in principal amount have given any
notice, consent or waiver or taken any other action permitted
under the Indenture, any old Notes that remain outstanding after
the exchange offer will be aggregated with the new Notes, and
the holders of such old Notes and the new Notes will vote
together as a single class for all such purposes. Accordingly,
all references herein to specified percentages in aggregate
principal amount of the Notes outstanding shall be deemed to
mean, at any time after the exchange offer is consummated, such
percentages in aggregate principal amount of the old Notes and
the new Notes then outstanding.
General
The
New Notes
The new Notes:
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will be general unsecured, senior obligations of each Issuer;
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will mature on October 15, 2018;
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will be issued initially in an aggregate principal amount of
$300.0 million and in denominations of $2,000 and integral
multiples of $1,000 in excess thereof;
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will be represented by one or more registered Notes in global
form, but in certain circumstances may be represented by Notes
in definitive form, as described in Book-entry; Delivery
and Form;
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will rank senior in right of payment to any future Subordinated
Obligations of each Issuer;
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will rank equally in right of payment to any other existing and
future senior Indebtedness of each Issuer, without giving effect
to collateral arrangements; and
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will be initially unconditionally guaranteed on a senior
unsecured basis by each current Subsidiary of the Company (other
than the Co-Issuer and certain Immaterial Subsidiaries) and
future Domestic Subsidiaries (other than Immaterial
Subsidiaries), as described in Subsidiary
Guarantees; and
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will effectively rank junior to any existing or future secured
Indebtedness of each Issuer, including under the Senior Secured
Credit Agreement, to the extent of the value of the collateral
securing such Indebtedness.
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The
Subsidiary Guarantees
Initially, all of the Subsidiaries of the Company (other than
the Co-Issuer and certain Immaterial Subsidiaries) will
unconditionally guarantee the Notes on a senior unsecured basis.
In addition, future Domestic Subsidiaries (other than Immaterial
Subsidiaries) of the Company will guarantee the Notes. See
Certain Covenants Future
Subsidiary Guarantors.
Each Subsidiary Guarantee of the Notes:
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will be general unsecured senior obligations of the Subsidiary
Guarantor;
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will rank senior in right of payment to any future Guarantor
Subordinated Obligations of the Subsidiary Guarantor;
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will rank equally in right of payment to any other existing and
future senior Indebtedness of the Subsidiary Guarantor, without
giving effect to collateral arrangements;
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will effectively rank junior to all existing and future secured
Indebtedness of the Subsidiary Guarantor, including under the
Senior Secured Credit Agreement, to the extent of the value of
the collateral securing such Indebtedness; and
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will effectively rank junior to all future Indebtedness of any
non-guarantor Subsidiary of the Subsidiary Guarantor.
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Not all of our Subsidiaries will be Subsidiary Guarantors. As of
and for the six months ended June 30, 2010, on a pro forma
basis, our non-Guarantor Subsidiaries collectively held less
than 1.0% of our consolidated total assets and generated less
than 1.0% of our consolidated revenues and had no outstanding
indebtedness, except that certain of such non-Guarantor
Subsidiaries have provided guarantees under our Senior Secured
Credit Agreement. The Notes and Guarantees will effectively be
subordinated to the claims of creditors of any non-Guarantor
Subsidiaries to the extent of the value of the assets thereof.
Initially, all of the Subsidiaries of the Company (including the
Co-Issuer) will be Restricted Subsidiaries, but under the
circumstances described below in the definition of
Unrestricted Subsidiary under the heading
Certain Definitions, the Company may
designate certain of its Subsidiaries as Unrestricted
Subsidiaries. Unrestricted Subsidiaries will not guarantee
the Notes and will not be subject to the restrictive covenants
in the Indenture.
Interest
Interest on the Notes will:
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accrue at the rate of
95/8%
per annum;
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accrue from the Issue Date or, if interest has already been
paid, from the most recent interest payment date;
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be payable in cash semi-annually in arrears on April 15 and
October 15, commencing on April 15, 2011;
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be payable to the holders of record on the April 1 and October 1
immediately preceding the related interest payment dates; and
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be computed on the basis of a
360-day year
comprised of twelve
30-day
months.
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The Issuers will pay interest on any overdue principal of the
new Notes and on any overdue installment of interest at the
above rate plus 1.0%, to the extent lawful.
If an interest payment date falls on a day that is not a
Business Day, the interest payment to be made on such interest
payment date will be made on the next succeeding Business Day
with the same force and effect as if made on such interest
payment date, and no additional interest will accrue as a result
of such delayed payment.
Payments
on the Notes; Paying Agent and Registrar
The Issuers will pay principal of, premium, if any, and interest
on the Notes at the office or agency designated by us in the
City and State of New York, except that they may, at their
option, pay interest on the Notes by check mailed to holders of
the Notes at their registered address as it appears in the
registrars books. The Issuers have initially designated
the Trustee to act as their paying agent at the corporate trust
office of the Trustee in New York, New York, and they have also
designated the Trustee to act as registrar at its corporate
trust office in Dallas, Texas. The Issuers may, however, change
the paying agent or registrar without prior notice to the
holders of the Notes, and the Company or any of its Restricted
Subsidiaries may act as paying agent or registrar.
The Issuers will pay principal of, premium, if any, and interest
on, Notes in global form registered in the name of
Cede & Co., the nominee or The Depository
Trust Company, in immediately available funds, directly to
The Depository Trust Company.
Transfer
and Exchange
A holder may transfer or exchange Notes in accordance with the
Indenture. The registrar and the Trustee may require a holder,
among other things, to furnish appropriate endorsements and
transfer documents in connection with a transfer of Notes. No
service charge will be imposed by the Issuers, the Trustee or
the registrar for any registration of transfer or exchange of
Notes, but the Issuers may require a holder to pay a sum
sufficient to cover any transfer tax or other governmental taxes
and fees required by law or permitted by the Indenture. The
Issuers are not required to transfer or exchange any Note
selected for redemption. Also, the Issuers are not required to
transfer or exchange any Note for a period of 15 days
before a selection of Notes to be redeemed.
Optional
Redemption
On and after October 15, 2014, the Issuers may redeem all
or, from time to time, a part of the Notes upon not less than 30
nor more than 60 days notice, at the following
redemption prices (expressed as a percentage of principal amount
of the Notes), plus accrued and unpaid interest on the Notes, if
any, to the applicable redemption date (subject to the right of
holders of record on the relevant record date to receive
interest due on the relevant interest payment date), if redeemed
during the twelve-month period beginning on October 15 of the
years indicated below:
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Year
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Percentage
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2014
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104.813
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2015
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102.406
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2016 and thereafter
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100.000
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Prior to October 15, 2013, the Issuers may, at their
option, on any one or more occasions redeem up to 35% of the
aggregate principal amount of the Notes (including Additional
Notes) issued under the Indenture
101
with the Net Cash Proceeds of one or more Equity Offerings at a
redemption price of 109.625% of the principal amount thereof,
plus accrued and unpaid interest, if any, to the redemption date
(subject to the right of holders of record on the relevant
record date to receive interest due on the relevant interest
payment date); provided that
(1) at least 65% of the aggregate principal amount of the
Notes (including Additional Notes) issued under the Indenture
remains outstanding after each such redemption; and
(2) the redemption occurs within 120 days after the
closing of the related Equity Offering.
In addition, the Notes may be redeemed, in whole or in part, at
any time prior to October 15, 2014 at the option of the
Issuers upon not less than 30 nor more than 60 days
prior notice mailed by first-class mail to each holder of Notes
at its registered address, at a redemption price equal to 100%
of the principal amount of the Notes redeemed plus the
Applicable Premium as of, and accrued and unpaid interest to,
the applicable redemption date (subject to the right of holders
of record on the relevant record date to receive interest due on
the relevant interest payment date).
Applicable Premium means, with respect to any
Note on any applicable redemption date, the greater of:
(1) 1.0% of the principal amount of such Note; or
(2) the excess, if any, of:
(a) the present value at such redemption date of
(i) the redemption price of such Note at October 15,
2014 (such redemption price being set forth in the table
appearing in the first paragraph of this Optional
Redemption section) plus (ii) all required interest
payments (excluding accrued and unpaid interest to such
redemption date) due on such Note through October 15, 2014
computed using a discount rate equal to the Treasury Rate as of
such redemption date plus 50 basis points; over
(b) the principal amount of such Note.
Treasury Rate means, as of any redemption
date, the yield to maturity at the time of computation of United
States Treasury securities with a constant maturity (as compiled
and published in the most recent Federal Reserve Statistical
Release H.15 (519) which has become publicly available at
least two Business Days prior to the redemption date (or, if
such Statistical Release is no longer published, any publicly
available source of similar market data)) most nearly equal to
the period from the redemption date to October 15, 2014;
provided, however, that if the period from the redemption date
to October 15, 2014 is not equal to the constant maturity
of a United States Treasury security for which a weekly average
yield is given, the Treasury Rate shall be obtained by linear
interpolation (calculated to the nearest one-twelfth of a year)
from the weekly average yields of United States Treasury
securities for which such yields are given, except that if the
period from the redemption date to October 15, 2014 is less
than one year, the weekly average yield on actually traded
United States Treasury securities adjusted to a constant
maturity of one year shall be used. The Company will
(a) calculate the Treasury Rate as of the second Business
Day preceding the applicable redemption date and (b) prior
to such redemption date file with the Trustee an Officers
Certificate setting forth the Applicable Premium and the
Treasury Rate and showing the calculation of each in reasonable
detail.
Selection
and Notice
If the Issuers are redeeming less than all of the outstanding
Notes, the Trustee will select the Notes for redemption in
compliance with the requirements of the principal national
securities exchange, if any, on which the Notes are listed or,
if the Notes are not listed, then on a pro rata basis (or, in
the case of Notes issued in global form as discussed under the
caption Book-Entry; Delivery and Form, the Trustee
will select the Notes for redemption based on DTCs method
that most nearly approximates a pro rata selection), by lot or
by such other method as the Trustee in its sole discretion will
deem to be fair and appropriate, although no Note of $2,000 in
original principal amount or less will be redeemed in part. If
any Note is to be redeemed in part only, the notice of
redemption relating to such Note will state the portion of the
principal amount thereof to be
102
redeemed. A new Note in principal amount equal to the unredeemed
portion thereof will be issued in the name of the holder thereof
upon cancellation of the partially redeemed Note. On and after
the redemption date, interest will cease to accrue on Notes or
the portion of them called for redemption unless we default in
the payment thereof.
Mandatory
Redemption; Offers to Purchase; Open Market Purchases
We are not required to make mandatory redemption payments or
sinking fund payments with respect to the Notes. However, under
certain circumstances, we may be required to offer to purchase
Notes as described under the captions Change
of Control and Certain
Covenants Limitation on Sales of Assets and
Subsidiary Stock.
The Company and its Subsidiaries may acquire Notes by means
other than a redemption or required repurchase, whether by
tender offer, open market purchases, negotiated transactions or
otherwise, in accordance with applicable securities laws, so
long as such acquisition does not otherwise violate the terms of
the Indenture. However, other existing or future agreements of
the Company or its Subsidiaries may limit the ability of the
Company or its Subsidiaries to purchase Notes prior to maturity.
Subsidiary
Guarantees
The Subsidiary Guarantors have, jointly and severally, fully and
unconditionally guaranteed on a senior unsecured basis our
obligations under the Notes and all obligations under the
Indenture. The obligations of each of the Subsidiary Guarantors
under the Subsidiary Guarantees rank equally in right of payment
with all other Indebtedness of such Subsidiary Guarantor, except
to the extent such other Indebtedness is expressly subordinated
in right of payment to the obligations arising under its
Subsidiary Guarantee.
Although the Indenture will limit the amount of Indebtedness
that the Subsidiary Guarantors may Incur, such Indebtedness may
be substantial and such limitation is subject to a number of
significant qualifications. Moreover, the Indenture does not
impose any limitation on the Incurrence by the Subsidiary
Guarantors of liabilities that are not considered Indebtedness
under the Indenture. See Certain
Covenants Limitation on Indebtedness and Preferred
Stock.
The obligations of each Subsidiary Guarantor under its
Subsidiary Guarantee will be limited as necessary to prevent
that Subsidiary Guarantee from constituting a fraudulent
conveyance or fraudulent transfer under applicable law, although
no assurance can be given that a court would give the holder the
benefit of such provision. See Risk Factors
Risks Related to the Exchange Offer and New Notes If
the subsidiary guarantees are deemed fraudulent conveyances or
preferential transfers, a court may subordinate or void
them. Any guarantees of the notes by us or our operating
subsidiaries could be deemed fraudulent conveyances under
certain circumstances, and a court may subordinate or void the
guarantees. If a Subsidiary Guarantee were rendered voidable, it
could be subordinated by a court to all other indebtedness
(including guarantees and other contingent liabilities) of the
applicable Subsidiary Guarantor, and, depending on the amount of
such indebtedness, a Subsidiary Guarantors liability on
its Subsidiary Guarantee could be reduced to zero. If the
obligations of a Subsidiary Guarantor under its Subsidiary
Guarantee were avoided, holders of Notes would have to look to
the assets of any remaining Subsidiary Guarantors for payment.
There can be no assurance in that event that such assets would
suffice to pay the outstanding principal and interest on the
Notes.
In the event a Subsidiary Guarantor is sold or disposed of
(whether by merger, consolidation, the sale of all of its
Capital Stock or the sale of all or substantially all of its
assets (other than by lease) and whether or not the Subsidiary
Guarantor is the surviving entity in such transaction) to a
Person which is not the Company or a Subsidiary of the Company,
such Subsidiary Guarantor will be released from its obligations
under its Subsidiary Guarantee if the sale or other disposition
does not violate the covenants described under
Certain Covenants Limitation on
Sales of Assets and Subsidiary Stock.
In addition, a Subsidiary Guarantor will be released from its
obligations under its Subsidiary Guarantee, (a) if the
Company designates such Subsidiary as an Unrestricted Subsidiary
and such designation complies with the other applicable
provisions of the Indenture or if such Subsidiary otherwise no
longer qualifies as
103
such or (b) in connection with any covenant defeasance,
legal defeasance or satisfaction and discharge of the Notes as
provided below under the captions Defeasance
and Satisfaction and Discharge.
Change of
Control
If a Change of Control occurs, unless the Issuers have
previously or concurrently exercised their right to redeem all
of the Notes as described under Optional
Redemption, each holder will have the right to require the
Company to repurchase all or any part (equal to $2,000 or an
integral multiple of $1,000 in excess thereof) of such
holders Notes at a purchase price in cash equal to 101% of
the principal amount of the Notes plus accrued and unpaid
interest, if any, to the date of purchase (subject to the right
of holders of record on the relevant record date to receive
interest due on the relevant interest payment date).
Within 30 days following any Change of Control, unless the
Issuers have previously or concurrently exercised their right to
redeem all of the Notes as described under
Optional Redemption, we will mail a
notice (the Change of Control Offer) to each holder,
with a copy to the Trustee, stating:
(1) that a Change of Control has occurred and that such
holder has the right to require us to purchase such
holders Notes at a purchase price in cash equal to 101% of
the principal amount of such Notes plus accrued and unpaid
interest, if any, to the date of purchase (subject to the right
of holders of record on a record date to receive interest on the
relevant interest payment date) (the Change of Control
Payment);
(2) the repurchase date (which shall be no earlier than
30 days nor later than 60 days from the date such
notice is mailed) (the Change of Control Payment
Date);
(3) that any Note not properly tendered will remain
outstanding and continue to accrue interest;
(4) that unless we default in the payment of the Change of
Control Payment, all Notes accepted for payment pursuant to the
Change of Control Offer will cease to accrue interest on the
Change of Control Payment Date;
(5) that holders electing to have any Notes purchased
pursuant to a Change of Control Offer will be required to
surrender such Notes, with the form entitled Option of
Holder to Elect Purchase on the reverse of such Notes in
certificated form completed, to the paying agent specified in
the notice at the address specified in the notice prior to the
close of business on the third Business Day preceding the Change
of Control Payment Date;
(6) that holders will be entitled to withdraw their
tendered Notes and their election to require us to purchase such
Notes, provided that the paying agent receives, not later than
the close of business on the third Business Day preceding the
Change of Control Payment Date, a telegram, telex, facsimile
transmission or letter setting forth the name of the holder of
the Notes, the principal amount of Notes tendered for purchase,
and a statement that such holder is withdrawing its tendered
Notes and its election to have such Notes purchased;
(7) that if we are repurchasing a portion of the Note of
any holder, the holder will be issued a new Note equal in
principal amount to the unpurchased portion of the Note
surrendered, provided that the unpurchased portion of the Note
must be equal to a minimum principal amount of $2,000 and an
integral multiple of $1,000 in excess thereof; and
(8) the procedures determined by us, consistent with the
Indenture, that a holder must follow in order to have its Notes
repurchased.
On the Change of Control Payment Date, the Company will, to the
extent lawful:
(1) accept for payment all Notes or portions of Notes (in a
minimum principal amount of $2,000 and integral multiples of
$1,000 in excess thereof) properly tendered pursuant to the
Change of Control Offer and not properly withdrawn;
104
(2) deposit with the paying agent an amount equal to the
Change of Control Payment in respect of all Notes or portions of
Notes accepted for payment; and
(3) deliver or cause to be delivered to the Trustee the
Notes so accepted together with an Officers Certificate
stating the aggregate principal amount of Notes or portions of
Notes being purchased by the Company.
The paying agent will promptly mail or deliver to each holder of
Notes accepted for payment the Change of Control Payment for
such Notes, and the Trustee, upon delivery of a written request
from the Company, will promptly authenticate and mail (or cause
to be transferred by book entry) to each holder a new Note equal
in principal amount to any unpurchased portion of the Notes
surrendered, if any; provided that each such new Note will be in
a minimum principal amount of $2,000 or an integral multiple of
$1,000 in excess thereof.
If the Change of Control Payment Date is on or after an interest
record date and on or before the related interest payment date,
any accrued and unpaid interest, will be paid to each Person in
whose name a Note is registered at the close of business on such
record date, and no further interest will be payable to holders
who tender pursuant to the Change of Control Offer.
The Change of Control provisions described above will be
applicable whether or not any other provisions of the Indenture
are applicable. Except as described above with respect to a
Change of Control, the Indenture will not contain provisions
that permit the holders to require that the Company or any
Subsidiary repurchase or redeem the Notes in the event of a
takeover, recapitalization or similar transaction.
We will not be required to make a Change of Control Offer upon a
Change of Control if any other Person makes the Change of
Control Offer in the manner, at the times and otherwise in
compliance with the requirements set forth in the Indenture
applicable to a Change of Control Offer made by us and purchases
all Notes validly tendered and not withdrawn under such Change
of Control Offer.
A Change of Control Offer may be made in advance of a Change of
Control, and conditioned upon the occurrence of a Change of
Control, if a definitive agreement is in place for the Change of
Control at the time of making the Change of Control Offer.
We will comply, to the extent applicable, with the requirements
of
Rule 14e-1
of the Exchange Act and any other securities laws or regulations
in connection with the repurchase of Notes as a result of a
Change of Control. To the extent that the provisions of any
securities laws or regulations conflict with provisions of this
covenant, we will comply with the applicable securities laws and
regulations and will not be deemed to have breached our
obligations under in the Indenture by virtue of our compliance
with such securities laws or regulations.
Our ability to repurchase Notes pursuant to a Change of Control
Offer may be limited by a number of factors. The occurrence of
certain of the events that constitute a Change of Control would
constitute a default under the Senior Secured Credit Agreement.
In addition, certain events that may constitute a change of
control under the Senior Secured Credit Agreement and cause a
default under that agreement will not constitute a Change of
Control under the Indenture. Future Indebtedness of the Company
and its Subsidiaries may also contain prohibitions of certain
events that would constitute a Change of Control or require such
Indebtedness to be repaid upon a Change of Control. Moreover,
the exercise by the holders of their right to require us to
repurchase the Notes could cause a default under other
Indebtedness, even if the Change of Control itself does not, due
to the financial effect of such repurchase on the Company and
its Restricted Subsidiaries. Finally, the Companys ability
to pay cash to the holders upon a repurchase may be limited by
the then existing financial resources of the Company and its
Restricted Subsidiaries. There can be no assurance that
sufficient funds will be available when necessary to make any
required repurchases.
Even if sufficient funds were otherwise available, the other
Indebtedness of the Company or its Restricted Subsidiaries may
prohibit the Companys repurchase of Notes before their
scheduled maturity. Consequently, if the Company and its
Restricted Subsidiaries are not able to prepay the Indebtedness
under the Senior Secured Credit Agreement and any such other
Indebtedness containing similar restrictions or obtain requisite
consents,
105
the Company will be unable to fulfill its repurchase obligations
if holders of Notes exercise their repurchase rights following a
Change of Control, resulting in a default under the Indenture. A
default under the Indenture may result in a cross-default under
the Senior Secured Credit Agreement.
The Change of Control provisions described above may deter
certain mergers, tender offers and other takeover attempts
involving the Company. The Change of Control purchase feature is
a result of negotiations between the initial purchasers and the
Company. As of the Issue Date, the Company has no present
intention to engage in a transaction involving a Change of
Control, although it is possible that it could decide to do so
in the future. Subject to the limitations discussed below, the
Company or its Subsidiaries could, in the future, enter into
certain transactions, including acquisitions, refinancings or
other recapitalizations, that would not constitute a Change of
Control under the Indenture, but that could increase the amount
of indebtedness outstanding at such time or otherwise affect our
capital structure or credit ratings. Restrictions on the ability
of the Company and its Restricted Subsidiaries to incur
additional Indebtedness are contained in the covenants described
under Certain Covenants Limitation
on Indebtedness and Preferred Stock and
Certain Covenants Limitation on
Liens. Such restrictions in the Indenture can be waived
only with the consent of the holders of a majority in principal
amount of the Notes then outstanding. Except for the limitations
contained in such covenants, however, the Indenture will not
contain any covenants or provisions that may afford holders of
the Notes protection in the event of a highly leveraged
transaction.
The definition of Change of Control includes a
disposition of all or substantially all of the assets of the
Company and its Restricted Subsidiaries taken as a whole to any
Person. Although there is a limited body of case law
interpreting the phrase substantially all, there is
no precise established definition of the phrase under applicable
law. Accordingly, in certain circumstances there may be a degree
of uncertainty as to whether a particular transaction would
involve a disposition of all or substantially all of
the assets of a Person. As a result, it may be unclear as to
whether a Change of Control has occurred and whether a holder of
Notes may require the Company to make an offer to repurchase the
Notes as described above.
The provisions under the Indenture relative to our obligation to
make an offer to repurchase the Notes as a result of a Change of
Control may be waived or modified or terminated with the consent
of the holders of a majority in principal amount of the Notes
then outstanding (including consents obtained in connection with
a tender offer or exchange offer for the Notes), but only if
done prior to the occurrence of such Change of Control.
Certain
Covenants
Limitation
on Indebtedness and Preferred Stock
The Company will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, Incur any Indebtedness
(including Acquired Indebtedness), and the Company will not
permit any of its Restricted Subsidiaries to issue Preferred
Stock; provided, however, that the Company and any of the
Subsidiary Guarantors may Incur Indebtedness and issue Preferred
Stock if on the date thereof:
(1) the Consolidated Coverage Ratio for the Company and its
Restricted Subsidiaries is at least 2.25 to 1.00, determined on
a pro forma basis (including a pro forma application of
proceeds); and
(2) no Default would occur as a consequence of, and no
Event of Default would be continuing following, Incurring the
Indebtedness or its application.
The first paragraph of this covenant will not prohibit the
Incurrence of the following:
(1) Indebtedness under one or more Credit Facilities
(including the Senior Secured Credit Agreement) Incurred
pursuant to this clause (1) by the Issuers or any
Subsidiary Guarantor in an aggregate amount outstanding at any
one time not to exceed the greater of
(i) $300.0 million or (ii) 30.0% of the
Companys Adjusted Consolidated Net Tangible Assets
determined as of the date of the Incurrence of such Indebtedness
after giving effect to the application of the proceeds therefrom;
(2) guarantees of Indebtedness Incurred in accordance with
the provisions of the Indenture; provided that in the event such
Indebtedness that is being guaranteed is a Subordinated
Obligation or a Guarantor
106
Subordinated Obligation, then the related guarantee shall be
subordinated in right of payment to the Notes or the Subsidiary
Guarantees to at least the same extent as the Indebtedness being
guaranteed, as the case may be;
(3) Indebtedness of the Company owing to and held by any
Restricted Subsidiary or Indebtedness of a Restricted Subsidiary
owing to and held by the Company or any Restricted Subsidiary;
provided, however, that (a)(i) if the Company is the obligor on
such Indebtedness and the obligee is not a Subsidiary Guarantor,
such Indebtedness must be expressly subordinated to the prior
payment in full in cash of all obligations with respect to the
Notes and (ii) if a Subsidiary Guarantor is the obligor of
such Indebtedness and the obligee is neither the Company nor a
Subsidiary Guarantor, such Indebtedness must be expressly
subordinated to the prior payment in full in cash of all
obligations of such Subsidiary Guarantor with respect to its
Subsidiary Guarantee and (b)(i) any subsequent issuance or
transfer of Capital Stock or any other event which results in
any such Indebtedness being held by a Person other than the
Company or a Restricted Subsidiary of the Company and
(ii) any sale or other transfer of any such Indebtedness to
a Person other than the Company or a Restricted Subsidiary of
the Company shall be deemed, in each case, to constitute an
Incurrence of such Indebtedness by the Company or such
Restricted Subsidiary, as the case may be, that was not
permitted by this clause;
(4) Indebtedness represented by (a) the Notes issued
on the Issue Date and all Subsidiary Guarantees, (b) any
Indebtedness (other than the Indebtedness described in clauses
(1), (3), 4(a) and (9) of this paragraph) outstanding on
the Issue Date, (c) any Exchange Notes and related
Subsidiary Guarantees issued pursuant to a Registration Rights
Agreement and (d) any Refinancing Indebtedness Incurred in
respect of any Indebtedness described in this clause (4) or
clause (5) or Incurred pursuant to the first paragraph of
this covenant;
(5) Permitted Acquisition Indebtedness;
(6) Indebtedness Incurred in respect of
(a) self-insurance obligations or bid, plugging and
abandonment, appeal, reimbursement, performance, surety and
similar bonds provided by the Company or a Restricted Subsidiary
in the ordinary course of business and any guarantees or letters
of credit functioning as or supporting any of such obligations
or bonds and (b) obligations represented by letters of
credit for the account of the Company or a Restricted Subsidiary
in order to provide security for workers compensation
claims (in the case of both clauses (a) and (b) other
than for an obligation for money borrowed);
(7) Indebtedness of the Company or any Subsidiary Guarantor
represented by Capitalized Lease Obligations (whether or not
incurred pursuant to Sale/Leaseback Transactions) or other
Indebtedness incurred or assumed in connection with the
acquisition, construction, improvement or development of real or
personal, movable or immovable, property, in each case Incurred
for the purpose of financing, refinancing, renewing, defeasing
or refunding all or any part of the purchase price or cost of
acquisition, construction, improvement or development of
property used in the business of the Company or the Subsidiary
Guarantors; provided that the aggregate principal amount
incurred by the Company or any Subsidiary Guarantor pursuant to
this clause (7) outstanding at any time shall not exceed
the greater of (x) $25.0 million and (y) 2.5% of
the Companys Adjusted Consolidated Net Tangible Assets;
and provided further that the principal amount of any
Indebtedness permitted under this clause (7) did not in
each case at the time of incurrence exceed the Fair Market
Value, as determined in accordance with the definition of such
term, of the acquired or constructed asset or improvement so
financed;
(8) Indebtedness to the extent that the net proceeds
thereof are promptly deposited to defease the Notes or to
satisfy and discharge the Indenture;
(9) in addition to the items referred to in clauses
(1) through (8) above, Indebtedness of the Company and
its Restricted Subsidiaries in an aggregate outstanding
principal amount which, when taken together with the principal
amount of all other Indebtedness Incurred pursuant to this
clause (9) and then outstanding, will not exceed the
greater of (a) $35.0 million, and (b) 5.0% of the
Companys Adjusted Consolidated Net Tangible Assets.
107
For purposes of determining compliance with, and the outstanding
principal amount of any particular Indebtedness Incurred
pursuant to and in compliance with, this covenant:
(1) in the event an item of that Indebtedness meets the
criteria of more than one of the types of Indebtedness described
in the first and second paragraphs of this covenant, the
Company, in its sole discretion, will classify such item of
Indebtedness on the date of Incurrence and, subject to clause
(2) below may later classify, reclassify or redivide all or
a portion of such item of Indebtedness, in any manner that
complies with this covenant;
(2) any Indebtedness outstanding on the date of the
Indenture under the Senior Secured Credit Agreement shall be
deemed Incurred on the Issue Date under clause (1) of the
second paragraph of this covenant;
(3) guarantees of, or obligations in respect of letters of
credit supporting, Indebtedness which is otherwise included in
the determination of a particular amount of Indebtedness shall
not be included;
(4) the principal amount of any Disqualified Stock of the
Company or a Restricted Subsidiary, or Preferred Stock of a
Restricted Subsidiary, will be equal to the greater of the
maximum mandatory redemption or repurchase price (including, in
either case, any redemption or repurchase premium) or the
liquidation preference thereof;
(5) Indebtedness permitted by this covenant need not be
permitted solely by reference to one provision permitting such
Indebtedness but may be permitted in part by one such provision
and in part by one or more other provisions of this covenant
permitting such Indebtedness; and
(6) the amount of Indebtedness issued at a price that is
less than the principal amount thereof will be equal to the
amount of the liability in respect thereof determined in
accordance with GAAP.
Accrual of interest, accrual of dividends, the amortization of
debt discount or the accretion of accreted value and unrealized
losses or charges in respect of Hedging Obligations (including
those resulting from the application of Statement of Financial
Accounting Standard No. 133) will not be deemed to be
an Incurrence of Indebtedness for purposes of this covenant.
The Company will not permit any of its Unrestricted Subsidiaries
to Incur any Indebtedness other than Non-Recourse Debt. If at
any time an Unrestricted Subsidiary becomes a Restricted
Subsidiary, any Indebtedness of such Subsidiary shall be deemed
to be Incurred by a Restricted Subsidiary as of such date (and,
if such Indebtedness is not permitted to be Incurred as of such
date under this Limitation on Indebtedness and Preferred
Stock covenant, the Company shall be in Default of this
covenant).
The Indenture will not treat (1) unsecured Indebtedness as
subordinated or junior to secured Indebtedness merely because it
is unsecured or (2) senior Indebtedness as subordinated or
junior to any other senior Indebtedness merely because it has a
junior priority with respect to the same collateral.
Limitation
on Restricted Payments
The Company will not, and will not permit any of its Restricted
Subsidiaries, directly or indirectly, to:
(1) declare or pay any dividend or make any payment or
distribution on or in respect of its Capital Stock (including
any payment or distribution in connection with any merger or
consolidation involving the Company or any of its Restricted
Subsidiaries) except:
(a) dividends or distributions by the Company payable
solely in Capital Stock of the Company (other than Disqualified
Stock); and
(b) dividends or distributions payable to the Company or a
Restricted Subsidiary and if such Restricted Subsidiary is not a
Wholly Owned Subsidiary, to minority stockholders (or owners of
an equivalent interest in the case of a Subsidiary that is an
entity other than a corporation) so long as the Company or a
Restricted Subsidiary receives at least its pro rata share of
such dividend or distribution;
108
(2) purchase, repurchase, redeem, defease or otherwise
acquire or retire for value any Capital Stock of the Company or
any direct or indirect parent of the Company held by Persons
other than the Company or a Wholly Owned Subsidiary;
(3) purchase, repurchase, redeem, defease or otherwise
acquire or retire for value, prior to scheduled maturity,
scheduled repayment or scheduled sinking fund payment, any
Subordinated Obligations or Guarantor Subordinated Obligations
(other than (x) Indebtedness permitted under clause
(3) of the second paragraph of the covenant described above
under Limitation on Indebtedness and Preferred
Stock or (y) the purchase, repurchase, redemption,
defeasance or other acquisition or retirement of Subordinated
Obligations or Guarantor Subordinated Obligations purchased in
anticipation of satisfying a sinking fund obligation, principal
installment or final maturity, in each case due within one year
of the date of purchase, repurchase, redemption, defeasance or
other acquisition or retirement); or
(4) make any Restricted Investment in any Person;
(any such dividend, distribution, purchase, repurchase,
redemption, defeasance, other acquisition or retirement or
Restricted Investment referred to in clauses (1) through
(4) is referred to herein as a Restricted
Payment), if at the time the Company or such Restricted
Subsidiary makes such Restricted Payment:
(a) a Default has occurred and is continuing (or would
result therefrom);
(b) the Company is not able to Incur an additional $1.00 of
Indebtedness pursuant to the first paragraph of the covenant
described under Limitation on Indebtedness and
Preferred Stock after giving effect, on a pro forma basis,
to such Restricted Payment; or
(c) the aggregate amount of such Restricted Payment and all
other Restricted Payments declared or made subsequent to the
Issue Date (other than under clauses (1), (2), (4), (5), (6),
(7), (8), (9), (10), and (11) of the next paragraph) would
exceed the sum of (the Basket Amount):
(i) 50% of Consolidated Net Income accrued on a cumulative
basis for the period (treated as one accounting period) from
October 1, 2010 to the end of the most recent fiscal
quarter ending prior to the date of such Restricted Payment for
which financial statements are in existence (or, in case such
Consolidated Net Income is a deficit, minus 100% of such
deficit);
(ii) 100% of the aggregate Net Cash Proceeds and the Fair
Market Value of any Capital Stock of Persons engaged primarily
in the Oil and Gas Business or assets used in the Oil and Gas
Business, in each case received by the Company from the issue or
sale of its Capital Stock (other than Disqualified Stock) or
from cash capital contributions subsequent to the Issue Date
(other than Net Cash Proceeds received from an issuance or sale
of such Capital Stock to (x) a Subsidiary of the Company or
(y) an employee stock ownership plan, option plan or
similar trust (to the extent such sale to an employee stock
ownership plan, option plan or similar trust is financed by
loans from or guaranteed by the Company or any Restricted
Subsidiary unless such loans have been repaid with cash on or
prior to the date of determination));
(iii) the amount by which Indebtedness of the Company or
its Restricted Subsidiaries is reduced on the Companys
balance sheet upon the conversion or exchange (other than by a
Subsidiary of the Company) subsequent to the Issue Date of any
Indebtedness of the Company or its Restricted Subsidiaries
convertible or exchangeable for Capital Stock (other than
Disqualified Stock) of the Company (less the amount of any cash,
or the Fair Market Value of any other property (other than such
Capital Stock), distributed by the Company upon such conversion
or exchange), together with the net proceeds, if any, received
by the Company or any of its Restricted Subsidiaries upon such
conversion or exchange; and
109
(iv) the amount equal to the aggregate net reduction in
Restricted Investments made by the Company or any of its
Restricted Subsidiaries in any other Person after the Issue Date
resulting from:
(A) repurchases, repayments or redemptions of such
Restricted Investments by such Person, proceeds realized upon
the sale of such Restricted Investments (other than to a
Subsidiary of the Company), or repayments of loans or advances
or other transfers of assets (including by way of dividend or
distribution) by such Person to the Company or any Restricted
Subsidiary; and
(B) the redesignation of Unrestricted Subsidiaries as
Restricted Subsidiaries (valued in each case as provided in the
definition of Investment) not to exceed, in the case
of any Unrestricted Subsidiary, the amount of Investments
previously made by the Company or any Restricted Subsidiary in
such Unrestricted Subsidiary, which amount in each case under
this clause (iv) was included in the calculation of the
amount of Restricted Payments; provided, however, that no amount
will be included under this clause (iv) to the extent it is
already included in Consolidated Net Income.
The provisions of the preceding paragraph will not prohibit:
(1) any Restricted Payment made by exchange for, or out of
the proceeds of the substantially concurrent sale of, Capital
Stock of the Company (other than Disqualified Stock and other
than Capital Stock issued or sold to a Subsidiary of the Company
or an employee stock ownership plan, option plan or similar
trust to the extent such sale to an employee stock ownership
plan, option plan or similar trust is financed by loans from or
guaranteed by the Company or any Restricted Subsidiary unless
such loans have been repaid with cash on or prior to the date of
determination) or a substantially concurrent cash capital
contribution received by the Company from the owners of its
Capital Stock; provided that the Net Cash Proceeds from such
sale of Capital Stock or capital contribution will be excluded
from clause (c)(ii) of the preceding paragraph;
(2) any purchase, repurchase, redemption, defeasance or
other acquisition or retirement of Subordinated Obligations of
an Issuer or Guarantor Subordinated Obligations of any
Subsidiary Guarantor made by exchange for, or out of the
proceeds of the substantially concurrent sale of Refinancing
Indebtedness with respect to such Subordinated Obligations or
Guarantor Subordinated Obligations permitted to be Incurred
pursuant to the covenant described above under
Limitation on Indebtedness and Preferred
Stock;
(3) dividends paid or distributions made within
60 days after the date of declaration if at such date of
declaration such dividend or distribution would have complied
with this covenant; provided, however, that such dividends and
distributions will be included in subsequent calculations of the
Basket Amount; and provided further, however, that for purposes
of clarification, this clause (3) shall not include cash
payments in lieu of the issuance of fractional shares included
in clause (8) below;
(4) the repurchase or other acquisition of Capital Stock
(including options, warrants, equity appreciation rights or
other rights to purchase or acquire Capital Stock) of the
Company held by any existing or former employees, officers or
directors of the Company or the General Partner or any
Restricted Subsidiary of the Company or their assigns, estates
or heirs, in each case pursuant to the repurchase or other
acquisition provisions under employee stock option or stock
purchase plans or agreements or other agreements to compensate
employees, officers or directors, in each case approved by the
Companys Board of Directors; provided that such
repurchases or other acquisitions pursuant to this clause
(4) will not exceed $2.0 million in the aggregate
during any calendar year; and provided that the proceeds
received from any such transaction will be excluded from clause
(c)(ii) of the preceding paragraph;
(5) purchases, repurchases, redemptions or other
acquisitions or retirements for value of Capital Stock deemed to
occur upon the exercise of stock options, warrants, rights to
acquire Capital Stock or other convertible securities if such
Capital Stock represents a portion of the exercise or exchange
price
110
thereof, and any purchases, repurchases, redemptions or other
acquisitions or retirements for value of Capital Stock made in
lieu of withholding taxes in connection with any exercise or
exchange of warrants, options or rights to acquire Capital Stock;
(6) the purchase, repurchase, redemption, defeasance or
other acquisition or retirement for value of any Subordinated
Obligation (i) at a purchase price not greater than 101% of
the principal amount of such Subordinated Obligation in the
event of a Change of Control in accordance with provisions
similar to the covenant described under Change
of Control or (ii) at a purchase price not greater
than 100% of the principal amount thereof in accordance with
provisions similar to the covenant described under
Limitation on Sales of Assets and Subsidiary
Stock; provided that, prior to or simultaneously with such
purchase, repurchase, redemption, defeasance or other
acquisition or retirement, the Company has made the Change of
Control Offer or Asset Disposition Offer, as applicable, as
provided in such covenant with respect to the Notes and has
completed the repurchase of all Notes accepted for payment in
connection with such Change of Control Offer or Asset
Disposition Offer;
(7) so long as no Default has occurred and is continuing,
payments or distributions to dissenting equityholders pursuant
to applicable law or in connection with the settlement or other
satisfaction of legal claims made pursuant to or in connection
with a consolidation, merger or transfer of assets;
(8) cash payments in lieu of the issuance of fractional
shares;
(9) the declaration and payment of scheduled or accrued
dividends to holders of any class of or series of Disqualified
Stock of the Company issued after the Issue Date in accordance
with the covenant captioned Limitation on
Indebtedness and Preferred Stock, to the extent such
dividends are included in Consolidated Interest Expense;
(10) so long as the Company is treated for U.S. federal tax
purposes as a disregarded entity or partnership, Permitted Tax
Distributions;
(11) dividends paid or distributions made by the Company,
or purchases, repurchases, redemptions or other acquisitions or
retirements for value of Capital Stock of the Company, within
60 days after the Issue Date from proceeds of the issuance
of the Notes in an aggregate amount not to exceed
$50.0 million; and
(12) so long as no Default has occurred and is continuing,
Restricted Payments in an amount not to exceed
$25.0 million in the aggregate since the Issue Date.
The amount of all Restricted Payments (other than cash) shall be
the Fair Market Value on the date of such Restricted Payment of
the securities or other assets proposed to be paid, transferred
or issued by the Company or such Restricted Subsidiary, as the
case may be, pursuant to such Restricted Payment. The Fair
Market Value of any cash Restricted Payment shall be its face
amount, and the Fair Market Value of any non-cash Restricted
Payment shall be determined in accordance with the definition of
that term. Not later than the date of making any Restricted
Payment pursuant to clause (c) of the second preceding
paragraph or clause (12) of the preceding paragraph, the
Company shall deliver to the Trustee an Officers
Certificate stating that such Restricted Payment is permitted
and setting forth the basis upon which the calculations required
by this covenant were computed and the Basket Amount after
giving effect to such Restricted Payment.
In the event that a Restricted Payment meets the criteria of
more than one of the exceptions described in clauses
(1) through (12) above or is entitled to be made
pursuant to the first paragraph above, the Company shall, in its
sole discretion, classify such Restricted Payment and may later
re-classify all or a portion of such Restricted Payment.
The Company will not permit any Unrestricted Subsidiary to
become a Restricted Subsidiary except pursuant to the last
sentence of the definition of Unrestricted
Subsidiary. For purpose of designating any Restricted
Subsidiary as an Unrestricted Subsidiary, all outstanding
Investments by the Company and its Restricted Subsidiaries
(except to the extent repaid) in the Subsidiary so designated
will be deemed to be Restricted Payments in an amount determined
as set forth in the last sentence of the definition of
Investment. Such designation will be permitted only
if a Restricted Payment in such amount would be
111
permitted at such time, whether pursuant to the first paragraph
of this covenant or under clause (12) of the second
paragraph of this covenant, or pursuant to the definition of
Permitted Investments, and if such Subsidiary
otherwise meets the definition of an Unrestricted Subsidiary.
Unrestricted Subsidiaries will not guarantee the Notes and will
not be subject to any of the restrictive covenants set forth in
the Indenture.
Limitation
on Liens
The Company will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, create, Incur or suffer
to exist any Lien (other than Permitted Liens) upon any of its
property or assets (including Capital Stock of Restricted
Subsidiaries), including any income or profits therefrom,
whether owned on the date of the Indenture or acquired after
that date, which Lien is securing any Indebtedness, unless
contemporaneously with the Incurrence of such Lien effective
provision is made to secure the Indebtedness due under the Notes
(in the case of the Company) or any Subsidiary Guarantee of such
other Restricted Subsidiary, equally and ratably with (or senior
in priority to in the case of Liens with respect to Subordinated
Obligations or Guarantor Subordinated
Obligations, as the case may be) the Indebtedness secured by
such Lien for so long as such Indebtedness is so secured.
Limitation
on Restrictions on Distributions from Restricted
Subsidiaries
The Company will not, and will not permit any Restricted
Subsidiary (other than the Co-Issuer) to, create or otherwise
cause or permit to exist or become effective any consensual
encumbrance or consensual restriction on the ability of any such
Restricted Subsidiary to:
(1) pay dividends or make any other distributions on its
Capital Stock or pay any Indebtedness or other obligations owed
to the Company or any other Restricted Subsidiary (it being
understood that the priority of any Preferred Stock in receiving
dividends or liquidating distributions prior to dividends or
liquidating distributions being paid on Common Stock shall not
be deemed a restriction on the ability to make distributions on
Capital Stock);
(2) make any loans or advances to the Company or any other
Restricted Subsidiary (it being understood that the
subordination of loans or advances made to the Company or any
Restricted Subsidiary to other Indebtedness Incurred by the
Company or any Restricted Subsidiary shall not be deemed a
restriction on the ability to make loans or advances); or
(3) sell, lease or transfer any of its property or assets
to the Company or any other Restricted Subsidiary.
The preceding provisions will not prohibit:
(i) any encumbrance or restriction pursuant to or by reason
of an agreement in effect at or entered into on the Issue Date,
including the Indenture and the Senior Secured Credit Agreement,
each as in effect on such date;
(ii) any encumbrance or restriction with respect to a
Person pursuant to or by reason of an agreement relating to any
Capital Stock or Indebtedness Incurred by a Person on or before
the date on which such Person was acquired by the Company or
another Restricted Subsidiary (other than Capital Stock or
Indebtedness Incurred as consideration in, or to provide all or
any portion of the funds utilized to consummate, the transaction
or series of related transactions pursuant to which such Person
was acquired by the Company or a Restricted Subsidiary or in
contemplation of the transaction) and outstanding on such date;
provided that any such encumbrance or restriction shall not
extend to any assets or property of the Company or any other
Restricted Subsidiary other than the assets and property so
acquired;
(iii) any encumbrance or restriction contained in contracts
entered into in the ordinary course of business, not relating to
any Indebtedness, and that do not, individually or in the
aggregate, detract from the value of, or from the ability of the
Company and the Restricted Subsidiaries to realize the value of,
112
property or assets of the Company or any Restricted Subsidiary
in any manner material to the Company or any Restricted
Subsidiary;
(iv) any encumbrance or restriction with respect to a
Restricted Subsidiary pursuant to an agreement effecting a
refunding, replacement or refinancing of Indebtedness Incurred
pursuant to an agreement referred to in clauses (i) and
(ii) or clause (ix) of this paragraph or this clause
(iv) or contained in any amendment, restatement,
modification, renewal, supplemental, refunding, replacement or
refinancing of an agreement referred to in clauses (i) and
(ii) or clause (ix) of this paragraph or this clause
(iv); provided that the encumbrances and restrictions with
respect to such Restricted Subsidiary contained in any such
agreement taken as a whole are no less favorable in any material
respect to the holders of the Notes than the encumbrances and
restrictions contained in the agreements governing the
Indebtedness being refunded, replaced or refinanced;
(v) in the case of clause (3) of the first paragraph
of this covenant, any encumbrance or restriction:
(a) that restricts in a customary manner the subletting,
assignment or transfer of any property or asset that is subject
to a lease (including leases governing leasehold interests or
farm-in agreements or farm-out agreements relating to leasehold
interests in Oil and Gas Properties), license or similar
contract, or the assignment or transfer of any such lease
(including leases governing leasehold interests or farm-in
agreements or farm-out agreements relating to leasehold
interests in Oil and Gas Properties), license (including
licenses of intellectual property) or other contract;
(b) contained in mortgages, pledges or other security
agreements permitted under the Indenture securing Indebtedness
of the Company or a Restricted Subsidiary to the extent such
encumbrances or restrictions restrict the transfer of the
property subject to such mortgages, pledges or other security
agreements;
(c) contained in any agreement creating Hedging Obligations
permitted from time to time under the Indenture;
(d) pursuant to customary provisions restricting
dispositions of real property interests set forth in any
reciprocal easement agreements of the Company or any Restricted
Subsidiary;
(e) on cash or other deposits imposed by customers under
contracts entered into in the ordinary course of business; or
(f) with respect to the disposition or distribution of
assets or property in operating agreements, joint venture
agreements, development agreements, area of mutual interest
agreements and other agreements that are customary in the Oil
and Gas Business and entered into in the ordinary course of
business;
(vi) any encumbrance or restriction contained in
(a) purchase money obligations for property acquired in the
ordinary course of business and (b) Capitalized Lease
Obligations, in each case that are permitted under the Indenture
and that impose encumbrances or restrictions of the nature
described in clause (3) of the first paragraph of this
covenant on the property or assets so acquired, and any proceeds
thereof;
(vii) any encumbrance or restriction with respect to a
Restricted Subsidiary (or any of its property or assets) imposed
pursuant to an agreement entered into for the direct or indirect
sale or other disposition of all or a portion of the Capital
Stock or property or assets of such Restricted Subsidiary
pending the closing of such sale or other disposition;
(viii) any encumbrance or restriction arising or existing
by reason of applicable law or any applicable rule, regulation
or order;
(ix) any encumbrance or restriction contained in agreements
governing Indebtedness of the Company or any of its Restricted
Subsidiaries permitted to be Incurred pursuant to an agreement
entered into subsequent to the Issue Date in accordance with the
covenant described above under the caption
Limitation on Indebtedness and Preferred
Stock; provided that the provisions relating to such
113
encumbrance or restriction contained in such Indebtedness, taken
as a whole, are not materially less favorable to the Company
taken as a whole, as determined by the Board of Directors of the
Company in good faith, than the provisions contained in the
Senior Secured Credit Agreement and in the Indenture as in
effect on the Issue Date; and
(x) any encumbrance or restriction on cash or other
deposits or net worth imposed by customers under contracts or
required by insurance, surety or bonding companies, in each case
entered into or incurred in the ordinary course of business.
Limitation
on Sales of Assets and Subsidiary Stock
The Company will not, and will not permit any of its Restricted
Subsidiaries to, make any Asset Disposition unless:
(1) the Company or such Restricted Subsidiary, as the case
may be, receives consideration at the time of such Asset
Disposition at least equal to the Fair Market Value (such Fair
Market Value to be determined on the date of contractually
agreeing to such Asset Disposition) of the Capital Stock or
other assets subject to such Asset Disposition;
(2) at least 75% of the consideration received by the
Company or such Restricted Subsidiary, as the case may be, is in
the form of cash or Cash Equivalents or Additional Assets, or
any combination thereof; and
(3) except as provided in the next paragraph, an amount
equal to 100% of the Net Available Cash from such Asset
Disposition is applied, within 360 days from the later of
the date of such Asset Disposition or the receipt of such Net
Available Cash, by the Company or such Restricted Subsidiary, as
the case may be:
(a) to prepay, repay, redeem or purchase Indebtedness
(other than intercompany Indebtedness, Subordinated Obligations,
Capital Stock or Indebtedness owed to an Affiliate of the
Company); provided, however, that, in connection with any
prepayment, repayment, redemption or purchase of Indebtedness
pursuant to this clause (a), the Company or such Restricted
Subsidiary will cause the related commitment to be permanently
reduced in an amount equal to the principal amount so prepaid,
repaid, redeemed or purchased; or
(b) to invest in Additional Assets or to make capital
expenditures in the Oil and Gas Business;
provided that pending the final application of any such
Net Available Cash in accordance with clause (a) or clause
(b) above, the Company and its Restricted Subsidiaries may
temporarily reduce revolving credit Indebtedness or otherwise
invest such Net Available Cash in any manner not prohibited by
the Indenture.
Any Net Available Cash from Asset Dispositions that is not
applied or invested as provided in the preceding paragraph will
be deemed to constitute Excess Proceeds. Not later
than the 360th day from the later of the date of such Asset
Disposition or the receipt of such Net Available Cash, if the
aggregate amount of Excess Proceeds exceeds $20.0 million,
the Company will be required to make an offer (Asset
Disposition Offer) to all holders of Notes and, to the
extent required by the terms of other Pari Passu Indebtedness,
to all holders of other Pari Passu Indebtedness outstanding with
similar provisions requiring the Company to make an offer to
purchase such Pari Passu Indebtedness with the proceeds from any
Asset Disposition (Pari Passu Notes), to purchase
the maximum principal amount of Notes and any such Pari Passu
Notes to which the Asset Disposition Offer applies that may be
purchased out of the Excess Proceeds, at an offer price in cash
in an amount equal to 100% of the principal amount (or, in the
event such Pari Passu Indebtedness was issued with original
issue discount, 100% of the accreted value thereof) of the Notes
and Pari Passu Notes plus accrued and unpaid interest, if any
(or in respect of such Pari Passu Notes, such lesser price, if
any, as may be provided for by its terms), to the date of
purchase (subject to the right of holders of record on the
relevant record date to receive interest due on the relevant
interest payment date), in accordance with the procedures set
forth in the Indenture or the agreements governing the Pari
Passu Notes, as applicable, in each case in a minimum principal
amount of $2,000 and integral multiples of $1,000 in excess
thereof. If the aggregate
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principal amount of Notes surrendered by holders thereof and
other Pari Passu Notes surrendered by holders or lenders,
collectively, exceeds the amount of Excess Proceeds, the Trustee
shall select the Notes to be purchased on a pro rata basis (or,
in the case of Notes issued in global form as discussed under
the caption Book-Entry; Delivery and Form, the
Trustee will select the Notes for purchase based on DTCs
method that most nearly approximates a pro rata selection) on
the basis of the aggregate principal amount of tendered Notes
and Pari Passu Notes. To the extent that the aggregate amount of
Notes and Pari Passu Notes so validly tendered and not properly
withdrawn pursuant to an Asset Disposition Offer is less than
the Excess Proceeds, the Company and its Restricted Subsidiaries
may use any remaining Excess Proceeds for general corporate
purposes, subject to the other covenants contained in the
Indenture. Upon completion of such Asset Disposition Offer, the
amount of Excess Proceeds shall be reset at zero.
The Asset Disposition Offer will remain open for a period of 20
Business Days following its commencement, except to the extent
that a longer period is required by applicable law (the
Asset Disposition Offer Period). No later than two
Business Days after the termination of the Asset Disposition
Offer Period (the Asset Disposition Purchase Date),
the Company will purchase the principal amount of Notes and Pari
Passu Notes required to be purchased pursuant to this covenant
(the Asset Disposition Offer Amount) or, if less
than the Asset Disposition Offer Amount has been so validly
tendered and not properly withdrawn, all Notes and Pari Passu
Notes validly tendered and not properly withdrawn in response to
the Asset Disposition Offer.
If the Asset Disposition Purchase Date is on or after an
interest record date and on or before the related interest
payment date, any accrued and unpaid interest will be paid to
each Person in whose name a Note is registered at the close of
business on such record date, and no further interest will be
payable to holders who tender Notes pursuant to the Asset
Disposition Offer.
On or before the Asset Disposition Purchase Date, the Company
will, to the extent lawful, accept for payment, on a pro rata
basis to the extent necessary, the Asset Disposition Offer
Amount of Notes and Pari Passu Notes or portions of Notes and
Pari Passu Notes so validly tendered and not properly withdrawn
pursuant to the Asset Disposition Offer, or if less than the
Asset Disposition Offer Amount has been validly tendered and not
properly withdrawn, all Notes and Pari Passu Notes so validly
tendered and not properly withdrawn, in each case in a minimum
principal amount of $2,000 and integral multiples of $1,000 in
excess thereof. The Company will deliver to the Trustee an
Officers Certificate stating that such Notes or portions
thereof were accepted for payment by the Company in accordance
with the terms of this covenant and, in addition, the Company
will deliver all certificates required, if any, by the
agreements governing the Pari Passu Notes. On the Asset
Disposition Purchase Date, the Company or the paying agent, as
the case may be, will mail or deliver to each tendering holder
of Notes or holder or lender of Pari Passu Notes, as the case
may be, an amount equal to the purchase price of the Notes or
Pari Passu Notes so validly tendered and not properly withdrawn
by such holder or lender, as the case may be, and accepted by
the Company for purchase, and the Company will promptly issue a
new Note, and the Trustee, upon delivery of a written request
from the Company, will authenticate and mail or deliver such new
Note to such holder, in a principal amount equal to any
unpurchased portion of the Note surrendered; provided that each
such new Note will be in a minimum principal amount of $2,000 or
an integral multiple of $1,000 in excess thereof. In addition,
the Company will take any and all other actions required by the
agreements governing the Pari Passu Notes. Any Note not so
accepted will be promptly mailed or delivered by the Issuer to
the holder thereof. The Company will publicly announce the
results of the Asset Disposition Offer on the Asset Disposition
Purchase Date.
The Company will comply, to the extent applicable, with the
requirements of
Rule 14e-1
of the Exchange Act and any other securities laws or regulations
in connection with the repurchase of Notes pursuant to an Asset
Disposition Offer. To the extent that the provisions of any
securities laws or regulations conflict with provisions of this
covenant, the Company will comply with the applicable securities
laws and regulations and will not be deemed to have breached its
obligations under the Indenture by virtue of its compliance with
such securities laws or regulations.
115
For the purposes of clause (2) of the first paragraph of
this covenant, the following will be deemed to be cash:
(1) the assumption by the transferee of Indebtedness of the
Company or Indebtedness of a Restricted Subsidiary (other than
intercompany Indebtedness, Subordinated Obligations, Capital
Stock or Indebtedness owed to an Affiliate of the Company) and
the release of such Issuer or Restricted Subsidiary from all
liability on such Indebtedness in connection with such Asset
Disposition; and
(2) securities, notes or other obligations received by the
Company or any Restricted Subsidiary from the transferee that
are converted by the Company or such Restricted Subsidiary into
cash within 30 days after receipt thereof.
The Company will not, and will not permit any Restricted
Subsidiary to, engage in any Asset Swaps, unless in the event
such Asset Swap involves the transfer by the Company or any
Restricted Subsidiary of assets having an aggregate Fair Market
Value in excess of $20.0 million, the terms of such Asset
Swap have been approved by a majority of the members of the
Board of Directors of the Company.
Limitation
on Affiliate Transactions
The Company will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, enter into, make, amend
or conduct any transaction (including making a payment to, the
purchase, sale, lease or exchange of any property or the
rendering of any service), contract, agreement or understanding
with or for the benefit of any Affiliate of the Company (an
Affiliate Transaction) unless:
(1) the terms of such Affiliate Transaction are no less
favorable to the Company or such Restricted Subsidiary, as the
case may be, than those that could reasonably be expected to be
obtained in a comparable transaction at the time of such
transaction in arms-length dealings with a Person who is
not such an Affiliate;
(2) if such Affiliate Transaction involves an aggregate
consideration in excess of $20.0 million, the terms of such
transaction have been approved by a majority of the members of
the Board of Directors of the Company having no personal stake
in such transaction, if any (and such majority determines that
such Affiliate Transaction satisfies the criteria in clause
(1) above); and
(3) if such Affiliate Transaction involves an aggregate
consideration in excess of $50.0 million, the Board of
Directors of the Company has received a written opinion from an
independent investment banking, accounting, engineering or
appraisal firm of nationally recognized standing that such
Affiliate Transaction is fair, from a financial standpoint, to
the Company or such Restricted Subsidiary or, in the case of
non-financial transactions, is not less favorable to the Company
or such Restricted Subsidiary than those that could reasonably
be expected to be obtained in a comparable transaction at such
time on an arms-length basis from a Person that is not an
Affiliate.
The preceding paragraph will not apply to:
(1) any Restricted Payment permitted to be made pursuant to
the covenant described above under
Limitation on Restricted Payments;
(2) any issuance of Capital Stock (other than Disqualified
Stock), or other payments, awards or grants in cash, Capital
Stock (other than Disqualified Stock) or otherwise pursuant to,
or the funding of, any employment, consulting, service or
severance agreements or other compensation arrangements, options
to purchase Capital Stock (other than Disqualified Stock) of the
Company, restricted stock plans, long-term incentive plans,
stock appreciation rights plans, participation plans or similar
employee benefits plans or insurance and indemnification
arrangements provided to or for the benefit of directors,
officers and employees, in each case in the ordinary course of
business and approved by the Board of Directors of the Company;
116
(3) any merger or other transaction with an Affiliate
solely for the purpose of reincorporating or reorganizing the
Company or any of its Restricted Subsidiaries in another
jurisdiction or creating a holding company for the Company;
(4) advances to or reimbursements of employees for moving,
entertainment and travel expenses, drawing accounts and similar
expenditures in the ordinary course of business of the Company
or any of its Restricted Subsidiaries;
(5) any transaction between the Company and a Restricted
Subsidiary or between Restricted Subsidiaries, and guarantees
issued by the Company or a Restricted Subsidiary for the benefit
of the Company or a Restricted Subsidiary, as the case may be,
in accordance with Limitation on Indebtedness
and Preferred Stock;
(6) the issuance or sale of any Capital Stock (other than
Disqualified Stock) of the Company to, or the receipt by the
Company of any capital contribution from, the holders of its
Capital Stock;
(7) indemnities of officers, directors and employees of the
Company or any of its Restricted Subsidiaries permitted by
charter, bylaw or statutory provisions;
(8) the payment of reasonable compensation and fees to
officers or directors of the Company or any Restricted
Subsidiary;
(9) any transaction with a joint venture or similar entity
(other than an Unrestricted Subsidiary) which would constitute
an Affiliate Transaction solely because the Company or a
Restricted Subsidiary owns, directly or indirectly, an equity
interest in or otherwise controls such joint venture or similar
entity; and
(10) the performance of obligations of the Company or any
of its Restricted Subsidiaries under the terms of any agreement
to which the Company or any of its Restricted Subsidiaries is a
party as of or on the Issue Date that is disclosed in this
prospectus under Certain Relationships and Related Party
Transactions, as these agreements may be amended,
modified, supplemented, extended or renewed from time to time;
provided, however, that any future amendment, modification,
supplement, extension or renewal entered into after the Issue
Date will be permitted only to the extent that its terms are not
materially more disadvantageous, taken as a whole, to the
holders of the Notes than the terms of the agreements in effect
on the Issue Date.
Provision
of Financial Information
The Indenture provides that, whether or not the Company is
subject to the reporting requirements of Section 13 or
Section 15(d) of the Exchange Act, the Company will make
available to the Trustee and the holders of the Notes without
cost, by posting the same on its website for public
availability, the annual reports and the information, documents
and other reports that are specified in Sections 13 and
15(d) of the Exchange Act and applicable to a U.S. corporation
that would be due after the Issue Date, within the time periods
specified therein with respect to a non-accelerated filer;
provided, however, that in lieu of a Quarterly Report on
Form 10-Q
for the quarter ended September 30, 2010, the Company may
instead provide, no later than 15 days after the applicable
deadline under SEC rules for such report, unaudited quarterly
financial statements together with a Managements
Discussion and Analysis of Financial Condition and Results of
Operations, in each case consistent with those that would be
included in a Quarterly Report on
Form 10-Q
(the Initial Report), and no information required to
be reported in a Current Report on
Form 8-K
shall be required to be reported with respect to any event
occurring prior to the date of such Initial Report provided that
information required in any such Current Report on
Form 8-K
is included in such Initial Report. In addition, following the
consummation of the Exchange Offer contemplated by the
Registration Rights Agreement, the Company will file a copy of
each of the reports referred to in the preceding sentence with
the SEC for public availability within the time periods
specified in the rules and regulations applicable to such
reports (unless the SEC will not accept such a filing).
117
This covenant will not impose any duty on the Company under the
Sarbanes-Oxley Act of 2002 and the related SEC rules that would
not otherwise be applicable.
If the Company has designated any of its Subsidiaries as
Unrestricted Subsidiaries, then the financial information
required will include a reasonably detailed presentation, either
on the face of the financial statements or in the footnotes
thereto, and in any accompanying Managements Discussion
and Analysis of Financial Condition and Results of Operations,
of the financial condition and results of operations of the
Company and its Restricted Subsidiaries separate from the
financial condition and results of operations of the
Unrestricted Subsidiaries of the Company.
For so long as any Notes remain outstanding and constitute
restricted securities under Rule 144, the
Company will furnish to the holders of the Notes, and to
securities analysts and prospective investors, upon their
request, the information required to be delivered pursuant to
Rule 144A(d)(4) under the Securities Act.
Merger
and Consolidation
Neither the Company nor the Co-Issuer will consolidate with or
merge with or into or wind up into (whether or not it is the
surviving Person), or sell, convey, transfer, lease or otherwise
dispose of all or substantially all its assets in one or more
related transactions to, any Person, unless:
(1) the resulting, surviving or transferee Person (the
Successor Company) will be a corporation (in the
case of either the Company or the Co-Issuer), or a partnership,
trust or limited liability company (but only in the case of the
Company), organized and existing under the laws of the United
States of America, any State of the United States or the
District of Columbia and the Successor Company (if not the
Company or the Co-Issuer, as the case may be) will expressly
assume, by supplemental indenture, executed and delivered to the
Trustee, in form reasonably satisfactory to the Trustee, all the
obligations of the Company or the Co-Issuer, as the case may be,
under the Indenture, the Notes and the applicable Registration
Rights Agreement;
(2) immediately after giving effect to such transaction
(and treating any Indebtedness that becomes an obligation of the
Successor Company or any Subsidiary of the Successor Company as
a result of such transaction as having been Incurred by the
Successor Company or such Subsidiary at the time of such
transaction), no Default or Event of Default shall have occurred
and be continuing;
(3) immediately after giving effect to such transaction,
the Successor Company would be able to Incur at least an
additional $1.00 of Indebtedness pursuant to the first paragraph
of the covenant described under Limitation on
Indebtedness and Preferred Stock;
(4) if an Issuer is not the Successor Company in any of the
transactions referred to above that involve such Issuer, each
Subsidiary Guarantor (unless it is the other party to the
transactions, in which case clause (1) shall apply) shall
have by supplemental indenture confirmed that its Subsidiary
Guarantee shall apply to the Successor Companys
obligations in respect of the Indenture and the Notes and that
its Subsidiary Guarantee shall continue to be in effect; and
(5) the Company or the Co-Issuer, as the case may be, shall
have delivered to the Trustee an Officers Certificate and
an Opinion of Counsel, each stating that such transaction and
such supplemental indenture (if any) comply with the Indenture.
For purposes of this covenant, the sale, conveyance, transfer,
lease or other disposition of all or substantially all of the
assets of one or more Subsidiaries of the Company, which assets,
if held by the Company instead of such Subsidiaries, would
constitute all or substantially all of the assets of the Company
on a consolidated basis, shall be deemed to be the transfer of
all or substantially all of the assets of the Company.
The Successor Company will succeed to, and be substituted for,
and may exercise every right and power of, the Company or the
Co-Issuer, as the case may be, under the Indenture; and its
predecessor, except in the case of a lease of all or
substantially all its assets, will be released from all
obligations under the Indenture Documents.
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Although there is a limited body of case law interpreting the
phrase substantially all, there is no precise
established definition of the phrase under applicable law.
Accordingly, in certain circumstances there may be a degree of
uncertainty as to whether a particular transaction would involve
all or substantially all of the assets of a Person.
Notwithstanding the preceding clause (3), (x) any
Restricted Subsidiary (other than the Co-Issuer) may consolidate
with, merge into or transfer all or part of its assets to the
Company, and the Company may consolidate with, merge into or
transfer all or part of its assets to a Subsidiary Guarantor and
(y) the Company may merge with an Affiliate formed solely
for the purpose of reorganizing the Company in another
jurisdiction.
In addition, the Company will not permit any Subsidiary
Guarantor to consolidate with or merge with or into, and will
not permit the sale, conveyance, transfer, lease or other
disposition of all or substantially all of the assets of any
Subsidiary Guarantor to, any Person (other than the Company or
another Subsidiary Guarantor) unless:
(1) either (a)
(i) the resulting, surviving or transferee Person will be a
corporation, partnership, trust or limited liability company
organized and existing under the laws of the United States of
America, any State of the United States or the District of
Columbia and such Person (if not such Subsidiary Guarantor) will
expressly assume by supplemental indenture, executed and
delivered to the Trustee, in form reasonably satisfactory to the
Trustee, all the obligations of the Subsidiary Guarantor under
the Indenture, the Subsidiary Guarantee and the applicable
Registration Rights Agreement and
(ii) immediately after giving effect to such transaction
(and treating any Indebtedness that becomes an obligation of the
resulting, surviving or transferee Person or any Restricted
Subsidiary as a result of such transaction as having been
Incurred by such Person or such Restricted Subsidiary at the
time of such transaction), no Default shall have occurred and be
continuing; or
(b) the transaction results in the release of the
Subsidiary Guarantor from its obligations under its Subsidiary
Guarantee in compliance with the conditions described in the
penultimate paragraph of Subsidiary
Guarantees; and
(2) the Company shall have delivered to the Trustee an
Officers Certificate and an Opinion of Counsel, each
stating that such transaction and such supplemental indenture
(if any) comply with the Indenture.
Future
Subsidiary Guarantors
The Company will cause (a) each Domestic Subsidiary of the
Company formed or acquired after the Issue Date and (b) any
other Restricted Subsidiary (except the Co-Issuer) that is not
already a Subsidiary Guarantor that guarantees any Indebtedness
of the Company or a Subsidiary Guarantor, in each case to
execute and deliver to the Trustee within 30 days a
supplemental indenture (in the form specified in the Indenture)
pursuant to which such Subsidiary will unconditionally
guarantee, on a joint and several basis, the full and prompt
payment of the principal of, premium, if any, and interest on
the Notes on a senior basis; provided that (i) any
Restricted Subsidiary that constitutes an Immaterial Subsidiary
need not become a Subsidiary Guarantor until such time as it
ceases to be an Immaterial Subsidiary and (ii) Brayton
Resources, L.P., Brayton Resources II, L.P. and Orion Operating
Company, LP shall not be required to become Subsidiary
Guarantors for so long as they remain Immaterial Subsidiaries
and do not guarantee Indebtedness of the Company or any
Subsidiary Guarantor other than the Senior Secured Credit
Agreement.
Payments
for Consent
Neither the Company nor any of its Restricted Subsidiaries will,
directly or indirectly, pay or cause to be paid any
consideration, whether by way of interest, fees or otherwise, to
any holder of any Notes for or as an inducement to any consent,
waiver or amendment of any of the terms or provisions of the
Indenture or the
119
Notes unless such consideration is offered to be paid or is paid
to all holders of the Notes that consent, waive or agree to
amend in the time frame set forth in the solicitation documents
relating to such consent, waiver or amendment.
Business
Activities
The Company will not, and will not permit any of its Restricted
Subsidiaries to, engage in any business other than the Oil and
Gas Business, except to such extent as would not be material to
the Company and its Restricted Subsidiaries taken as a whole.
The Co-Issuer may not engage in any business not related
directly or indirectly to obtaining money or arranging financing
for the Company or its Restricted Subsidiaries. The Co-Issuer
may not have any Subsidiary, and no Person other than the
Company or any of its other Restricted Subsidiaries may own any
Capital Stock of the Co-Issuer.
Events of
Default
Each of the following is an Event of Default with respect to the
Notes:
(1) default in any payment of interest on any Note when
due, continued for 30 days;
(2) default in the payment of principal of or premium, if
any, on any Note when due at its Stated Maturity, upon optional
redemption, upon required repurchase, upon declaration of
acceleration or otherwise;
(3) failure by either Issuer or any Subsidiary Guarantor to
comply with its obligations under
Certain Covenants Merger and
Consolidation;
(4) failure by either Issuer or any Subsidiary Guarantor to
comply for 30 days after notice as provided below with any
of its obligations under the covenant described under
Change of Control above or under the
covenants described under Certain
Covenants above (in each case, other than a failure to
purchase Notes which will constitute an Event of Default under
clause (2) above and other than a failure to comply with
Certain Covenants Merger and
Consolidation which is covered by clause (3));
(5) failure by either Issuer or any Subsidiary Guarantor to
comply for 60 days after notice as provided below with its
other agreements contained in the Indenture;
(6) default under any mortgage, indenture or instrument
under which there may be issued or by which there may be secured
or evidenced any Indebtedness for money borrowed by the Company
or any of its Restricted Subsidiaries (or the payment of which
is guaranteed by the Company or any of its Restricted
Subsidiaries), other than Indebtedness owed to the Company or a
Restricted Subsidiary, whether such Indebtedness or guarantee
now exists, or is created after the date of the Indenture, which
default:
(a) is caused by a failure to pay principal of, or interest
or premium, if any, on such Indebtedness prior to the expiration
of the grace period provided in such Indebtedness (and any
extensions of any grace period) (payment default); or
(b) results in the acceleration of such Indebtedness prior
to its Stated Maturity (the cross acceleration
provision);
and, in each case, the principal amount of any such
Indebtedness, together with the principal amount of any other
such Indebtedness under which there has been a payment default
or the maturity of which has been so accelerated, aggregates
$20.0 million or more;
(7) certain events of bankruptcy, insolvency or
reorganization of the Company, the Co-Issuer or a Significant
Subsidiary or group of Restricted Subsidiaries that, taken
together (as of the latest audited consolidated financial
statements for the Company and its Restricted Subsidiaries),
would constitute a Significant Subsidiary (the bankruptcy
provisions);
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(8) failure by the Company, the Co-Issuer or any
Significant Subsidiary or group of Restricted Subsidiaries that,
taken together (as of the latest audited consolidated financial
statements for the Company and its Restricted Subsidiaries),
would constitute a Significant Subsidiary to pay final judgments
aggregating in excess of $20.0 million (to the extent not
covered by insurance by a reputable and creditworthy insurer as
to which the insurer has not disclaimed coverage), which
judgments are not paid or discharged, and there shall be any
period of 60 consecutive days following entry of such final
judgment or decree during which a stay of enforcement of such
final judgment or decree, by reason of pending appeal or
otherwise, shall not be in effect (the judgment default
provision); or
(9) any Subsidiary Guarantee of a Significant Subsidiary or
group of Restricted Subsidiaries that, taken together (as of the
latest audited consolidated financial statements for the Company
and its Restricted Subsidiaries) would constitute a Significant
Subsidiary, ceases to be in full force and effect (except as
contemplated by the terms of the Indenture) or is declared null
and void in a judicial proceeding or the Company or any
Subsidiary Guarantor that is a Significant Subsidiary or group
of Subsidiary Guarantors that, taken together (as of the latest
audited consolidated financial statements of the Company and its
Restricted Subsidiaries) would constitute a Significant
Subsidiary, denies or disaffirms its obligations under the
Indenture or its Subsidiary Guarantee.
However, a default under clauses (4) and (5) of this
paragraph will not constitute an Event of Default until the
Trustee or the holders of at least 25% in principal amount of
the outstanding Notes notify the Issuers in writing and, in the
case of a notice given by the holders, the Trustee of the
default and the Issuers do not cure such default within the time
specified in clauses (4) and (5) of this paragraph
after receipt of such notice.
If an Event of Default (other than an Event of Default described
in clause (7) above) occurs and is continuing, the Trustee
by notice to Issuers, or the holders of at least 25% in
principal amount of the outstanding Notes by notice to the
Issuers and the Trustee, may, and the Trustee at the request of
such holders shall, declare the principal of, premium, if any,
accrued and unpaid interest, if any, on all the Notes to be due
and payable. If an Event of Default described in clause
(7) above occurs and is continuing, the principal of, and
premium, if any, and accrued and unpaid interest, if any, on all
the Notes will become and be immediately due and payable without
any declaration or other act on the part of the Trustee or any
holders. The holders of a majority in principal amount of the
outstanding Notes may waive all past defaults (except with
respect to nonpayment of principal, premium or interest) and
rescind any such acceleration with respect to the Notes and its
consequences if (1) rescission would not conflict with any
judgment or decree of a court of competent jurisdiction and
(2) all existing Events of Default, other than the
nonpayment of the principal of, premium, if any, and interest on
the Notes that have become due solely by such declaration of
acceleration, have been cured or waived.
Notwithstanding the foregoing, if an Event of Default specified
in clause (6) above shall have occurred and be continuing,
such Event of Default and any consequential acceleration (to the
extent not in violation of any applicable law or in conflict
with any judgment or decree of a court of competent
jurisdiction) shall be automatically rescinded if (i) the
Indebtedness that is the subject of such Event of Default has
been repaid or (ii) if the default relating to such
Indebtedness is waived by the holders of such Indebtedness or
cured and if such Indebtedness has been accelerated, then the
holders thereof have rescinded their declaration of acceleration
in respect of such Indebtedness, in each case within
20 days after the declaration of acceleration with respect
thereto, and (iii) any other existing Events of Default,
except nonpayment of principal, premium or interest on the Notes
that became due solely because of the acceleration of the Notes,
have been cured or waived.
Subject to the provisions of the Indenture relating to the
duties of the Trustee if an Event of Default occurs and is
continuing, the Trustee will be under no obligation to exercise
any of the rights or powers under the Indenture at the request
or direction of any of the holders unless such holders have
offered to the Trustee indemnity or security satisfactory to the
Trustee against any loss, liability or expense. Except to
enforce the right to receive payment of principal, premium, if
any, or interest when due, no holder may pursue any remedy with
respect to the Indenture or the Notes unless:
(1) such holder has previously given the Trustee notice
that an Event of Default is continuing;
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(2) holders of at least 25% in principal amount of the
outstanding Notes have requested the Trustee to pursue the
remedy;
(3) such holders have offered the Trustee security or
indemnity satisfactory to the Trustee against any loss,
liability or expense;
(4) the Trustee has not complied with such request within
60 days after the receipt of the request and the offer of
security or indemnity; and
(5) the holders of a majority in principal amount of the
outstanding Notes have not waived such Event of Default or
otherwise given the Trustee a direction that, in the opinion of
the Trustee, is inconsistent with such request within such
60-day
period.
Subject to the provisions of the Indenture, the holders of a
majority in principal amount of the outstanding Notes will have
the right to direct the time, method and place of conducting any
proceeding for any remedy available to the Trustee or of
exercising any trust or power conferred on the Trustee. If an
Event of Default has occurred and is continuing, the Trustee
will be required in the exercise of its powers to use the degree
of care that a prudent person would use under the circumstances
in the conduct of his own affairs. The Trustee, however, may
refuse to follow any direction that conflicts with law or the
Indenture or that the Trustee determines is unduly prejudicial
to the rights of any other holder or that would involve the
Trustee in personal liability. Prior to taking any action under
the Indenture, the Trustee will be entitled to indemnification
satisfactory to it in its sole discretion against all losses and
expenses caused by taking or not taking such action.
If a Default occurs and is continuing and is known to the
Trustee, the Trustee must mail to each holder notice of the
Default within 90 days after it occurs. Except in the case
of a Default in the payment of principal of, premium, if any, or
interest on any Note, the Trustee may withhold such notice if
and so long as a committee of trust officers of the Trustee in
good faith determines that withholding notice is in the
interests of the holders. In addition, the Issuers are required
to deliver to the Trustee, within 120 days after the end of
each fiscal year, a certificate indicating whether the signers
thereof know of any Default that occurred during the previous
year. The Issuers also are required to deliver to the Trustee,
within 30 days after the occurrence thereof, written notice
of any Defaults, their status and what action the Issuers are
taking or proposing to take in respect thereof.
Amendments
and Waivers
The Indenture and the Notes may be amended with the consent of
the holders of a majority in principal amount of the Notes then
outstanding (including consents obtained in connection with a
purchase of, or tender offer or exchange offer for, Notes) and,
subject to certain exceptions, any past default or compliance
with any provisions of any Indenture Document may be waived with
the consent of the holders of a majority in principal amount of
the Notes then outstanding (including consents obtained in
connection with a purchase of, or tender offer or exchange offer
for, Notes). However, without the consent of each holder of an
outstanding Note affected thereby, no amendment or waiver may:
(1) reduce the principal amount of Notes whose holders must
consent to an amendment or waiver;
(2) reduce the stated rate of or extend the stated time for
payment of interest on any Note;
(3) reduce the principal of or extend the Stated Maturity
of any Note;
(4) reduce the premium payable upon the redemption of any
Note as described above under Optional
Redemption, change the time at which any Note may be
redeemed as described above under
Optional Redemption or make any
change relative to our obligation to make an offer to repurchase
the Notes as a result of a Change of Control as described above
under Change of Control after (but not
before) the occurrence of such Change of Control;
(5) make any Note payable in money other than U.S. dollars;
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(6) impair the right of any holder to receive payment of
the principal of, premium, if any, and interest on such
holders Notes on or after the due dates therefor or to
institute suit for the enforcement of any payment on or with
respect to such holders Notes;
(7) make any change in the amendment provisions which
require each holders consent or in the waiver provisions;
(8) release any Subsidiary Guarantor from any of its
obligations under its Subsidiary Guarantee otherwise than in
accordance with the applicable provisions of the Indenture; or
(9) subordinate the Notes or any Subsidiary Guarantee in
right of payment to any other Indebtedness of either Issuer or
any Subsidiary Guarantor.
Notwithstanding the preceding, without the consent of any
holder, the Issuers, the Subsidiary Guarantors and the Trustee
may amend the Indenture and the Notes to:
(1) cure any ambiguity, omission, defect, mistake or
inconsistency;
(2) provide for the assumption by a successor of the
obligations of the Company, the Co-Issuer or any Subsidiary
Guarantor under the Indenture;
(3) provide for uncertificated Notes in addition to or in
place of certificated Notes (provided that the uncertificated
Notes are issued in registered form for purposes of
Section 163(f) of the Code, or in a manner such that the
uncertificated Notes are described in Section 163(f)(2)(B)
of the Code);
(4) add Subsidiary Guarantors (or any other guarantors)
with respect to the Notes or release a Subsidiary Guarantor from
its Subsidiary Guarantee and terminate such Subsidiary
Guarantee; provided that the release and termination is in
accordance with the applicable provisions of the Indenture;
(5) secure the Notes or Guarantees;
(6) add to the covenants of the Company, the Co-Issuer or a
Subsidiary Guarantor for the benefit of the holders or surrender
any right or power conferred upon the Company, the Co-Issuer or
a Subsidiary Guarantor;
(7) make any change that does not adversely affect the
legal rights of any holder; provided, however, that any change
to conform the Indenture to this Description of New
Notes will not be deemed to adversely affect such legal
rights;
(8) comply with any requirement of the SEC in connection
with the qualification of the Indenture under the
Trust Indenture Act; or
(9) provide for the succession of a successor Trustee,
provided that the successor Trustee is otherwise qualified and
eligible to act as such under the Indenture.
The consent of the holders is not necessary under the Indenture
to approve the particular form of any proposed amendment. It is
sufficient if such consent approves the substance of the
proposed amendment. After an amendment under the Indenture
requiring the consent of the holders becomes effective, the
Company will mail to the holders a notice briefly describing
such amendment. However, the failure to give such notice to all
the holders, or any defect in the notice will not impair or
affect the validity of the amendment.
Defeasance
The Issuers at any time may terminate all their obligations
under the Notes and the Indenture (legal
defeasance), except for certain obligations specified in
the Indenture, including those respecting the defeasance trust
and obligations to register the transfer or exchange of the
Notes, to replace mutilated, destroyed, lost or stolen Notes and
to maintain a registrar and paying agent in respect of the Notes.
The Issuers at any time may terminate their obligations
described under Change of Control and
under the covenants described under Certain
Covenants (other than clauses (1), (2), (4) and
(5) of Merger and
Consolidation), the operation of the cross default upon a
payment default, cross acceleration provisions, the
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bankruptcy provisions with respect to Significant Subsidiaries,
the judgment default provision, the Subsidiary Guarantee
provision described under Events of
Default above and the limitations contained in clause
(3) under Merger and Consolidation
above (covenant defeasance).
If the Issuers exercise their legal defeasance or covenant
defeasance option, the Subsidiary Guarantees in effect at such
time will terminate.
The Issuers may exercise their legal defeasance option
notwithstanding their prior exercise of their covenant
defeasance option. If the Issuers exercise their legal
defeasance option, payment of the Notes may not be accelerated
because of an Event of Default with respect to the Notes. If the
Issuers exercise their covenant defeasance option, payment of
the Notes may not be accelerated because of an Event of Default
specified in clause (4), (5), (6), (7) (with respect only to
Significant Subsidiaries), (8) or (9) under
Events of Default above or because of
the failure of the Company or the Co-Issuer to comply with
clause (3) under Merger and
Consolidation above.
In order to exercise either defeasance option, an Issuer or a
Subsidiary Guarantor must, among other things, irrevocably
deposit in trust (the defeasance trust) with the
Trustee money or U.S. Government Obligations for the payment of
principal, premium, if any, and interest on the Notes to
redemption or Stated Maturity, as the case may be, and must
comply with certain other conditions, including delivery to the
Trustee of an Opinion of Counsel (subject to customary
exceptions and exclusions) to the effect that holders of the
Notes will not recognize income, gain or loss for federal income
tax purposes as a result of such deposit and defeasance and will
be subject to federal income tax on the same amount and in the
same manner and at the same times as would have been the case if
such deposit and defeasance had not occurred. In the case of
legal defeasance only, such Opinion of Counsel must be based on
a ruling of the Internal Revenue Service or other change in
applicable federal income tax law.
Satisfaction
and Discharge
The Indenture will be discharged and will cease to be of further
effect as to all Notes issued thereunder (except as to surviving
rights of registration of transfer or exchange of the Notes and
as otherwise expressly provided for in the Indenture), and all
Subsidiary Guarantees will be released, when either:
(1) all Notes that have been authenticated (except lost,
stolen or destroyed Notes that have been replaced or paid and
Notes for whose payment money has theretofore been deposited in
trust or segregated and held in trust by an Issuer and
thereafter repaid to such Issuer or discharged from such trust)
have been delivered to the Trustee for cancellation, or
(2) all Notes that have not been delivered to the Trustee
for cancellation have become due and payable or will become due
and payable within one year by reason of the giving of a notice
of redemption or otherwise and an Issuer or any Subsidiary
Guarantor has irrevocably deposited or caused to be irrevocably
deposited with the Trustee as trust funds in trust solely for
such purpose, cash in U.S. dollars in such amount as will be
sufficient without consideration of any reinvestment of
interest, to pay and discharge the entire indebtedness on the
Notes not delivered to the Trustee for cancellation for
principal and accrued interest to the date of Stated Maturity or
redemption, and in each case certain other procedural
requirements set forth in the Indenture are satisfied.
No
Personal Liability of Directors, Officers, Employees and
Stockholders
No director, officer, employee, incorporator, stockholder,
member, partner or trustee of the Company, the Co-Issuer or any
Subsidiary Guarantor, as such, shall have any liability for any
obligations of the Company, the Co-Issuer or any Subsidiary
Guarantor under the Notes, the Indenture or the Subsidiary
Guarantees or for any claim based on, in respect of, or by
reason of, such obligations or their creation. Each holder by
accepting a Note waives and releases all such liability. The
waiver and release are part of the consideration for issuance of
the Notes.
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The
Trustee
Wells Fargo Bank, N.A. will be the Trustee under the Indenture
and has been appointed by the Issuers as registrar and paying
agent with regard to the Notes.
The Indenture will contain certain limitations on the rights of
the Trustee, should it become a creditor of an Issuer or any
Subsidiary Guarantor, to obtain payment of claims in certain
cases, or to realize on certain property received in respect of
any such claim as security or otherwise. The Trustee will be
permitted to engage in other transactions; provided, however,
that if it acquires any conflicting interest (as defined in the
Trust Indenture Act) while any Default exists it must
eliminate such conflict within 90 days, apply to the SEC
for permission to continue as Trustee with such conflict or
resign as Trustee.
Governing
Law
The Indenture provides that it and the Notes will be governed
by, and construed in accordance with, the laws of the State of
New York.
Book-Entry;
Delivery and Form
Global
Notes
The new Notes, like the old Notes, will be issued in the form of
one or more fully registered notes in global form, without
interest coupons. Each Global Note will be deposited with the
Trustee, as custodian for The Depository Trust Company
(DTC), and registered in the name of a nominee of
DTC.
Ownership of beneficial interests in each global note will be
limited to persons who have accounts with DTC (DTC
participants) or persons who hold interests through DTC
participants. We expect that under procedures established by DTC:
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upon deposit of each global note with DTCs custodian, DTC
will credit portions of the principal amount of the global notes
to the accounts of the DTC participants designated by the
exchange agent; and
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ownership of beneficial interests in each global note will be
shown on, and transfer of ownership of those interests will be
effected only through, records maintained by DTC (with respect
to interests of DTC participants) and the records of DTC
participants (with respect to other owners of beneficial
interests in the global notes).
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Beneficial interests in the global notes may not be exchanged
for notes in physical, certificated form except in the limited
circumstances described below.
Book-Entry
Procedures for the Global Notes
All interests in the global notes will be subject to the
operations and procedures of DTC, including its participants,
Euroclear Bank S.A./N.V., as operator of the Euroclear System
(Euroclear), and Clearstream Banking S.A.
(Clearstream). We provide the following summaries of
those operations and procedures solely for the convenience of
investors. The operations and procedures of each settlement
system are controlled by that settlement system and may be
changed at any time.
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Neither we nor the Trustee is responsible for those operations
or procedures.
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DTC has advised us that it is:
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a limited purpose trust company organized under the laws of the
State of New York;
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a banking organization within the meaning of the New
York State Banking Law;
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a member of the Federal Reserve System;
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a clearing corporation within the meaning of the
Uniform Commercial Code; and
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a clearing agency registered under Section 17A
of the Exchange Act.
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DTC was created to hold securities for its participants and to
facilitate the clearance and settlement of securities
transactions between its participants through electronic
book-entry changes to the accounts of its participants.
DTCs participants include securities brokers and dealers,
including the initial purchasers, banks and trust companies,
clearing corporations, and other organizations. Indirect access
to DTCs system is also available to others such as banks,
brokers, dealers, and trust companies. These indirect
participants clear through or maintain a custodial relationship
with a DTC participant, either directly or indirectly. Investors
who are not DTC participants may beneficially own securities
held by or on behalf of DTC only through DTC participants or
indirect participants in DTC.
So long as DTCs nominee is the registered owner of a
global note, that nominee will be considered the sole owner or
holder of the notes represented by that global note for all
purposes under the indenture. Except as provided below, owners
of beneficial interests in a global note:
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will not be entitled to have notes represented by the global
note registered in their names;
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will not receive or be entitled to receive physical,
certificated notes; and
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will not be considered the owners or holders of the notes under
the indenture for any purpose, including with respect to the
giving of any direction, instruction, or approval to the Trustee.
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As a result, each investor who owns a beneficial interest in a
global note must rely on the procedures of DTC to exercise any
rights of a holder of notes under the Indenture (and, if the
investor is not a participant or an indirect participant in DTC,
on the procedures of the DTC participant through which the
investor owns its interest).
Payments of principal, premium (if any), and interest with
respect to the new notes represented by a global note will be
made by the Trustee to DTCs nominee, as the registered
holder of the global note. Neither we nor the Trustee will have
any responsibility or liability for the payment of amounts to
owners of beneficial interests in a global note, for any aspect
of the records relating to or payments made on account of those
interests by DTC, or for maintaining, supervising, or reviewing
any records of DTC relating to those interests.
Payments by participants and indirect participants in DTC to the
owners of beneficial interests in a global note will be governed
by standing instructions and customary industry practice and
will be the responsibility of those participants or indirect
participants and DTC.
Transfers between participants in DTC will be effected under
DTCs procedures and will be settled in
same-day
funds. Transfers between participants in Euroclear or
Clearstream will be effected in the ordinary way under the rules
and operating procedures of those systems.
Cross market transfers between DTC participants, on the one
hand, and Euroclear or Clearstream participants, on the other
hand, will be effected within DTC through the DTC participants
that are acting as depositaries for Euroclear and Clearstream.
To deliver or receive an interest in a global note held in a
Euroclear or Clearstream account, an investor must send transfer
instructions to Euroclear or Clearstream, as the case may be,
under the rules and procedures of that system and within the
established deadlines of that system. If the transaction meets
its settlement requirements, Euroclear or Clearstream, as the
case may be, will send instructions to its DTC depositary to
take action to effect final settlement by delivering or
receiving interests in the relevant global notes in DTC, and
making or receiving payment under normal procedures for
same-day
funds settlement applicable to DTC. Euroclear and Clearstream
participants may not deliver instructions directly to the DTC
depositaries that are acting for Euroclear or Clearstream.
Because of time zone differences, the securities account of a
Euroclear or Clearstream participant that purchases an interest
in a global note from a DTC participant will be credited on the
business day for Euroclear or Clearstream immediately following
the DTC settlement date. Cash received in Euroclear or
Clearstream from the sale of an interest in a global note to a
DTC participant will be received with value on the DTC
settlement date but will be available in the relevant Euroclear
or Clearstream cash account as of the business day for Euroclear
or Clearstream following the DTC settlement date.
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DTC, Euroclear, and Clearstream have agreed to the above
procedures to facilitate transfers of interests in the global
notes among participants in those settlement systems. However,
the settlement systems are not obligated to perform these
procedures and may discontinue or change these procedures at any
time. Neither we nor the Trustee will have any responsibility
for the performance by DTC, Euroclear, or Clearstream, or their
participants or indirect participants, of their obligations
under the rules and procedures governing their operations.
Certificated
Notes
New Notes in physical, certificated form will be issued and
delivered to each person that DTC identifies as a beneficial
owner of the related notes only if:
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DTC notifies us at any time that it is unwilling or unable to
continue as depositary for the global notes and a successor
depositary is not appointed within 90 days;
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DTC ceases to be registered as a clearing agency under the
Exchange Act and a successor depositary is not appointed within
90 days; or
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we, at our option, notify the Trustee that we elect to cause the
issuance of certificated Notes.
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Certain
Definitions
Set forth below are certain defined terms used in the Indenture.
References to Statements of Financial Accounting Standards of
the Financial Accounting Standards Board do not reflect the new
nomenclature resulting from the FASBs codification of such
Statements in its ASC 105, Generally Accepted Accounting
Principles, issued in June 2009, but are deemed to include the
codified Statements under their current nomenclature.
Acquired Indebtedness means Indebtedness
(i) of a Person or any of its Subsidiaries existing at the
time such Person becomes or is merged with and into a Restricted
Subsidiary or (ii) assumed in connection with the
acquisition of assets from such Person, in each case whether or
not Incurred by such Person in connection with, or in
anticipation or contemplation of, such Person becoming a
Restricted Subsidiary or such acquisition. Acquired Indebtedness
shall be deemed to have been Incurred, with respect to clause
(i) of the preceding sentence, on the date such Person
becomes or is merged with and into a Restricted Subsidiary and,
with respect to clause (ii) of the preceding sentence, on
the date of consummation of such acquisition of assets.
Additional Assets means:
(1) any properties or assets (other than current assets) to
be used by the Company or a Restricted Subsidiary in the Oil and
Gas Business; or
(2) the Capital Stock of a Person that is or becomes a
Restricted Subsidiary as a result of the acquisition of such
Capital Stock by the Company or a Restricted Subsidiary;
provided, however, that such Restricted Subsidiary is primarily
engaged in the Oil and Gas Business.
Adjusted Consolidated Net Tangible Assets of
the Company means (without duplication), as of the date of
determination, the remainder of:
(a) the sum of:
(i) discounted future net revenues from proved oil and gas
reserves of the Company and its Restricted Subsidiaries
calculated in accordance with SEC guidelines before any state or
federal income taxes, as estimated by the Company in a reserve
report prepared as of the end of the Companys most
recently completed fiscal year for which audited financial
statements are available, which reserve report is prepared,
reviewed or audited by independent petroleum engineers, as
increased by, as of the date of determination, the estimated
discounted future net revenues from
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(A) estimated proved oil and gas reserves acquired since
such year end, which reserves were not reflected in such year
end reserve report, and
(B) estimated oil and gas reserves attributable to
extensions, discoveries and other additions and upward revisions
of estimates of proved oil and gas reserves since such year end
due to exploration, development or exploitation, production or
other activities, which would, in accordance with standard
industry practice, cause such revisions (including the impact to
proved reserves and future net revenues from estimated
development costs incurred and the accretion of discount since
such year end),
and decreased by, as of the date of determination, the estimated
discounted future net revenues from
(C) estimated proved oil and gas reserves produced or
disposed of since such year end, and
(D) estimated oil and gas reserves attributable to downward
revisions of estimates of proved oil and gas reserves since such
year end due to changes in geological conditions or other
factors which would, in accordance with standard industry
practice, cause such revisions, in each case calculated on a
pre-tax basis and substantially in accordance with SEC
guidelines,
in the case of clauses (A) through (D) utilizing
prices and costs calculated in accordance with SEC guidelines as
if the end of the most recent fiscal quarter preceding the date
of determination for which such information is available to the
Company were year end; provided, however, that in the case of
each of the determinations made pursuant to clauses
(A) through (D), such increases and decreases shall be as
estimated by the Companys petroleum engineers;
(ii) the capitalized costs that are attributable to Oil and
Gas Properties of the Company and its Restricted Subsidiaries to
which no proved oil and gas reserves are attributable, based on
the Companys books and records as of a date no earlier
than the date of the Companys latest available annual or
quarterly financial statements;
(iii) the Net Working Capital of the Company and its
Restricted Subsidiaries on a date no earlier than the date of
the Companys latest annual or quarterly financial
statements; and
(iv) the greater of
(A) the net book value of other tangible assets of the
Company and its Restricted Subsidiaries, as of a date no earlier
than the date of the Companys latest annual or quarterly
financial statements, and
(B) the appraised value, as estimated by independent
appraisers, of other tangible assets of the Company and its
Restricted Subsidiaries, as of a date no earlier than the date
of the Companys latest audited financial statements;
provided, that, if no such appraisal has been performed the
Company shall not be required to obtain such an appraisal and
only clause (iv)(A) of this definition shall apply;
minus
(b) the sum of:
(i) Minority Interests;
(ii) any net gas balancing liabilities of the Company and
its Restricted Subsidiaries reflected in the Companys
latest annual or quarterly balance sheet (to the extent not
deducted in calculating Net Working Capital of the Company in
accordance with clause (a)(iii) above of this definition);
(iii) to the extent included in (a)(i) above, the
discounted future net revenues, calculated in accordance with
SEC guidelines (but utilizing prices and costs calculated in
accordance with SEC guidelines as if the end of the most recent
fiscal quarter preceding the date of determination for
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which such information is available to the Company were year
end), attributable to reserves which are required to be
delivered to third parties to fully satisfy the obligations of
the Company and its Restricted Subsidiaries with respect to
Volumetric Production Payments (determined, if applicable, using
the schedules specified with respect thereto); and
(iv) the discounted future net revenues, calculated in
accordance with SEC guidelines, attributable to reserves subject
to Dollar-Denominated Production Payments which, based on the
estimates of production and price assumptions included in
determining the discounted future net revenues specified in
(a)(i) above, would be necessary to fully satisfy the payment
obligations of the Company and its Subsidiaries with respect to
Dollar-Denominated Production Payments (determined, if
applicable, using the schedules specified with respect thereto).
If the Company changes its method of accounting from the
successful efforts method of accounting to the full cost or a
similar method, Adjusted Consolidated Net Tangible
Assets will continue to be calculated as if the Company
were still using the successful efforts method of accounting.
Affiliate of any specified Person means any
other Person, directly or indirectly, controlling or controlled
by or under direct or indirect common control with such
specified Person. For the purposes of this definition,
control when used with respect to any Person means
the power to direct the management and policies of such Person,
directly or indirectly, whether through the ownership of voting
securities, by contract or otherwise; and the terms
controlling and controlled have meanings
correlative to the foregoing.
Asset Disposition means any direct or
indirect sale, lease (including by means of Production Payments
and Reserve Sales and a Sale/Leaseback Transaction but excluding
an operating lease entered into in the ordinary course of the
Oil and Gas Business), transfer, issuance or other disposition,
or a series of related sales, leases, transfers, issuances or
dispositions that are part of a common plan, of (A) any
Capital Stock of a Restricted Subsidiary (other than
directors qualifying shares or shares required by
applicable law to be held by a Person other than the Company or
a Restricted Subsidiary) or (B) any other assets of the
Company or any Restricted Subsidiary outside of the ordinary
course of business of the Company or such Restricted Subsidiary
(each referred to for the purposes of this definition as a
disposition), in each case by the Company or any of
its Restricted Subsidiaries, including any disposition by means
of a merger, consolidation or similar transaction.
Notwithstanding the preceding, the following items shall not be
deemed to be Asset Dispositions:
(1) a disposition by a Restricted Subsidiary to the Company
or by the Company or a Restricted Subsidiary to a Restricted
Subsidiary;
(2) a disposition of cash, Cash Equivalents or other
financial assets in the ordinary course of business;
(3) a disposition of Hydrocarbons in the ordinary course of
business;
(4) a disposition of damaged, unserviceable, obsolete or
worn out equipment or equipment that is no longer necessary for
the proper conduct of the business of the Company and its
Restricted Subsidiaries and that is disposed of in each case in
the ordinary course of business;
(5) transactions in accordance with the covenant described
under Certain Covenants Merger and
Consolidation;
(6) an issuance of Capital Stock by a Restricted Subsidiary
to the Company or to a Restricted Subsidiary;
(7) the making of a Permitted Investment or a Restricted
Payment (or a disposition that would constitute a Restricted
Payment but for the exclusions from the definition thereof)
permitted by the covenant described under
Certain Covenants Limitation on
Restricted Payments;
(8) an Asset Swap;
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(9) dispositions of assets with a Fair Market Value of less
than $10.0 million in any single transaction or series of
related transactions;
(10) Permitted Liens;
(11) dispositions of receivables in connection with the
compromise, settlement or collection thereof in the ordinary
course of business or in bankruptcy or similar proceedings and
exclusive of factoring or similar arrangements;
(12) the licensing or sublicensing of intellectual property
(including the licensing of seismic data or rights to access and
use seismic data libraries);
(13) any Production Payments and Reserve Sales pursuant to
incentive compensation programs on terms that are reasonably
customary in the Oil and Gas Business for geologists,
geophysicists and other providers of technical or management
services to the Company or a Restricted Subsidiary;
(14) surrender or waiver of contract rights, oil and gas
leases, or the settlement, release or surrender of contract,
tort or other claims of any kind; and
(15) the abandonment, assignment, farmout, lease, sublease,
forfeiture or other disposition of developed or undeveloped Oil
and Gas Properties in the ordinary course of business.
Asset Swap means any substantially
contemporaneous (and in any event occurring within 180 days
of each other) purchase and sale or exchange of any Oil and Gas
Assets between the Company or any of its Restricted
Subsidiaries and another Person; provided, that any cash
received must be applied in accordance with
Certain Covenants Limitation on
Sales of Assets and Subsidiary Stock as if the Asset Swap
were an Asset Disposition.
Attributable Debt in respect of a sale and
leaseback transaction means, at the time of determination, the
present value of the obligation of the lessee for net rental
payments during the remaining term of the lease included in such
sale and leaseback transaction including any period for which
such lease has been extended or may, at the option of the
lessor, be extended. Such present value shall be calculated
using a discount rate equal to the rate of interest implicit in
such transaction, determined in accordance with GAAP; provided,
however, that if such sale and leaseback transaction results in
a Capitalized Lease Obligation, the amount of Indebtedness
represented thereby will be determined in accordance with the
definition of Capitalized Lease Obligation.
Average Life means, as of the date of
determination, with respect to any Indebtedness or Preferred
Stock, the quotient obtained by dividing (1) the sum of the
products of the numbers of years from the date of determination
to the dates of each successive scheduled principal payment of
such Indebtedness or redemption or similar payment with respect
to such Preferred Stock multiplied by the amount of such payment
by (2) the sum of all such payments.
Beneficial Owner has the meaning assigned to
such term in
Rule 13d-3
and
Rule 13d-5
under the Exchange Act, except that in calculating the
beneficial ownership of any particular person (as
that term is used in Section 13(d)(3) of the Exchange Act),
such person will be deemed to have beneficial
ownership of all securities that such person has the
right to acquire by conversion or exercise of other securities,
whether such right is currently exercisable or is exercisable
only after the passage of time. The terms Beneficially
Owns and Beneficially Owned have a
corresponding meaning.
Board of Directors means, as to any Person
that is a corporation, the board of directors of such Person or
any duly authorized committee thereof or as to any Person that
is not a corporation, the board of managers or such other
individual or group serving a similar function. For so long as
the Company is a limited partnership, the board of directors of
the General Partner shall be deemed to be the Board of Directors
of the Company.
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Business Day means each day that is not a
Saturday, Sunday or other day on which commercial banking
institutions in New York, New York are authorized or required by
law to close.
Capital Stock of any Person means any and all
shares, units, interests, rights to purchase, warrants, options,
participations or other equivalents of or interests in (however
designated) the equity of such Person, including any Preferred
Stock, but excluding any debt securities convertible into, or
exchangeable for, such equity.
Capitalized Lease Obligation means an
obligation that is required to be classified and accounted for
as a capitalized lease for financial reporting purposes in
accordance with GAAP, and the amount of Indebtedness represented
by such obligation will be the capitalized amount of such
obligation at the time any determination thereof is to be made
as determined in accordance with GAAP, and the Stated Maturity
thereof will be the date of the last payment of rent or any
other amount due under such lease prior to the first date such
lease may be terminated without penalty.
Cash Equivalents means:
(1) securities issued or directly and fully guaranteed or
insured by the United States Government or any agency or
instrumentality of the United States (provided that the full
faith and credit of the United States is pledged in support
thereof), having maturities of not more than one year from the
date of acquisition;
(2) marketable general obligations issued by any state of
the United States of America or any political subdivision of any
such state or any public instrumentality thereof maturing within
one year from the date of acquisition and, at the time of
acquisition, having one of the two highest ratings obtainable
from either S&P or Moodys;
(3) certificates of deposit, time deposits, eurodollar time
deposits, overnight bank deposits or bankers acceptances
having maturities of not more than one year from the date of
acquisition thereof issued by any commercial bank the short-term
deposit of which is rated at the time of acquisition thereof at
least
A-2
or the equivalent thereof by S&P, or
P-2
or the equivalent thereof by Moodys, and having combined
capital and surplus in excess of $500.0 million;
(4) repurchase obligations with a term of not more than
seven days for underlying securities of the types described in
clauses (1), (2) and (3) entered into with any bank
meeting the qualifications specified in clause (3) above;
(5) commercial paper rated at the time of acquisition
thereof at least
A-2
by S&P or
P-2
by Moodys, and in either case maturing within nine months
after the date of acquisition thereof; and
(6) interests in any investment company or money market
fund which invests 95% or more of its assets in instruments of
the type specified in clauses (1) through (5) above.
Change of Control means:
(1) any person or group of related
persons (as such terms are used in Sections 13(d) and 14(d)
of the Exchange Act), other than a Permitted Holder, is or
becomes the Beneficial Owner, directly or indirectly, of more
than 50% of the total voting power of the Voting Stock of the
General Partner (or, following the conversion of the Company
into another form as described below, more than 50% of the total
voting power of the Voting Stock of the successor entity to the
Company);
(2) the first day on which a majority of the members of the
Board of Directors of the Company are not Continuing Directors;
(3) the sale, lease, transfer, conveyance or other
disposition (other than by way of merger or consolidation), in
one or a series of related transactions, of all or substantially
all of the assets of the Company and its Restricted Subsidiaries
taken as a whole to any person (as such term is used
in Sections 13(d) and 14(d) of the Exchange Act), other
than to the Company, a Restricted Subsidiary or a Permitted
Holder; or
131
(4) the adoption by the members of the General Partner or
the partners of the Company (or, following the conversion of the
Company into another form as described below, its equity
holders) of a plan or proposal for the liquidation or
dissolution of the Company.
Notwithstanding the preceding, a conversion (whether by merger,
statutory conversion or otherwise) of the Company from a limited
partnership to a limited liability company or corporation, or an
exchange of all of the outstanding partnership interests in the
Company for Capital Stock in a corporation or a limited
liability company, shall not constitute a Change of Control, so
long as following such conversion or exchange the
persons (as that term is used in
Section 13(d)(3) of the Exchange Act) who Beneficially
Owned the Capital Stock of the General Partner and the Company
immediately prior to such transactions continue to Beneficially
Own in the aggregate sufficient Capital Stock of such successor
entity to elect a majority of its directors, managers, trustees
or other persons serving in a similar capacity for such
successor entity.
Code means the Internal Revenue Code of 1986,
as amended.
Commodity Agreements means, in respect of any
Person, any forward contract, commodity swap agreement,
commodity option agreement or other similar agreement or
arrangement in respect of Hydrocarbons used, produced, processed
or sold by such Person that is customary in the Oil and Gas
Business and designed to protect such Person against fluctuation
in Hydrocarbon prices.
Common Stock means, with respect to any
Person, any and all Capital Stock (however designated and
whether voting or nonvoting) of such Person other than any
Preferred Stock, whether or not outstanding on the Issue Date,
and includes all series and classes of such Capital Stock.
Consolidated Coverage Ratio means, for any
Person, as of any date of determination, the ratio of
(x) the aggregate amount of Consolidated EBITDAX of such
Person for the period of the most recent four consecutive fiscal
quarters ending prior to the date of such determination for
which financial statements are in existence to
(y) Consolidated Interest Expense for such four fiscal
quarters, provided, however, that:
(1) if the Company or any Restricted Subsidiary:
(a) has Incurred any Indebtedness since the beginning of
such period that remains outstanding on such date of
determination or if the transaction giving rise to the need to
calculate the Consolidated Coverage Ratio is an Incurrence of
Indebtedness, Consolidated EBITDAX and Consolidated Interest
Expense for such period will be calculated after giving effect
on a pro forma basis to the Incurrence of such Indebtedness and
the use of proceeds thereof as if such Indebtedness had been
Incurred on the first day of such period and such proceeds had
been applied as of such date (except that in making such
computation, the amount of any revolving credit Indebtedness
outstanding on the date of such calculation will be deemed to be
(i) the average daily balance of such Indebtedness during
such four fiscal quarters or such shorter period during which
such Indebtedness was outstanding or (ii) if such revolving
credit Indebtedness was Incurred after the end of such four
fiscal quarters, the average daily balance of such Indebtedness
during the period from the date of Incurrence of such revolving
credit Indebtedness to the date of such calculation, in each
case, provided that such average daily balance shall take into
account any permanent repayment of such revolving credit
Indebtedness as provided in clause (b)); or
(b) has repaid, repurchased, defeased or otherwise
discharged any Indebtedness since the beginning of the period,
including with the proceeds of such new Indebtedness, that is no
longer outstanding on such date of determination or if the
transaction giving rise to the need to calculate the
Consolidated Coverage Ratio involves a discharge of Indebtedness
(in each case other than any revolving credit Indebtedness,
unless such revolving credit Indebtedness has been permanently
repaid and the related commitment terminated), Consolidated
EBITDAX and Consolidated Interest Expense for such period will
be calculated after giving effect on a pro forma basis to such
discharge of such Indebtedness as if such discharge had occurred
on the first day of such period;
(2) if, since the beginning of such period, the Company or
any Restricted Subsidiary has made any Asset Disposition or if
the transaction giving rise to the need to calculate the
Consolidated Coverage
132
Ratio is such an Asset Disposition, the Consolidated EBITDAX for
such period will be reduced by an amount equal to the
Consolidated EBITDAX (if positive) directly attributable to the
assets which are the subject of such Asset Disposition for such
period or increased by an amount equal to the Consolidated
EBITDAX (if negative) directly attributable thereto for such
period and Consolidated Interest Expense for such period shall
be reduced by an amount equal to the Consolidated Interest
Expense directly attributable to any Indebtedness of the Company
or any Restricted Subsidiary repaid, repurchased, defeased or
otherwise discharged with respect to the Company and its
continuing Restricted Subsidiaries in connection with or with
the proceeds from such Asset Disposition for such period (or, if
the Capital Stock of any Restricted Subsidiary is sold, the
Consolidated Interest Expense for such period directly
attributable to the Indebtedness of such Restricted Subsidiary
to the extent the Company and its continuing Restricted
Subsidiaries are no longer liable for such Indebtedness after
such sale);
(3) if, since the beginning of such period, the Company or
any Restricted Subsidiary (by merger or otherwise) has made an
Investment in any Restricted Subsidiary (or any Person which
becomes a Restricted Subsidiary or is merged with or into the
Company or a Restricted Subsidiary) or an acquisition (or has
received a contribution) of assets, including any acquisition or
contribution of assets occurring in connection with a
transaction causing a calculation to be made under the
Indenture, which constitutes all or substantially all of a
Company division, operating unit, segment, business, group of
related assets or line of business, Consolidated EBITDAX and
Consolidated Interest Expense for such period will be calculated
after giving pro forma effect thereto (including the Incurrence
of any Indebtedness) as if such Investment or acquisition or
contribution had occurred on the first day of such period; and
(4) if, since the beginning of such period, any Person
(that subsequently became a Restricted Subsidiary or was merged
with or into the Company or any Restricted Subsidiary since the
beginning of such period) made any Asset Disposition or any
Investment or acquisition of assets that would have required an
adjustment pursuant to clause (2) or (3) above if made
by the Company or a Restricted Subsidiary during such period,
Consolidated EBITDAX and Consolidated Interest Expense for such
period will be calculated after giving pro forma effect thereto
as if such Asset Disposition or Investment or acquisition of
assets had occurred on the first day of such period.
For purposes of this definition, whenever pro forma effect is to
be given to any calculation under this definition, the pro forma
calculations will be determined on behalf of the Company in good
faith by a responsible financial or accounting officer of the
Company; provided that such officer may in his or her discretion
include any reasonably identifiable and factually supportable
pro forma changes to Consolidated EBITDAX, including any pro
forma expenses and cost reductions, that have occurred or in the
judgment of such officer are reasonably expected to occur within
12 months of the date of the applicable transaction
(regardless of whether such expense or cost reduction or any
other operating improvements could then be reflected properly in
pro forma financial statements prepared in accordance with
Regulation S-X
under the Securities Act or any other regulation or policy of
the SEC). If any Indebtedness bears a floating rate of interest
and is being given pro forma effect, the interest expense on
such Indebtedness will be calculated as if the average rate in
effect from the beginning of such period to the date of
determination had been the applicable rate for the entire period
(taking into account any Interest Rate Agreement applicable to
such Indebtedness, but if the remaining term of such Interest
Rate Agreement is less than 12 months, then such Interest
Rate Agreement shall only be taken into account for that portion
of the period equal to the remaining term thereof). If any
Indebtedness that is being given pro forma effect bears an
interest rate at the option of the Company or any Restricted
Subsidiary, the interest rate shall be calculated by applying
such optional rate chosen by the Company or such Restricted
Subsidiary. Interest on Indebtedness that may optionally be
determined at an interest rate based upon a factor of a prime or
similar rate, a eurocurrency interbank offered rate, or other
rate, shall be deemed to have been based upon the rate actually
chosen, or, if none, then based upon such optional rate chosen
as the Company or the applicable Restricted Subsidiary may
designate.
133
Consolidated EBITDAX for any period means,
without duplication, the Consolidated Net Income for such
period, plus the following, without duplication and to the
extent deducted (and not added back) in calculating such
Consolidated Net Income:
(1) Consolidated Interest Expense;
(2) Consolidated Income Tax Expense;
(3) consolidated depletion and depreciation expense of the
Company and its Restricted Subsidiaries;
(4) consolidated amortization expense or impairment charges
of the Company and its Restricted Subsidiaries recorded in
connection with the application of Statement of Financial
Accounting Standard No. 142, Goodwill and Other
Intangibles and Statement of Financial Accounting Standard
No. 144, Accounting for the Impairment or Disposal of
Long Lived Assets;
(5) other non-cash charges of the Company and its
Restricted Subsidiaries (excluding any such non-cash charge to
the extent it represents an accrual of or reserve for cash
charges in any future period or amortization of a prepaid cash
expense that was paid in a prior period not included in the
calculation); and
(6) the consolidated exploration and abandonment expense of
the Company and its Restricted Subsidiaries,
if applicable for such period; and less, to the extent included
in calculating such Consolidated Net Income and in excess of any
costs or expenses attributable thereto that were deducted (and
not added back) in calculating such Consolidated Net Income, the
sum of (x) the amount of deferred revenues that is
amortized during such period and is attributable to reserves
that are subject to Volumetric Production Payments,
(y) amounts recorded in accordance with GAAP as repayments
of principal and interest pursuant to Dollar-Denominated
Production Payments and (z) other non-cash gains (excluding
any non-cash gain to the extent it represents the reversal of an
accrual or reserve for a potential cash item that reduced
Consolidated EBITDAX in any prior period).
Notwithstanding the preceding sentence, clauses (2) through
(6) relating to amounts of a Restricted Subsidiary will be
added to Consolidated Net Income to compute Consolidated EBITDAX
of the Company only to the extent (and in the same proportion)
that the net income (loss) of such Restricted Subsidiary was
included in calculating the Consolidated Net Income of the
Company and, to the extent the amounts set forth in clauses
(2) through (6) are in excess of those necessary to
offset a net loss of such Restricted Subsidiary or if such
Restricted Subsidiary has net income for such period included in
Consolidated Net Income, only if a corresponding amount would be
permitted at the date of determination to be dividended to the
Company by such Restricted Subsidiary without prior approval
(that has not been obtained), pursuant to the terms of its
charter and all agreements, instruments, judgments, decrees,
orders, statutes, rules and governmental regulations applicable
to that Restricted Subsidiary or the holders of its Capital
Stock.
Consolidated Income Tax Expense means, with
respect to any period, the provision for federal, state, local
and foreign taxes (including state franchise taxes) based on
income of the Company and its Restricted Subsidiaries for such
period as determined in accordance with GAAP, or (for any period
in which the Company is a partnership) the Tax Amount for such
period.
Consolidated Interest Expense means, for any
period, the total consolidated interest expense (excluding
interest income) of the Company and its Restricted Subsidiaries,
whether paid or accrued, plus, to the extent not included in
such interest expense and without duplication:
(1) interest expense attributable to Capitalized Lease
Obligations or Attributable Debt and the interest component of
any deferred payment obligations;
(2) amortization of debt discount and debt issuance cost
(provided that any amortization of bond premium will be credited
to reduce Consolidated Interest Expense unless, pursuant to
GAAP, such amortization of bond premium has otherwise reduced
Consolidated Interest Expense);
(3) non-cash interest expense;
134
(4) commissions, discounts and other fees and charges owed
with respect to letters of credit and bankers acceptance
financing;
(5) the interest expense on Indebtedness of another Person
that is guaranteed by the Company or one of its Restricted
Subsidiaries or secured by a Lien on assets of the Company or
one of its Restricted Subsidiaries;
(6) cash costs associated with Interest Rate Agreements
(including amortization of fees); provided, however, that if
Interest Rate Agreements result in net cash benefits rather than
costs, such benefits shall be credited to reduce Consolidated
Interest Expense unless, pursuant to GAAP, such net benefits are
otherwise reflected in Consolidated Net Income;
(7) the consolidated interest expense of the Company and
its Restricted Subsidiaries that was capitalized during such
period; and
(8) all dividends paid or payable in cash, Cash Equivalents
or Indebtedness, or accrued during such period, in each case on
any series of Disqualified Stock of the Company or on Preferred
Stock of its Restricted Subsidiaries payable to a party other
than the Company or a Wholly Owned Subsidiary.
For the purpose of calculating the Consolidated Coverage Ratio
in connection with the Incurrence of any Indebtedness described
in the final paragraph of the definition of
Indebtedness, the calculation of Consolidated
Interest Expense shall include all interest expense (including
any amounts described in clauses (1) through
(8) above) relating to any Indebtedness of the Company or
any Restricted Subsidiary described in the final paragraph of
the definition of Indebtedness.
Consolidated Net Income means, for any
period, the aggregate net income (loss) of the Company and its
Subsidiaries determined in accordance with GAAP and before any
reduction in respect of Preferred Stock dividends of such
Person, less (for any period the Company is a partnership) the
Tax Amount for such period; provided, however, that there will
not be included (to the extent otherwise included therein) in
such Consolidated Net Income:
(1) any net income (loss) of any Person (other than the
Company) if such Person is not a Restricted Subsidiary, except
that:
(a) subject to the limitations contained in clauses
(3) and (4) below, the Companys equity in the
net income of any such Person for such period will be included
in such Consolidated Net Income up to the aggregate amount of
cash actually distributed by such Person during such period to
the Company or a Restricted Subsidiary as a dividend or other
distribution (subject, in the case of a dividend or other
distribution to a Restricted Subsidiary, to the limitations
contained in clause (2) below); and
(b) the Companys equity in a net loss of any such
Person for such period will be included in determining such
Consolidated Net Income to the extent such loss has been funded
with cash from the Company or a Restricted Subsidiary during
such period;
(2) any net income (but not loss) of any Restricted
Subsidiary if such Subsidiary is subject to restrictions,
directly or indirectly, on the payment of dividends or the
making of distributions by such Restricted Subsidiary, directly
or indirectly, to the Company, except that:
(a) subject to the limitations contained in clauses
(3) and (4) below, the Companys equity in the
net income of any such Restricted Subsidiary for such period
will be included in such Consolidated Net Income up to the
aggregate amount of cash that could have been distributed by
such Restricted Subsidiary during such period to the Company or
another Restricted Subsidiary as a dividend or other
distribution (subject, in the case of a dividend or other
distribution paid to another Restricted Subsidiary, to the
limitation contained in this clause); and
(b) the Companys equity in a net loss of any such
Restricted Subsidiary for such period will be included in
determining such Consolidated Net Income;
135
(3) any gain (loss) realized upon the sale or other
disposition of any property, plant or equipment of the Company
or its Subsidiaries (including pursuant to any Sale/Leaseback
Transaction) which is not sold or otherwise disposed of in the
ordinary course of business and any gain (loss) realized upon
the sale or other disposition of any Capital Stock of any Person;
(4) any extraordinary or nonrecurring gains or losses,
together with any related provision for taxes (and, without
duplication, any related Permitted Tax Distributions) on such
gains or losses and all related fees and expenses;
(5) the cumulative effect of a change in accounting
principles;
(6) any asset impairment writedowns on Oil and Gas
Properties under GAAP or SEC guidelines;
(7) any unrealized non-cash gains or losses or charges in
respect of Hedging Obligations (including those resulting from
the application of Statement of Financial Accounting Standard
No. 133);
(8) income or loss attributable to discontinued operations
(including operations disposed of during such period whether or
not such operations were classified as discontinued);
(9) all deferred financing costs written off, and premiums
paid, in connection with any early extinguishment of
Indebtedness; and
(10) any non-cash compensation charge arising from any
grant of stock, stock options or other equity based awards;
provided that the proceeds resulting from any such grant will be
excluded from clause (4)(c)(ii) of the first paragraph of the
covenant described under Certain
Covenants Limitation on Restricted Payments.
Continuing Directors means, as of any date of
determination, any member of the Board of Directors of the
Company who: (1) was a member of such Board of Directors on
the date of the Indenture; or (2) was nominated for
election or elected to such Board of Directors with the approval
of a majority of the Continuing Directors who were members of
such Board of Directors at the time of such nomination or
election.
Credit Facility means, with respect to the
Company or any Subsidiary Guarantor, one or more debt facilities
(including, without limitation, the Senior Secured Credit
Agreement), or commercial paper facilities providing for
revolving credit loans, term loans, receivables financing
(including through the sale of receivables to lenders or to
special purpose entities formed to borrow from such lenders
against such receivables) or letters of credit from banks or
other institutional lenders, in each case, as amended, restated,
modified, renewed, refunded, replaced or refinanced in whole or
in part from time to time (and whether or not with the original
administrative agent and lenders or another administrative agent
or agents or other lenders and whether provided under the
original Senior Secured Credit Agreement or any other credit or
other agreement or indenture).
Currency Agreement means in respect of a
Person any foreign exchange contract, currency swap agreement,
futures contract, option contract or other similar agreement as
to which such Person is a party or a beneficiary.
Default means any event which is, or after
notice or passage of time or both would be, an Event of Default.
Disqualified Stock means, with respect to any
Person, any Capital Stock of such Person which by its terms (or
by the terms of any security into which it is convertible or for
which it is exchangeable) at the option of the holder of the
Capital Stock or upon the happening of any event:
(1) matures or is mandatorily redeemable (other than
redeemable only for Capital Stock of such Person which is not
itself Disqualified Stock) pursuant to a sinking fund obligation
or otherwise;
(2) is convertible or exchangeable for Disqualified Stock
or other Indebtedness (excluding Capital Stock which is
convertible or exchangeable solely at the option of the Company
or a Restricted Subsidiary); or
136
(3) is required to be repurchased by such Person at the
option of the holder of the Capital Stock in whole or in part,
in each case on or prior to the date that is 91 days after
the earlier of the date (a) of the Stated Maturity of the
Notes or (b) on which there are no Notes outstanding;
provided that only the portion of Capital Stock which so matures
or is mandatorily redeemable, is so convertible or exchangeable
or is so required to be repurchased at the option of the holder
thereof prior to such date will be deemed to be Disqualified
Stock; provided further, that any Capital Stock that would
constitute Disqualified Stock solely because the holders thereof
have the right to require the Company or any of its Restricted
Subsidiaries to repurchase such Capital Stock upon the
occurrence of a change of control or asset sale (each defined in
a substantially identical manner to the corresponding
definitions in the Indenture) shall not constitute Disqualified
Stock if the terms of such Capital Stock (and all such
securities into which it is convertible or for which it is
exchangeable) provide that (i) the Company and its
Restricted Subsidiaries may not repurchase or redeem any such
Capital Stock (and all such securities into which it is
convertible or for which it is ratable or exchangeable) pursuant
to such provision prior to compliance by the Company and its
Restricted Subsidiaries with the provisions of the Indenture
described under the captions Change of
Control and Certain
Covenants Limitation on Sales of Assets and
Subsidiary Stock and (ii) such repurchase or
redemption will be permitted solely to the extent also permitted
in accordance with the provisions of the Indenture described
under the caption Certain Covenants
Limitation on Restricted Payments.
Dollar-Denominated Production Payments means
production payment obligations recorded as liabilities in
accordance with GAAP, together with all undertakings and
obligations in connection therewith.
Domestic Subsidiary means any Restricted
Subsidiary that is not a Foreign Subsidiary.
Equity Offering means a public or private
offering for cash by the Company of its Capital Stock (other
than Disqualified Stock).
Exchange Act means the Securities Exchange
Act of 1934, as amended, and the rules and regulations of the
SEC promulgated thereunder.
Exchange Notes means Notes issued in exchange
for old Notes or Additional Notes pursuant to a Registration
Rights Agreement.
Fair Market Value means, with respect to any
asset or property, the sale value that would be obtained in an
arms-length free market transaction between an informed
and willing seller under no compulsion to sell and an informed
and willing buyer under no compulsion to buy. Fair Market Value
of an asset or property in excess of $20.0 million shall be
determined by the Board of Directors of the Company acting in
good faith, whose determination shall be conclusive and
evidenced by a resolution of such Board of Directors, and any
lesser Fair Market Value may be determined by an officer of the
Company acting in good faith.
Foreign Subsidiary means any Restricted
Subsidiary that is not organized under the laws of the United
States of America or any state thereof or the District of
Columbia and that conducts substantially all of its operations
outside the United States of America.
GAAP means generally accepted accounting
principles in the United States of America as in effect on the
Issue Date. All ratios and computations based on GAAP contained
in the Indenture will be computed in conformity with GAAP.
General Partner means Alta Mesa Holdings GP,
LLC, a Texas limited liability company, and its successors as
general partner of the Company.
The term guarantee means any obligation,
contingent or otherwise, of any Person directly or indirectly
guaranteeing any Indebtedness of any other Person and any
obligation, direct or indirect, contingent or otherwise, of such
Person:
(1) to purchase or pay (or advance or supply funds for the
purchase or payment of) such Indebtedness of such other Person
(whether arising by virtue of partnership arrangements, or by
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agreement to keep-well, to purchase assets, goods, securities or
services, to
take-or-pay,
or to maintain financial statement conditions or otherwise); or
(2) entered into for purposes of assuring in any other
manner the obligee of such Indebtedness of the payment thereof
or to protect such obligee against loss in respect thereof (in
whole or in part);
provided, however, that the term guarantee will not
include endorsements for collection or deposit in the ordinary
course of business or any obligation to the extent it is payable
only in Capital Stock of the guarantor that is not Disqualified
Stock. The term guarantee used as a verb has a
corresponding meaning.
Guarantor Subordinated Obligation means, with
respect to a Subsidiary Guarantor, any Indebtedness of such
Subsidiary Guarantor (whether outstanding on the Issue Date or
thereafter Incurred) which is expressly subordinated in right of
payment to the obligations of such Subsidiary Guarantor under
its Subsidiary Guarantee pursuant to a written agreement.
Hedging Obligations of any Person means the
obligations of such Person pursuant to any Interest Rate
Agreement, Currency Agreement or Commodity Agreement.
The term holder means a Person in whose name
a Note is registered on the registrars books.
Hydrocarbons means oil, natural gas, casing
head gas, drip gasoline, natural gasoline, condensate,
distillate, liquid hydrocarbons, gaseous hydrocarbons and all
constituents, elements or compounds thereof and products refined
or processed therefrom.
Immaterial Subsidiary means, as of any date,
any Restricted Subsidiary with no Indebtedness in excess of
$500,000 (excluding guarantees of Indebtedness under the Senior
Secured Credit Agreement by Brayton Resources, L.P., Brayton
Resources II, L.P. and Orion Operating Company, LP), and whose
total assets, as of the end of the most recent month for which
financial statements are available, taken together with those of
all other Immaterial Subsidiaries, are less than 1.0% of the
Companys Adjusted Consolidated Net Tangible Assets and
whose total revenues, taken together with those of all other
Immaterial Subsidiaries, for the most recent
12-month
period for which financial statements are available do not
exceed 1.0% of the Companys total consolidated revenues
for such period.
Incur means issue, create, assume, guarantee,
incur or otherwise become directly or indirectly liable for,
contingently or otherwise; provided, however, that any
Indebtedness or Capital Stock of a Person existing at the time
such Person becomes a Restricted Subsidiary (whether by merger,
consolidation, acquisition or otherwise) will be deemed to be
Incurred by such Restricted Subsidiary at the time it becomes a
Restricted Subsidiary; and the terms Incurred and
Incurrence have meanings correlative to the
foregoing.
Indebtedness means, with respect to any
Person on any date of determination (without duplication,
whether or not contingent):
(1) the principal of and premium (if any) in respect of
indebtedness of such Person for borrowed money;
(2) the principal of and premium (if any) in respect of
obligations of such Person evidenced by bonds, debentures, notes
or other similar instruments;
(3) the principal component of all obligations of such
Person in respect of letters of credit, bankers
acceptances or other similar instruments (including
reimbursement obligations with respect thereto except to the
extent such reimbursement obligation relates to a trade payable
and except to the extent such letters of credit are not drawn
upon or, if and to the extent drawn upon, such obligation is
satisfied within five Business Days of payment on the letter of
credit);
(4) the principal component of all obligations of such
Person to pay the deferred and unpaid purchase price of
property, which purchase price is due more than six months after
the date of placing such property in service or taking delivery
and title thereto to the extent such obligations would appear as
liabilities upon the consolidated balance sheet of such Person
in accordance with GAAP, as obligor on conditional sales of
property or under any title retention agreement;
138
(5) Capitalized Lease Obligations or Attributable Debt of
such Person;
(6) the principal component or liquidation preference of
all obligations of such Person with respect to the redemption,
repayment or other repurchase of any Disqualified Stock or, with
respect to any Subsidiary of such Person, any Preferred Stock
(but excluding, in each case, any accrued dividends);
(7) the principal component of all Indebtedness of other
Persons secured by a Lien on any asset of such Person, whether
or not such Indebtedness is assumed by such Person; provided,
however, that the amount of such Indebtedness will be the lesser
of (a) the Fair Market Value of such asset at such date of
determination and (b) the amount of such Indebtedness of
such other Persons;
(8) the principal component of Indebtedness of other
Persons to the extent guaranteed by such Person; and
(9) to the extent not otherwise included in this
definition, net obligations of such Person under Commodity
Agreements, Currency Agreements and Interest Rate Agreements
(the amount of any such obligations to be equal at any time to
the termination value of such agreement or arrangement giving
rise to such obligation that would be payable by such Person at
such time);
provided, however, that any indebtedness which has been
defeased in accordance with GAAP or defeased pursuant to the
deposit of cash or Cash Equivalents (in an amount sufficient to
satisfy all such indebtedness obligations at maturity or
redemption, as applicable, and all payments of interest and
premium, if any) in a trust or account created or pledged for
the sole benefit of the holders of such indebtedness, and
subject to no other Liens, shall not constitute
Indebtedness.
The amount of Indebtedness of any Person at any date will be the
outstanding balance at such date of all unconditional
obligations as described above and the maximum liability, upon
the occurrence of the contingency giving rise to the obligation,
of any contingent obligations at such date.
Notwithstanding the preceding, Indebtedness shall
not include:
(1) Production Payments and Reserve Sales;
(2) any obligation of a Person in respect of a farm-in
agreement or similar arrangement whereby such Person agrees to
pay all or a share of the drilling, completion or other expenses
of an exploratory or development well (which agreement may be
subject to a maximum payment obligation, after which expenses
are shared in accordance with the working or participation
interest therein or in accordance with the agreement of the
parties) or perform the drilling, completion or other operation
on such well in exchange for an ownership interest in an Oil and
Gas Property;
(3) any obligations under Currency Agreements, Commodity
Agreements and Interest Rate Agreements; provided that such
Agreements are entered into for bona fide hedging purposes of
the Company or its Restricted Subsidiaries (as determined in
good faith by the Board of Directors or senior management of the
Company, whether or not accounted for as a hedge in accordance
with GAAP) and, in the case of Currency Agreements or Commodity
Agreements, such Currency Agreements or Commodity Agreements are
related to business transactions of the Company or its
Restricted Subsidiaries entered into in the ordinary course of
business and, in the case of Interest Rate Agreements, such
Interest Rate Agreements substantially correspond in terms of
notional amount, duration and interest rates, as applicable, to
Indebtedness of the Company or its Restricted Subsidiaries
Incurred without violation of the Indenture;
(4) any obligation arising from customary agreements of the
Company or a Restricted Subsidiary providing for
indemnification, guarantees, adjustment of purchase price,
holdbacks, contingency payment obligations or similar
obligations, in each case, Incurred or assumed in connection
with the acquisition or disposition of any business, assets or
Capital Stock of a Restricted Subsidiary, provided that such
Indebtedness is not reflected on the face of the balance sheet
of the Company or any Restricted Subsidiary;
(5) any obligation arising from the honoring by a bank or
other financial institution of a check, draft or similar
instrument (including daylight overdrafts) drawn against
insufficient funds in the ordinary
139
course of business, provided that such Indebtedness is
extinguished within five Business Days of Incurrence;
(6) in-kind obligations relating to net oil or natural gas
balancing positions arising in the ordinary course of business;
and
(7) accrued expenses and trade payables and other accrued
liabilities arising in the ordinary course of business that are
not overdue by 90 days or more or are being contested in
good faith by appropriate proceedings promptly instituted and
diligently conducted.
In addition, Indebtedness of any Person shall
include Indebtedness described in the first paragraph of this
definition of Indebtedness whether or not it would
appear as a liability on the balance sheet of such Person if:
(1) such Indebtedness is the obligation of a joint venture
or partnership that is not a Restricted Subsidiary (a
Joint Venture);
(2) such Person or a Restricted Subsidiary of such Person
is a general partner of the Joint Venture or otherwise liable
for all or a portion of the Joint Ventures liabilities (a
general partner); and
(3) there is recourse, by contract or operation of law,
with respect to the payment of such Indebtedness to property or
assets of such Person or a Restricted Subsidiary of such Person;
and then such Indebtedness shall be included in an amount not to
exceed:
(a) the lesser of (i) the net assets of the general
partner and (ii) the amount of such obligations to the
extent that there is recourse, by contract or operation of law,
to the property or assets of such Person or a Restricted
Subsidiary of such Person; or
(b) if less than the amount determined pursuant to clause
(a) immediately above, the actual amount of such
Indebtedness that is with recourse to such Person or a
Restricted Subsidiary of such Person, if the Indebtedness is
evidenced by a writing and is for a determinable amount.
Interest Rate Agreement means with respect to
any Person any interest rate protection agreement, interest rate
future agreement, interest rate option agreement, interest rate
swap agreement, interest rate cap agreement, interest rate
collar agreement, interest rate hedge agreement or other similar
agreement or arrangement as to which such Person is party or a
beneficiary.
Investment means, with respect to any Person,
all investments by such Person in other Persons (including
Affiliates) in the form of any direct or indirect advance, loan
or other extensions of credit (including by way of guarantee or
similar arrangement, but excluding any debt or extension of
credit represented by a bank deposit other than a time deposit
and advances or extensions of credit to customers in the
ordinary course of business) or capital contribution to (by
means of any transfer of cash or other property to others or any
payment for property or services for the account or use of
others), or any purchase or acquisition of Capital Stock,
Indebtedness or other similar instruments (excluding any
interest in an oil or natural gas leasehold to the extent
constituting a security under applicable law) issued by, such
other Person and all other items that are or would be classified
as investments on a balance sheet prepared in accordance with
GAAP; provided that none of the following will be deemed to be
an Investment:
(1) Hedging Obligations entered into in the ordinary course
of business and in compliance with the Indenture; and
(2) endorsements of negotiable instruments and documents in
the ordinary course of business.
The amount of any Investment shall not be adjusted for increases
or decreases in value,
write-ups,
write-downs or write-offs with respect to such Investment.
For purposes of the definition of Unrestricted
Subsidiary and the covenant described under
Certain Covenants Limitation on
Restricted Payments,
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(1) Investment will include the portion
(proportionate to the Companys equity interest in a
Restricted Subsidiary to be designated as an Unrestricted
Subsidiary) of the Fair Market Value of the net assets of such
Restricted Subsidiary at the time that such Restricted
Subsidiary is designated an Unrestricted Subsidiary; provided,
however, that upon a redesignation of such Subsidiary as a
Restricted Subsidiary, the Company will be deemed to continue to
have a permanent Investment in an Unrestricted
Subsidiary in an amount (if positive) equal to
(a) the Companys Investment in such
Subsidiary at the time of such redesignation less (b) the
portion (proportionate to the Companys equity interest in
such Subsidiary) of the Fair Market Value of the net assets of
such Subsidiary at the time that such Subsidiary is so
redesignated a Restricted Subsidiary; and
(2) any property transferred to or from an Unrestricted
Subsidiary will be valued at its Fair Market Value at the time
of such transfer.
Issue Date means the first date on which the
Notes are issued under the Indenture, October 13, 2010.
Lien means, with respect to any asset, any
mortgage, lien (statutory or otherwise), pledge, hypothecation,
charge, security interest, preference, priority or encumbrance
of any kind in respect of such asset, whether or not filed,
recorded or otherwise perfected under applicable law, including
any conditional sale or other title retention agreement, any
lease in the nature thereof, any option or other agreement to
sell or give a security interest in and any filing of or
agreement to give any financing statement under the Uniform
Commercial Code (or equivalent statutes) of any jurisdiction
other than a precautionary financing statement not intended as a
security agreement.
Minority Interest means the percentage
interest represented by any class of Capital Stock of a
Restricted Subsidiary that are not owned by the Company or a
Restricted Subsidiary.
Moodys means Moodys Investors
Service, Inc., or any successor to the rating agency business
thereof.
Net Available Cash from an Asset Disposition
means cash payments received (including any cash payments
received by way of deferred payment of principal pursuant to a
note or installment receivable or otherwise and net proceeds
from the sale or other disposition of any securities received as
consideration, but only as and when received, but excluding any
other consideration received in the form of assumption by the
acquiring Person of Indebtedness or other obligations relating
to the assets that are the subject of such Asset Disposition or
received in any other non-cash form) therefrom, in each case net
of:
(1) all legal, accounting, investment banking, title and
recording tax expenses, commissions and other fees and expenses
Incurred, and all federal, state, provincial, foreign and local
taxes (or Permitted Tax Distributions in respect thereof)
required to be paid or accrued as a liability under GAAP (after
taking into account any available tax credits or deductions and
any tax sharing agreements), as a consequence of such Asset
Disposition;
(2) all payments made on any Hedging Obligation or other
Indebtedness which is secured by any assets subject to such
Asset Disposition, in accordance with the terms of any Lien upon
such assets, or which must by its terms, or in order to obtain a
necessary consent to such Asset Disposition, or by applicable
law be repaid out of the proceeds from such Asset Disposition;
(3) all distributions and other payments required to be
made to minority interest holders in Subsidiaries or joint
ventures or to holders of royalty or similar interests as a
result of such Asset Disposition;
(4) the deduction of appropriate amounts to be provided by
the seller as a reserve, in accordance with GAAP, against any
liabilities associated with the assets disposed of in such Asset
Disposition and retained by the Company or any Restricted
Subsidiary after such Asset Disposition; and
(5) all relocation expenses incurred as a result thereof
and all related severance and associated costs, expenses and
charges of personnel related to assets and related operations
disposed of;
141
provided, however, that if any consideration for an Asset
Disposition (that would otherwise constitute Net Available Cash)
is required to be held in escrow pending determination of
whether or not a purchase price adjustment will be made, such
consideration (or any portion thereof) shall become Net
Available Cash only at such time as it is released to the
Company or any of its Restricted Subsidiaries from escrow.
Net Cash Proceeds, with respect to any
issuance or sale of Capital Stock or any contribution to equity
capital, means the cash proceeds of such issuance, sale or
contribution net of attorneys fees, accountants
fees, underwriters or placement agents fees, listing
fees, discounts or commissions and brokerage, consultant and
other fees and charges actually Incurred in connection with such
issuance, sale or contribution and net of taxes paid or payable
as a result of such issuance or sale (after taking into account
any available tax credit or deductions and any tax sharing
arrangements).
Net Working Capital means (a) the sum of
all current assets of the Company and its Restricted
Subsidiaries, except current assets from commodity price risk
management activities arising in the ordinary course of the Oil
and Gas Business, (other than accounts receivable with respect
to any non-contingent periodic settlement payments due
thereunder), less (b) all current liabilities of the
Company and its Restricted Subsidiaries, except current
liabilities (i) associated with asset retirement
obligations relating to Oil and Gas Properties,
(ii) included in Indebtedness and (iii) any current
liabilities of the Company and its Restricted Subsidiaries from
commodity price risk management activities arising in the
ordinary course of the Oil and Gas Business, (other than
accounts payable with respect to any non-contingent periodic
settlement payments due thereunder), in each case as set forth
in the consolidated financial statements of the Company prepared
in accordance with GAAP.
Non-Recourse Debt means Indebtedness of a
Person:
(1) as to which neither the Company nor any Restricted
Subsidiary (a) provides any guarantee or credit support of
any kind (including any undertaking, guarantee, indemnity,
agreement or instrument that would constitute Indebtedness),
(b) is directly or indirectly liable (as a guarantor or
otherwise) or (c) constitutes the lender;
(2) no default with respect to which (including any rights
that the holders thereof may have to take enforcement action
against an Unrestricted Subsidiary) would permit (upon notice,
lapse of time or both) any holder of any other Indebtedness of
the Company or any Restricted Subsidiary to declare a default
under such other Indebtedness or cause the payment thereof to be
accelerated or payable prior to its Stated Maturity; and
(3) the explicit terms of which provide there is no
recourse against any of the assets of the Company or its
Restricted Subsidiaries.
Officer means the Chairman of the Board, the
Chief Executive Officer, the President, the Chief Financial
Officer, Chief Accounting Officer, any Vice President, the
Treasurer or the Secretary of an Issuer. Officer of any
Subsidiary Guarantor has a correlative meaning, and in the case
of the Company (so long as it is a limited partnership), Officer
means an Officer of its General Partner.
Officers Certificate means a
certificate signed by two Officers of the Company, at least one
of whom shall be the Chief Executive Officer, the Chief
Financial Officer or the Chief Accounting Officer of the Company.
Oil and Gas Business means the business of
exploiting, exploring for, developing, acquiring, operating,
producing, processing, gathering, marketing, storing, selling,
hedging, treating, swapping and transporting (but not refining)
Hydrocarbons.
Oil and Gas Properties means any and all
rights, titles, interests and estates in and to (1) oil or
gas leases or (2) other liquid or gaseous Hydrocarbon
leases, mineral fee interests, overriding royalty and royalty
interests, net profit interests and production payment
interests, in each case including any reserved or residual
interests of whatever nature.
142
Opinion of Counsel means a written opinion
from legal counsel who is acceptable to the Trustee. The counsel
may be an employee of or counsel to an Issuer, a Subsidiary
Guarantor or the Trustee.
Pari Passu Indebtedness means any
Indebtedness of either Issuer or any Subsidiary Guarantor that
ranks equally in right of payment to the Notes or the Subsidiary
Guarantees, as the case may be.
Permitted Acquisition Indebtedness means
Indebtedness (including Disqualified Stock) of the Company or
any of the Restricted Subsidiaries to the extent such
Indebtedness was Indebtedness:
(1) of an acquired Person prior to the date on which such
Person became a Restricted Subsidiary as a result of having been
acquired and not incurred in contemplation of such acquisition;
or
(2) of a Person that was merged or consolidated with or
into the Company or a Restricted Subsidiary that was not
incurred in contemplation of such merger or consolidation,
provided that on the date such Person became a Restricted
Subsidiary or the date such Person was merged or consolidated
with or into the Company or a Restricted Subsidiary, as
applicable, after giving pro forma effect thereto, the
Restricted Subsidiary or the Company, as applicable, would be
permitted to incur at least $1.00 of additional Indebtedness
pursuant to the Consolidated Coverage Ratio test described under
Certain Covenants Limitation on
Indebtedness and Preferred Stock.
Permitted Business Investment means any
Investment made in the ordinary course of, and of a nature that
is or shall have become customary in, the Oil and Gas Business
including through agreements, transactions, interests or
arrangements which permit one to share risks or costs, comply
with regulatory requirements regarding local ownership or
satisfy other objectives customarily achieved through the
conduct of the Oil and Gas Business jointly with third parties
including:
(1) ownership interests in oil, natural gas, other
Hydrocarbon and mineral properties, processing facilities,
gathering systems, storage facilities or related systems or
ancillary real property interests;
(2) Investments in the form of or pursuant to operating
agreements, working interests, royalty interests, mineral
leases, processing agreements, farm-in agreements, farm-out
agreements, contracts for the sale, transportation or exchange
of oil, natural gas, other Hydrocarbons and minerals, production
sharing agreements, participation agreements, development
agreements, area of mutual interest agreements, unitization
agreements, pooling agreements, joint bidding agreements,
service contracts, joint venture agreements, partnership
agreements (whether general or limited), subscription
agreements, stock purchase agreements, stockholder agreements
and other similar agreements (including for limited liability
companies) with third parties.
Permitted Holder means any of the following
(A) (i) Michael E. Ellis, Mickey Ellis and their children,
estates, heirs or lineal descendants, (ii) any trust having
as its sole beneficiaries one or more of the persons listed in
clause (A)(i) above, (iii) any Person a majority of the
Voting Stock of which is owned or controlled one or more of the
Persons referred to in clauses (A)(i) or (ii); (B) DCPF IV
and any of its affiliates (other than any operating company in
which it has a portfolio investment) and (C) any group
(within the meaning of Section 13(d)(3) or
Section 14(d)(2) of the Exchange Act or any successor
provision) of which any of the forgoing are members.
Permitted Investment means an Investment by
the Company or any Restricted Subsidiary in:
(1) the Company or a Restricted Subsidiary;
(2) another Person whose primary business is the Oil and
Gas Business if as a result of such Investment such other Person
becomes a Restricted Subsidiary or is merged or consolidated
with or into, or transfers or conveys all or substantially all
its assets to, the Company or a Restricted Subsidiary; provided,
however, that the primary business of such Restricted Subsidiary
is the Oil and Gas Business;
(3) cash and Cash Equivalents;
(4) receivables owing to the Company or any Restricted
Subsidiary created or acquired in the ordinary course of
business and payable or dischargeable in accordance with
customary trade terms;
143
provided, however, that such trade terms may include such
concessionary trade terms as the Company or any such Restricted
Subsidiary deems reasonable under the circumstances;
(5) payroll, commission, travel, relocation, expense and
similar advances to cover matters that are expected at the time
of such advances ultimately to be treated as expenses for
accounting purposes and that are made in the ordinary course of
business;
(6) loans or advances to employees (other than executive
officers or directors) made in the ordinary course of business
of the Company or such Restricted Subsidiary;
(7) Capital Stock or other securities received in
settlement of debts (x) created in the ordinary course of
business and owing to the Company or any Restricted Subsidiary
or in satisfaction of judgments or (y) pursuant to any plan
of reorganization or similar arrangement in a bankruptcy or
insolvency proceeding;
(8) any Person as a result of the receipt of non-cash
consideration from an Asset Disposition that was made pursuant
to and in compliance with the covenant described under
Certain Covenants Limitation on Sales of
Assets and Subsidiary Stock;
(9) Investments in existence on the Issue Date;
(10) Commodity Agreements, Currency Agreements, Interest
Rate Agreements described in clause (3) of the penultimate
paragraph of the definition of Indebtedness, and
related Hedging Obligations;
(11) guarantees issued in accordance with the covenant
described under Certain
Covenants Limitation on Indebtedness and
Preferred Stock;
(12) Permitted Business Investments;
(13) any Person to the extent such Investments consist of
prepaid expenses, negotiable instruments held for collection and
lease, utility and workers compensation, performance and
other similar deposits made in the ordinary course of business
by the Company or any Restricted Subsidiary;
(14) guarantees of performance or other obligations (other
than Indebtedness) arising in the ordinary course of the Oil and
Gas Business, including obligations under oil and natural gas
exploration, development, joint operating, and related
agreements and licenses, concessions or operating leases related
to the Oil and Gas Business;
(15) Investments in the Notes;
(16) Investments made after the Issue Date in Unrestricted
Subsidiaries in an aggregate amount outstanding at any time not
to exceed $10.0 million; and
(17) Investments by the Company or any of its Restricted
Subsidiaries, together with all other Investments pursuant to
this clause (17), in an aggregate amount outstanding at the time
of such Investment not to exceed the greater of
(i) $25.0 million and (ii) 2.5% of the
Companys Adjusted Consolidated Net Tangible Assets.
Permitted Liens means, with respect to any
Person:
(1) Liens securing Indebtedness under a Credit Facility
permitted to be Incurred under clause (1) of the second
paragraph of the covenant set forth under
Limitation on Indebtedness and Preferred
Stock;
(2) pledges or deposits by such Person under workers
compensation laws, unemployment insurance laws, social security
or old age pension laws or similar legislation, or good faith
deposits in connection with bids, tenders, contracts (other than
for the payment of Indebtedness) or leases to which such Person
is a party, or deposits (which may be secured by a Lien) to
secure public or statutory obligations of such Person including
letters of credit and bank guarantees required or requested by
the United States, any State thereof or any foreign government
or any subdivision, department, agency, organization or
instrumentality of any of the foregoing in connection with any
contract or statute (including lessee or
144
operator obligations under statutes, governmental regulations,
contracts or instruments related to the ownership, exploration
and production of oil, natural gas, other hydrocarbons and
minerals on state, federal or foreign lands or waters), or
deposits of cash or United States government bonds to secure
indemnity performance, surety or appeal bonds or other similar
bonds to which such Person is a party, or deposits as security
for contested taxes or import or customs duties or for the
payment of rent, in each case Incurred in the ordinary course of
business;
(3) statutory and contractual Liens of landlords and Liens
imposed by law, including carriers, warehousemens,
mechanics, materialmens and repairmens Liens,
in each case for sums not yet due or being contested in good
faith by appropriate proceedings if a reserve or other
appropriate provisions, if any, as shall be required by GAAP
shall have been made in respect thereof;
(4) Liens for taxes, assessments or other governmental
charges or claims not yet subject to penalties for non-payment
or which are being contested in good faith by appropriate
proceedings; provided that appropriate reserves, if any,
required pursuant to GAAP have been made in respect thereof;
(5) Liens in favor of issuers of surety or performance
bonds or bankers acceptances issued pursuant to the
request of and for the account of such Person in the ordinary
course of its business;
(6) survey exceptions, encumbrances, ground leases,
easements or reservations of, or rights of others for, licenses,
rights of way, sewers, electric lines, telegraph and telephone
lines and other similar purposes, or zoning, building codes or
other restrictions (including minor defects or irregularities in
title and similar encumbrances) as to the use of real properties
or Liens incidental to the conduct of the business of such
Person or to the ownership of its properties or assets which do
not in the aggregate materially adversely affect the value of
the properties or assets of such Person and its Restricted
Subsidiaries, taken as a whole, or materially impair their use
in the operation of the business of such Person;
(7) Liens arising from the deposit of funds or securities
in trust for the purpose of decreasing or defeasing Indebtedness
so long as such deposit of funds or securities and such
decreasing or defeasing of Indebtedness are permitted under the
covenant described under Certain
Covenants Limitation on Restricted Payments;
(8) Liens arising from leases, licenses, subleases and
sublicenses of any property or assets (including real property
and intellectual property rights) entered into in the ordinary
course of the Oil and Gas Business;
(9) prejudgment Liens and judgment Liens not giving rise to
an Event of Default so long as such Lien is adequately bonded
and any appropriate legal proceedings which may have been duly
initiated for the review of such judgment have not been finally
terminated or the period within which such proceedings may be
initiated has not expired;
(10) Liens for the purpose of securing the payment of all
or a part of the purchase price of, or Capitalized Lease
Obligations, purchase money obligations or other payments
Incurred to finance the acquisition, lease, improvement or
construction of or repairs or additions to, assets or property
acquired or constructed in the ordinary course of business;
provided that:
(a) the aggregate principal amount of Indebtedness secured
by such Liens is otherwise permitted to be Incurred under the
Indenture and does not exceed the cost of the assets or property
so acquired or constructed; and
(b) such Liens are created within 180 days of the
later of the acquisition, lease, completion of improvements,
construction, repairs or additions or commencement of full
operation of the assets or property subject to such Lien and do
not encumber any other assets or property of the Company or any
Restricted Subsidiary other than such assets or property and
assets affixed or appurtenant thereto;
145
(11) Liens arising solely by virtue of any statutory or
common law provisions relating to bankers Liens, rights of
set-off or similar rights and remedies as to deposit accounts or
other funds maintained with a depositary institution; provided
that:
(a) such deposit account is not a dedicated cash collateral
account and is not subject to restrictions against access by the
Company in excess of those set forth by regulations promulgated
by the Federal Reserve Board; and
(b) such deposit account is not intended by the Company or
any Restricted Subsidiary to provide collateral to the
depository institution;
(12) Liens arising from deposits made in the ordinary
course of business to secure any liability to insurance carriers;
(13) Liens existing on the Issue Date;
(14) Liens on any property or assets of a Person at the
time such Person becomes a Subsidiary; provided, however, that
such Liens are not created or Incurred in connection with, or in
contemplation of, such other Person becoming a Subsidiary;
provided further, however, that any such Lien may not extend to
any other property or assets owned by the Company or any
Restricted Subsidiary (other than any property or assets affixed
or appurtenant thereto);
(15) Liens on any property or assets at the time the
Company or any of its Subsidiaries acquired the property or
assets, including any acquisition by means of a merger or
consolidation with or into the Company or any of its
Subsidiaries; provided, however, that such Liens are not created
or Incurred in connection with, or in contemplation of, such
acquisition; provided further, however, that such Liens may not
extend to any other property or assets owned by the Company or
any Restricted Subsidiary (other than any property or assets
affixed or appurtenant thereto);
(16) Liens securing the Notes, the Subsidiary Guarantees
and any other Obligations under the Indenture;
(17) Liens securing Refinancing Indebtedness Incurred to
refinance Indebtedness described under clauses (10), (13), (14),
(15) or this clause (17) that was previously so
secured, provided that any such Lien is limited to all or part
of the same property or assets that secured (or, under the
written arrangements under which the original Lien arose, could
secure) the Indebtedness being refinanced or is in respect of
property or assets that is the security for a Permitted Lien
hereunder;
(18) any interest or title of a lessor under any operating
lease;
(19) Liens arising under farm-out agreements, farm-in
agreements, division orders, contracts for the sale, purchase,
exchange, transportation, gathering or processing of
Hydrocarbons, unitizations and pooling designations,
declarations, orders and agreements, development agreements,
joint venture agreements, partnership agreements, operating
agreements, royalties, working interests, net profits interests,
joint interest billing arrangements, participation agreements,
production sales contracts, area of mutual interest agreements,
gas balancing or deferred production agreements, injection,
repressuring and recycling agreements, salt water or other
disposal agreements, seismic or geophysical permits or
agreements, and other agreements that are customary in the Oil
and Gas Business; provided, however, in all instances that such
Liens are limited to the property or assets that are the subject
of the relevant agreement, program, order or contract;
(20) Liens on pipelines or pipeline facilities that arise
by operation of law;
(21) Liens in favor of the Company, the Co-Issuer or any
Subsidiary Guarantor; and
(22) Liens securing Indebtedness in an aggregate principal
amount outstanding at any one time, added together with all
other Indebtedness secured by Liens Incurred pursuant to this
clause (22), not to exceed the greater of
(a) $10.0 million and (b) 1.0% of the
Companys Adjusted Consolidated Net Tangible Assets.
146
In each case set forth above, notwithstanding any stated
limitation on the property or assets that may be subject to such
Lien, a Permitted Lien on a specified property or asset or group
or type of properties or assets may include Liens on all
improvements, additions and accessions thereto and all products
and proceeds thereof (including dividends, distributions and
increases in respect thereof).
Permitted Tax Distributions means for any
calendar year or portion thereof of the Company during which it
is a pass-through entity for U.S. federal income tax purposes,
payments and distributions to the partners of the Company on
each estimated payment date as well as each other applicable due
date to enable the partners of the Company (or, if any of them
are themselves a pass-through entity for US. Federal income tax
purposes, their shareholders or partners) to make payments of
U.S. federal and state income taxes (including estimates
therefor) as a result of the operations of the Company and its
Subsidiaries during the current and any previous calendar year,
not to exceed an amount equal to the amount of each such
partners (or, in the case of a pass-through entity, its
shareholders or partners) U.S. federal and state
income tax liability resulting solely from the pass-through tax
treatment of such partners interest in the Company and as
calculated pursuant to the limited partnership agreement of the
Company as in effect on the Issue Date and as it may be amended
from time to time thereafter in a manner that is not, considered
as a whole, materially adverse to the holders of the Notes.
Person means any individual, corporation,
partnership, joint venture, association, joint-stock company,
trust, unincorporated organization, limited liability company,
government or any agency or political subdivision thereof or any
other entity.
Preferred Stock, as applied to the Capital
Stock of any Person, means Capital Stock of any class or classes
(however designated) which is preferred as to the payment of
dividends, or as to the distribution of assets upon any
voluntary or involuntary liquidation or dissolution of such
Person, over shares of Capital Stock of any other class of such
Person.
Production Payments and Reserve Sales means
the grant or transfer by the Company or a Restricted Subsidiary
to any Person of a royalty, overriding royalty, net profits
interest, production payment (whether volumetric or dollar
denominated), partnership or other interest in Oil and Gas
Properties, reserves or the right to receive all or a portion of
the production or the proceeds from the sale of production
attributable to such properties where the holder of such
interest has recourse solely to such production or proceeds of
production, subject to the obligation of the grantor or
transferor to operate and maintain, or cause the subject
interests to be operated and maintained, in a reasonably prudent
manner or other customary standard or subject to the obligation
of the grantor or transferor to indemnify for environmental,
title or other matters customary in the Oil and Gas Business,
including any such grants or transfers pursuant to incentive
compensation programs on terms that are reasonably customary in
the Oil and Gas Business for geologists, geophysicists or other
providers of technical or management services to the Company or
a Restricted Subsidiary.
Refinancing Indebtedness means Indebtedness
that is Incurred to refund, refinance, replace, exchange, renew,
repay, extend, prepay, redeem or retire (including pursuant to
any defeasance or discharge mechanism) (collectively,
refinance and the terms refinances and
refinanced shall have correlative meanings) any
Indebtedness (including Indebtedness of the Company that
refinances Indebtedness of any Restricted Subsidiary and
Indebtedness of any Restricted Subsidiary that refinances
Indebtedness of another Restricted Subsidiary, but excluding
Indebtedness of a Restricted Subsidiary that refinances
Indebtedness of the Company), including Indebtedness that
refinances Refinancing Indebtedness, provided, however, that:
(1) (a) if the Stated Maturity of the Indebtedness
being refinanced is earlier than the Stated Maturity of the
Notes, the Refinancing Indebtedness has a Stated Maturity no
earlier than the Stated Maturity of the Indebtedness being
refinanced or (b) if the Stated Maturity of the
Indebtedness being refinanced is later than the Stated Maturity
of the Notes, the Refinancing Indebtedness has a Stated Maturity
at least 91 days later than the Stated Maturity of the
Notes;
(2) the Refinancing Indebtedness has an Average Life at the
time such Refinancing Indebtedness is Incurred that is equal to
or greater than the Average Life of the Indebtedness being
refinanced;
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(3) such Refinancing Indebtedness is Incurred in an
aggregate principal amount (or if issued with original issue
discount, an aggregate issue price) that is equal to or less
than the sum of the aggregate principal amount (or if issued
with original issue discount, the aggregate accreted value) then
outstanding of the Indebtedness being refinanced (plus, without
duplication, any additional Indebtedness Incurred to pay
interest, premiums or defeasance costs required by the
instruments governing such existing Indebtedness and fees and
expenses Incurred in connection therewith); and
(4) if the Indebtedness being refinanced is subordinated in
right of payment to the Notes or a Subsidiary Guarantee, such
Refinancing Indebtedness is subordinated in right of payment to
the Notes or the Subsidiary Guarantee on terms at least as
favorable to the holders as those contained in the documentation
governing the Indebtedness being refinanced.
Registration Rights Agreement means that
certain registration rights agreement dated as of the Issue Date
by and among the Issuers, the Subsidiary Guarantors and the
initial purchasers set forth therein and, with respect to any
Additional Notes, one or more substantially similar registration
rights agreements among the Issuers and the other parties
thereto, as any such agreement may be amended from time to time.
Restricted Investment means any Investment
other than a Permitted Investment.
Restricted Subsidiary means any Subsidiary of
the Company other than an Unrestricted Subsidiary.
S&P means Standard &
Poors Ratings Services, a division of The McGraw-Hill
Companies, Inc., or any successor to the rating agency business
thereof.
Sale/Leaseback Transaction means an
arrangement relating to property now owned or hereafter acquired
whereby the Company or a Restricted Subsidiary transfers such
property to a Person and the Company or a Restricted Subsidiary
leases it from such Person.
SEC means the United States Securities and
Exchange Commission.
Senior Secured Credit Agreement means the
Sixth Amended and Restated Credit Agreement dated as of
May 13, 2010 among the Company, as borrower, Wells Fargo
Bank, N.A., as administrative agent and the lenders parties
thereto from time to time, including any guarantees, collateral
documents, instruments and agreements executed in connection
therewith, and any amendments, supplements, modifications,
extensions, renewals, restatements, refundings or refinancings
thereof with other revolving credit facilities with banks or
other institutional lenders that replace, refund or refinance
any part of the loans or commitments thereunder, including any
such replacement, refunding or refinancing revolving credit
facility that increases the amount borrowable thereunder or
alters the maturity thereof.
Significant Subsidiary means any Restricted
Subsidiary that would be a Significant Subsidiary of
the Company within the meaning of
Rule 1-02
under
Regulation S-X
promulgated by the SEC, as in effect on the Issue Date.
Stated Maturity means, with respect to any
security, the date specified in such security as the fixed date
on which the payment of principal of such security is due and
payable, including pursuant to any mandatory redemption
provision, but shall not include any contingent obligations to
repay, redeem or repurchase any such principal prior to the date
originally scheduled for the payment thereof.
Subordinated Obligation means any
Indebtedness of either Issuer (whether outstanding on the Issue
Date or thereafter Incurred) which is expressly subordinated in
right of payment to the Notes pursuant to a written agreement.
Subsidiary of any Person means (a) any
corporation, association or other business entity (other than a
partnership, joint venture, limited liability company or similar
entity) of which more than 50% of the Voting Stock or
(b) any partnership, joint venture, limited liability
company or similar entity of which more than 50% of the capital
accounts, distribution rights, total equity and voting interests
or general or limited partnership interests, as applicable, is,
in the case of clauses (a) and (b), at the time owned or
controlled, directly or indirectly, by (1) such Person,
(2) such Person and one or more Subsidiaries of such Person
or (3) one or more
148
Subsidiaries of such Person. Unless otherwise specified herein,
each reference to a Subsidiary (other than in this definition)
refers to a Subsidiary of the Company.
Subsidiary Guarantee means, individually, any
guarantee of payment of the Notes by a Subsidiary Guarantor
pursuant to the terms of the Indenture and any supplemental
indenture thereto, and, collectively, all such guarantees.
Subsidiary Guarantor means any Subsidiary of
the Company that is a guarantor of the Notes, including any
Person that is required after the Issue Date to guarantee the
Notes pursuant to the Future Subsidiary Guarantors
covenant, in each case until a successor replaces such Person
pursuant to the applicable provisions of the Indenture and,
thereafter, means such successor; provided, however, that the
Co-Issuer shall not be a Subsidiary Guarantor.
Tax Amount means, for any period, the
combined federal, state and local income taxes, including
estimated taxes, that would be payable by the Company if it were
a Texas corporation filing separate tax returns with respect to
its Taxable Income for such period; provided that in determining
the Tax Amount, the effect thereon of any net operating loss
carryforwards or other carryforwards or tax attributes, such as
alternative minimum tax carryforwards, that would have arisen if
the Company were a Texas corporation shall be taken into
account; provided, further, that, if there is an adjustment in
the amount of the Taxable Income for any period, an appropriate
positive or negative adjustment shall be made in the Tax Amount,
and if the Tax Amount is negative, then the Tax Amount for
succeeding periods shall be reduced to take into account such
negative amount until such negative amount is reduced to zero.
Notwithstanding anything to the contrary, Tax Amount shall not
include taxes resulting from the Companys reorganization
as, or change in the status to, a corporation for tax purposes.
Taxable Income means, for any period, the
taxable income or loss of the Company for such period for U.S.
federal income tax purposes.
Unrestricted Subsidiary means:
(1) any Subsidiary of the Company (other than the
Co-Issuer) that at the time of determination shall be designated
an Unrestricted Subsidiary by the Board of Directors of the
Company in the manner provided below; and
(2) any Subsidiary of an Unrestricted Subsidiary.
The Board of Directors of the Company may designate any
Subsidiary of the Company (including any newly acquired or newly
formed Subsidiary or a Person becoming a Subsidiary through
merger or consolidation or Investment therein) to be an
Unrestricted Subsidiary only if:
(1) such Subsidiary or any of its Subsidiaries does not own
any Capital Stock or Indebtedness of or have any Investment in,
or own or hold any Lien on any property of, any other Subsidiary
of the Company which is not a Subsidiary of the Subsidiary to be
so designated or otherwise an Unrestricted Subsidiary;
(2) all the Indebtedness of such Subsidiary and its
Subsidiaries shall, at the date of designation, and will at all
times thereafter, consist of Non-Recourse Debt;
(3) on the date of such designation, such designation and
the Investment of the Company or a Restricted Subsidiary in such
Subsidiary complies with Certain
Covenants Limitation on Restricted Payments;
(4) such Subsidiary is a Person with respect to which
neither the Company nor any of its Restricted Subsidiaries has
any direct or indirect obligation (a) to subscribe for
additional Capital Stock of such Person or (b) to maintain
or preserve such Persons financial condition or to cause
such Person to achieve any specified levels of operating results;
149
(5) such Subsidiary, either alone or in the aggregate with
all other Unrestricted Subsidiaries, does not operate, directly
or indirectly, all or substantially all of the business of the
Company and its Subsidiaries; and
(6) such Subsidiary is not a party to any agreement,
contract, arrangement or understanding with the Company or any
Restricted Subsidiary with terms less favorable to the Company
or such Restricted Subsidiary than those that might have been
obtained from Persons who are not Affiliates of the Company.
Any such designation by the Board of Directors of the Company
shall be evidenced to the Trustee by filing with the Trustee a
resolution of the Board of Directors of the Company giving
effect to such designation and an Officers Certificate
certifying that such designation complies with the preceding
conditions. If, at any time, any Unrestricted Subsidiary would
fail to meet the foregoing requirements as an Unrestricted
Subsidiary, it shall thereafter cease to be an Unrestricted
Subsidiary for purposes of the Indenture and any Indebtedness of
such Subsidiary shall be deemed to be Incurred as of such date.
The Board of Directors of the Company may designate any
Unrestricted Subsidiary to be a Restricted Subsidiary; provided
that immediately after giving effect to such designation, no
Default or Event of Default shall have occurred and be
continuing or would occur as a consequence thereof and the
Company could Incur at least $1.00 of additional Indebtedness
under the first paragraph of the covenant described under
Certain Covenants Limitation on
Indebtedness and Preferred Stock on a pro forma basis
taking into account such designation.
U.S. Government Obligations means securities
that are (a) direct obligations of the United States of
America for the timely payment of which its full faith and
credit is pledged or (b) obligations of a Person controlled
or supervised by and acting as an agency or instrumentality of
the United States of America the timely payment of which is
unconditionally guaranteed as a full faith and credit obligation
of the United States of America, which, in either case, are not
callable or redeemable at the option of the issuer thereof, and
shall also include a depositary receipt issued by a bank (as
defined in Section 3(a)(2) of the Securities Act), as
custodian with respect to any such U.S. Government Obligations
or a specific payment of principal of or interest on any such
U.S. Government Obligations held by such custodian for the
account of the holder of such depositary receipt; provided that
(except as required by law) such custodian is not authorized to
make any deduction from the amount payable to the holder of such
depositary receipt from any amount received by the custodian in
respect of the U.S. Government Obligations or the specific
payment of principal of or interest on the U.S. Government
Obligations evidenced by such depositary receipt.
Volumetric Production Payments means
production payment obligations recorded as deferred revenue in
accordance with GAAP, together with all undertakings and
obligations in connection therewith.
Voting Stock of a Person means all classes of
Capital Stock of such Person then outstanding and normally
entitled to vote in the election of members of such
Persons Board of Directors.
Wholly Owned Subsidiary means a Restricted
Subsidiary, all of the Capital Stock of which (other than
directors qualifying shares or other shares required by
applicable law to be held by a Person other than the Company or
another Wholly Owned Subsidiary) is owned by the Company or
another Wholly Owned Subsidiary.
150
PLAN OF
DISTRIBUTION
Based on interpretations by the staff of the SEC in no-action
letters issued to third parties, we believe you may transfer new
notes issued under the exchange offer in exchange for the old
notes if:
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you acquire the new notes in the ordinary course of your
business;
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you have no arrangement or understanding with any person to
participate in the distribution (within the meaning of the
Securities Act) of such new notes in violation of the provisions
of the Securities Act; and
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you are not our affiliate (within the meaning of
Rule 405 under the Securities Act).
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Each broker-dealer that receives new notes for its own account
pursuant to the exchange offer in exchange for old notes that
were acquired by such broker-dealer as a result of market-making
or other trading activities must acknowledge that it will
deliver a prospectus in connection with any resale of such new
notes. This prospectus, as it may be amended or supplemented
from time to time, may be used by a broker-dealer in connection
with resales of new notes received in exchange for old notes
where such old notes were acquired as a result of market-making
activities or other trading activities.
If you wish to exchange new notes for your old notes in the
exchange offer, you will be required to make representations to
us as described in Exchange Offer Purpose and
Effect of the Exchange Offer and Exchange
Offer Your Representations to Us in this
prospectus and in the letter of transmittal.
We will not receive any proceeds from any sale of new notes by
broker-dealers. New notes received by broker-dealers for their
own account pursuant to the exchange offer may be sold from time
to time in one or more transactions in any of the following ways:
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in the
over-the-counter
market;
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in negotiated transactions;
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through the writing of options on the new notes or a combination
of such methods of resale;
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at market prices prevailing at the time of resale;
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at prices related to such prevailing market prices; or
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at negotiated prices.
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Any such resale may be made directly to purchasers or to or
through brokers or dealers who may receive compensation in the
form of commissions or concessions from any such broker-dealer
or the purchasers of any such new notes.
Any broker-dealer that resells new notes that were received by
it for its own account pursuant to the exchange offer in
exchange for old notes that were acquired by such broker-dealer
as a result of market-making or other trading activities may be
deemed to be an underwriter within the meaning of
the Securities Act and profit on any such resale of notes issued
in the exchange and any commission or concessions received by
any such persons may be deemed to be underwriting compensation
under the Securities Act. The letter of transmittal states that
by acknowledging that it will deliver and by delivering a
prospectus, a broker-dealer will not be deemed to admit that it
is an underwriter within the meaning of the
Securities Act.
For a period of up to one year after the exchange offer
registration statement is declared effective, we will promptly
send additional copies of this prospectus and any amendment or
supplement to this prospectus to any such broker-dealers that
requests such documents. Furthermore, we agreed to amend or
supplement this prospectus during such period if so requested in
order to expedite or facilitate the disposition of any new notes
by broker-dealers.
We have agreed to pay all expenses incident to the exchange
offer other than fees and expenses of counsel to the holders and
brokerage commissions and transfer taxes payable in respect of
any transfer involved in the issuance or delivery of any new
note in a name other that that of the holder of the old note in
respect of which such new note is being issued, if any, and will
indemnify the holders of the old notes (including any
broker-dealers) against certain liabilities, including
liabilities under the Securities Act.
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CERTAIN
UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
The following discussion is a summary of the material federal
income tax considerations relevant to the exchange of old notes
for new notes, but does not purport to be a complete analysis of
all potential tax effects. The discussion is based upon the
Internal Revenue Code of 1986, as amended (the
Code), Treasury Regulations, Internal Revenue
Service rulings and pronouncements and judicial decisions now in
effect, all of which may be subject to change at any time by
legislative, judicial or administrative action. These changes
may be applied retroactively in a manner that could adversely
affect a holder of new notes. Some holders, including financial
institutions, insurance companies, regulated investment
companies, tax-exempt organizations, dealers in securities or
currencies, persons whose functional currency is not the U.S.
dollar, or persons who hold the notes as part of a hedge,
conversion transaction, straddle or other risk reduction
transaction may be subject to special rules not discussed below.
We recommend that each holder consult his own tax advisor as to
the particular tax consequences of exchanging such holders
old notes for new notes, including the applicability and effect
of any foreign, state, local or other tax laws or estate or gift
tax considerations.
We believe that the exchange of old notes for new notes will not
be an exchange or otherwise a taxable event to a holder for
United States federal income tax purposes. Accordingly, a holder
will not recognize gain or loss upon receipt of a new note in
exchange for an old note in the exchange, and the holders
basis and holding period in the new note will be the same as its
basis and holding period in the corresponding old note
immediately before the exchange.
LEGAL
MATTERS
The validity of the new notes offered in this exchange offer
will be passed upon for us by Haynes and Boone, LLP, Houston,
Texas.
EXPERTS
Independent
Registered Public Accounting Firms
The Alta Mesa financial statements as of December 31, 2009
and December 31, 2010 and for the three years ended
December 31, 2010 included in this prospectus have been
audited by UHY LLP, an independent registered accounting firm,
as stated in the report appearing herein. The Statements of
Revenue and Direct Operating Expenses for the period
January 1, 2009 through July 22, 2009 and for the
twelve months ended December 31, 2008 (for the Chesapeake
acquisition) and for the period January 1, 2011 through
March 31, 2011 and for the twelve months ended
December 31, 2010 (for the Sydson and TODD acquisitions)
have been audited by UHY LLP, independent auditors, as stated in
the reports appearing herein. The Meridian financial statements
as of December 31, 2008 and December 31, 2009 and for
the three years ended December 31, 2009 included in this
prospectus have been audited by BDO USA, LLP (formerly known as
BDO Seidman, LLP), an independent registered public accounting
firm, whose report included an explanatory paragraph expressing
substantial doubt about Meridians ability to continue as a
going concern.
Independent
Petroleum Engineers
Estimates of proved reserves included in this prospectus as of
December 31, 2010 using SEC guidelines, were prepared or
derived from estimates prepared by T.J. Smith &
Company, Inc., independent petroleum engineers, and W.D. Von
Gonten & Co., independent petroleum engineers, and
audited by Netherland, Sewell & Associates, Inc.,
independent petroleum engineers. These estimates are included in
this prospectus in reliance on the authority of such firm as
experts in these matters.
152
GLOSSARY
OF OIL AND NATURAL GAS TERMS
The terms and abbreviations defined in this section are used
throughout this prospectus:
3-D
seismic (Three-Dimensional Seismic Data). Geophysical
data that depicts the subsurface strata in three dimensions.
3-D seismic
data typically provides a more detailed and accurate
interpretation of the subsurface strata than two-dimensional
seismic data.
Bbl. One stock tank barrel, of 42
U.S. gallons liquid volume, used herein in reference to crude
oil, condensate or natural gas liquids.
Bcf. One billion cubic feet of
natural gas.
Bcfe. One billion cubic feet of
natural gas equivalent with one barrel of oil converted to six
thousand cubic feet of natural gas.
BOE. One barrel of oil equivalent,
converting gas to oil at the ratio of 6 Mcf of gas to one
Bbl of oil.
Basin. A large natural depression
on the earths surface in which sediments generally brought
by water accumulate.
Btu or British Thermal Unit. The
quantity of heat required to raise the temperature of one pound
of water by one degree Fahrenheit.
Completion. The process of
treating a drilled well followed by the installation of
permanent equipment for the production of natural gas or oil, or
in the case of a dry hole, the reporting of abandonment to the
appropriate agency.
DD&A. Depreciation, depletion
and amortization.
De-bottlenecking. The process of
increasing production capacity of existing facilities through
the modification of existing equipment to remove throughput
restrictions.
Delineation. The process of
placing a number of wells in various parts of a reservoir to
determine its boundaries and production characteristics.
Developed acreage. The number of
acres that are allocated or assignable to productive wells or
wells capable of production.
Developed oil and natural gas
reserves. Developed oil and natural gas
reserves are reserves of any category that can be expected to be
recovered: (i) through existing wells with existing
equipment and operating methods or in which the cost of the
related equipment is relatively minor compared to the cost of a
new well; and (ii) through installed extraction equipment
and infrastructure operational at the time of the reserves
estimate if the extraction is by means not involving a well.
Development 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. A well found to be
incapable of producing hydrocarbons in sufficient quantities
such that proceeds from the sale of such production exceed
production expenses and taxes.
Dry hole costs. Costs incurred in
drilling a well, assuming a well is not successful, including
plugging and abandonment costs.
Enhanced recovery. The recovery of
oil and natural gas through the injection of liquids or gases
into the reservoir, supplementing its natural energy. Enhanced
recovery methods are often applied when production slows due to
depletion of the natural pressure.
Exploratory well. A well drilled
to find and produce natural gas or oil reserves not classified
as proved, to find a new reservoir in a field previously found
to be productive of natural gas or oil in another reservoir or
to extend a known reservoir.
153
Farm-in or farm-out. An agreement
under which the owner of a working interest in an oil and
natural gas lease assigns the working interest or a portion of
the working interest to another party who desires to drill on
the leased acreage. Generally, the assignee is required to drill
one or more wells in order to earn its interest in the acreage.
The assignor usually retains a royalty or reversionary interest
in the lease. The interest received by an assignee is a
farm-in while the interest transferred by the
assignor is a farm-out.
Fault. A break or planar surface
in brittle rock across which there is observable displacement.
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. The field name refers to the surface
area, although it may refer to both the surface and the
underground productive formations.
Formation. A layer of rock which
has distinct characteristics that differs from nearby rock.
Fracing or fracture stimulation
technology. The technique of improving a
wells production or injection rates by pumping a mixture
of fluids into the formation and rupturing the rock, creating an
artificial channel. As part of this technique, sand or other
material may also be injected into the formation to keep the
channel open, so that fluids or natural gases may more easily
flow through the formation.
Gross acres or gross wells. The
total acres or wells, as the case may be, in which a working
interest is owned.
Horizontal drilling. A drilling
technique used in certain formations where a well is drilled
vertically to a certain depth and then drilled at a right angle
within a specified interval.
Infill wells. Wells drilled into
the same pool as known producing wells so that oil or natural
gas does not have to travel as far through the formation.
Lease operating expenses. The
expenses of lifting oil or natural gas from a producing
formation to the surface, constituting part of the current
operating expenses of a working interest, and also including
labor, superintendence, supplies, repairs, short-lived assets,
maintenance, allocated overhead costs, workover, ad valorem
taxes, insurance and other expenses incidental to production,
but excluding lease acquisition or drilling or completion
expenses.
MBbl. One thousand barrels of
crude oil, condensate or natural gas liquids.
Mcf. One thousand cubic feet of
natural gas.
Mcfe. One thousand cubic feet
equivalent determined using the ratio of six Mcf of natural gas
to one barrel of oil, condensate or natural gas liquids.
Mcfe/d. Mcfe per day.
MMBtu. One million British thermal
units.
MMcf. One million cubic feet of
natural gas.
MMcfe. 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.
MMcfe/d. MMcfe per day.
MMBbl. One million barrels of
crude oil, condensate or natural gas liquids.
NGLs. Natural gas liquids.
Hydrocarbons found in natural gas which may be extracted as
liquefied petroleum gas and natural gasoline.
NYMEX. The New York Mercantile
Exchange.
Net Acres. The percentage of total
acres an owner has out of a particular number of acres, or a
specified tract. An owner who has 50% interest in 100 acres owns
50 net acres.
154
Non-operated working
interests. The working interest or fraction
thereof in a lease or unit, the owner of which is without
operating rights by reason of an operating agreement.
Pay. A reservoir or portion of a
reservoir that contains economically producible hydrocarbons.
The overall interval in which pay sections occur is the gross
pay; the smaller portions of the gross pay that meet local
criteria for pay (such as a minimum porosity, permeability and
hydrocarbon saturation) are net pay.
Potential drilling
locations. Total gross resource play
locations that we may be able to drill on our existing acreage.
Our actual drilling activities may change depending on the
availability of capital, regulatory approvals, seasonal
restrictions, oil and natural gas prices, costs, drilling
results and other factors.
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.
Prospect. A specific geographic
area which, based on supporting geological, geophysical or other
data and also preliminary economic analysis using reasonably
anticipated prices and costs, is deemed to have potential for
the discovery of commercial hydrocarbons.
PDNP. Proved developed
non-producing reserves.
PDP. Proved developed producing
reserves.
Proved reserves. Proved oil and
natural gas reserves are those quantities of oil and natural
gas, which, by analysis of geoscience and engineering data, can
be estimated with reasonable certainty to be economically
producible from a given date forward from known
reservoirs, and under existing economic conditions, operating
methods and government regulations prior to the time
at which contracts providing the right to operate expire, unless
evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are
used for the estimation. The project to extract the hydrocarbons
must have commenced or the operator must be reasonably certain
that it will commence the project within a reasonable time.
Proved undeveloped reserves
(PUD). Proved undeveloped oil
and natural gas reserves are 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. Reserves on undrilled acreage are limited to those
drilling units offsetting productive units that are reasonably
certain of production when drilled. Proved reserves for other
undrilled units are claimed only where it can be demonstrated
with certainty that there is continuity of production from the
existing productive formation. Estimates for proved undeveloped
reserves will not be attributable to any acreage for which an
application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been
proved effective by actual tests in the area and in the same
reservoir.
PV-10. When
used with respect to oil and natural gas reserves,
PV-10 means
the estimated future gross revenue to be generated from the
production of proved reserves, net of estimated production and
future development and abandonment costs, using prices and costs
in effect at the determination date, before income taxes, and
without giving effect to non-property related expenses,
discounted to a present value using an annual discount rate of
10% in accordance with the guidelines of the SEC.
PV-10 is not
a financial measure calculated in accordance with generally
accepted accounting principles (GAAP) and generally
differs from Standardized Measure, the most directly comparable
GAAP financial measure, because it does not include the effects
of income taxes on future net revenues. Neither
PV-10 nor
Standardized Measure represents an estimate of the fair market
value of our oil and natural gas properties. We and others in
the industry use
PV-10 as a
measure to compare the relative size and value of proved
reserves held by companies without regard to the specific tax
characteristics of such entities. Our
PV-10 is the
same as our standardized measure for the periods presented in
this prospectus.
Recompletion. The process of
re-entering an existing wellbore that is either producing or not
producing and completing new reservoirs in an attempt to
establish or increase existing production.
155
Reserve life index. A measure of
the productive life of an oil and natural gas property or a
group of properties, expressed in years.
Reservoir. A porous and permeable
underground formation containing a natural accumulation of
producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is separate from other
reservoirs.
Spacing. The distance between
wells producing from the same reservoir. Spacing is often
expressed in terms of acres, e.g.,
40-acre
spacing, and is often established by regulatory agencies.
Standardized measure. Standardized
measure is the present value of estimated future net revenues to
be generated from the production of proved reserves, determined
in accordance with the rules and regulations of the Securities
and Exchange Commission, without giving effect to
non property related expenses such as certain
general and administrative expenses, debt service and future
federal income tax expenses or to depreciation, depletion and
amortization and discounted using an annual discount rate of
10%. Our standardized measure includes future obligations under
the Texas gross margin tax, but it does not include future
federal income tax expenses because we are a partnership and are
not subject to federal income taxes. Our standardized measure is
the same as our
PV-10 for
the periods presented in this prospectus.
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 oil
and natural gas regardless of whether such acreage contains
proved reserves.
Unit. The joining of all or
substantially all interests in a reservoir or field, rather than
a single tract, to provide for development and operation without
regard to separate property interests. Also, the area covered by
a unitization agreement.
Waterflood. The injection of water
into an oil reservoir to push additional oil out of
the reservoir rock and into the wellbores of producing wells.
Typically an enhanced recovery process.
Wellbore. The hole drilled by the
bit that is equipped for natural gas production on a completed
well. Also called well or borehole.
Working interest. The right
granted to the lessee of a property to explore for and to
produce and own natural gas or other minerals. The working
interest owners bear the exploration, development, and operating
costs on either a cash, penalty, or carried basis.
156
INDEX TO
FINANCIAL STATEMENTS
Below is an index to the financial statements and notes
contained in Financial Statements and Supplementary Data.
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Page
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Introduction
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F-2
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F-3
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F-4
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F-5
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F-6
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|
Audited Financial Statements
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F-11
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F-12
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F-13
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|
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|
F-14
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|
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|
F-15
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|
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|
|
F-16
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|
Unaudited Financial Statements
|
|
|
|
|
|
|
|
F-44
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|
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|
|
F-45
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|
|
|
|
F-46
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|
|
|
|
F-47
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|
Audited Financial Statements (Deep Bossier Acquisition)
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|
|
|
|
|
|
|
F-63
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|
|
|
|
F-64
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|
|
|
|
F-65
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|
Unaudited Financial Statements (Meridian)
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|
|
|
|
|
|
|
F-68
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|
|
|
|
F-69
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|
|
|
|
F-70
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|
|
|
|
F-71
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|
|
|
|
F-72
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|
|
|
|
F-73
|
|
Audited Financial Statements (Meridian)
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|
|
|
|
|
|
|
F-89
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|
|
|
|
F-90
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|
|
|
|
F-91
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|
|
|
|
F-92
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|
|
|
|
F-93
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|
|
|
|
F-94
|
|
|
|
|
F-95
|
|
Audited Financial Statements (Sydson Acquisition)
|
|
|
|
|
|
|
|
F-136
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|
|
|
|
F-137
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|
|
|
|
F-138
|
|
Audited Financial Statements (TODD Acquisition)
|
|
|
|
|
|
|
|
F-141
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|
|
|
|
F-142
|
|
|
|
|
F-143
|
|
F-1
UNAUDITED
PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following unaudited pro forma condensed consolidated
financial statements and explanatory notes give effect to the
acquisition of The Meridian Resource Corporation
(Meridian) and the acquisitions of certain
properties from Sydson Energy and certain of its related parties
(together, Sydson and the Sydson
acquisition) and of certain similar properties from Texas
Oil Distribution & Development, Inc. and Matrix
Petroleum LLC (together, TODD and the TODD
acquisition).
The unaudited pro forma condensed consolidated financial
statements and explanatory notes are based on the estimates and
assumptions set forth in the explanatory notes. The unaudited
pro forma condensed consolidated financial statements have been
prepared utilizing the historical consolidated financial
statements of Alta Mesa Holdings, LP (Alta Mesa) and
Meridian as well as operational data for the Sydson and TODD
acquisitions provided primarily from our own records as
operators of the properties we acquired, and should be read in
conjunction with the historical consolidated financial
statements and notes thereto.
The unaudited pro forma consolidated statements of operations
have been prepared as if the Meridian, Sydson and TODD
acquisitions had been consummated on January 1, 2010. The
unaudited condensed consolidated balance sheet has been prepared
as if the Sydson and TODD acquisitions had been consummated
March 31, 2011.
The unaudited pro forma condensed consolidated financial
statements are presented for informational purposes only, are
based on certain assumptions that we believe are reasonable, and
do not purport to represent our financial condition or our
results of operations had the business combinations occurred on
the dates noted above or to project the results for any future
date or period. In the opinion of management, all adjustments
have been made that are necessary to present fairly the
unaudited pro forma condensed consolidated financial information.
The Meridian, Sydson and TODD acquisitions have been treated as
purchase business combinations for accounting purposes, and the
assets acquired and liabilities assumed have been recorded at
their fair values.
The allocations of the purchase price to the acquired assets and
liabilities of Sydson and TODD are preliminary based on
estimates of fair value and may change when the fair values are
finalized.
F-2
UNAUDITED
PRO FORMA CONDENSED CONSOLIDATED
FOR THE
YEAR ENDED DECEMBER 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sydson
|
|
|
TODD
|
|
|
Pro Forma
|
|
|
Pro Forma
|
|
|
|
Alta Mesa
|
|
|
Meridian
|
|
|
Acquisition
|
|
|
Acquisition
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
1/1-12/31/10
|
|
|
1/1-5/12/10
|
|
|
1/1-12/31/10
|
|
|
1/1-12/31/10
|
|
|
(Note 4)
|
|
|
1/1-12/31/10
|
|
|
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, oil and natural gas liquids
|
|
$
|
208,537
|
|
|
$
|
29,820
|
|
|
$
|
3,876
|
|
|
$
|
4,143
|
|
|
$
|
|
|
|
$
|
246,376
|
|
Other
|
|
|
1,475
|
|
|
|
69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
210,012
|
|
|
|
29,889
|
|
|
|
3,876
|
|
|
|
4,143
|
|
|
|
|
|
|
|
247,920
|
|
Unrealized gain derivative contracts
|
|
|
10,088
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,088
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL REVENUES
|
|
|
220,100
|
|
|
|
29,889
|
|
|
|
3,876
|
|
|
|
4,143
|
|
|
|
|
|
|
|
258,008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
41,905
|
|
|
|
4,642
|
|
|
|
534
|
|
|
|
570
|
|
|
|
|
|
|
|
47,651
|
|
Production, ad valorem and other taxes
|
|
|
11,141
|
|
|
|
2,520
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,661
|
|
Workover expense
|
|
|
7,409
|
|
|
|
152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,561
|
|
Exploration expense
|
|
|
31,037
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,841
|
a
|
|
|
32,878
|
|
Depreciation, depletion and amortization
|
|
|
59,090
|
|
|
|
10,766
|
|
|
|
|
|
|
|
|
|
|
|
1,320
|
b
|
|
|
71,176
|
|
Impairment of oil and natural gas properties
|
|
|
8,399
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,399
|
|
Accretion of asset retirement obligations
|
|
|
1,370
|
|
|
|
798
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,168
|
|
Rig operations
|
|
|
|
|
|
|
2,088
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,088
|
|
General and administrative expense
|
|
|
20,135
|
|
|
|
7,905
|
|
|
|
|
|
|
|
|
|
|
|
(1,609
|
)a
|
|
|
26,431
|
|
Gain on sale of assets
|
|
|
(1,766
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,766
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
178,720
|
|
|
|
28,871
|
|
|
|
534
|
|
|
|
570
|
|
|
|
1,552
|
|
|
|
210,247
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(27,149
|
)
|
|
|
(3,062
|
)
|
|
|
|
|
|
|
|
|
|
|
145
|
c
|
|
|
(30,066
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(27,149
|
)
|
|
|
(3,062
|
)
|
|
|
|
|
|
|
|
|
|
|
145
|
|
|
|
(30,066
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Provision) for state income tax
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
14,229
|
|
|
$
|
(2,044
|
)
|
|
$
|
3,342
|
|
|
$
|
3,573
|
|
|
$
|
(1,407
|
)
|
|
$
|
17,693
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to the unaudited pro forma condensed consolidated
financial statements.
F-3
UNAUDITED
PRO FORMA CONDENSED CONSOLIDATED
FOR THE
THREE MONTHS ENDED MARCH 31, 2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sydson
|
|
|
TODD
|
|
|
Pro Forma
|
|
|
Pro Forma
|
|
|
|
Alta Mesa
|
|
|
Acquisition
|
|
|
Acquisition
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
1/1-3/31/11
|
|
|
1/1-3/31/11
|
|
|
1/1-3/31/11
|
|
|
(Note 4)
|
|
|
1/1-3/31/11
|
|
|
|
(Dollars in thousands)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, oil and natural gas liquids
|
|
$
|
70,631
|
|
|
$
|
1,030
|
|
|
$
|
1,072
|
|
|
$
|
|
|
|
$
|
72,733
|
|
Other
|
|
|
469
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
469
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
71,100
|
|
|
|
1,030
|
|
|
|
1,072
|
|
|
|
|
|
|
|
73,202
|
|
Unrealized (loss) derivative contracts
|
|
|
(19,184
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19,184
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
51,916
|
|
|
|
1,030
|
|
|
|
1,072
|
|
|
|
|
|
|
|
54,018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
13,331
|
|
|
|
185
|
|
|
|
195
|
|
|
|
|
|
|
|
13,711
|
|
Production, ad valorem and other taxes
|
|
|
5,401
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,401
|
|
Workover expense
|
|
|
1,626
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,626
|
|
Exploration expense
|
|
|
2,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,731
|
|
Depreciation, depletion and amortization
|
|
|
19,468
|
|
|
|
|
|
|
|
|
|
|
|
184
|
b
|
|
|
19,652
|
|
Impairment of oil and natural gas properties
|
|
|
5,826
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,826
|
|
Accretion of asset retirement obligations
|
|
|
470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
470
|
|
Rig obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expense
|
|
|
5,751
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,751
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
54,604
|
|
|
|
185
|
|
|
|
195
|
|
|
|
184
|
|
|
|
55,168
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(9,478
|
)
|
|
|
|
|
|
|
|
|
|
|
(359
|
)c
|
|
|
(9,837
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(9,478
|
)
|
|
|
|
|
|
|
|
|
|
|
(359
|
)
|
|
|
(9,837
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit (provision) for state income tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(12,166
|
)
|
|
$
|
845
|
|
|
$
|
877
|
|
|
$
|
(543
|
)
|
|
$
|
(10,987
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to the unaudited pro forma condensed consolidated
financial statements.
F-4
UNAUDITED
PRO FORMA CONDENSED CONSOLIDATED
MARCH 31,
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sydson
|
|
|
TODD
|
|
|
Pro Forma
|
|
|
Pro Forma
|
|
|
|
Alta Mesa
|
|
|
Acquisition
|
|
|
Acquisition
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(Dollars in thousands)
|
|
|
ASSETS
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
5,527
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
5,527
|
|
Accounts receivable and other current assets
|
|
|
43,837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43,837
|
|
Derivative financial instruments
|
|
|
2,051
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,051
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL CURRENT ASSETS
|
|
|
51,415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
51,415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and gas properties, successful efforts method, net
|
|
|
445,268
|
|
|
|
18,330
|
|
|
|
15,247
|
|
|
|
|
|
|
|
478,845
|
|
Unproved properties, net
|
|
|
9,785
|
|
|
|
10,092
|
|
|
|
8,116
|
|
|
|
|
|
|
|
27,993
|
|
Other property and equipment, net
|
|
|
14,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL PROPERTY AND EQUIPMENT
|
|
|
469,314
|
|
|
|
28,422
|
|
|
|
23,363
|
|
|
|
|
|
|
|
521,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other non-current assets
|
|
|
25,817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,817
|
|
Derivative financial instruments
|
|
|
3,366
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,366
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL OTHER ASSETS
|
|
|
29,183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
549,912
|
|
|
$
|
28,422
|
|
|
$
|
23,363
|
|
|
$
|
|
|
|
$
|
601,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and other current liabilities
|
|
$
|
79,298
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
79,298
|
|
Derivative financial instruments
|
|
|
2,472
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,472
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL CURRENT LIABILITIES
|
|
|
81,770
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
81,770
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, net of current portion
|
|
|
41,270
|
|
|
|
922
|
|
|
|
863
|
|
|
|
|
|
|
|
43,055
|
|
Long-term debt
|
|
|
385,341
|
|
|
|
27,500
|
|
|
|
22,500
|
|
|
|
|
|
|
|
435,341
|
|
Notes payable to founder
|
|
|
20,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,007
|
|
Derivative financial instruments
|
|
|
2,873
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,873
|
|
Other long-term liabilities
|
|
|
6,159
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,159
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL LONG-TERM LIABILITIES
|
|
|
455,650
|
|
|
|
28,422
|
|
|
|
23,363
|
|
|
|
|
|
|
|
507,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES
|
|
|
537,420
|
|
|
|
28,422
|
|
|
|
23,363
|
|
|
|
|
|
|
|
589,205
|
|
PARTNERS CAPITAL
|
|
|
12,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND PARTNERS CAPITAL
|
|
$
|
549,912
|
|
|
$
|
28,422
|
|
|
$
|
23,363
|
|
|
$
|
|
|
|
$
|
601,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to the unaudited pro forma condensed consolidated
financial statements.
F-5
NOTES TO
THE UNAUDITED PRO FORMA CONDENSED
CONSOLIDATED
FINANCIAL STATEMENTS
|
|
1.
|
Description
of Transactions
|
Meridian
Acquisition
On May 13, 2010, Alta Mesa Acquisition Sub, LLC
(AMAS), a newly-formed, wholly-owned subsidiary of
Alta Mesa Holdings, LP (Alta Mesa), acquired 100% of
and merged with The Meridian Resource Corporation
(Meridian), with AMAS as the surviving entity.
Meridian was a publicly traded company engaged in exploration
for and production of oil and natural gas. The oil and gas
properties of Meridian are similar and in some cases proximate
to our areas of operation. Meridian shareholders were paid in
cash, funded by proceeds of our senior secured revolving credit
facility as well as a $50 million equity contribution from
Alta Mesa Investment Holdings Inc., an affiliate of Denham
Commodity Partners Fund IV LP. The merger increased the oil
portion of our reserves portfolio, improving the balance of our
reserves between oil and natural gas, as well as providing us
significant growth potential, significant additions to our
library of
3-D seismic
data, and additional experienced staff.
Sydson
Acquisition
On April 21, 2011, we completed the purchase of certain oil
and natural gas assets primarily located in Texas and South
Louisiana in which we had shared interests from Sydson Energy
and certain of its related parties (together, Sydson
and the Sydson acquisition) for $27.5 million.
Total net proved reserves acquired are estimated to be
800 MBOE (5 Bcfe), 45% of which is oil. By virtue of
this acquisition, we increased our after payout net revenue
interest in the Eagle Ford Shale by over 50%. Funding for the
acquisition was provided through our credit facility. In
addition, litigation associated with a portion of the assets
purchased was resolved as a result of the transaction.
TODD
Acquisition
On June 17, 2011, we completed the purchase of certain oil
and natural gas assets primarily located in Texas and South
Louisiana in which we had shared interests from Texas Oil
Distribution & Development, Inc. and Matrix Petroleum
LLC (together, TODD and the TODD
acquisition) and certain other parties for
$22.5 million. Total net proved reserves acquired are
estimated to be 700 MBOE (4 Bcfe), 36% of which is
oil. By virtue of this acquisition, we increased our after
payout net revenue interest in the Eagle Ford Shale by 15%.
Funding for the acquisition was provided through our credit
facility. In addition, litigation associated with TODD was
resolved as a result of the transaction.
The unaudited pro forma condensed consolidated financial
information was prepared using the acquisition method of
accounting and was based on the historical consolidated
financial statements of Alta Mesa and Meridian as well as
operational data for the Sydson and TODD acquisitions provided
primarily from our own records as operators of the properties we
acquired.
The unaudited pro forma condensed consolidated financial
information was prepared under the existing U.S. GAAP
standards, which are subject to change and interpretation.
Accordingly, the assets acquired and liabilities assumed have
been recorded as of the completion of the transactions primarily
at their respective fair values and added to those of Alta Mesa.
Reported results of operations of Alta Mesa issued after
completion of the transactions will reflect those values.
F-6
NOTES TO
THE UNAUDITED PRO FORMA CONDENSED
CONSOLIDATED
FINANCIAL STATEMENTS (Continued)
|
|
3.
|
Summary
of Consideration and Purchase Price Allocation
|
A summary of the consideration paid and the allocation of the
purchase price follows.
|
|
|
|
|
|
|
Meridian
|
|
|
|
Acquisition
|
|
|
|
(Dollars in thousands)
|
|
|
Summary of consideration:
|
|
|
|
|
Cash
|
|
$
|
30,948
|
|
Debt retired
|
|
|
82,000
|
|
Debt assumed
|
|
|
5,346
|
|
Working capital deficit
|
|
|
753
|
|
Other liabilities assumed
|
|
|
7,971
|
|
Fair value of asset retirement obligations assumed
|
|
|
30,920
|
|
|
|
|
|
|
Total consideration
|
|
$
|
157,938
|
|
|
|
|
|
|
Summary of purchase price allocation:
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
144,325
|
|
Unproved oil and gas properties
|
|
|
3,113
|
|
Other tangible assets
|
|
|
10,500
|
|
|
|
|
|
|
Total purchase price allocation
|
|
$
|
157,938
|
|
|
|
|
|
|
A summary of the consideration paid and the allocation of the
purchase price for Sydson and TODD follows. The Sydson and TODD
allocations are preliminary and may be subject to change.
|
|
|
|
|
|
|
|
|
|
|
Sydson
|
|
|
TODD
|
|
|
|
Acquisition
|
|
|
Acquisition
|
|
|
|
(Dollars in thousands)
|
|
|
Summary of consideration:
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
27,500
|
|
|
$
|
22,500
|
|
Fair value of asset retirement obligations assumed
|
|
|
922
|
|
|
|
863
|
|
|
|
|
|
|
|
|
|
|
Total consideration
|
|
$
|
28,422
|
|
|
$
|
23,363
|
|
|
|
|
|
|
|
|
|
|
Summary of purchase price allocation:
|
|
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
18,330
|
|
|
$
|
15,247
|
|
Unproved oil and gas properties
|
|
|
10,092
|
|
|
|
8,116
|
|
|
|
|
|
|
|
|
|
|
Total purchase price allocation
|
|
$
|
28,422
|
|
|
$
|
23,363
|
|
|
|
|
|
|
|
|
|
|
F-7
NOTES TO
THE UNAUDITED PRO FORMA CONDENSED
CONSOLIDATED
FINANCIAL STATEMENTS (Continued)
This note should be read in conjunction with the preceding notes
above. Adjustments included in the column under the heading
Pro Forma Adjustments represent the following:
(a) To record the conversion of Meridian to the successful
efforts method of accounting from the full cost method of
accounting as follows:
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Three Months Ended
|
|
|
|
December 31, 2010
|
|
|
March 31, 2010
|
|
|
|
(Dollars in thousands)
|
|
|
Recognize exploration costs that had been capitalized under the
full cost method
|
|
$
|
232
|
|
|
$
|
|
|
Reclassify general and administrative costs associated with
exploration activities
|
|
|
1,609
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total exploration costs
|
|
$
|
1,841
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
(b) To adjust depreciation, depletion and amortization
expense as follows:
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Three Months Ended
|
|
|
|
December 31, 2010
|
|
|
March 31, 2011
|
|
|
|
(Dollars in thousands)
|
|
|
Eliminate Meridians historical depreciation, depletion and
amortization expense
|
|
$
|
(10,343
|
)
|
|
$
|
|
|
Estimate of Meridians depreciation, depletion and
amortization expense under the successful efforts method of
accounting
|
|
|
8,077
|
|
|
|
|
|
Estimate of Sydsons depreciation, depletion and
amortization expense under the successful efforts method of
accounting
|
|
|
1,958
|
|
|
|
90
|
|
Estimate of TODDs depreciation, depletion and amortization
expense under the successful efforts method of accounting
|
|
|
1,628
|
|
|
|
94
|
|
|
|
|
|
|
|
|
|
|
Total depreciation, depletion and amortization expense adjustment
|
|
$
|
1,320
|
|
|
$
|
184
|
|
|
|
|
|
|
|
|
|
|
(c) To adjust interest expense to reflect debt incurred by
Alta Mesa to fund acquisitions:
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Three Months Ended
|
|
|
|
December 31, 2010
|
|
|
March 31, 2011
|
|
|
|
(Dollars in thousands)
|
|
|
Eliminate Meridians historical interest expense
|
|
$
|
(3,120
|
)
|
|
$
|
|
|
Estimated interest expense for debt incurred by Alta Mesa to
fund the Meridian acquisition
|
|
|
1,537
|
|
|
|
|
|
Estimated interest expense for debt incurred by Alta Mesa to
fund the Sydson acquisition
|
|
|
791
|
|
|
|
197
|
|
Estimated interest expense for debt incurred by Alta Mesa to
fund the TODD acquisition
|
|
|
647
|
|
|
|
162
|
|
|
|
|
|
|
|
|
|
|
Total interest expense adjustment
|
|
$
|
(145
|
)
|
|
$
|
359
|
|
|
|
|
|
|
|
|
|
|
F-8
NOTES TO
THE UNAUDITED PRO FORMA CONDENSED
CONSOLIDATED
FINANCIAL STATEMENTS (Continued)
|
|
5.
|
Pro
Forma Supplemental Oil and Natural Gas Disclosures
|
The following table sets forth certain unaudited pro forma
information concerning our proved oil and natural gas reserves
at December 31, 2010, giving effect to the Meridian, Sydson
and TODD acquisitions as if they had occurred as of
January 1, 2010. There are numerous uncertainties inherent
in estimating the quantities of proved reserves and projecting
future rates of production and timing of development
expenditures. The following reserve data represents estimates
only and should not be construed as being exact. See Risk
Factors Risks Related to Our Business and the Oil
and Natural Gas Industry. Reserve estimates depend on many
assumptions that may be inaccurate. Any material inaccuracies in
these reserve estimates or underlying assumptions could
materially affect the quantity and present values of our
reserves. All of the reserves are located in the United States.
Proved
Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma(1)
|
|
|
|
Oil
|
|
|
Gas
|
|
|
NGL
|
|
Reserves
|
|
(MBbl)
|
|
|
(MMcf)
|
|
|
(MBbl)
|
|
|
Balance, December 31, 2009
|
|
|
12,004
|
|
|
|
241,598
|
|
|
|
710
|
|
Production
|
|
|
(1,258
|
)
|
|
|
(27,022
|
)
|
|
|
(201
|
)
|
Purchases of reserves in-place
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions, discoveries and improved recovery
|
|
|
3,707
|
|
|
|
24,313
|
|
|
|
211
|
|
Transfers/sales of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
(1,823
|
)
|
|
|
8,732
|
|
|
|
1,103
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2010
|
|
|
12,630
|
|
|
|
247,621
|
|
|
|
1,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
This table combines all proved reserve information for Meridian,
Sydson and TODD with Alta Mesa. The volumes at December 31,
2009 for Meridian, Sydson and TODD were estimated based on the
2009 reserve report for Meridian; the volumes at
December 31, 2010 for Sydson and TODD were estimated based
on the 2010 reserve report for Alta Mesa. The Alta Mesa volumes
at December 31, 2009 and 2010 were based on the
consolidated reserve reports for Alta Mesa. For further
information regarding Alta Mesas reserve reports, see
BUSINESS Our Oil and Natural Gas
Reserves. The Meridian 2009 reserve report was prepared by
T. J. Smith & Company, Inc., independent
petroleum engineers. |
Standardized
Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows
from estimated proved reserves is provided as a common base for
comparing oil and natural gas reserves of enterprises in the
industry and may not represent the fair market value of the oil
and natural gas reserves or the present value of future cash
flow of equivalent reserves due to various uncertainties
inherent in making these estimates. Those factors include
changes in oil and natural gas prices from prices used in the
estimates, unanticipated changes in future production and
development costs and other uncertainties in estimating
quantities and present values of oil and natural gas reserves.
The following table presents the standardized measure of
discounted future pre-tax net cash flow from the ownership
interest in proved oil and natural gas reserves as of
December 31, 2010. The standardized measure of future
pre-tax net cash flow as of December 31, 2010 is calculated
based on average prices as of the first
F-9
NOTES TO
THE UNAUDITED PRO FORMA CONDENSED
CONSOLIDATED
FINANCIAL STATEMENTS (Continued)
day of each of the twelve months ended December 31, 2010 of
$79.43 per Bbl for oil and $4.38 per Mcf for natural gas.
The resulting estimated future pre-tax cash flow is reduced by
estimated future costs to produce the estimated proved reserves
based on actual operating cost levels at December 31, 2010.
The future pre-tax cash flow is reduced to present value by
applying a 10% discount rate.
The standardized measure of estimated discounted future pre-tax
cash flow is not intended to represent the replacement cost or
fair market value of the oil and natural gas properties. Our
standardized measure does not include future federal income tax
expenses or future obligations under the Texas gross margin tax
because we are a partnership and are not subject to federal
income taxes.
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
At December 31,
|
|
|
|
2010
|
|
|
|
(Dollars in thousands)
|
|
|
Future pre-tax cash flow
|
|
$
|
2,124,437
|
|
Future production costs
|
|
|
(635,449
|
)
|
Future development costs
|
|
|
(265,311
|
)
|
|
|
|
|
|
Future pre-tax net cash flow
|
|
|
1,223,677
|
|
Effect of discounting future annual pre-tax net cash flow at 10%
|
|
|
(489,912
|
)
|
|
|
|
|
|
Discounted future pre-tax net cash flow
|
|
$
|
733,765
|
|
|
|
|
|
|
F-10
Report
of Independent Registered Public Accounting Firm
To the Partners of
Alta Mesa Holdings, LP and Subsidiaries
Houston, Texas
We have audited the accompanying consolidated balance sheets of
Alta Mesa Holdings, LP and Subsidiaries (the
Company) as of December 31, 2010 and 2009, and
the related consolidated statements of operations, changes in
partners capital and cash flows for each of the three
fiscal years in the period ended December 31, 2010. These
consolidated financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these consolidated financial statements based on our
audits.
We conducted our audits in accordance with standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audits to obtain
reasonable assurance about whether the consolidated financial
statements are free of material misstatement. The Company is not
required to have, nor were we engaged to perform, an audit of
its internal control over financial reporting. Our audit
included consideration of internal control over financial
reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the Companys
internal control over financial reporting. Accordingly, we
express no such opinion. An audit also includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the consolidated financial statements. An audit also includes
assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
consolidated 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
consolidated financial position of the Company as of
December 31, 2010 and 2009, and the consolidated results of
their operations and their cash flows for each of the three
fiscal years in the period ended December 31, 2010, in
conformity with accounting principles generally accepted in the
United States of America.
/s/ UHY LLP
Houston, Texas
March 31, 2011
F-11
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
ASSETS
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
4,836
|
|
|
$
|
4,274
|
|
Accounts receivable, net
|
|
|
38,081
|
|
|
|
19,291
|
|
Other receivables
|
|
|
6,338
|
|
|
|
1,726
|
|
Prepaid expenses and other current assets
|
|
|
2,292
|
|
|
|
148
|
|
Derivative financial instruments
|
|
|
10,436
|
|
|
|
8,374
|
|
|
|
|
|
|
|
|
|
|
TOTAL CURRENT ASSETS
|
|
|
61,983
|
|
|
|
33,813
|
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Proved oil and gas properties, successful efforts method, net
|
|
|
433,546
|
|
|
|
225,965
|
|
Unproved properties, net
|
|
|
9,334
|
|
|
|
8,351
|
|
Land
|
|
|
1,185
|
|
|
|
1,185
|
|
Drilling rig, net
|
|
|
10,056
|
|
|
|
|
|
Other property and equipment, net
|
|
|
2,143
|
|
|
|
695
|
|
|
|
|
|
|
|
|
|
|
TOTAL PROPERTY AND EQUIPMENT, NET
|
|
|
456,264
|
|
|
|
236,196
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
Investment in Partnership cost
|
|
|
9,000
|
|
|
|
9,000
|
|
Deferred financing costs, net
|
|
|
13,552
|
|
|
|
1,451
|
|
Derivative financial instruments
|
|
|
14,165
|
|
|
|
7,929
|
|
Advances to operators
|
|
|
2,699
|
|
|
|
1,613
|
|
Deposits
|
|
|
576
|
|
|
|
604
|
|
|
|
|
|
|
|
|
|
|
TOTAL OTHER ASSETS
|
|
|
39,992
|
|
|
|
20,597
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
558,239
|
|
|
$
|
290,606
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
87,255
|
|
|
$
|
32,629
|
|
Current portion, asset retirement obligations
|
|
|
1,617
|
|
|
|
|
|
Derivative financial instruments
|
|
|
3,092
|
|
|
|
3,861
|
|
|
|
|
|
|
|
|
|
|
TOTAL CURRENT LIABILITIES
|
|
|
91,964
|
|
|
|
36,490
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM LIABILITIES
|
|
|
|
|
|
|
|
|
Asset retirement obligations, net of current portion
|
|
|
41,096
|
|
|
|
10,267
|
|
Long-term debt
|
|
|
371,276
|
|
|
|
201,500
|
|
Notes payable to founder
|
|
|
19,709
|
|
|
|
18,330
|
|
Derivative financial instruments
|
|
|
2,296
|
|
|
|
4,203
|
|
Other long-term liabilities
|
|
|
7,240
|
|
|
|
9,152
|
|
|
|
|
|
|
|
|
|
|
TOTAL LONG-TERM LIABILITIES
|
|
|
441,617
|
|
|
|
243,452
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES
|
|
|
533,581
|
|
|
|
279,942
|
|
COMMITMENTS AND CONTINGENCIES (NOTE 11)
|
|
|
|
|
|
|
|
|
PARTNERS CAPITAL
|
|
|
24,658
|
|
|
|
10,664
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND PARTNERS CAPITAL
|
|
$
|
558,239
|
|
|
$
|
290,606
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
F-12
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(Dollars in thousands)
|
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
$
|
125,866
|
|
|
$
|
66,290
|
|
|
$
|
58,458
|
|
Oil
|
|
|
75,827
|
|
|
|
34,283
|
|
|
|
38,055
|
|
Natural gas liquids
|
|
|
6,844
|
|
|
|
1,690
|
|
|
|
2,470
|
|
Sale of oil and gas prospects
|
|
|
666
|
|
|
|
364
|
|
|
|
502
|
|
Other revenues
|
|
|
809
|
|
|
|
1,194
|
|
|
|
3,127
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
210,012
|
|
|
|
103,821
|
|
|
|
102,612
|
|
Unrealized gain (loss) oil and natural gas
derivative contracts
|
|
|
10,088
|
|
|
|
(26,258
|
)
|
|
|
60,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL REVENUES
|
|
|
220,100
|
|
|
|
77,563
|
|
|
|
163,224
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease and plant operating expense
|
|
|
41,905
|
|
|
|
23,871
|
|
|
|
20,658
|
|
Production and ad valorem taxes
|
|
|
11,141
|
|
|
|
4,755
|
|
|
|
6,954
|
|
Workover expense
|
|
|
7,409
|
|
|
|
8,988
|
|
|
|
8,113
|
|
Exploration expense
|
|
|
31,037
|
|
|
|
12,839
|
|
|
|
11,675
|
|
Depreciation, depletion, and amortization
|
|
|
59,090
|
|
|
|
48,659
|
|
|
|
49,219
|
|
Impairment expense
|
|
|
8,399
|
|
|
|
6,165
|
|
|
|
11,487
|
|
Accretion expense
|
|
|
1,370
|
|
|
|
492
|
|
|
|
729
|
|
General and administrative expense
|
|
|
20,135
|
|
|
|
8,738
|
|
|
|
6,401
|
|
Gain on sale of assets
|
|
|
(1,766
|
)
|
|
|
(738
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL EXPENSES
|
|
|
178,720
|
|
|
|
113,769
|
|
|
|
115,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) FROM OPERATIONS
|
|
|
41,380
|
|
|
|
(36,206
|
)
|
|
|
47,988
|
|
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(27,172
|
)
|
|
|
(13,835
|
)
|
|
|
(14,497
|
)
|
Interest income
|
|
|
23
|
|
|
|
4
|
|
|
|
40
|
|
Gain on extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
3,349
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL OTHER INCOME (EXPENSE)
|
|
|
(27,149
|
)
|
|
|
(13,831
|
)
|
|
|
(11,108
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) BEFORE STATE INCOME TAXES
|
|
|
14,231
|
|
|
|
(50,037
|
)
|
|
|
36,880
|
|
BENEFIT FROM (PROVISION FOR) STATE INCOME TAXES
|
|
|
(2
|
)
|
|
|
750
|
|
|
|
(250
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
|
$
|
14,229
|
|
|
$
|
(49,287
|
)
|
|
$
|
36,630
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
F-13
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
YEARS
ENDED DECEMBER 31, 2010, 2009, AND 2008
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
BALANCE, DECEMBER 31, 2007
|
|
$
|
(11,661
|
)
|
CONTRIBUTIONS
|
|
|
14,700
|
|
DISTRIBUTIONS
|
|
|
(1,918
|
)
|
NET INCOME
|
|
|
36,630
|
|
|
|
|
|
|
BALANCE, DECEMBER 31, 2008
|
|
|
37,751
|
|
CONTRIBUTIONS
|
|
|
27,800
|
|
DISTRIBUTIONS
|
|
|
(100
|
)
|
REDEMPTION OF PARTNERSHIP INTEREST
|
|
|
(5,500
|
)
|
NET LOSS
|
|
|
(49,287
|
)
|
|
|
|
|
|
BALANCE, DECEMBER 31, 2009
|
|
|
10,664
|
|
CONTRIBUTIONS
|
|
|
50,000
|
|
DISTRIBUTIONS
|
|
|
(50,235
|
)
|
NET INCOME
|
|
|
14,229
|
|
|
|
|
|
|
BALANCE, DECEMBER 31, 2010
|
|
$
|
24,658
|
|
|
|
|
|
|
See notes to consolidated financial statements.
F-14
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(Dollars in thousands)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
14,229
|
|
|
$
|
(49,287
|
)
|
|
$
|
36,630
|
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
59,090
|
|
|
|
48,659
|
|
|
|
49,219
|
|
Impairment expense
|
|
|
8,399
|
|
|
|
6,165
|
|
|
|
11,487
|
|
Accretion expense
|
|
|
1,370
|
|
|
|
492
|
|
|
|
729
|
|
Gain on extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
(3,349
|
)
|
Gain on sales of assets
|
|
|
(1,766
|
)
|
|
|
(738
|
)
|
|
|
|
|
Dry hole expense
|
|
|
15,834
|
|
|
|
244
|
|
|
|
1,504
|
|
Expired leases
|
|
|
|
|
|
|
918
|
|
|
|
578
|
|
Amortization of loan costs
|
|
|
4,240
|
|
|
|
772
|
|
|
|
288
|
|
Unrealized (gain) loss on derivatives
|
|
|
(10,974
|
)
|
|
|
25,308
|
|
|
|
(55,708
|
)
|
Interest converted into debt
|
|
|
1,379
|
|
|
|
1,191
|
|
|
|
1,194
|
|
Settlement of asset retirement obligation
|
|
|
(453
|
)
|
|
|
(97
|
)
|
|
|
(66
|
)
|
Deferred state tax (benefit) expense
|
|
|
|
|
|
|
(750
|
)
|
|
|
250
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(9,255
|
)
|
|
|
(7,416
|
)
|
|
|
2,458
|
|
Other receivables
|
|
|
(4,612
|
)
|
|
|
1,192
|
|
|
|
(2,918
|
)
|
Prepaid expenses and other assets
|
|
|
(3,305
|
)
|
|
|
2,738
|
|
|
|
(3,280
|
)
|
Accounts payable, accrued liabilities and other long-term
liabilities
|
|
|
(13,056
|
)
|
|
|
4,952
|
|
|
|
(18,716
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY OPERATING ACTIVITIES
|
|
|
61,120
|
|
|
|
34,343
|
|
|
|
20,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures for property and equipment
|
|
|
(110,083
|
)
|
|
|
(100,261
|
)
|
|
|
(111,096
|
)
|
Acquisition of The Meridian Resource Company
|
|
|
(101,359
|
)
|
|
|
|
|
|
|
|
|
Proceeds from sale of assets
|
|
|
3,030
|
|
|
|
13,688
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH USED IN INVESTING ACTIVITIES
|
|
|
(208,412
|
)
|
|
|
(86,573
|
)
|
|
|
(111,096
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
|
584,486
|
|
|
|
37,380
|
|
|
|
69,370
|
|
Repayments of long-term debt
|
|
|
(420,056
|
)
|
|
|
(6,969
|
)
|
|
|
(2,231
|
)
|
Proceeds from short-term debt
|
|
|
|
|
|
|
8,000
|
|
|
|
|
|
Repayments of short-term debt
|
|
|
|
|
|
|
(8,000
|
)
|
|
|
|
|
Additions to deferred financing costs
|
|
|
(16,341
|
)
|
|
|
(788
|
)
|
|
|
(1,150
|
)
|
Capital contributions from partners
|
|
|
50,000
|
|
|
|
27,800
|
|
|
|
14,700
|
|
Redemption of partnership interest
|
|
|
|
|
|
|
(5,500
|
)
|
|
|
|
|
Distributions to partners
|
|
|
(50,235
|
)
|
|
|
(100
|
)
|
|
|
(1,918
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY FINANCING ACTIVITIES
|
|
|
147,854
|
|
|
|
51,823
|
|
|
|
78,771
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
|
|
562
|
|
|
|
(407
|
)
|
|
|
(12,025
|
)
|
CASH AND CASH EQUIVALENTS, beginning of year
|
|
|
4,274
|
|
|
|
4,681
|
|
|
|
16,706
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, end of year
|
|
$
|
4,836
|
|
|
$
|
4,274
|
|
|
$
|
4,681
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year for interest
|
|
$
|
21,537
|
|
|
$
|
9,064
|
|
|
$
|
7,802
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year for taxes
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in property and equipment asset retirement obligations,
net
|
|
$
|
609
|
|
|
$
|
162
|
|
|
$
|
1,067
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures financed through accounts payable and
accrued liabilities
|
|
$
|
36,025
|
|
|
$
|
3,382
|
|
|
$
|
19,233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
F-15
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
YEARS
ENDED DECEMBER 31, 2010, 2009 AND 2008
|
|
NOTE 1
|
SUMMARY
OF ORGANIZATION AND NATURE OF OPERATIONS
|
Organization. The consolidated
financial statements presented herein are of Alta Mesa Holdings,
LP and its (i) wholly-owned subsidiaries: Alta Mesa Finance
Services Corp., Alta Mesa Acquisition Sub, LLC and its direct
and indirect wholly-owned subsidiaries, Aransas Resources, LP
and its wholly-owned subsidiary ARI Development, L.L.C., Brayton
Resources II, LP, Buckeye Production Company, LP, Galveston Bay
Resources, LP, Louisiana Exploration & Acquisitions,
LP and its wholly-owned subsidiary Louisiana
Exploration & Acquisition Partnership, LLC, Navasota
Resources, Ltd., LLP, Nueces Resources, LP, Oklahoma Energy
Acquisitions, LP, Alta Mesa Drilling, LLC, Petro Acquisitions,
LP, Petro Operating Company, LP, Texas Energy Acquisitions, LP,
Virginia Oil and Gas, LLC and Alta Mesa Services, LP, and
(ii) partially-owned subsidiaries: Brayton Resources, LP,
and Orion Operating Company, LP. The entities above are
collectively referred to as the Company.
Nature of Operations. The Company is
engaged primarily in the acquisition, exploration, development,
and production of oil and gas properties. The Companys
properties are located in Texas, Oklahoma, Louisiana, Florida
and the Appalachian Region.
Accounting policies used by the Company and its subsidiaries
reflect industry practices and conform to accounting principles
generally accepted in the U.S. (GAAP). As used
herein, the following acronyms have the following meanings:
FASB means the Financial Accounting Standards Board;
the Codification refers to the Accounting Standards
Codification, the collected accounting and reporting guidance
maintained by the FASB; ASC means Accounting
Standards Codification and is generally followed by a number
indicating a particular section of the Codification; and
ASU means Accounting Standards Update, followed by
an identification number, which are the periodic updates made to
the Codification by the FASB. SEC means the
Securities and Exchange Commission.
|
|
NOTE 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. The Companys
interest in oil and gas exploration and production ventures and
partnerships are proportionately consolidated.
Use of Estimates. The preparation of
consolidated financial statements in conformity with GAAP
requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the consolidated financial statements and the reported amounts
of revenues and expenses during the reporting period.
Reserve estimates significantly impact depreciation, depletion
and amortization expense and potential impairments of oil and
natural gas properties and are subject to change based on
changes in oil and natural gas prices and trends and changes in
estimated reserve quantities. We analyze estimates, including
those related to oil and natural gas reserves, the value of oil
and natural gas properties, oil and natural gas revenues, bad
debts, asset retirement obligations, derivative contracts,
income taxes and contingencies. We base our estimates on
historical experience and various other assumptions that are
believed to be reasonable under the circumstances. Actual
results may differ from these estimates.
Cash and Cash Equivalents. We consider
all highly liquid investments purchased with an original
maturity of three months or less to be cash equivalents. The
Company maintains cash balances at financial institutions in the
United States of America, which at times exceed federally
insured amounts. In July 2010, the Federal Deposit Insurance
Corporation permanently increased its insurance to $250,000 per
depositor. Additionally, coverage for non-interest bearing
accounts, which is temporary, extends through December 31,
2012. This coverage is separate from, and in addition to, the
coverage provided for other accounts held at an
F-16
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
insured depository institution. We monitor the financial
condition of the financial institutions and have experienced no
losses associated with these accounts.
Accounts Receivable. The Companys
receivables arise from the sale of oil and gas to third parties
and joint interest owner receivables for properties in which we
serve as the operator. This concentration of customers may
impact our overall credit risk, either positively or negatively,
in that these entities may be similarly affected by changes in
economic or other conditions affecting the oil and gas industry.
Accounts receivable are generally not collateralized.
Allowance for Doubtful Accounts. We
routinely assess the recoverability of all material trade and
other receivables to determine their collectability. We accrue a
reserve when, based on the judgment of management, it is
probable that a receivable will not be collected and the amount
of the reserve can be reasonably estimated. Accounts receivable
are shown net of allowance for doubtful accounts of $338,000 and
$177,000 as of December 31, 2010 and 2009, respectively.
Deferred Financing Costs. Deferred financing costs
and the amount of discount at which notes payable have been
issued (debt discount) are amortized using the straight-line
method, which approximates the interest method, over the term of
the related debt. For the years ended December 31, 2010,
2009, and 2008, amortization of deferred financing costs
included in interest expense amounted to $4.2 million,
$772,000, and $288,000, respectively. Deferred financing costs
are listed among our long-term assets, net of accumulated
amortization of $4.7 million and $437,000 at
December 31, 2010 and 2009, respectively.
Property and Equipment. Oil and gas
producing activities are accounted for using the successful
efforts method of accounting. Under the successful efforts
method, lease acquisition costs and all development costs,
including unsuccessful development wells, are capitalized.
Unproved Properties Acquisition costs
associated with the acquisition of leases are recorded as
unproved leasehold costs and capitalized as incurred. These
consist of costs incurred in obtaining a mineral interest or
right in a property, such as a lease in addition to options to
lease, broker fees, recording fees and other similar costs
related to activities in acquiring properties. Leasehold costs
are classified as unproved until proved reserves are discovered,
at which time related costs are transferred to proved oil and
gas properties.
Exploration Expense Exploration expenses,
other than exploration drilling costs, are charged to expense as
incurred. These expenses include seismic expenditures and other
geological and geophysical costs, expired leases, and lease
rentals. The costs of drilling exploratory wells and
exploratory-type stratigraphic wells are initially capitalized
pending determination of whether the well has discovered proved
commercial reserves. If the exploratory well is determined to be
unsuccessful, the cost of the well is transferred to expense.
Exploratory well drilling costs may continue to be capitalized
if the reserve quantity is sufficient to justify completion as a
producing well and sufficient progress in assessing the reserves
and the economic and operating viability of the project is being
made. Assessments of such capitalized costs are made quarterly.
Proved Oil and Gas Properties Costs incurred
to obtain access to proved reserves and to provide facilities
for extracting, treating, gathering, and storing oil and gas are
capitalized. All costs incurred to drill and equip successful
exploratory wells, development wells, development-type
stratigraphic test wells, and service wells, including
unsuccessful development wells, are capitalized.
Impairment The capitalized costs of proved
oil and gas properties are reviewed at least annually for
impairment in accordance with
ASC 360-10-35,
Property, Plant and Equipment, Subsequent
Measurement, or whenever events or changes in
circumstances indicate that the carrying amount of a long-lived
asset or asset group exceeds its fair market value and is not
recoverable. The determination of recoverability is based on
comparing the estimated undiscounted future net cash flows at a
producing field level to the carrying value of the assets. If
the future undiscounted cash flows, based on estimates of
anticipated production from proved reserves and future crude oil
and natural gas prices and operating costs, are lower than the
carrying cost, the
F-17
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
carrying cost of the asset or group of assets is reduced to fair
value. For our proved oil and natural gas properties, we
estimate fair value by discounting the projected future cash
flows at an appropriate risk-adjusted discount rate. Our
evaluation of the Companys proved producing properties
resulted in impairment expense of $6.4 million,
$3.1 million, and $10.4 million for the years ended
December 31, 2010, 2009, and 2008, respectively.
In addition, the Company recorded as impairment expense,
write-downs of casing and tubing to lower of cost or market, of
$18,000, $2.4 million and $80,000 for the years ended
December 31, 2010, 2009 and 2008, respectively.
Unproved leasehold costs are assessed at least annually to
determine whether they have been impaired. Individually
significant properties are assessed for impairment on a
property-by-property
basis, while individually insignificant unproved leasehold costs
may be assessed in the aggregate. If unproved leasehold costs
are found to be impaired, an impairment allowance is provided
and a loss is recognized in the statement of operations. For the
years ended December 31, 2010, 2009 and 2008, impairment
expense of unproved leasehold costs was $2.0 million,
$696,000, and $225,000, respectively.
Management evaluates whether the carrying value of all other
long-lived assets has been impaired when circumstances indicate
the carrying value of those assets may not be recoverable. This
evaluation is based on undiscounted cash flow projections. The
carrying amount is not recoverable if it exceeds the
undiscounted sum of cash flows expected to result from the use
and eventual disposition of the assets. Management considers
various factors when determining if these assets should be
evaluated for impairment.
If the carrying value is not recoverable on an undiscounted
basis, the impairment loss is measured as the excess of the
assets carrying value over its fair value. Management
assesses the fair value of long-lived assets using commonly
accepted techniques, and may use more than one method,
including, but not limited to, recent third party comparable
sales, internally developed discounted cash flow analysis and
analysis from outside advisors. Significant changes in market
conditions resulting from events such as the condition of an
asset or a change in managements intent to utilize the
asset would generally require management to reassess the cash
flows related to the long-lived assets. For the years ended
December 31, 2010, 2009, and 2008, respectively, the
Company did not record any impairment expense related to other
long-lived assets.
Depreciation, Depletion and Amortization
Depreciation, depletion, and amortization
(DD&A) of capitalized costs of proved oil and
gas properties is computed using the
unit-of-production
method based upon estimated proved reserves. Assets are grouped
for DD&A on the basis of reasonable aggregation of
properties with a common geological structural feature or
stratigraphic condition, such as a reservoir or field. The
reserve base used to calculate DD&A for leasehold
acquisition costs and the cost to acquire proved properties is
the sum of proved developed reserves and proved undeveloped
reserves. The reserve base used to calculate DD&A for lease
and well equipment costs, which include development costs and
successful exploration drilling costs, includes only proved
developed reserves.
DD&A expense for the years ended December 31, 2010,
2009, and 2008 related to oil and gas properties was
$58.2 million, $47.3 million, and $47.9 million,
respectively.
The Companys drilling rigs, one of which was sold in
December 2009, and the other of which was acquired in connection
with the acquisition of The Meridian Resource Corporation
(Meridian) in May 2010, have been depreciated using
the straight-line method of depreciation over a period of
approximately fifteen years. Depreciation expense of the rigs
for the years ended December 31, 2010, 2009, and 2008 was
$444,000, $930,000, and $930,000, respectively.
Other property and equipment is depreciated using the
straight-line method over periods ranging from three to seven
years. Depreciation expense for other property and equipment for
the years ended December 31, 2010, 2009, and 2008 was
$494,000, $468,000, and $421,000 respectively.
F-18
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Investment. The Companys
investment consists of a 10% ownership interest in a drilling
company, Orion Drilling Company, LP (Orion). The
investment is accounted for under the cost method. Under this
method, the Companys share of earnings or losses of the
investment are not included in the statements of operations.
Distributions from Orion are recognized in current period
earnings as declared. For the years ended December 31,
2010, 2009, and 2008, distributions of $735,000, $957,000, and
$1.7 million respectively, were included in Other
revenues in the Consolidated Statements of Operations.
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. We follow ASC 410,
Asset Retirement and Environmental Obligations.
ASC 410 requires that an asset retirement obligation
(ARO) associated with the retirement of a tangible
long-lived asset be recognized as a liability in the period in
which it is incurred or becomes determinable (as defined by the
ASC), with an associated increase in the carrying amount of the
related long-lived asset. The cost of the tangible asset,
including the initially recognized asset retirement cost, is
depreciated over the useful life of the asset and accretion
expense is recognized over time as the discounted liability is
accreted to its expected settlement value. The fair value of new
AROs are measured using expected future cash outflows for
abandonment discounted generally at our cost of capital at the
time of recognition.
Derivative Financial Instruments. We
use derivative contracts to hedge the effects of fluctuations in
the prices of oil, natural gas and interest rates. We account
for such derivative instruments in accordance with ASC 815,
Derivatives and Hedging, which establishes
accounting and disclosure requirements for derivative
instruments and requires them to be measured at fair value and
recorded as assets or liabilities in the statements of financial
position (see Note 5 for information on fair value).
Under ASC 815, hedge accounting is used to defer
recognition of unrealized changes in the fair value of such
financial instruments, for those contracts which qualify as fair
value or cash flow hedges, as defined in the guidance.
Historically, we have not designated any of our derivative
contracts as fair value or cash flow hedges. Accordingly, the
unrealized changes in fair value of the contracts are included
in earnings in the period of the change as Unrealized gain
(loss) oil and natural gas derivative
contracts for oil and gas contracts, and in interest
expense for interest derivative contracts. Realized gains and
losses are recorded in income in the period of settlement, and
included in the related revenue account or in interest expense.
Cash flows from settlements of derivative contracts are
classified with the income or expense item to which such
settlements directly relate.
Income Taxes. The Company has elected
under the Internal Revenue Code provisions to be treated as
individual partnerships for tax purposes. Accordingly, items of
income, expense, gains and losses flow through to the partners
and are taxed at the partner level. Accordingly, no tax
provision for federal income taxes is included in the
consolidated financial statements.
The Company is subject to the Texas margin tax, which is
considered a state income tax, and is included in Benefit
from (provision for) state income tax on the consolidated
statements of operations. The Company records state income tax
(current and deferred) based on taxable income, as defined under
the rules for the margin tax.
Effective January 1, 2009 we adopted guidance issued by the
FASB in accounting for uncertainty in income taxes. This
guidance clarifies the accounting for income taxes by
prescribing the minimum recognition threshold an income tax
position is required to meet before being recognized in the
consolidated financial statements and applies to all income tax
positions. Each income tax position is assessed using a two step
process. A determination is first made as to whether it is more
likely than not that the income tax position will be sustained,
based upon technical merits, upon examination by the taxing
authorities. If the income tax
F-19
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
position is expected to meet the more likely than not criteria,
the benefit recorded in the consolidated financial statements
equals the largest amount that is greater than 50% likely to be
realized upon its ultimate settlement.
Management has considered the Companys exposure under the
standard at both the federal and state tax levels. We did not
recognize any uncertain tax positions upon adoption of the
guidance and had no uncertain tax positions as of
December 31, 2010. Upon adoption of this guidance, we
elected to record income tax, related interest, and penalties,
if any, as a component of income tax expense. We did not incur
any interest or penalties for the years ended December 31,
2010 and 2009, respectively.
The Companys tax returns for the year ended
December 31, 2007 forward remain open for examination. None
of the Companys federal or state tax returns are currently
under examination by the relevant authorities.
Revenue Recognition. We recognize oil,
gas and natural gas liquids revenues when products are delivered
at a fixed or determinable price, title has transferred and
collectability is reasonably assured (sales method). Revenue
from drilling rigs has been recorded when services were
performed.
Financial Instruments. The fair value
of cash, accounts receivable and current liabilities approximate
book value due to their short-term nature. The estimate of fair
value of long-term debt under our credit facility is not
considered to be materially different from carrying value due to
market rates of interest. The fair value of the debt to our
founder is not practicable to determine. We have estimated the
fair value of our senior notes payable at $291 million on
December 31, 2010. See Note 5 for further information
on fair values of financial instruments. See Note 9 for
information on long-term debt.
Acquisitions. Acquisitions are
accounted for as purchases and, accordingly, the results of
operations are included in our consolidated statements of
operations from the closing date of the acquisitions. Purchase
prices are allocated to acquired assets and assumed liabilities
based on their estimated fair value at the time of the
acquisition.
Reclassifications. Certain amounts in
the 2009 and 2008 consolidated financial statements have been
reclassified to conform to the 2010 presentation.
Recent
Accounting Pronouncements
In January 2010, the FASB updated Topic 820 with 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. We
adopted the new guidance effective January 1, 2010. The
adoption had no material impact on our consolidated financial
position or results of operations.
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
F-20
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
became effective for reserve reports as of December 31,
2009; the FASB incorporated the new guidance into the
Codification as ASU
2010-03,
effective also on December 31, 2009, ASC Topic 932,
Extractive Activities Oil and Gas.
We adopted the new guidance effective December 31, 2009;
information about our reserves has been prepared in accordance
with the new guidance and is included in Note 19. As of
December 31, 2009, our reserves calculations were affected
primarily by the use of the average prices rather than the
period-end prices required under the prior rules. The changes
resulting from the new rules did not significantly impact our
impairment testing, depreciation, depletion and amortization
expense, or other results of operations.
In December 2009, the FASB issued revised authoritative guidance
regarding consolidation of variable interest entities
(VIEs) 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
VIEs, rather than only when specific events occur. The revised
guidance also requires additional disclosures about consolidated
and unconsolidated VIEs, including their impact on the
companys risk exposure and its financial statements. The
revised guidance is effective for financial statements for
annual and interim periods beginning after November 15,
2009. We adopted the new guidance effective January 1,
2010. The adoption did not have a material impact on our
consolidated 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 was effective for interim and annual periods ending
after June 15, 2009, with early adoption permitted for
periods ending after March 15, 2009. We adopted the new
guidance effective April 1, 2009. The adoption did not have
a material impact on our consolidated financial position or
results of operations of the Company. The disclosures are
included above, Financial Instruments.
In May 2009, the FASB issued SFAS 165, Subsequent
Events, codified in ASC 855. ASC 855 defines the
period during which management should evaluate events or
transactions that occur after the balance sheet date for
potential recognition or disclosure in the financial statements,
the circumstances under which an entity should recognize events
or transactions occurring after the balance sheet date, and the
disclosures about such subsequent events. It did not
substantially change existing guidance, but added a new
disclosure of the date through which events have been evaluated
and whether that is the date of issuance of the financial
statements or an alternate date. The new guidance was effective
for interim or annual financial periods ending after
June 15, 2009. We adopted the new guidance effective
June 30, 2009; the adoption did not have a material impact
on the consolidated financial position or results of operations
of the Company. The disclosures are included in Note 16.
On and effective May 13, 2010, Alta Mesa Acquisition Sub,
LLC (AMAS), a wholly owned subsidiary of the
Company, acquired 100% of the shares of and merged with The
Meridian Resource Corporation (Meridian), with AMAS
as the surviving entity. Meridian was a publicly traded company
engaged in exploration for and production of oil and natural
gas. The oil and natural gas properties of Meridian are similar
and in some cases proximate to our areas of operation. Meridian
shareholders were paid in cash, funded by proceeds of our senior
secured revolving credit facility as well as a $50 million
equity contribution from our private equity partner Alta Mesa
Investment Holdings Inc., an affiliate of Denham Commodities
Partners Fund IV LP (AMIH). The merger
increased the oil portion of our reserves portfolio, improving
the
F-21
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
balance of our reserves between oil and natural gas, and
provided significant additions to our library of
3-D seismic
data.
Total cost of the acquisition was $158 million. It was
recorded using the acquisition method of accounting. The
purchase price was allocated to acquired assets and assumed
liabilities based on their estimated fair values at date of
acquisition. Acquisition-related costs of approximately $532,000
were recorded in general and administrative expense for the year
ended December 31, 2010.
A summary of the consideration paid and the preliminary
allocation of the purchase price is as follows
(dollars in thousands):
|
|
|
|
|
Summary of Consideration:
|
|
|
|
|
Cash
|
|
$
|
30,948
|
|
Debt retired
|
|
|
82,000
|
|
Debt assumed
|
|
|
5,346
|
|
Working capital deficit(1)
|
|
|
753
|
|
Other liabilities assumed
|
|
|
7,971
|
|
Fair value of asset retirement obligations assumed
|
|
|
30,920
|
|
|
|
|
|
|
Total
|
|
$
|
157,938
|
|
|
|
|
|
|
Summary of Purchase Price Allocation:
|
|
|
|
|
Proved oil and natural gas properties
|
|
$
|
144,325
|
|
Unproved oil and natural gas properties
|
|
|
3,113
|
|
Other tangible assets
|
|
|
10,500
|
|
|
|
|
|
|
Total
|
|
$
|
157,938
|
|
|
|
|
|
|
|
|
|
(1) |
|
Working capital deficit included a cash balance of $11,589. |
The revenue and earnings related to this acquisition are
included in our consolidated statement of operations for the
year ended December 31, 2010 from date of acquisition. The
revenue and earnings of the combined entity, had the acquisition
occurred at the beginning of each of the periods presented, are
provided below. This unaudited pro forma information has been
derived from historical information and is for illustrative
purposes only. The unaudited pro forma financial information
does not attempt to predict or suggest future results. It also
does not necessarily reflect what the historical results of the
combined company would have been had the companies been combined
during these periods.
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
Income
|
|
|
Revenue
|
|
(Loss)
|
|
|
(Dollars in thousands)
|
|
Actual results of Meridian included in our consolidated
statement of operations for the period from May 13, 2010
through December 31, 2010
|
|
$
|
58,661
|
|
|
$
|
13,136
|
|
Pro forma results for the combined entity for the year ended
December 31, 2010
|
|
$
|
249,989
|
|
|
$
|
15,802
|
|
Pro forma results for the combined entity for the year ended
December 31, 2009
|
|
$
|
166,802
|
|
|
$
|
(47,693
|
)
|
Adjustments to actual historical earnings for Meridian include
the effect of conversion from the full cost of method of
accounting for oil and natural gas properties to the successful
efforts method, as well as revision of depreciation, depletion
and amortization based on acquisition date values for the oil
and natural gas
F-22
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
properties. Adjustments to Meridians actual historical
earnings also include removal of interest expense related to
debt retired by the Company on the date of acquisition.
Adjustments to actual earnings for the Company include
additional interest expense for debt incurred to fund the
acquisition.
On July 23, 2009, Navasota Resources Ltd., LLP, a
wholly-owned subsidiary of the Company, made a payment of
$25.5 million and took assignment of substantially all
working interests that had been held by Chesapeake Energy
Corporation (Chesapeake) in an approximate
50,000 acre area of Leon and Robertson Counties, Texas in
the Deep Bossier play. We had exercised our preferential right
to purchase these interests from Gastar Exploration Ltd.
(Gastar) in late 2005, but Gastar and Chesapeake had
opposed this and Chesapeake took record title until we finally
and conclusively prevailed, and in 2008 a Texas court of appeals
directed that specific performance take place. In early 2009,
the Texas Supreme Court denied the defendants request to
hear the appeal. As a result, we were able to take
25% 33% working interests in over 30 producing wells
and participate in further development of the area, primarily
with EnCana Oil and Gas (USA) (EnCana), but also
with Gastar. A subsequent payment to EnCana of
$15.2 million plus purchase accounting adjustments of
$3.8 million brought the total cost of the acquisition to
$44.5 million. The purchase price was financed with equity
contributions by our private equity partner and borrowings under
our senior credit facility. All consideration was allocated to
oil and gas properties; $44.3 million was recorded as
proved oil and gas properties and $0.2 million was recorded
as unproved oil and gas properties.
Acquisition-related costs of approximately $481,000 were
recorded in general and administrative expense for the year
ended December 31, 2009.
The revenue and earnings related to this acquisition included in
our consolidated statement of operations for the year ended
December 31, 2009, and the revenue and earnings of the
combined entity had the acquisition occurred at the beginning of
2009 are provided below. This unaudited pro forma information
has been derived from historical information provided by the
operators of the properties and is for illustrative purpose
only. Pro forma adjustments include an adjustment for DD&A.
The unaudited pro forma financial information does not attempt
to predict or suggest future results. It also does not
necessarily reflect what the historical results of the combined
company would have been had the companies been combined during
these periods.
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
Income
|
|
|
Revenues
|
|
(Loss)
|
|
|
(Dollars in thousands)
|
|
Actual results for the acquired properties included in our
consolidated statement of operations for the year ended
December 31, 2009(1)
|
|
$
|
11,277
|
|
|
$
|
4,853
|
|
Pro forma results for the combined entity for the year ended
December 31, 2009(2)
|
|
$
|
87,378
|
|
|
$
|
(42,878
|
)
|
|
|
|
(1) |
|
Actual results of the Deep Bossier properties from the date of
acquisition, July 23, 2009. Expenses include severance tax,
lease operating costs, and depreciation, depletion and
amortization of the properties. |
|
(2) |
|
Pro forma revenues and earnings of the Company include the Deep
Bossier properties as if they had been acquired at the beginning
of the period. Adjustments to actual earnings include severance
tax, lease operating costs, and depreciation, depletion and
amortization for the Deep Bossier properties for the year ended
December 31, 2009. |
F-23
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 4
|
PROPERTY
AND EQUIPMENT
|
Property and equipment consists of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
OIL AND GAS PROPERTIES
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
$
|
12,020
|
|
|
$
|
9,047
|
|
Land
|
|
|
1,185
|
|
|
|
1,185
|
|
Accumulated impairment
|
|
|
(2,686
|
)
|
|
|
(696
|
)
|
|
|
|
|
|
|
|
|
|
Unproved properties, net
|
|
|
10,519
|
|
|
|
9,536
|
|
|
|
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
|
707,364
|
|
|
|
435,706
|
|
Accumulated depreciation, depletion, amortization and impairment
|
|
|
(273,818
|
)
|
|
|
(209,741
|
)
|
|
|
|
|
|
|
|
|
|
Proved oil and gas properties, net
|
|
|
433,546
|
|
|
|
225,965
|
|
|
|
|
|
|
|
|
|
|
TOTAL OIL AND GAS PROPERTIES, net
|
|
|
444,065
|
|
|
|
235,501
|
|
|
|
|
|
|
|
|
|
|
DRILLING RIG
|
|
|
10,500
|
|
|
|
|
|
Accumulated depreciation
|
|
|
(444
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL DRILLING RIG, net
|
|
|
10,056
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER PROPERTY AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Office furniture and equipment
|
|
|
3,321
|
|
|
|
1,767
|
|
Vehicles
|
|
|
523
|
|
|
|
347
|
|
Accumulated depreciation
|
|
|
(1,701
|
)
|
|
|
(1,419
|
)
|
|
|
|
|
|
|
|
|
|
OTHER PROPERTY AND EQUIPMENT, net
|
|
|
2,143
|
|
|
|
695
|
|
|
|
|
|
|
|
|
|
|
TOTAL PROPERTY AND EQUIPMENT, net
|
|
$
|
456,264
|
|
|
$
|
236,196
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 5
|
FAIR
VALUE DISCLOSURES
|
Effective January 1, 2008, the Company adopted new
authoritative guidance from the FASB regarding fair value,
contained in ASC 820, Fair Value Measurements and
Disclosure. 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.
We 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 gas and
interest rate derivatives contracts.
In accordance with the deferred effective date provided by the
FASB, on January 1, 2009, we 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 the valuation
of long-lived assets for which an impairment write-down is
recorded during the period, such as oil and gas properties.
F-24
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We utilize 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. We have classified the fair
values of all our oil and natural gas derivative contracts as
Level 2.
The fair value of our interest rate derivative contracts was
calculated using the Black-Scholes option pricing model and is
also considered a Level 2 fair value.
Our senior notes are carried at historical cost, net of
amortized discount; we estimate the fair value of the senior
notes for disclosure purposes (see Note 2). This estimation
is based on the most recent trading values of the notes at or
near the reporting date.
Oil and gas properties are subject to impairment testing and
potential impairment write down as described in Note 2. Oil
and gas properties with a carrying amount of $19.1 million
were written down to their fair value of $10.7 million,
resulting in an impairment charge of $8.4 million for the
year ended December 31, 2010. Oil and gas properties with a
carrying amount of $8.3 million were written down to their
fair value of $4.5 million, resulting in an impairment
charge of $3.8 million for the year ended December 31,
2009. The impairment analysis is based on the estimated
discounted future cash flows for those properties. Significant
Level 3 assumptions used in the calculation of estimated
discounted cash flows included our estimate of future oil and
gas prices, production costs, development expenditures,
estimated quantities and timing of production of proved
reserves, appropriate risk-adjusted discount rates, and other
relevant data.
In addition, other equipment, included in oil and gas
properties, was impaired $18,000 and $2.4 million for the
years ended December 31, 2010 and 2009, respectively, based
on market information for similar products, which is a
Level 3 value.
In connection with the Deep Bossier acquisition in 2009, we
recorded oil and gas properties with a fair value of
$44.5 million. In connection with the Meridian acquisition
in the second quarter of 2010 (Note 3), we recorded oil and
natural gas properties with a fair value of $147 million.
Significant Level 3 inputs used were the same as those used
in determining impairments based on estimated discounted cash
flows for the acquired properties.
New additions to asset retirement obligations result from
estimations 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 for such inputs as cost and timing of plug and
abandonment of wells and facilities. We recorded a total of
$31.6 million in additions to asset retirement obligations
measured at fair value for the year ended December 31,
2010, including $30.9 million added as a result of the
Meridian acquisition. We recorded a total of $748,000 in
additions to asset retirement obligations measured at fair value
for the year ended December 31, 2009.
F-25
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table presents information about our financial
assets and liabilities measured at fair value on a recurring
basis as of December 31, 2010 and 2009, and indicates the
fair value hierarchy of the valuation techniques we utilized to
determine such fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
|
(Dollars in thousands)
|
|
At December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts for oil and gas
|
|
|
|
|
|
$
|
61,623
|
|
|
|
|
|
|
$
|
61,623
|
|
Financial Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts for oil and gas
|
|
|
|
|
|
$
|
37,022
|
|
|
|
|
|
|
$
|
37,022
|
|
Derivative contracts for interest rate
|
|
|
|
|
|
$
|
5,388
|
|
|
|
|
|
|
$
|
5,388
|
|
At December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts for oil and gas
|
|
|
|
|
|
$
|
27,699
|
|
|
|
|
|
|
$
|
27,699
|
|
Financial Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts for oil and gas
|
|
|
|
|
|
$
|
13,186
|
|
|
|
|
|
|
$
|
13,186
|
|
Derivative contracts for interest rate
|
|
|
|
|
|
$
|
6,274
|
|
|
|
|
|
|
$
|
6,274
|
|
The amounts above are presented on a gross basis; presentation
on our Consolidated Balance Sheets utilizes netting of assets
and liabilities with the same counterparty where master netting
agreements are in place.
For additional information on derivative contracts, see
Note 6.
|
|
NOTE 6
|
DERIVATIVE
FINANCIAL INSTRUMENTS
|
We account for our derivative contracts under the provisions of
ASC 815, Derivatives and Hedging. The Company
has entered into forward-swap contracts and collar contracts to
reduce its exposure to price risk in the spot market for oil and
natural gas. The Company also utilizes financial basis swap
contracts, which address the price differential between
market-wide benchmark prices and other benchmark pricing
referenced in certain of our natural gas sales contracts. All of
the Companys hedging agreements are executed by affiliates
of the lenders (Lenders) under our senior secured
revolving credit facility described in Note 9 below, and
are collateralized by the security interests of the respective
affiliated Lenders in certain assets of the Company under the
credit facility. The contracts settle monthly and are scheduled
to coincide with either oil production equivalent to barrels
(Bbl) per month or gas production equivalent to volumes in
millions of British thermal units (MMbtu) per month. The
contracts represent agreements between the Company and the
counter-parties to exchange cash based on a designated price.
Prices are referenced to natural gas and crude oil futures
contracts traded on either the Houston Ship Channel/ Beaumont,
Texas index or on the New York Mercantile Exchange (NYMEX)
index. Cash settlement occurs monthly based on the specified
price benchmark. The Company has not designated any of its
derivative contracts as fair value or cash flow hedges;
accordingly we use
mark-to-market
accounting as described in Note 2, recognizing unrealized
gains and losses in the consolidated statement of operations at
each reporting date. Realized gains and losses on commodities
hedging contracts are included in oil and natural gas revenues.
The Company has entered into a series of interest rate swap
agreements with several financial institutions to mitigate the
risk of loss due to changes in interest rates. The interest rate
swaps are not designated as cash flow hedges in accordance with
ASC 815. Both realized gains and losses from settlement and
unrealized gains and losses from changes in the fair market
value of the interest rate swaps are included in interest
expense.
F-26
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
No derivative contracts have been entered into for trading
purposes, and the Company typically holds each instrument to
maturity.
The second table below provides information on the location and
amounts of realized and unrealized gains and losses on
derivatives included in the statement of operations for each of
the years ended December 31, 2010 and 2009.
The following table summarizes the fair value (see Note 5
for further discussion of fair value) and classification of the
Companys derivative instruments, all of which have not
been designated as hedging instruments under ASC 815:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Values of Derivative Contracts
|
|
|
|
Balance Sheet Location at December 31, 2010
|
|
|
|
Current
|
|
|
Current
|
|
|
Long-Term
|
|
|
Long-Term
|
|
|
|
Asset
|
|
|
Liability
|
|
|
Asset
|
|
|
Liability
|
|
|
|
Portion of
|
|
|
Portion of
|
|
|
Portion of
|
|
|
Portion of
|
|
|
|
Derivative
|
|
|
Derivative
|
|
|
Derivative
|
|
|
Derivative
|
|
|
|
Financial
|
|
|
Financial
|
|
|
Financial
|
|
|
Financial
|
|
|
|
Instruments
|
|
|
Instruments
|
|
|
Instruments
|
|
|
Instruments
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
Fair value of oil and gas commodity contracts, assets
|
|
|
27,118
|
|
|
|
|
|
|
|
34,505
|
|
|
|
|
|
Fair value of oil and gas commodity contracts, (liabilities)
|
|
|
(16,682
|
)
|
|
|
|
|
|
|
(20,340
|
)
|
|
|
|
|
Fair value of interest rate contracts, (liabilities)
|
|
|
|
|
|
|
(3,092
|
)
|
|
|
|
|
|
|
(2,296
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net assets, (liabilities)
|
|
|
10,436
|
|
|
|
(3,092
|
)
|
|
|
14,165
|
|
|
|
(2,296
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Values of Derivative Contracts
|
|
|
|
Balance Sheet Location at December 31, 2009
|
|
|
|
Current
|
|
|
Current
|
|
|
Long-Term
|
|
|
Long-Term
|
|
|
|
Asset
|
|
|
Liability
|
|
|
Asset
|
|
|
Liability
|
|
|
|
Portion of
|
|
|
Portion of
|
|
|
Portion of
|
|
|
Portion of
|
|
|
|
Derivative
|
|
|
Derivative
|
|
|
Derivative
|
|
|
Derivative
|
|
|
|
Financial
|
|
|
Financial
|
|
|
Financial
|
|
|
Financial
|
|
|
|
Instruments
|
|
|
Instruments
|
|
|
Instruments
|
|
|
Instruments
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
Fair value of oil and gas commodity contracts, assets
|
|
|
12,078
|
|
|
|
1,396
|
|
|
|
12,815
|
|
|
|
1,410
|
|
Fair value of oil and gas commodity contracts, (liabilities)
|
|
|
(3,704
|
)
|
|
|
(2,035
|
)
|
|
|
(4,886
|
)
|
|
|
(2,561
|
)
|
Fair value of interest rate contracts, (liabilities)
|
|
|
|
|
|
|
(3,222
|
)
|
|
|
|
|
|
|
(3,052
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net assets, (liabilities)
|
|
|
8,374
|
|
|
|
(3,861
|
)
|
|
|
7,929
|
|
|
|
(4,203
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts are subject to master netting arrangements
and are presented on a net basis in the Consolidated Balance
Sheets. This netting can cause derivative assets to be
ultimately presented in a (liability) account on the
Consolidated Balance Sheets. Likewise, derivative (liabilities)
could be presented in an asset account.
F-27
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the effect of the Companys
derivative instruments in the consolidated statements of
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not Designated as
|
|
Location of Gain
|
|
Classification of
|
|
|
Years Ended December 31,
|
|
Hedging Instruments Under ASC 815
|
|
(Loss)
|
|
Gain (Loss)
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
Natural gas commodity contracts
|
|
Natural gas revenues
|
|
|
Realized
|
|
|
$
|
23,206
|
|
|
$
|
26,835
|
|
|
$
|
(3,446
|
)
|
Oil commodity contracts
|
|
Oil revenues
|
|
|
Realized
|
|
|
|
(224
|
)
|
|
|
4,397
|
|
|
|
(6,112
|
)
|
Interest rate contracts
|
|
Interest expense
|
|
|
Realized
|
|
|
|
(4,380
|
)
|
|
|
(2,967
|
)
|
|
|
(486
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized gains (losses) from derivatives not designated as
hedges
|
|
|
|
|
|
|
|
$
|
18,602
|
|
|
$
|
28,265
|
|
|
$
|
(10,044
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas commodity contracts
|
|
Unrealized gain (loss) oil and natural gas
derivative contracts
|
|
|
Unrealized
|
|
|
$
|
17,066
|
|
|
$
|
(3,579
|
)
|
|
$
|
25,463
|
|
Oil commodity contracts
|
|
Unrealized gain (loss) oil and natural gas
derivative contracts
|
|
|
Unrealized
|
|
|
|
(6,978
|
)
|
|
|
(22,679
|
)
|
|
|
35,149
|
|
Interest rate contracts
|
|
Interest expense
|
|
|
Unrealized
|
|
|
|
886
|
|
|
|
951
|
|
|
|
(4,903
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized gains (losses) from derivatives not designated
as hedges
|
|
|
|
|
|
|
|
$
|
10,974
|
|
|
$
|
(25,307
|
)
|
|
$
|
55,709
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Although the Companys counterparties provide no
collateral, the master derivative agreements with each
counterparty effectively 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 an unpaid hedging agreement
receivable against the interest of the counterparty in any
outstanding balance under the Credit Facility.
If a counterparty were to default in payment of an obligation
under the master derivative agreements, the Company could be
exposed to commodity price fluctuations, and the protection
intended by the hedge could be lost. The value of our derivative
financial instruments would be impacted.
In the tables below for natural gas and crude oil derivative
positions open as of December 31, 2010, the notional amount
is equal to the total net volumetric hedge position of the
Company during the periods presented. We have hedged
approximately 70% of our forecasted production from proved
developed reserves through 2014.
F-28
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company had the following open derivative contracts for
natural gas at December 31, 2010:
Natural
Gas Derivative Contracts
NATURAL
GAS DERIVATIVE CONTRACTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume in
|
|
|
Weighted
|
|
|
Range
|
|
Period and Type of Contract
|
|
MMbtu
|
|
|
Average
|
|
|
High
|
|
|
Low
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
4,230,000
|
|
|
$
|
7.37
|
|
|
$
|
8.83
|
|
|
$
|
6.62
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
11,315,000
|
|
|
|
6.46
|
|
|
|
7.60
|
|
|
|
5.40
|
|
Long Put Options
|
|
|
14,585,000
|
|
|
|
5.28
|
|
|
|
6.30
|
|
|
|
4.50
|
|
Short Put Options
|
|
|
18,785,000
|
|
|
|
4.43
|
|
|
|
5.25
|
|
|
|
4.00
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
3,410,000
|
|
|
|
7.56
|
|
|
|
8.83
|
|
|
|
6.81
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
4,350,000
|
|
|
|
7.74
|
|
|
|
9.25
|
|
|
|
7.00
|
|
Long Put Options
|
|
|
4,350,000
|
|
|
|
5.93
|
|
|
|
6.75
|
|
|
|
5.50
|
|
Short Put Options
|
|
|
1,920,000
|
|
|
|
5.56
|
|
|
|
5.75
|
|
|
|
5.25
|
|
2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
3,000,000
|
|
|
|
7.22
|
|
|
|
9.15
|
|
|
|
6.94
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
1,500,000
|
|
|
|
8.51
|
|
|
|
8.80
|
|
|
|
8.31
|
|
Long Put Options
|
|
|
1,500,000
|
|
|
|
6.09
|
|
|
|
6.15
|
|
|
|
6.00
|
|
Short Put Options
|
|
|
900,000
|
|
|
|
5.50
|
|
|
|
5.50
|
|
|
|
5.50
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
1,300,000
|
|
|
|
7.21
|
|
|
|
7.50
|
|
|
|
7.07
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
1,650,000
|
|
|
|
8.21
|
|
|
|
9.00
|
|
|
|
7.92
|
|
Long Put Options
|
|
|
1,650,000
|
|
|
|
6.73
|
|
|
|
7.00
|
|
|
|
6.00
|
|
Short Put Options
|
|
|
1,200,000
|
|
|
|
5.50
|
|
|
|
5.50
|
|
|
|
5.50
|
|
F-29
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company had the following open derivative contracts for
crude oil at December 31, 2010:
Crude
Oil Derivative Contracts
OIL
DERIVATIVE CONTRACTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume in
|
|
|
Weighted
|
|
|
Range
|
|
Period and Type of Contract
|
|
Bbls
|
|
|
Average
|
|
|
High
|
|
|
Low
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
365,000
|
|
|
$
|
78.95
|
|
|
$
|
96.00
|
|
|
$
|
67.50
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
365,000
|
|
|
|
93.13
|
|
|
|
99.00
|
|
|
|
82.25
|
|
Long Put Options
|
|
|
501,425
|
|
|
|
78.38
|
|
|
|
100.00
|
|
|
|
55.00
|
|
Long Call Options
|
|
|
109,500
|
|
|
|
75.00
|
|
|
|
75.00
|
|
|
|
75.00
|
|
Short Put Options
|
|
|
630,720
|
|
|
|
60.19
|
|
|
|
62.50
|
|
|
|
55.00
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
228,900
|
|
|
|
85.69
|
|
|
|
96.00
|
|
|
|
67.25
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
198,372
|
|
|
|
104.66
|
|
|
|
108.00
|
|
|
|
100.00
|
|
Long Put Options
|
|
|
522,648
|
|
|
|
80.75
|
|
|
|
85.00
|
|
|
|
80.00
|
|
Long Call Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Put Options
|
|
|
635,376
|
|
|
|
62.26
|
|
|
|
65.00
|
|
|
|
60.00
|
|
2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
136,500
|
|
|
|
84.35
|
|
|
|
94.74
|
|
|
|
77.00
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
235,435
|
|
|
|
101.80
|
|
|
|
127.00
|
|
|
|
90.00
|
|
Long Put Options
|
|
|
310,250
|
|
|
|
80.88
|
|
|
|
85.00
|
|
|
|
80.00
|
|
Long Call Options
|
|
|
82,500
|
|
|
|
79.00
|
|
|
|
79.00
|
|
|
|
79.00
|
|
Short Put Options
|
|
|
392,750
|
|
|
|
60.91
|
|
|
|
65.00
|
|
|
|
60.00
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
127,300
|
|
|
|
87.63
|
|
|
|
91.05
|
|
|
|
81.00
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
91,250
|
|
|
|
110.10
|
|
|
|
114.00
|
|
|
|
107.50
|
|
Long Put Options
|
|
|
273,750
|
|
|
|
81.67
|
|
|
|
85.00
|
|
|
|
80.00
|
|
Short Put Options
|
|
|
273,750
|
|
|
|
61.67
|
|
|
|
65.00
|
|
|
|
60.00
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
155,100
|
|
|
|
118.73
|
|
|
|
119.70
|
|
|
|
116.40
|
|
Long Put Options
|
|
|
155,100
|
|
|
|
85.00
|
|
|
|
85.00
|
|
|
|
85.00
|
|
Short Put Options
|
|
|
155,100
|
|
|
|
63.53
|
|
|
|
65.00
|
|
|
|
60.00
|
|
F-30
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company had the following open financial basis swap
contracts at December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Spread
|
Volume in MMbtu
|
|
Reference Price
|
|
Period
|
|
($ per MMbtu)
|
|
|
2,400,000
|
|
|
Houston Ship Channel
|
|
Jan11 Dec11
|
|
|
(0.20
|
)
|
|
2,400,000
|
|
|
Houston Ship Channel
|
|
Jan11 Dec11
|
|
|
(0.16
|
)
|
|
912,500
|
|
|
Houston Ship Channel
|
|
Jan11 Dec11
|
|
|
(0.085
|
)
|
|
2,737,500
|
|
|
Houston Ship Channel
|
|
Jan11 Dec11
|
|
|
(0.155
|
)
|
|
3,650,000
|
|
|
Houston Ship Channel
|
|
Jan11 Dec11
|
|
|
(0.115
|
)
|
|
1,830,000
|
|
|
Houston Ship Channel
|
|
Jan12 Dec12
|
|
|
(0.1575
|
)
|
|
3,660,000
|
|
|
Houston Ship Channel
|
|
Jan12 Dec12
|
|
|
(0.14
|
)
|
The Company had the following open interest rate swap contracts
at December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
Interest Rate Swaps
|
|
|
|
|
Fixed
|
|
|
Principal
|
|
Interest
|
Term
|
|
Amount
|
|
Rate(1)
|
|
|
(Dollars in
|
|
|
|
|
thousands)
|
|
|
|
Floating to Fixed Rate Swaps:
|
|
|
|
|
|
|
|
|
January 2011 August 2012
|
|
$
|
50,000
|
|
|
|
4.95
|
%
|
January 2011 March 2011
|
|
$
|
25,000
|
|
|
|
2.30
|
%
|
January 2011 March 2011
|
|
$
|
25,000
|
|
|
|
2.12
|
%
|
January 2011 October 2011
|
|
$
|
25,000
|
|
|
|
3.21
|
%
|
Fixed to Floating Rate Swaps:
|
|
|
|
|
|
|
|
|
January 2011 December 2014
|
|
$
|
150,000
|
|
|
|
9.625
|
%
|
|
|
|
(1) |
|
The floating rate is the three-month LIBOR rate, except the swap
for $150 million, which is a fixed to floating rate swap
using a floating rate of three-month LIBOR plus 7.72%. |
|
|
NOTE 7
|
ASSET
RETIREMENT OBLIGATIONS
|
As discussed in Note 2, the Company follows ASC 410 in
accounting for asset retirement obligations. A summary of the
changes in asset retirement obligations is included in the table
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(Dollars in thousands)
|
|
|
Balance, beginning of year
|
|
$
|
10,267
|
|
|
$
|
9,710
|
|
|
$
|
7,980
|
|
Liabilities incurred
|
|
|
702
|
|
|
|
748
|
|
|
|
870
|
|
Liabilities assumed in acquisition of Meridian
|
|
|
30,920
|
|
|
|
|
|
|
|
|
|
Liabilities settled
|
|
|
(453
|
)
|
|
|
(97
|
)
|
|
|
(66
|
)
|
Revisions to previous estimates
|
|
|
(93
|
)
|
|
|
(586
|
)
|
|
|
197
|
|
Accretion expense
|
|
|
1,370
|
|
|
|
492
|
|
|
|
729
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
|
42,713
|
|
|
|
10,267
|
|
|
|
9,710
|
|
Less: Current portion
|
|
|
1,617
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term portion
|
|
$
|
41,096
|
|
|
$
|
10,267
|
|
|
$
|
9,710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-31
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 8
|
RELATED
PARTY TRANSACTIONS
|
The Company has notes payable to our founder which bear interest
at 10% with a balance of $19.7 million and
$18.3 million at December 31, 2010 and 2009,
respectively. See further information at Note 9.
Alta Mesa Services, LP (Alta Mesa Services), one of
our wholly owned subsidiaries, conducts our business and
operations and, in addition to the board of directors of our
general partner, makes decisions on our behalf. Prior to the
consummation of the offering of our senior notes in October
2010, Alta Mesa Services was owned by Michael E. Ellis, the
founder of the Company, as well as Chief Operating Officer and
Chairman of the Board and Mickey Ellis, his spouse. The
consolidated results of operations include the financial
activity of Alta Mesa Services for the years ended
December 31, 2010, 2009, and 2008, respectively.
Long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Senior Debt On November 13, 2008, the Company
entered into a Fifth Amended and Restated Credit Agreement with
a group of banks, which was replaced by the Sixth Amended and
Restated Credit Agreement on May 13, 2010 (credit
facility). The credit facility matures on
November 13, 2012 and is secured by substantially all of
the Companys oil and gas properties. The credit facility
borrowing base is redetermined periodically and as of
December 31, 2010 the borrowing base under the facility was
$220 million. The credit facility bears interest at LIBOR
plus applicable margins between 2.50% and 3.25% or a
Reference Rate, which is based on the prime rate of
Wells Fargo Bank, N. A., plus a margin ranging from 1.50% to
2.25%, depending on the utilization of our borrowing base. The
rate was 2.875% and 3.52% as of December 31, 2010 and 2009,
respectively
|
|
$
|
73,290
|
|
|
$
|
161,500
|
|
Senior Notes Payable On October 13, 2010, the
Company issued notes due October 15, 2018 with a face value
of $300 million, at a discount of $2.1 million. The
senior notes carry a face interest rate of 9.625%, with an
effective rate of 9.75%; interest is payable semi-annually each
April 15th and October 15th. The senior notes are secured by
general corporate credit, and effectively rank junior to any
existing or future secured indebtedness of the Company, which
includes the credit facility. The senior notes are
unconditionally guaranteed on a senior unsecured basis by each
material subsidiary of the Company. The balance is presented net
of unamortized discount of $2,014,000
|
|
|
297,986
|
|
|
|
|
|
Subordinated Debt On November 13, 2008, the
Company entered into a Subordinated Credit Agreement
(Subordinated Credit Facility) with a group of
banks. The borrowing base under the Subordinated Credit Facility
was redetermined periodically and as of December 31, 2009
was $65 million. The Subordinated Credit Facility, which
was secured by scheduled oil and gas properties, bore interest
at LIBOR or a bank reference rate plus a margin of 8.50% with a
LIBOR floor rate of 3.50%. The rate was 12.00% as of
December 31, 2009. The Subordinated Credit Facility was
repaid and the agreement was cancelled in October 2010, using
the proceeds from the issuance of the senior notes
|
|
|
|
|
|
|
40,000
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
$
|
371,276
|
|
|
$
|
201,500
|
|
|
|
|
|
|
|
|
|
|
Total proceeds from the issuance of the senior notes before
expenses were $297.9 million. The proceeds were used to
retire the Subordinated Credit Facility ($40 million),
along with related accrued interest and a prepayment penalty
(total $1.7 million). Additionally, we paid
$199.7 million against the outstanding balance
F-32
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
under our credit facility. In addition to the debt payoff, the
Company utilized $50 million of the proceeds to provide a
distribution to AMIH. Under the terms of the credit facility,
the borrowing base under that facility was reduced from
$285 million to $220 million, based on a formula
related to the new debt issuance.
The senior notes contain an optional redemption provision
beginning in October 2013 allowing the Company to retire up to
35% of the principal outstanding under the senior notes with the
proceeds of an equity offering, at 109.625%. Additional optional
redemption provisions allow for retirement at 104.813%,
102.406%, and 100.0% beginning on each of October 15, 2014,
2015, and 2016, respectively.
On October 13, 2010, the Company entered into a
registration rights agreement with the initial purchasers of the
senior notes. Under the terms of the registration rights
agreement, the Company must file a registration statement with
the SEC to become effective no later than 360 days after
the senior notes were issued, to allow for registration of
exchange notes with terms substantially identical to
the senior notes. The exchange notes are to be exchanged for the
original senior notes.
In addition, the Company has notes payable to our founder which
bear simple interest at 10% with a balance of $19.7 million
and $18.3 million at December 31, 2010 and 2009,
respectively. The notes mature December 31, 2018. Interest
and principal are payable at maturity. The notes are subordinate
to all debt. Interest on our notes payable to our founder
amounted to $1.4 million during 2010, and $1.2 million
during each of 2009 and 2008. Such amounts have been added to
the balance of the notes.
Future maturities of long-term debt, including the notes payable
to our founder, at December 31, 2010 are as follows
(dollars in thousands):
|
|
|
|
|
Year Ending December 31,
|
|
|
|
|
2011
|
|
$
|
|
|
2012
|
|
|
73,290
|
|
2013
|
|
|
|
|
2014
|
|
|
|
|
2015
|
|
|
|
|
Thereafter
|
|
|
319,709
|
|
|
|
|
|
|
|
|
$
|
392,999
|
|
|
|
|
|
|
The credit facility and senior notes include covenants requiring
that the Company maintain certain financial covenants including
a Current Ratio, Leverage Ratio, and Interest Coverage Ratio. At
December 31, 2010, the Company was in compliance with the
covenants. The terms of the credit facility also restrict the
Companys ability to make distributions and investments.
In January 2008, the Company entered into a Compromise,
Settlement and Release Agreement with a bank holding a
9.25% note payable which had been scheduled to mature in
October 2009. Per the terms of the agreement, the outstanding
debt balance was forgiven. As such, a gain on extinguishment of
debt of $3.3 million was recognized in the consolidated
statement of operations for the year ended December 31,
2008.
F-33
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 10
|
ACCOUNTS
PAYABLE, ACCRUED LIABILITIES, AND OTHER LONG-TERM
LIABILITIES
|
The following provides the detail of accounts payable and
accrued liabilities:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Capital expenditures
|
|
$
|
22,743
|
|
|
$
|
4,437
|
|
Revenues and royalties payable
|
|
|
5,962
|
|
|
|
1,688
|
|
Operating expenses/taxes
|
|
|
18,220
|
|
|
|
4,320
|
|
Compensation
|
|
|
2,591
|
|
|
|
646
|
|
Acquisition costs payable
|
|
|
|
|
|
|
15,756
|
|
Liability related to drilling rig
|
|
|
9,785
|
|
|
|
|
|
Other
|
|
|
1,775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total accrued liabilities
|
|
|
61,076
|
|
|
|
26,847
|
|
Accounts payable
|
|
|
26,179
|
|
|
|
5,782
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
87,255
|
|
|
$
|
32,629
|
|
|
|
|
|
|
|
|
|
|
The following provides the detail of other long-term liabilities:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Acquisition obligation
|
|
$
|
411
|
|
|
$
|
787
|
|
Remediation liability
|
|
|
943
|
|
|
|
898
|
|
Other
|
|
|
5,886
|
|
|
|
7,467
|
|
|
|
|
|
|
|
|
|
|
Total other long-term liabilities
|
|
$
|
7,240
|
|
|
$
|
9,152
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 11
|
COMMITMENTS
AND CONTINGENCIES
|
Contingencies
Deep Bossier Litigation: On
July 23, 2009, we made a payment of $25.5 million and
took assignment of substantially all working interests that had
been held by Chesapeake in an approximate 50,000 acre area
of Leon and Robertson Counties, Texas in the Deep Bossier play.
We had exercised our preferential right to purchase these
interests from Gastar in late 2005, but Gastar and Chesapeake
had opposed this and Chesapeake took record title until we
finally and conclusively prevailed, and in 2008 a Texas court of
appeals directed that specific performance take place. In early
2009, the Texas Supreme Court denied the dependants
request to hear the appeal. As a result, we were able to take
working interests in over 30 producing wells and participate in
further development of the area, primarily with EnCana, but also
with Gastar. A subsequent payment to EnCana of
$15.2 million plus purchase accounting adjustments of
$3.8 million brought the total cost of the acquisition to
$44.5 million. While the ownership of these interests has
been decided by the courts, we are pursuing other claims against
Chesapeake; Chesapeake is claiming an additional
$36.5 million of past expenses. 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 consolidated financial statements at
December 31, 2010.
F-34
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Sydson Energy v. Alta Mesa Holdings, L.P. and
The Meridian Resource and Exploration, LLC: In
January 2011, Sydson Energy brought suit for declaratory relief,
breach of contract and tortious interference related to certain
assignments of oil and gas interests. Meridian filed a
counterclaim for declaratory relief and is seeking rescission of
the disputed assignments. The Company intends to contest this
matter vigorously. The Company has not provided any amount for
this matter in its consolidated financial statements at
December 31, 2010.
Texas Oil Distribution & Development, Inc. and
Matrix Petroleum, LLC v. Alta Mesa Holdings, LP and The
Meridian Resource & Exploration,
LLC: In November, 2010, Texas Oil
Distribution & Development, Inc. and Matrix Petroleum
LLC (together, TODD), filed a petition seeking
declaratory relief based on TODDs employment of Thomas
Tourek, a former independent contractor of the Company.
Mr. Tourek owed certain contractual and common law
obligations to the Company, including, without limitation,
confidentiality and non-compete obligations. TODD seeks
declaratory relief of those obligations. In addition, on
January 10, 2011, TODD filed an amended petition for
declaratory relief, breach of contract and tortious interference
related to certain assignments of oil and gas interests and
joined Meridian as a defendant. Meridian filed a counterclaim
for declaratory relief and seeking rescission of the disputed
assignments. The Company intends to contest this matter
vigorously. The Company has not provided any amount for this
matter in its consolidated financial statements at
December 31, 2010.
Environmental Claims: Management has
established a liability for soil contamination in Florida of
approximately $943,000 and $898,000 at December 31, 2010
and 2009, respectively, based on the Companys undiscounted
engineering estimates. The obligations are included in other
long-term liabilities in the accompanying consolidated balance
sheets.
Various landowners have sued Meridian (along with numerous other
oil companies) in lawsuits concerning several fields in which
Meridian 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 Meridians oil and
natural gas operations. 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, we have not provided any amount for these claims in
our consolidated financial statements at December 31, 2010.
Due to the nature of the Companys business, some
contamination of the real estate property owned or leased by the
Company is possible. Environmental site assessments of the
property would be necessary to adequately determine remediation
costs, if any.
Other Contingencies: The Company is
subject to legal proceedings, claims and liabilities arising in
the ordinary course of business. The outcome cannot be
reasonably estimated; however, in the opinion of management,
such litigation and claims will be resolved without material
adverse effect on the Companys consolidated financial
position, results of operations or cash flows. Accruals for
losses associated with litigation are made when losses are
deemed probable and can be reasonably estimated.
The Company has a contingent commitment to pay an amount up to a
maximum of approximately $5 million for properties acquired
in 2008 and prior years. The additional purchase consideration
will be paid only if certain product price conditions are met.
The Company cannot estimate the amounts that will be paid in the
future, if any, or the fiscal years in which such amounts could
become due.
Title/lease disputes: Title and lease
disputes may arise in the normal course of the Companys
operations. These disputes are usually small but could result in
an increase or decrease in reserves once a final resolution to
the title dispute is made.
F-35
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Commitments
Office and Equipment Leases: The
Company leases office space, as well as certain field equipment
such as compressors, under long-term operating lease agreements.
Rent expense, including office space and compressors, for the
years ended December 31, 2010, 2009, and 2008 amounted to
approximately $2.9 million, $1.4 million, and
$1.2 million, respectively. At December 31, 2010,
future base rentals for non-cancelable leases are as follows
(dollars in thousands):
|
|
|
|
|
Year Ending December 31,
|
|
|
|
|
2011
|
|
$
|
2,881
|
|
2012
|
|
|
1,095
|
|
2013
|
|
|
1,665
|
|
2014
|
|
|
1,551
|
|
2015
|
|
|
1,181
|
|
Thereafter
|
|
|
7,695
|
|
|
|
|
|
|
|
|
$
|
16,068
|
|
|
|
|
|
|
Additionally, at December 31, 2010, the Company had posted
bonds in the aggregate amount of $8.8 million, primarily to
cover future abandonment costs.
Drilling rig: Included in the
Companys acquisition of Meridian was a contractual
obligation for the use of a drilling rig. The Companys
capital expenditure plans do not include full use of this rig;
however, the Company is obligated for the dayrate regardless of
whether the rig is working or idle. The operator, Orion
Drilling, LP, has sought other parties to use the rig and agreed
to credit the Companys obligation, based on revenues from
third parties who utilize the rig when the Company is unable to.
Management cannot predict whether utilization of the rig by
third parties will be consistent, nor to what extent it may
offset obligations under the dayrate contract. The Company
provided approximately $9.8 million for future losses on
this drilling contract in its financial statements at
December 31, 2010. The drilling contract terminated in
February 2011.
A related forbearance agreement with Orion may grant title to
the Company-owned rig to Orion, the operator under the dayrate
contract, in exchange for release of all accrued and future
liabilities under the rig contract and under a similar rig
contract now expired. This would occur at termination and final
payment of the related rig note held by a third party, which was
scheduled for 2013, if the Company continues to perform its
obligations under the rig note and the Company-owned rig is free
of any significant security interest at title transfer. The
third party note was paid off on November 17, 2010. 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, and
retain title to the rig. We are evaluating our options regarding
transfer of title to the rig, which is no longer encumbered by
the related term note.
At December 31, 2010, the rig is included in equipment at a
net book value of $10.1 million; current accrued
liabilities include a total of $9.8 million for the
accumulated obligation to Orion.
|
|
NOTE 12
|
MAJOR
CUSTOMERS
|
The Company markets production on a competitive basis. Gas is
sold under short-term contracts generally with
month-to-month
pricing based on published regional indices (typically the
market index for delivery at the Houston Ship Channel), with
differentials for transportation taken into account. Our oil is
primarily sold under short-term contracts, based on local posted
prices, adjusted for transportation, location, and quality.
For the year ended December 31, 2010, based on revenues
excluding hedging activities, one major customer accounted for
10% or more of those revenues individually, with a contribution
of $38.4 million. On
F-36
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the same basis, for the year ended December 31, 2009, four
major customers accounted for 10% or more of those revenues
individually, with contributions of $12.2 million,
$9.0 million, $8.5 million, and $7.4 million. On
the same basis, for the year ended December 31, 2008, three
major customers accounted for 10% or more of those revenues
individually, with contributions of $27.7 million,
$13.8 million, and $16.9 million. We believe that the
loss of such customers would not have a material adverse effect
on us because alternative purchasers are readily available.
|
|
NOTE 13
|
401(k)
SAVINGS PLAN
|
Employees of Alta Mesa Services and Petro Operating Company, LP
(POC) may participate in a 401(k) savings plan,
whereby the employees may elect to make contributions pursuant
to a salary reduction agreement. Alta Mesa Services and POC make
a matching contribution equal to fifty-percent (50%) of an
employees salary deferral contribution up to a maximum of
eight percent (8%) of an employees salary. Matching
contributions to the plan were approximately $393,000, $128,000,
and $104,000 for the years ended December 31, 2010, 2009,
and 2008, respectively. Meridian employees entered the plan in
2010, and for vesting purposes, were credited with their years
of service with Meridian. Meridian also had a 401(k) plan, the
assets and liabilities of which we assumed.
|
|
NOTE 14
|
SIGNIFICANT
RISKS AND UNCERTAINTIES
|
The Companys business makes it vulnerable to changes in
wellhead prices of crude oil and natural gas. Such prices have
been volatile in the past and can be expected to be volatile in
the future. By definition, proved reserves are based on analysis
of current oil and gas prices. Price declines reduce the
estimated value of proved reserves and increase annual
amortization expense (which is based on proved reserves). The
Company mitigates some of this vulnerability by entering into
oil and gas price derivative contracts. See Note 6.
|
|
NOTE 15
|
PARTNERS
CAPITAL
|
AMIH and affiliates of Alta Mesa Holdings created a partnership
in September 2005, whereby the affiliates of Alta Mesa Holdings
were Class A limited partners and AMIH was a Class B
limited partner.
Management and Control:
The business and affairs of the Company are managed by the
General Partner; which is a wholly owned subsidiary of Alta Mesa
Holdings. With certain exceptions, the General Partner may not
be removed except for the reasons of cause, which
are defined in the Alta Mesa Holdings, LP Partnership Agreement
(Partnership Agreement).
Distribution and Income Allocation:
Prior to January 1, 2012, net cash flow from operations is
to be retained by the Company to fund development, exploration,
and acquisition. After January 1, 2012, net cash from
operations, as defined in the Partnership Agreement, is
distributed among the partners based on a variable formula.
Generally, net cash from operations is to be distributed 85% to
the Class B Limited Partner, and 15% to the General Partner
and the Class A Limited Partners. The formula varies after
the Class B Limited Partner has received cumulative
distributions equal to a return of his investment plus an
internal rate of return of 15%. The split is then reduced to 65%
to the Class B Limited Partner until his internal rate of
return reaches a cumulative 27.5%; the split is then reduced to
25% of distributions to the Class B Limited Partner and the
remaining 75% to the General Partner and the Class A
Limited Partners. Any distribution which occurs must be
permitted under the terms of our Credit Facility and our senior
notes.
F-37
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Distribution of net cash flow from a Liquidity Event as
distributed to the Class A and Class B Partners
according to a variable formula as defined in the Partnership
Agreement. A Liquidity Event is any event in which the Company
receives cash proceeds outside the ordinary course of the
Companys business. Further, after January 1, 2012,
the Class B Partners can, without consent of any other
partners, request that the General Partner take action to cause
the Company and its subsidiaries, or the assets of the Company
to be sold to one or more third parties.
During the year ended December 31, 2009, a partners
interest was redeemed for $5.5 million. During 2010, AMIH
contributed $50 million in contributions to the Company for
our purchase of Meridian. In conjunction with our subsequent
offering of senior notes, AMIH received a distribution of
$50 million from the proceeds of the offering.
|
|
NOTE 16
|
SUBSEQUENT
EVENTS
|
Management has evaluated all events subsequent to the balance
sheet date of December 31, 2010 to March 31, 2011,
which is the date of issuance, and has determined that no
subsequent events require disclosure.
|
|
NOTE 17
|
SUBSIDIARY GUARANTORS
|
All of our wholly-owned subsidiaries are guarantors under the
terms of both our senior notes and our Credit Facility.
Our consolidated financial statements reflect the combined
financial position of these subsidiary guarantors. Our parent
company, Alta Mesa Holdings, LP has no independent operations,
assets, or liabilities. The guarantees are full and
unconditional and joint and several. Those subsidiaries which
are not wholly owned and are not guarantors are minor. There are
no restrictions on dividends, distributions, loans, or other
transfers of funds from the subsidiary guarantors to our parent
company.
|
|
NOTE 18
|
QUARTERLY RESULTS OF OPERATIONS
(Unaudited)
|
Results of operations by quarter for the year ended
December 31, 2010 were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
2010
|
|
March 31
|
|
|
June 30
|
|
|
Sept. 30
|
|
|
Dec. 31
|
|
|
|
(Dollars in thousands)
|
|
|
Revenues
|
|
$
|
58,889
|
|
|
$
|
50,103
|
|
|
$
|
63,040
|
|
|
$
|
48,068
|
|
Results of operations from exploration and production
activities(1)
|
|
|
13,298
|
|
|
|
18,465
|
|
|
|
19,467
|
|
|
|
(1,569
|
)
|
Net earnings (loss)
|
|
$
|
27,679
|
|
|
$
|
11,366
|
|
|
$
|
10,130
|
|
|
$
|
(34,946
|
)
|
Results of operations by quarter for the year ended
December 31, 2009 were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
2009
|
|
March 31
|
|
|
June 30
|
|
|
Sept. 30
|
|
|
Dec. 31
|
|
|
|
(Dollars in thousands)
|
|
|
Revenues
|
|
$
|
27,423
|
|
|
$
|
3,063
|
|
|
$
|
19,788
|
|
|
$
|
27,289
|
|
Results of operations from exploration and production
activities(1)
|
|
|
(5,586
|
)
|
|
|
(4,140
|
)
|
|
|
1,998
|
|
|
|
5,780
|
|
Net earnings (loss)
|
|
$
|
(4,646
|
)
|
|
$
|
(31,741
|
)
|
|
$
|
(8,443
|
)
|
|
$
|
(4,457
|
)
|
|
|
|
(1) |
|
Results of operations from exploration and production
activities, which approximate gross profit, are computed as
revenues, exclusive of unrealized gain/loss on oil and natural
gas derivative contracts, less |
F-38
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
expenses for lease operating, severance and ad valorem taxes,
workovers, exploration, depletion and depreciation, impairment,
and accretion. |
|
|
NOTE 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.
We adopted the new guidance effective December 31, 2009;
information about our reserves has been prepared in accordance
with the new guidance; management has chosen not to provide
information on probable and possible reserves. Our reserves
calculations 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, 2010 and 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, previous rules
required that estimated future net cash flows from proved
reserves be based on period end prices. The changes resulting
from the new rules did not significantly impact our impairment
testing, depreciation, depletion and amortization expense, or
other results of operations.
Proved reserves and associated cash flows are based on the
Companys combined reserve reports as of December 31,
2010, which were prepared by T. J. Smith & Company,
Inc. and W. D. Von Gonten & Co., both of which are
independent reservoir engineering firms. Netherland,
Sewell & Associates, Inc. audited the combined reserve
reports as of December 31, 2010.
For further information on the methods and controls used in the
process of estimating reserves, as well as the qualifications of
each of the three engineering firms, see Our Oil and
Natural Gas Reserves Internal Control and
Qualifications included herein.
Oil and gas producing activities are conducted onshore within
the continental United States and all of our proved reserves are
located within the United States.
The unaudited reserve and other information presented below is
provided as supplemental information in accordance with the
provisions of ASC Topic
932-235.
Estimated
Quantities of Proved Reserves
The following table sets forth the net proved reserves of the
Company as of December 31, 2010, 2009, and 2008, and the
changes therein during the years then ended. Proved reserves are
the estimated quantities of crude oil, natural gas, and natural
gas liquids that geological and engineering data demonstrate
with reasonable
F-39
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
NGL
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBbls)(1)
|
|
|
Total Proved Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
5,850
|
|
|
|
83,471
|
|
|
|
|
|
Production during 2008
|
|
|
(492
|
)
|
|
|
(6,637
|
)
|
|
|
|
|
Purchases in place
|
|
|
797
|
|
|
|
19,105
|
|
|
|
|
|
Discoveries and extensions
|
|
|
219
|
|
|
|
7,273
|
|
|
|
|
|
Revisions of previous quantity estimates and other
|
|
|
(700
|
)
|
|
|
(16,026
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
5,674
|
|
|
|
87,186
|
|
|
|
|
|
Production during 2009
|
|
|
(552
|
)
|
|
|
(10,610
|
)
|
|
|
|
|
Purchases in place(2)
|
|
|
1
|
|
|
|
85,786
|
|
|
|
|
|
Discoveries and extensions
|
|
|
462
|
|
|
|
26,292
|
|
|
|
|
|
Revisions of previous quantity estimates and other
|
|
|
2,910
|
|
|
|
(5,549
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
8,495
|
|
|
|
183,105
|
|
|
|
|
|
Production during 2010
|
|
|
(964
|
)
|
|
|
(24,026
|
)
|
|
|
(147
|
)
|
Purchases in place(3)
|
|
|
5,301
|
|
|
|
49,217
|
|
|
|
660
|
|
Discoveries and extensions
|
|
|
3,306
|
|
|
|
24,022
|
|
|
|
207
|
|
Revisions of previous quantity estimates and other
|
|
|
(3,951
|
)
|
|
|
9,135
|
|
|
|
1,015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010
|
|
|
12,187
|
|
|
|
241,453
|
|
|
|
1,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
4,365
|
|
|
|
51,711
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
4,453
|
|
|
|
64,870
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
6,978
|
|
|
|
101,082
|
|
|
|
|
|
Balance at December 31, 2010
|
|
|
7,867
|
|
|
|
159,226
|
|
|
|
1,301
|
|
|
|
|
(1) |
|
Natural gas liquids were not tracked in our reserve reports
prior to 2010. |
|
(2) |
|
Primarily the purchase of producing properties in the Deep
Bossier trend in 2009. |
|
(3) |
|
Purchase of Meridian in 2010. |
Proved
Undeveloped Reserves
The total of the Companys proved undeveloped reserves
(PUDs) is 111 Bcfe, or approximately 34% of
total proved reserves at December 31, 2010. The PUDs are
primarily in our Deep Bossier area, in South Louisiana, and in
our Blackjack Creek field in Florida. Total PUDs for the prior
year-end were 91 Bcfe, or 39% of our total reserves. The
acquisition of Meridian in 2010, including PUDs booked
post-acquisition for Meridian properties, accounts for the
majority of the increase in PUDs (25 Bcfe). In addition,
there were extensions at Blackjack Creek and certain fields in
East Texas, which added approximately 19 Bcfe, offset by a
downward revision at Deep Bossier (22 Bcfe.)
In 2010, we converted 12.6 Bcfe, or 14% of total year end
2009 PUDs, to proved developed reserves. In addition, we
converted 7.0 Bcfe, or 17%, of PUDs acquired with Meridian,
to proved developed reserves. Costs relating to the development
of PUDs (including Meridian) were approximately
$28.4 million in 2010. Costs of PUD development in 2010 do
not represent the total costs of these conversions, as
additional costs
F-40
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
may have been recorded in previous years. Estimated future
development costs relating to the development of
2010 year-end PUDs are $156 million. All PUDs but one
are scheduled to be drilled by 2015.
Approximately 7.6 Bcfe of our PUDs at December 31,
2010 originated more than five years ago. The most significant
of these is a 5.6 Bcfe waterflood expansion project at the
East Hennessey Unit in Oklahoma which has been underway for four
years and is proceeding in stages. We expect to reach full
implementation of the project over the next 2-5 years.
Capitalized
Costs Relating to Oil and Natural Gas Producing
Activities
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Capitalized costs:
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
707,364
|
|
|
$
|
435,706
|
|
Unproved properties
|
|
|
13,205
|
|
|
|
10,232
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
720,569
|
|
|
|
445,938
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(276,504
|
)
|
|
|
(210,437
|
)
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
444,065
|
|
|
$
|
235,501
|
|
|
|
|
|
|
|
|
|
|
Costs
Incurred in Oil and Natural Gas Acquisition, Exploration and
Development Activities
Acquisition costs in the table below include costs incurred to
purchase, lease, or otherwise acquire property. Exploration
expenses include additions to exploratory wells, including those
in progress, and other exploration expenses, such as geological
and geophysical costs. Development costs include additions to
production facilities and equipment and additions to development
wells, including those in progress.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(Dollars in thousands)
|
|
|
Costs incurred during the year:
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved
|
|
$
|
3,018
|
|
|
$
|
2,383
|
|
|
$
|
4,293
|
|
Proved(1)
|
|
|
148,518
|
|
|
|
47,415
|
|
|
|
36,487
|
|
Exploration
|
|
|
57,830
|
|
|
|
17,636
|
|
|
|
24,077
|
|
Development(2)
|
|
|
98,053
|
|
|
|
46,480
|
|
|
|
76,935
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
307,419
|
|
|
$
|
113,914
|
|
|
$
|
141,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Property acquisition costs for proved properties in 2010 include
the purchase of Meridian for $147.4 million and an
adjustment to the purchase price of the Deep Bossier properties
of $1.0 million. Property acquisition costs for proved
properties in 2009 include acquisition of a group of producing
wells in the Deep Bossier, $43.5 million; acquisition of
proved properties in 2008 included primarily a group of
properties in San Jacinto County, Texas for
$29.0 million. |
|
(2) |
|
Includes asset retirement costs of $609,000, $162,000, and
$1,067,000, for the years ended December 31, 2010, 2009,
and 2008, respectively. |
F-41
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Suspended
Well Costs
There were no wells in suspense at December 31, 2010, 2009
and 2008, respectively.
Results
of Operations from Oil and Natural Gas Producing
Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(Dollars in thousands)
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
$
|
125,866
|
|
|
$
|
66,290
|
|
|
$
|
58,458
|
|
Oil
|
|
|
75,827
|
|
|
|
34,283
|
|
|
|
38,055
|
|
Natural gas liquids
|
|
|
6,844
|
|
|
|
1,690
|
|
|
|
2,470
|
|
Other revenue
|
|
|
1,475
|
|
|
|
1,558
|
|
|
|
3,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
210,012
|
|
|
|
103,821
|
|
|
|
102,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease and plant operating expense
|
|
|
41,905
|
|
|
|
23,871
|
|
|
|
20,658
|
|
Production and ad valorem taxes
|
|
|
11,141
|
|
|
|
4,755
|
|
|
|
6,954
|
|
Workover expense
|
|
|
7,409
|
|
|
|
8,988
|
|
|
|
8,113
|
|
Exploration expense
|
|
|
31,037
|
|
|
|
12,839
|
|
|
|
11,675
|
|
Depreciation, depletion and amortization
|
|
|
59,090
|
|
|
|
48,659
|
|
|
|
49,219
|
|
Impairment expense
|
|
|
8,399
|
|
|
|
6,165
|
|
|
|
11,487
|
|
Accretion expense
|
|
|
1,370
|
|
|
|
492
|
|
|
|
729
|
|
Gain on sale of assets
|
|
|
(1,766
|
)
|
|
|
(738
|
)
|
|
|
|
|
(Benefit from) provision for state income taxes
|
|
|
2
|
|
|
|
(750
|
)
|
|
|
250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
158,587
|
|
|
|
104,281
|
|
|
|
109,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations from oil and natural gas producing
activities
|
|
$
|
51,425
|
|
|
$
|
(460
|
)
|
|
$
|
(6,473
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion and amortization expense per Mcfe
|
|
$
|
1.93
|
|
|
$
|
3.50
|
|
|
$
|
5.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
Future cash inflows as of December 31, 2010 and 2009 were
calculated using an unweighted arithmetic average of oil and gas
prices in effect on the first day of each month in the
respective year, except where prices are defined by contractual
arrangements. Future cash inflows as of December 31, 2008
were estimated using oil and gas prices in effect at the end of
the year, except where prices are defined by contractual
arrangements, in accordance with SEC guidance in effect prior to
the issuance of the Modernization Rules. Operating costs,
production and ad valorem taxes and future development costs are
based on current costs with no escalation.
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
F-42
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
increases in consumption by natural gas purchasers, changes in
governmental regulations or taxation and the impact of inflation
on costs.
The following table sets forth the components of the
standardized measure of discounted future net cash flows for the
years ended December 31, 2010, 2009, and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(Dollars in thousands)
|
|
|
Future cash flows
|
|
$
|
2,060,794
|
|
|
$
|
1,154,974
|
|
|
$
|
771,781
|
|
Future production costs
|
|
|
(618,319
|
)
|
|
|
(360,639
|
)
|
|
|
(213,159
|
)
|
Future development costs
|
|
|
(255,128
|
)
|
|
|
(148,097
|
)
|
|
|
(49,524
|
)
|
Future taxes on income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
1,187,347
|
|
|
|
646,238
|
|
|
|
509,098
|
|
Discount to present value at 10 percent per annum
|
|
|
(482,165
|
)
|
|
|
(307,941
|
)
|
|
|
(231,740
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
705,182
|
|
|
$
|
338,297
|
|
|
$
|
277,358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Base price for natural gas, per Mcf, in the above computations
was:
|
|
$
|
4.38
|
|
|
$
|
3.87
|
|
|
$
|
5.71
|
|
Base price for crude oil, per Bbl, in the above computations was:
|
|
$
|
79.43
|
|
|
$
|
61.18
|
|
|
$
|
44.60
|
|
No consideration was given to the Companys hedged
transactions.
Changes
in Standardized Measure of Discounted Future Net Cash
Flows
The following table sets forth the changes in standardized
measure of discounted future net cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(Dollars in thousands)
|
|
|
Balance at beginning of year
|
|
$
|
338,297
|
|
|
$
|
277,358
|
|
|
$
|
415,237
|
|
Sales of oil and natural gas, net production costs
|
|
|
(148,082
|
)
|
|
|
(64,649
|
)
|
|
|
(63,258
|
)
|
Changes in sales and transfer prices, net of production costs
|
|
|
27,025
|
|
|
|
(124,417
|
)
|
|
|
(177,634
|
)
|
Revisions of previous quantity estimates
|
|
|
(15,189
|
)
|
|
|
16,223
|
|
|
|
(41,803
|
)
|
Purchases of
reserves-in-place
|
|
|
250,996
|
|
|
|
177,581
|
|
|
|
56,451
|
|
Sales of
reserves-in-place
|
|
|
|
|
|
|
|
|
|
|
|
|
Current year discoveries and extensions
|
|
|
131,492
|
|
|
|
48,744
|
|
|
|
69,765
|
|
Changes in estimated future development costs
|
|
|
5,998
|
|
|
|
(9,740
|
)
|
|
|
(3,610
|
)
|
Development costs incurred during the year
|
|
|
29,413
|
|
|
|
27,917
|
|
|
|
11,077
|
|
Accretion of discount
|
|
|
33,830
|
|
|
|
27,736
|
|
|
|
41,524
|
|
Net change in income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in production rate (timing) and other
|
|
|
51,402
|
|
|
|
(38,456
|
)
|
|
|
(30,391
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change
|
|
|
366,885
|
|
|
|
60,939
|
|
|
|
(137,879
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of year
|
|
$
|
705,182
|
|
|
$
|
338,297
|
|
|
$
|
277,358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-43
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
ASSETS
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
5,527
|
|
|
$
|
4,836
|
|
Accounts receivable, net
|
|
|
40,002
|
|
|
|
38,081
|
|
Other receivables
|
|
|
2,180
|
|
|
|
6,338
|
|
Prepaid expenses and other current assets
|
|
|
1,655
|
|
|
|
2,292
|
|
Derivative financial instruments
|
|
|
2,051
|
|
|
|
10,436
|
|
|
|
|
|
|
|
|
|
|
TOTAL CURRENT ASSETS
|
|
|
51,415
|
|
|
|
61,983
|
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Proved oil and natural gas properties, successful
|
|
|
|
|
|
|
|
|
efforts method, net
|
|
|
455,053
|
|
|
|
442,880
|
|
Other property and equipment, net
|
|
|
14,261
|
|
|
|
13,384
|
|
|
|
|
|
|
|
|
|
|
TOTAL PROPERTY AND EQUIPMENT, NET
|
|
|
469,314
|
|
|
|
456,264
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
Investment in Partnership cost
|
|
|
9,000
|
|
|
|
9,000
|
|
Deferred financing costs, net
|
|
|
12,648
|
|
|
|
13,552
|
|
Derivative financial instruments
|
|
|
3,366
|
|
|
|
14,165
|
|
Advances to operators
|
|
|
3,470
|
|
|
|
2,699
|
|
Deposits
|
|
|
699
|
|
|
|
576
|
|
|
|
|
|
|
|
|
|
|
TOTAL OTHER ASSETS
|
|
|
29,183
|
|
|
|
39,992
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
549,912
|
|
|
$
|
558,239
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
77,532
|
|
|
$
|
87,255
|
|
Current portion, asset retirement obligations
|
|
|
1,766
|
|
|
|
1,617
|
|
Derivative financial instruments
|
|
|
2,472
|
|
|
|
3,092
|
|
|
|
|
|
|
|
|
|
|
TOTAL CURRENT LIABILITIES
|
|
|
81,770
|
|
|
|
91,964
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM LIABILITIES
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
41,270
|
|
|
|
41,096
|
|
Long-term debt
|
|
|
385,341
|
|
|
|
371,276
|
|
Notes payable to founder
|
|
|
20,007
|
|
|
|
19,709
|
|
Derivative financial instruments
|
|
|
2,873
|
|
|
|
2,296
|
|
Other long-term liabilities
|
|
|
6,159
|
|
|
|
7,240
|
|
|
|
|
|
|
|
|
|
|
TOTAL LONG-TERM LIABILITIES
|
|
|
455,650
|
|
|
|
441,617
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES
|
|
|
537,420
|
|
|
|
533,581
|
|
COMMITMENTS AND CONTINGENCIES (NOTE 10)
|
|
|
|
|
|
|
|
|
PARTNERS CAPITAL
|
|
|
12,492
|
|
|
|
24,658
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND PARTNERS CAPITAL
|
|
$
|
549,912
|
|
|
$
|
558,239
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
F-44
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
|
(Dollars in thousands)
|
|
|
|
(Unaudited)
|
|
|
REVENUES
|
|
|
|
|
|
|
|
|
Natural gas
|
|
$
|
35,381
|
|
|
$
|
27,815
|
|
Oil
|
|
|
32,197
|
|
|
|
9,521
|
|
Natural gas liquids
|
|
|
3,053
|
|
|
|
729
|
|
Other revenues
|
|
|
469
|
|
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
71,100
|
|
|
|
38,086
|
|
Unrealized gain (loss) oil and natural gas
derivative contracts
|
|
|
(19,184
|
)
|
|
|
20,803
|
|
|
|
|
|
|
|
|
|
|
TOTAL REVENUES
|
|
|
51,916
|
|
|
|
58,889
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
Lease and plant operating expense
|
|
|
13,331
|
|
|
|
8,078
|
|
Production and ad valorem taxes
|
|
|
5,401
|
|
|
|
1,613
|
|
Workover expense
|
|
|
1,626
|
|
|
|
1,959
|
|
Exploration expense
|
|
|
2,731
|
|
|
|
2,921
|
|
Depreciation, depletion, and amortization
|
|
|
19,468
|
|
|
|
8,622
|
|
Impairment expense
|
|
|
5,826
|
|
|
|
1,450
|
|
Accretion expense
|
|
|
470
|
|
|
|
145
|
|
General and administrative expenses
|
|
|
5,751
|
|
|
|
2,223
|
|
|
|
|
|
|
|
|
|
|
TOTAL EXPENSES
|
|
|
54,604
|
|
|
|
27,011
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) FROM OPERATIONS
|
|
|
(2,688
|
)
|
|
|
31,878
|
|
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(9,480
|
)
|
|
|
(4,199
|
)
|
Interest income
|
|
|
2
|
|
|
|
|
|
TOTAL OTHER EXPENSE
|
|
|
(9,478
|
)
|
|
|
(4,199
|
)
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) BEFORE STATE INCOME TAXES
|
|
|
(12,166
|
)
|
|
|
27,679
|
|
PROVISION FOR STATE INCOME TAXES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
|
$
|
(12,166
|
)
|
|
$
|
27,679
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
F-45
ALTA
MESA HOLDINGS, LP AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
|
(Dollars in thousands)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(12,166
|
)
|
|
$
|
27,679
|
|
Adjustments to reconcile net income (loss) to net cash
|
|
|
|
|
|
|
|
|
provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion, and amortization
|
|
|
19,468
|
|
|
|
8,622
|
|
Impairment expense
|
|
|
5,826
|
|
|
|
1,450
|
|
Accretion expense
|
|
|
470
|
|
|
|
145
|
|
Amortization of loan costs
|
|
|
904
|
|
|
|
123
|
|
Amortization of debt discount
|
|
|
65
|
|
|
|
|
|
Dry hole expense
|
|
|
717
|
|
|
|
174
|
|
Unrealized (gain) loss on derivatives
|
|
|
19,141
|
|
|
|
(20,718
|
)
|
Interest converted into debt
|
|
|
298
|
|
|
|
293
|
|
Settlement of asset retirement obligation
|
|
|
(233
|
)
|
|
|
(204
|
)
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(1,921
|
)
|
|
|
(1,815
|
)
|
Other receivables
|
|
|
4,158
|
|
|
|
668
|
|
Prepaid expenses and other non-current assets
|
|
|
(257
|
)
|
|
|
(3,804
|
)
|
Accounts payable, accrued liabilities, other long-term
liabilities
|
|
|
9,172
|
|
|
|
(13,964
|
)
|
|
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
|
|
|
45,642
|
|
|
|
(1,351
|
)
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Capital expenditures for property and equipment
|
|
|
(58,951
|
)
|
|
|
(13,226
|
)
|
|
|
|
|
|
|
|
|
|
NET CASH USED IN INVESTING ACTIVITIES
|
|
|
(58,951
|
)
|
|
|
(13,226
|
)
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
|
14,000
|
|
|
|
15,000
|
|
Repayments of long-term debt
|
|
|
|
|
|
|
|
|
Capital distributions
|
|
|
|
|
|
|
(25
|
)
|
|
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY FINANCING ACTIVITIES
|
|
|
14,000
|
|
|
|
14,975
|
|
|
|
|
|
|
|
|
|
|
NET INCREASE IN CASH
|
|
|
691
|
|
|
|
398
|
|
CASH AND CASH EQUIVALENTS, beginning of period
|
|
|
4,836
|
|
|
|
4,274
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, end of period
|
|
$
|
5,527
|
|
|
$
|
4,672
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
|
|
|
|
|
|
|
|
|
Cash paid during the period for interest
|
|
$
|
2,442
|
|
|
$
|
2,685
|
|
Cash paid during the period for taxes
|
|
|
|
|
|
|
|
|
Change in property asset retirement obligations, net
|
|
|
86
|
|
|
|
223
|
|
Change in accruals or liabilities for capital expenditures
|
|
|
(19,976
|
)
|
|
|
4,095
|
|
See notes to consolidated financial statements.
F-46
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
(unaudited)
|
|
1.
|
SUMMARY
OF ORGANIZATION AND NATURE OF OPERATIONS
|
The consolidated financial statements reflect the accounts of
Alta Mesa Holdings, LP and its subsidiaries (the
Company) after elimination of all significant
intercompany transactions and balances. The financial statements
should be read in conjunction with the consolidated financial
statements and notes thereto included in the Companys
annual financial statements for the years ended
December 31, 2010, 2009, and 2008.
The financial statements included herein as of March 31,
2011, and for the three month periods ended March 31, 2011
and 2010, are unaudited, and in the opinion of management, the
information furnished reflects all material adjustments,
consisting of normal recurring adjustments, necessary for a fair
presentation of consolidated financial position and of the
results of operations for the interim periods presented. The
financial statements have been prepared in accordance with
accounting principles generally accepted in the
U.S. (GAAP) for interim financial information
and with the instructions to
Form 10-Q
and Article 10 of
Regulation S-X.
Accordingly, they do not include all of the information and
footnotes required by GAAP for complete financial statements.
Certain minor reclassifications of prior period consolidated
financial statements have been made to conform to current
reporting practices. The results of operations for interim
periods are not necessarily indicative of results to be expected
for a full year.
Accounting policies used by the Company and its subsidiaries
reflect industry practices and conform to U.S. GAAP. As
used herein, the following acronyms have the following meanings:
FASB means the Financial Accounting Standards Board;
the Codification refers to the Accounting Standards
Codification, the collected accounting and reporting guidance
maintained by the FASB; ASC means Accounting
Standards Codification and is generally followed by a number
indicating a particular section of the Codification; and
ASU means Accounting Standards Update, followed by
an identification number, which are the periodic updates made to
the Codification by the FASB. SEC means the
Securities and Exchange Commission.
Organization: The consolidated
financial statements presented herein are of Alta Mesa Holdings,
LP and its (i) wholly-owned subsidiaries: Alta Mesa Finance
Services Corp., Alta Mesa Acquisition Sub, LLC and its direct
and indirect wholly-owned subsidiaries, Aransas Resources, LP
and its wholly-owned subsidiary ARI Development, L.L.C., Brayton
Resources II, LP, Buckeye Production Company, LP, Galveston Bay
Resources, LP, Louisiana Exploration & Acquisitions,
LP and its wholly-owned subsidiary Louisiana
Exploration & Acquisition Partnership, LLC, Navasota
Resources, Ltd., LLP, Nueces Resources, LP, Oklahoma Energy
Acquisitions, LP, Alta Mesa Drilling, LLC, Petro Acquisitions,
LP, Petro Operating Company, LP, Texas Energy Acquisitions, LP,
Virginia Oil and Gas, LLC and Alta Mesa Services, LP, and
(ii) partially-owned subsidiaries: Brayton Resources, LP,
and Orion Operating Company, LP. The entities above are
collectively referred to as the Company.
Nature of Operations: The Company is
engaged primarily in the acquisition, exploration, development,
and production of oil and natural gas properties. The
Companys properties are located primarily in Texas,
Oklahoma, Louisiana, Florida and the Appalachian Region.
|
|
2.
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
As of March 31, 2011, our significant accounting policies
are consistent with those discussed in Note 2 of the
consolidated financial statements for the fiscal year ended
December 31, 2010.
Use of Estimates: The
preparation of consolidated financial statements in conformity
with GAAP requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the consolidated financial statements and the reported amounts
of revenues and expenses during the reporting period.
F-47
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Reserve estimates significantly impact depreciation, depletion
and amortization expense and potential impairments of oil and
natural gas properties and are subject to change based on
changes in oil and natural gas prices and trends and changes in
estimated reserve quantities. We analyze estimates, including
those related to oil and natural gas reserves, oil and natural
gas revenues, the value of oil and natural gas properties, oil
and natural gas revenues, bad debts, asset retirement
obligations, derivative contracts, income taxes and
contingencies and litigation. We base our estimates on
historical experience and various other assumptions that are
believed to be reasonable under the circumstances. Actual
results may differ from these estimates.
Property and Equipment: Oil and
natural gas producing activities are accounted for using the
successful efforts method of accounting. Under the successful
efforts method, lease acquisition costs and all development
costs, including unsuccessful development wells, are capitalized.
Unproved Properties Acquisition costs
associated with the acquisition of leases are recorded as
unproved leasehold costs and capitalized as incurred. These
consist of costs incurred in obtaining a mineral interest or
right in a property such as a lease, in addition to options to
lease, broker fees, recording fees and other similar costs
related to activities in acquiring properties. Leasehold costs
are classified as unproved until proved reserves are discovered,
at which time related costs are transferred to proved oil and
natural gas properties.
Exploration Expense - Exploration expenses, other than
exploration drilling costs, are charged to expense as incurred.
These costs include seismic expenditures and other geological
and geophysical costs, expired leases, and lease rentals. The
costs of drilling exploratory wells and exploratory-type
stratigraphic wells are initially capitalized pending
determination of whether the well has discovered proved
commercial reserves. If the exploratory well is determined to be
unsuccessful, the cost of the well is transferred to expense.
Exploratory well drilling costs may continue to be capitalized
if the reserve quantity is sufficient to justify completion as a
producing well and sufficient progress in assessing the reserves
and the economic and operating viability of the project is being
made. Assessments of such capitalized costs are made quarterly.
Proved Oil and Natural Gas Properties Costs
incurred to obtain access to proved reserves and to provide
facilities for extracting, treating, gathering, and storing oil
and natural gas are capitalized. All costs incurred to drill and
equip successful exploratory wells, development wells,
development-type stratigraphic test wells, and service wells,
including unsuccessful development wells, are capitalized.
Impairment The capitalized costs of proved
oil and natural gas properties are reviewed quarterly for
impairment in accordance with
ASC 360-10-35,
Property, Plant and Equipment, Subsequent
Measurement, or whenever events or changes in
circumstances indicate that the carrying amount of a long-lived
asset or asset group exceeds its fair market value and is not
recoverable. The determination of recoverability is based on
comparing the estimated undiscounted future net cash flows at a
producing field level to the carrying value of the assets. If
the future undiscounted cash flows, based on estimates of
anticipated production from proved reserves and future crude oil
and natural gas prices and operating costs, are lower than the
carrying cost, the carrying cost of the asset or group of assets
is reduced to fair value. For our proved oil and natural gas
properties, we estimate fair value by discounting the projected
future cash flows at an appropriate risk-adjusted discount rate.
Unproved leasehold costs are assessed quarterly to determine
whether they have been impaired. Individually significant
properties are assessed for impairment on a
property-by-property
basis, while individually insignificant unproved leasehold costs
may be assessed in the aggregate. If unproved leasehold costs
are found to be impaired, an impairment allowance is provided
and a loss is recognized in the statement of operations.
Depreciation, Depletion, and Amortization
Depreciation, depletion, and amortization
(DD&A) of capitalized costs of proved oil and
natural gas properties is computed using the
unit-of-production
method based upon estimated proved reserves. Assets are grouped
for DD&A on the basis of reasonable aggregation of
properties with a common geological structural feature or
stratigraphic condition, such as a reservoir or
F-48
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
field. The reserve base used to calculate DD&A for
leasehold acquisition costs and the cost to acquire proved
properties is the sum of proved developed reserves and proved
undeveloped reserves. The reserve base used to calculate
DD&A for lease and well equipment costs, which include
development costs and successful exploration drilling costs,
includes only proved developed reserves.
Accounts Receivable, net: The
Companys receivables arise from the sale of oil and
natural gas to third parties and joint interest owner
receivables for properties in which we serve as the operator.
This concentration of customers may impact our overall credit
risk, either positively or negatively, in that these entities
may be similarly affected by changes in economic or other
conditions affecting the oil and gas industry. Accounts
receivable are generally not collateralized. Accounts receivable
are shown net of an allowance for doubtful accounts of $360,000
and $338,000 at March 31, 2011 and December 31, 2010,
respectively.
Deferred Financing
Costs: Deferred financing costs and
the amount of discount at which notes payable have been issued
(debt discount) are amortized using the straight-line method,
which approximates the interest method, over the term of the
related debt. For the three months ended March 31, 2011 and
2010, amortization of deferred financing costs included in
interest expense amounted to $904,000 and $123,000,
respectively. Deferred financing costs are listed among our
long-term assets, net of accumulated amortization of
$5.6 million and $4.7 million at March 31, 2011
and December 31, 2010, respectively.
Financial Instruments: The fair
value of cash, accounts receivable and current liabilities
approximate book value due to their short-term nature. The
estimate of fair value of long-term debt under our senior
secured revolving credit facility (credit facility)
is not considered to be materially different from carrying value
due to market rates of interest. The fair value of the debt to
our founder is not practicable to determine. We have estimated
the fair value of our senior notes payable at
$304.5 million and $291 million on March 31, 2011
and December 31, 2010, respectively. See Note 5 for
further information on fair values of financial instruments. See
Note 8 for information on long-term debt.
Recent
Accounting Pronouncements
On May 12, 2011, the FASB issued ASU
No. 2011-04
to Topic 820, Fair Value Measurements, Amendments to
Achieve Common Fair Value Measurement and Disclosure
Requirements in U.S. GAAP and IFRS. The ASU changes
certain definitions of terms used its guidance regarding fair
value measurements, as well as modifying certain disclosure
requirements and other aspects of the guidance. We are reviewing
the ASU, which is effective for interim and annual periods
beginning after December 15, 2011. We do not expect
adoption of the guidance to have a material impact on our
consolidated financial position or results of operations.
On and effective May 13, 2010, Alta Mesa Acquisition Sub,
LLC (AMAS), a wholly owned subsidiary of Alta Mesa
Holdings, L.P., acquired 100% of the shares of and merged with
The Meridian Resource Corporation (Meridian), with
AMAS as the surviving entity. Meridian was a publicly traded
company engaged in exploration for and production of oil and
natural gas. The oil and natural gas properties of Meridian are
similar and in some cases proximate to our areas of operation.
Meridian shareholders were paid in cash, funded by proceeds of
our credit facility as well as a $50 million equity
contribution from our private equity partner Alta Mesa
Investment Holdings Inc., an affiliate of Denham Commodities
Partners Fund IV LP (AMIH). The merger
increased the oil portion of our reserves portfolio, improving
the balance of our reserves between oil and natural gas, and
provided significant additions to our library of
3-D seismic
data.
Total cost of the acquisition was $158 million. It was
recorded using the acquisition method of accounting. The
purchase price was allocated to acquired assets and assumed
liabilities based on their
F-49
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
estimated fair values at date of acquisition.
Acquisition-related costs of approximately $532,000 were
recorded in general and administrative expense for the year
ended December 31, 2010.
A summary of the consideration paid and the preliminary
allocation of the purchase price is as follows (dollars in
thousands):
|
|
|
|
|
Summary of Consideration:
|
|
|
|
|
Cash
|
|
$
|
30,948
|
|
Debt retired
|
|
|
82,000
|
|
Debt assumed
|
|
|
5,346
|
|
Working capital deficit(1)
|
|
|
753
|
|
Other liabilities assumed
|
|
|
7,971
|
|
Fair value of asset retirement obligations assumed
|
|
|
30,920
|
|
|
|
|
|
|
Total
|
|
$
|
157,938
|
|
|
|
|
|
|
Summary of Purchase Price Allocation:
|
|
|
|
|
Proved oil and natural gas properties
|
|
$
|
144,325
|
|
Unproved oil and natural gas properties
|
|
|
3,113
|
|
Other tangible assets
|
|
|
10,500
|
|
|
|
|
|
|
Total
|
|
$
|
157,938
|
|
|
|
|
|
|
|
|
|
(1) |
|
Working capital deficit included a cash balance of $11,589,000. |
The revenue and earnings related to this acquisition are
included in our consolidated statement of operations for the
three months ended March 31, 2011. The revenue and earnings
of the combined entity, had the acquisition occurred on
January 1, 2010, are provided below. This unaudited pro
forma information has been derived from historical information
and is for illustrative purposes only. The unaudited pro forma
financial information does not attempt to predict or suggest
future results. It also does not necessarily reflect what the
historical results of the combined company would have been had
the companies been combined during these periods.
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
Income
|
|
|
(Unaudited)
|
|
|
(Dollars in thousands)
|
|
Actual results of Meridian included in our statement of
operations for the three months ended March 31, 2011
|
|
$
|
30,533
|
|
|
$
|
13,427
|
|
Pro forma results for the combined entity for the three months
ended March 31, 2010
|
|
$
|
79,936
|
|
|
$
|
30,569
|
|
F-50
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
4.
|
PROPERTY
AND EQUIPMENT
|
Property and equipment consists of the following:
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
OIL AND NATURAL GAS PROPERTIES
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
$
|
13,692
|
|
|
$
|
12,020
|
|
Accumulated impairment
|
|
|
(3,907
|
)
|
|
|
(2,686
|
)
|
|
|
|
|
|
|
|
|
|
Unproved properties, net
|
|
|
9,785
|
|
|
|
9,334
|
|
|
|
|
|
|
|
|
|
|
Proved oil and natural gas properties
|
|
|
742,844
|
|
|
|
707,364
|
|
Accumulated depreciation, depletion, amortization and impairment
|
|
|
(297,576
|
)
|
|
|
(273,818
|
)
|
|
|
|
|
|
|
|
|
|
Proved oil and natural gas properties, net
|
|
|
445,268
|
|
|
|
433,546
|
|
|
|
|
|
|
|
|
|
|
TOTAL OIL AND NATURAL GAS PROPERTIES, net
|
|
|
455,053
|
|
|
|
442,880
|
|
|
|
|
|
|
|
|
|
|
LAND
|
|
|
1,185
|
|
|
|
1,185
|
|
|
|
|
|
|
|
|
|
|
DRILLING RIG
|
|
|
10,500
|
|
|
|
10,500
|
|
Accumulated depreciation
|
|
|
(619
|
)
|
|
|
(444
|
)
|
|
|
|
|
|
|
|
|
|
TOTAL DRILLING RIG, net
|
|
|
9,881
|
|
|
|
10,056
|
|
|
|
|
|
|
|
|
|
|
OTHER PROPERTY AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Office furniture and equipment
|
|
|
4,437
|
|
|
|
3,321
|
|
Vehicles
|
|
|
598
|
|
|
|
523
|
|
Accumulated depreciation
|
|
|
(1,840
|
)
|
|
|
(1,701
|
)
|
|
|
|
|
|
|
|
|
|
OTHER PROPERTY AND EQUIPMENT, net
|
|
|
3,195
|
|
|
|
2,143
|
|
|
|
|
|
|
|
|
|
|
TOTAL PROPERTY AND EQUIPMENT, net
|
|
$
|
469,314
|
|
|
$
|
456,264
|
|
|
|
|
|
|
|
|
|
|
|
|
5.
|
FAIR
VALUE DISCLOSURES
|
The Company follows the guidance of ASC 820, Fair
Value Measurements and Disclosures, in the estimation of
fair values. 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.
We utilize 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 natural gas prices. We have classified the
fair values of all our oil and natural gas derivative contracts
as Level 2.
The fair value of our interest rate derivative contracts was
calculated using the modified Black-Scholes option pricing model
and is also considered a Level 2 fair value.
F-51
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Oil and natural gas properties are subject to impairment testing
and potential impairment write down. Oil and gas properties with
a carrying amount of $10.1 million were written down to
their fair value of $4.3 million, resulting in an
impairment charge of $5.8 million for the three months
ended March 31, 2011. Oil and gas properties with a
carrying amount of $4.7 million were written down to their
fair value of $3.2 million, resulting in an impairment
charge of $1.5 million for the three months ended
March 31, 2010. Significant Level 3 assumptions used
in the calculation of estimated discounted cash flows in the
impairment analysis included our estimate of future oil and
natural gas prices, production costs, development expenditures,
estimated timing of production of proved reserves, appropriate
risk-adjusted discount rates, and other relevant data.
In connection with the Meridian acquisition in the second
quarter of 2010 (see Note 3), we recorded oil and natural
gas properties with a fair value of $147 million.
Significant Level 3 inputs used were the same as those used
in determining impairments based on estimated discounted cash
flows for the acquired properties.
New additions to asset retirement obligations result from
estimations 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 for such inputs as cost and timing of plug and
abandonment of wells and facilities. We recorded $86,000 and
$223,000 in additions to asset retirement obligations measured
at fair value during the three months ended March 31, 2011
and 2010, respectively.
The following table presents information about our financial
assets and liabilities measured at fair value on a recurring
basis as of March 31, 2011 and December 31, 2010, and
indicates the fair value hierarchy of the valuation techniques
we utilized to determine such fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
|
(Dollars in thousands)
|
|
|
At March 31, 2011 (unaudited):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts for oil and natural gas
|
|
$
|
|
|
|
$
|
54,808
|
|
|
$
|
|
|
|
$
|
54,808
|
|
Financial Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts for oil and natural gas
|
|
|
|
|
|
|
49,391
|
|
|
|
|
|
|
|
49,391
|
|
Derivative contracts for interest rate
|
|
|
|
|
|
|
5,345
|
|
|
|
|
|
|
|
5,345
|
|
At December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts for oil and natural gas
|
|
$
|
|
|
|
$
|
61,623
|
|
|
$
|
|
|
|
$
|
61,623
|
|
Financial Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts for oil and natural gas
|
|
|
|
|
|
|
37,022
|
|
|
|
|
|
|
|
37,022
|
|
Derivative contracts for interest rate
|
|
|
|
|
|
|
5,388
|
|
|
|
|
|
|
|
5,388
|
|
The amounts above are presented on a gross basis; presentation
on our consolidated balance sheets utilizes netting of assets
and liabilities with the same counterparty where master netting
agreements are in place. For additional information on
derivative contracts, see Note 6.
|
|
6.
|
DERIVATIVE
FINANCIAL INSTRUMENTS
|
We account for our derivative contracts under the provisions of
ASC 815, Derivatives and Hedging. The Company
has entered into forward-swap contracts and collar contracts to
reduce its exposure to price risk in the spot market for oil and
natural gas. The Company also utilizes financial basis swap
contracts, which address the price differential between
market-wide benchmark prices and other benchmark pricing
referenced in certain of our natural gas sales contracts.
Substantially all of the Companys hedging agreements are
executed by affiliates of the lenders under the credit facility
described in Note 8 below, and are collateralized
F-52
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
by the security interests of the respective affiliated lenders
in certain assets of the Company under the credit facility. The
contracts settle monthly and are scheduled to coincide with
either oil production equivalent to barrels (Bbl) per month or
gas production equivalent to volumes in millions of British
thermal units (MMbtu) per month. The contracts represent
agreements between the Company and the counter-parties to
exchange cash based on a designated price. Prices are referenced
to the natural gas spot market benchmark price at the Houston
Ship Channel or the New York Mercantile Exchange (NYMEX) index.
Cash settlement occurs monthly based on the specified price
benchmark. The Company has not designated any of its derivative
contracts as fair value or cash flow hedges; accordingly we use
mark-to-market
accounting, recognizing unrealized gains and losses in the
statement of operations at each reporting date. Realized gains
and losses on commodities hedging contracts are included in oil
and natural gas revenues.
The Company has entered into a series of interest rate swap
agreements with several financial institutions to mitigate the
risk of loss due to changes in interest rates. The interest rate
swaps are not designated as cash flow hedges in accordance with
ASC 815. Both realized gains and losses from settlement and
unrealized gains and losses from changes in the fair market
value of the interest rate swaps are included in interest
expense.
The second table below provides information on the location and
amounts of realized and unrealized gains and losses on
derivatives included in the consolidated statements of
operations for each of the three month periods ended
March 31, 2011 and 2010.
The following table summarizes the fair value (see Note 5
for further discussion of fair value) and classification of the
Companys derivative instruments, all of which have not
been designated as hedging instruments under ASC 815:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Values of Derivative Contracts
|
|
|
|
Balance Sheet Location at March 31, 2011
|
|
|
|
Current
|
|
|
Current
|
|
|
Long-term
|
|
|
Long-term
|
|
|
|
Asset
|
|
|
Liability
|
|
|
Asset
|
|
|
Liability
|
|
|
|
Portion of
|
|
|
Portion of
|
|
|
Portion of
|
|
|
Portion of
|
|
|
|
Derivative
|
|
|
Derivative
|
|
|
Derivative
|
|
|
Derivative
|
|
|
|
Financial
|
|
|
Financial
|
|
|
Financial
|
|
|
Financial
|
|
|
|
Instruments
|
|
|
Instruments
|
|
|
Instruments
|
|
|
Instruments
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
Fair value of oil and gas commodity contracts, assets
|
|
$
|
25,926
|
|
|
$
|
|
|
|
$
|
28,882
|
|
|
$
|
|
|
Fair value of oil and gas commodity contracts, (liabilities)
|
|
|
(23,875
|
)
|
|
|
|
|
|
|
(25,516
|
)
|
|
|
|
|
Fair value of interest rate contracts, (liabilities)
|
|
|
|
|
|
|
(2,472
|
)
|
|
|
|
|
|
|
(2,873
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net assets, (liabilities)
|
|
$
|
2,051
|
|
|
$
|
(2,472
|
)
|
|
$
|
3,366
|
|
|
$
|
(2,873
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Values of Derivative Contracts
|
|
|
|
Balance Sheet Location at December 31, 2010
|
|
|
|
Current
|
|
|
Current
|
|
|
Long-term
|
|
|
Long-term
|
|
|
|
Asset
|
|
|
Liability
|
|
|
Asset
|
|
|
Liability
|
|
|
|
Portion of
|
|
|
Portion of
|
|
|
Portion of
|
|
|
Portion of
|
|
|
|
Derivative
|
|
|
Derivative
|
|
|
Derivative
|
|
|
Derivative
|
|
|
|
Financial
|
|
|
Financial
|
|
|
Financial
|
|
|
Financial
|
|
|
|
Instruments
|
|
|
Instruments
|
|
|
Instruments
|
|
|
Instruments
|
|
|
|
|
|
|
(dollars in thousands)
|
|
|
|
|
|
Fair value of oil and gas commodity contracts, assets
|
|
$
|
27,118
|
|
|
$
|
|
|
|
$
|
34,505
|
|
|
$
|
|
|
Fair value of oil and gas commodity contracts, (liabilities)
|
|
|
(16,682
|
)
|
|
|
|
|
|
|
(20,340
|
)
|
|
|
|
|
Fair value of interest rate contracts, (liabilities)
|
|
|
|
|
|
|
(3,092
|
)
|
|
|
|
|
|
|
(2,296
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net assets, (liabilities)
|
|
$
|
10,436
|
|
|
$
|
(3,092
|
)
|
|
$
|
14,165
|
|
|
$
|
(2,296
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-53
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Commodity contracts are subject to master netting arrangements
and are presented on a net basis in the consolidated balance
sheets. This netting can cause derivative assets to be
ultimately presented in a (liability) account on the
consolidated balance sheets. Likewise, derivative (liabilities)
could be presented in an asset account.
The following table summarizes the effect of the Companys
derivative instruments in the consolidated statements of
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not
|
|
|
|
|
|
For the Three
|
|
designated as hedging
|
|
|
|
|
|
Months Ended
|
|
instruments under
|
|
|
|
Classification
|
|
March 31,
|
|
ASC 815
|
|
Location of Gain (Loss)
|
|
of Gain (Loss)
|
|
2011
|
|
|
2010
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
Natural gas commodity contracts
|
|
Natural gas revenues
|
|
Realized
|
|
$
|
5,791
|
|
|
$
|
2,749
|
|
Oil commodity contracts
|
|
Oil revenues
|
|
Realized
|
|
|
(1,484
|
)
|
|
|
237
|
|
Interest rate contracts
|
|
Interest expense
|
|
Realized
|
|
|
(370
|
)
|
|
|
(1,028
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized gains (losses) from derivatives not designated as
hedges
|
|
|
|
|
|
$
|
3,937
|
|
|
$
|
1,958
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas commodity contracts
|
|
Unrealized gain (loss) oil and natural gas derivative
contracts
|
|
Unrealized
|
|
$
|
(16,227
|
)
|
|
$
|
21,281
|
|
Oil commodity contracts
|
|
Unrealized gain (loss) oil and natural gas derivative
contracts
|
|
Unrealized
|
|
|
(2,957
|
)
|
|
|
(478
|
)
|
Interest rate contracts
|
|
Interest benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
(expense)
|
|
Unrealized
|
|
|
43
|
|
|
|
(85
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized gains (losses) from derivatives not designated
as hedges
|
|
|
|
|
|
$
|
(19,141
|
)
|
|
$
|
20,718
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Although the Companys counterparties provide no
collateral, the master derivative agreements with each
counterparty effectively 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 an unpaid hedging agreement
receivable against the interest of the counterparty in any
outstanding balance under the credit facility.
If a counterparty were to default in payment of an obligation
under the master derivative agreements, the Company could be
exposed to commodity price fluctuations, and the protection
intended by the hedge could be lost. The value of our derivative
financial instruments would be impacted.
F-54
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company had the following open derivative contracts for
natural gas at March 31, 2011 (unaudited):
NATURAL
GAS DERIVATIVE CONTRACTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume in
|
|
|
Weighted
|
|
|
Range
|
|
Period and Type of Contract
|
|
MMbtu
|
|
|
Average
|
|
|
High
|
|
|
Low
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
8,415,000
|
|
|
$
|
5.64
|
|
|
$
|
8.83
|
|
|
$
|
4.44
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
12,570,000
|
|
|
|
6.02
|
|
|
|
8.25
|
|
|
|
4.70
|
|
Long Put Options
|
|
|
17,327,000
|
|
|
|
4.90
|
|
|
|
6.30
|
|
|
|
4.00
|
|
Long Call Options
|
|
|
2,830,000
|
|
|
|
6.55
|
|
|
|
8.25
|
|
|
|
4.70
|
|
Short Put Options
|
|
|
18,510,000
|
|
|
|
4.31
|
|
|
|
5.25
|
|
|
|
3.65
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
7,070,000
|
|
|
|
6.24
|
|
|
|
8.83
|
|
|
|
5.00
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
4,350,000
|
|
|
|
7.74
|
|
|
|
9.25
|
|
|
|
7.00
|
|
Long Put Options
|
|
|
4,350,000
|
|
|
|
5.93
|
|
|
|
6.75
|
|
|
|
5.50
|
|
Short Put Options
|
|
|
3,750,000
|
|
|
|
4.80
|
|
|
|
5.75
|
|
|
|
4.00
|
|
2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
3,000,000
|
|
|
|
7.17
|
|
|
|
9.15
|
|
|
|
6.94
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
1,500,000
|
|
|
|
8.51
|
|
|
|
8.80
|
|
|
|
8.31
|
|
Long Put Options
|
|
|
1,500,000
|
|
|
|
6.09
|
|
|
|
6.15
|
|
|
|
6.00
|
|
Short Put Options
|
|
|
900,000
|
|
|
|
5.50
|
|
|
|
5.50
|
|
|
|
5.50
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
1,300,000
|
|
|
|
7.21
|
|
|
|
7.50
|
|
|
|
7.07
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
1,650,000
|
|
|
|
8.21
|
|
|
|
9.00
|
|
|
|
7.92
|
|
Long Put Options
|
|
|
1,650,000
|
|
|
|
6.73
|
|
|
|
7.00
|
|
|
|
6.00
|
|
Short Put Options
|
|
|
1,200,000
|
|
|
|
5.50
|
|
|
|
5.50
|
|
|
|
5.50
|
|
F-55
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company had the following open derivative contracts for
crude oil at March 31, 2011 (unaudited):
OIL
DERIVATIVE CONTRACTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Range
|
|
Period and Type of Contract
|
|
Volume in Bbls
|
|
|
Average
|
|
|
High
|
|
|
Low
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long Swap Contract
|
|
|
22,750
|
|
|
$
|
93.25
|
|
|
$
|
93.25
|
|
|
$
|
93.25
|
|
Short Swap Contract
|
|
|
343,750
|
|
|
|
83.80
|
|
|
|
103.20
|
|
|
|
67.50
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
449,500
|
|
|
|
99.56
|
|
|
|
114.20
|
|
|
|
82.25
|
|
Long Put Options
|
|
|
364,175
|
|
|
|
79.26
|
|
|
|
100.00
|
|
|
|
55.00
|
|
Long Call Options
|
|
|
165,000
|
|
|
|
92.19
|
|
|
|
114.20
|
|
|
|
75.00
|
|
Short Put Options
|
|
|
475,200
|
|
|
|
60.19
|
|
|
|
62.50
|
|
|
|
55.00
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
228,900
|
|
|
|
85.69
|
|
|
|
96.00
|
|
|
|
67.25
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
491,172
|
|
|
|
115.89
|
|
|
|
123.50
|
|
|
|
100.00
|
|
Long Put Options
|
|
|
522,648
|
|
|
|
80.75
|
|
|
|
85.00
|
|
|
|
80.00
|
|
Short Put Options
|
|
|
536,556
|
|
|
|
61.76
|
|
|
|
65.00
|
|
|
|
60.00
|
|
2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
136,500
|
|
|
|
84.35
|
|
|
|
94.74
|
|
|
|
77.00
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
459,910
|
|
|
|
112.11
|
|
|
|
127.00
|
|
|
|
90.00
|
|
Long Put Options
|
|
|
351,500
|
|
|
|
81.95
|
|
|
|
90.00
|
|
|
|
80.00
|
|
Long Call Options
|
|
|
124,475
|
|
|
|
95.19
|
|
|
|
127.00
|
|
|
|
79.00
|
|
Short Put Options
|
|
|
434,000
|
|
|
|
61.58
|
|
|
|
70.00
|
|
|
|
60.00
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
|
127,300
|
|
|
|
87.63
|
|
|
|
91.05
|
|
|
|
81.00
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
91.250
|
|
|
|
110.10
|
|
|
|
114.00
|
|
|
|
107.50
|
|
Long Put Options
|
|
|
305,950
|
|
|
|
82.54
|
|
|
|
90.00
|
|
|
|
80.00
|
|
Short Put Options
|
|
|
305,950
|
|
|
|
62.54
|
|
|
|
70.00
|
|
|
|
60.00
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
|
155,100
|
|
|
|
118.73
|
|
|
|
119.70
|
|
|
|
116.40
|
|
Long Put Options
|
|
|
228,100
|
|
|
|
86.60
|
|
|
|
90.00
|
|
|
|
85.00
|
|
Short Put Options
|
|
|
228,100
|
|
|
|
65.60
|
|
|
|
70.00
|
|
|
|
60.00
|
|
F-56
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company had the following open financial basis swap
contracts at March 31, 2011 (unaudited):
|
|
|
|
|
|
|
|
|
Volume in MMbtu
|
|
Reference Price
|
|
Period
|
|
Spread ($ per MMbtu)
|
|
1,800,000
|
|
Houston Ship Channel
|
|
Apr 11 Dec 11
|
|
|
(0.2000
|
)
|
1,800,000
|
|
Houston Ship Channel
|
|
Apr 11 Dec 11
|
|
|
(0.1600
|
)
|
687,500
|
|
Houston Ship Channel
|
|
Apr 11 Dec 11
|
|
|
(0.0850
|
)
|
2,062,500
|
|
Houston Ship Channel
|
|
Apr 11 Dec 11
|
|
|
(0.1550
|
)
|
1,830,000
|
|
Houston Ship Channel
|
|
Jan 12 Dec 12
|
|
|
(0.1575
|
)
|
2,750,000
|
|
Houston Ship Channel
|
|
Apr 11 Dec 11
|
|
|
(0.1150
|
)
|
3,660,000
|
|
Houston Ship Channel
|
|
Jan 12 Dec 12
|
|
|
(0.1400
|
)
|
The Company had the following open interest rate swap contracts
at March 31, 2011 (unaudited):
|
|
|
|
|
|
|
|
|
Interest Rate Swaps
|
Term
|
|
Principal Amount
|
|
Interest Rate(1)
|
|
|
(Dollars in thousands)
|
|
|
|
Floating to Fixed Rate Swaps:
|
|
|
|
|
|
|
|
|
April 2011 August 2012
|
|
$
|
50,000
|
|
|
|
4.95
|
%
|
April 2011 October 2011
|
|
$
|
25,000
|
|
|
|
3.21
|
%
|
Fixed to Floating Rate Swaps:
|
|
|
|
|
|
|
|
|
April 2011 December 2014
|
|
$
|
150,000
|
|
|
|
9.625
|
%
|
|
|
|
(1) |
|
The floating rate is the three-month LIBOR rate, except the swap
for $150 million, which is a fixed to floating rate swap
using a floating rate of three-month LIBOR plus 7.72%. |
|
|
7.
|
ASSET
RETIREMENT OBLIGATIONS
|
A summary of the changes in asset retirement obligations is
included in the table below (unaudited, dollars in
thousands):
|
|
|
|
|
Balance, December 31, 2010
|
|
$
|
42,713
|
|
Liabilities incurred
|
|
|
86
|
|
Liabilities settled
|
|
|
(233
|
)
|
Revisions to previous estimates
|
|
|
|
|
Accretion expense
|
|
|
470
|
|
|
|
|
|
|
Balance, March 31, 2011
|
|
|
43,036
|
|
Less: Current portion
|
|
|
1,766
|
|
|
|
|
|
|
Long term portion
|
|
$
|
41,270
|
|
|
|
|
|
|
F-57
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
8.
|
LONG-TERM
DEBT AND NOTES PAYABLE TO FOUNDER
|
Long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
March 31, 2011
|
|
|
December 31, 2010
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
Senior Debt On November 13, 2008, the Company
entered into a Fifth Amended and Restated Credit Agreement with
a group of banks, which was replaced by the Sixth Amended and
Restated Credit Agreement on May 13, 2010 (credit
facility). The credit facility matures on
November 13, 2012 and is secured by substantially all of
the Companys oil and gas properties. The credit facility
borrowing base is redetermined periodically and, as of
March 31, 2011, the borrowing base under the facility was
$220 million. The credit facility bears interest at LIBOR
plus applicable margins between 2.50% and 3.25% or a
Reference Rate, which is based on the prime rate of
Wells Fargo Bank, N. A., plus a margin ranging from 1.50% to
2.25%, depending on the utilization of our borrowing base. The
rate was 2.875% as of March 31, 2011 and December 31,
2010
|
|
$
|
87,290
|
|
|
$
|
73,290
|
|
Senior Notes Payable On October 13, 2010, the
Company issued notes due October 15, 2018 with a face value
of $300 million, at a discount of $2.1 million. The
senior notes carry a face interest rate of 9 5/8%, with an
effective rate of 9 3/4%; interest is payable semi-annually each
April 15th and October 15th. The senior notes are secured by
general corporate credit, and effectively rank junior to any
existing or future secured indebtedness of the Company, which
includes the credit facility. The senior notes are
unconditionally guaranteed on a senior unsecured basis by each
material subsidiary of the Company. The balance is presented net
of unamortized discount of $1.9 million and
$2.0 million at March 31, 2011 and December 31,
2010, respectively
|
|
|
298,051
|
|
|
|
297,986
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
$
|
385,341
|
|
|
$
|
371,276
|
|
|
|
|
|
|
|
|
|
|
The senior notes contain an optional redemption provision
beginning in October 2013 allowing the Company to retire up to
35% of the principal outstanding under the senior notes with the
proceeds of an equity offering, at 109.625%. Additional optional
redemption provisions allow for retirement at 104.813%,
102.406%, and 100.0% beginning on each of October 15, 2014,
2015, and 2016, respectively.
On October 13, 2010, the Company entered into a
registration rights agreement with the initial purchasers of the
senior notes. Under the terms of the registration rights
agreement, the Company has filed a registration statement with
the SEC to become effective no later than 360 days after
the senior notes were issued, to allow for registration of
exchange notes with terms substantially identical to
the senior notes. The exchange notes are to be exchanged for the
original senior notes.
The credit facility and senior notes include covenants requiring
that the Company maintain certain financial covenants including
a Current Ratio, Leverage Ratio, and Interest Coverage Ratio. At
March 31, 2011, the Company was in compliance with the
covenants. The terms of the credit facility also restrict the
Companys ability to make distributions and investments.
F-58
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In addition, the Company has notes payable to our founder which
bear simple interest at 10% with a balance of $20 million
and $19.7 million at March 31, 2011 and
December 31, 2010, respectively. The notes mature
December 31, 2018. Interest and principal are payable at
maturity. The notes are subordinate to all debt. Interest on the
notes payable to our founder amounted to $298,000 and $293,000
for the three months ended March 31, 2011 and 2010,
respectively. Such amounts have been added to the balance of the
notes.
|
|
9.
|
ACCOUNTS
PAYABLE AND ACCRUED LIABILITIES
|
The following provides the detail of accounts payable and
accrued liabilities:
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
Capital expenditures
|
|
$
|
17,473
|
|
|
$
|
22,743
|
|
Revenues and royalties payable
|
|
|
5,507
|
|
|
|
5,962
|
|
Operating expenses/taxes
|
|
|
22,822
|
|
|
|
18,220
|
|
Compensation
|
|
|
3,156
|
|
|
|
2,591
|
|
Liability related to drilling rig
|
|
|
9,785
|
|
|
|
9,785
|
|
Other
|
|
|
2,304
|
|
|
|
1,775
|
|
|
|
|
|
|
|
|
|
|
Total accrued liabilities
|
|
|
61,047
|
|
|
|
61,076
|
|
Accounts payable
|
|
|
16,485
|
|
|
|
26,179
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
77,532
|
|
|
$
|
87,255
|
|
|
|
|
|
|
|
|
|
|
The following provides the detail of other long-term liabilities:
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
Acquisition obligation
|
|
$
|
249
|
|
|
$
|
411
|
|
Remediation liability
|
|
|
943
|
|
|
|
943
|
|
Other
|
|
|
4,967
|
|
|
|
5,886
|
|
|
|
|
|
|
|
|
|
|
Total other long-term liabilities
|
|
$
|
6,159
|
|
|
$
|
7,240
|
|
|
|
|
|
|
|
|
|
|
|
|
10.
|
COMMITMENTS
AND CONTINGENCIES
|
Contingencies
Deep Bossier litigation: On
July 23, 2009, we made a payment of $25.5 million and
took assignment of substantially all working interests that had
been held by Chesapeake Energy Corporation in an approximate
50,000 acre area of Leon and Robertson Counties, Texas in
the Deep Bossier play. We had exercised our preferential right
to purchase these interests from Gastar Exploration Ltd. in late
2005, but Gastar and Chesapeake had opposed this and Chesapeake
took record title until we finally and conclusively prevailed,
and in 2008 a Texas court of appeals directed that specific
performance take place. In early 2009, the Texas Supreme Court
denied the defendants request to hear the appeal. As a
result, we were able to take working interests in over 30
producing wells and participate in further development of the
area, primarily with EnCana, but also with Gastar. A subsequent
payment to EnCana of $15.2 million plus purchase accounting
adjustments of $3.8 million brought the total cost of the
acquisition to $44.5 million. While the ownership of these
interests has been decided by the courts, we are pursuing other
claims against Chesapeake; Chesapeake is claiming an additional
$36.5 million of past expenses from us. The Company is
unable to express an opinion
F-59
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 consolidated
financial statements at March 31, 2011.
Sydson Energy v. Alta Mesa Holdings, L.P. and The Meridian
Resource and Exploration, LLC: In January
2011, Sydson Energy brought suit for declaratory relief, breach
of contract and tortious interference related to certain
assignments of oil and gas interests. Meridian filed a
counterclaim for declaratory relief and was seeking rescission
of the disputed assignments. Subsequent to March 31, 2011,
the litigation was settled; see Note 14, Subsequent
Events. Based on the subsequent settlement of the
litigation, the Company did not provide any amount for this
matter in its consolidated financial statements at
March 31, 2011.
Texas Oil Distribution & Development, Inc. and
Matrix Petroleum, LLC v. Alta Mesa Holdings, LP and The
Meridian Resource & Exploration,
LLC: In November 2010, Texas Oil
Distribution & Development, Inc. and Matrix Petroleum
LLC (together, TODD), filed a petition seeking
declaratory relief based on TODDs employment of Thomas
Tourek, a former independent contractor of the Company.
Mr. Tourek owed certain contractual and common law
obligations to the Company, including, without limitation,
confidentiality and non-compete obligations. TODD seeks
declaratory relief of those obligations. In addition, on
January 10, 2011, TODD filed an amended petition for
declaratory relief, breach of contract and tortious interference
related to certain assignments of oil and gas interests and
joined Meridian as a defendant. Meridian filed a counterclaim
for declaratory relief and seeking rescission of the disputed
assignments. The Company and TODD are exploring settlement
options. The Company has not provided any amount for this matter
in its consolidated financial statements at March 31, 2011.
Environmental claims: Management has
established a liability for soil contamination in Florida of
$943,000 at March 31, 2011 and December 31, 2010,
based on the Companys undiscounted engineering estimates.
The obligations are included in other long-term liabilities in
the accompanying consolidated balance sheets.
Various landowners have sued Meridian (along with numerous other
oil companies) in lawsuits concerning several fields in which
Meridian 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 Meridians oil and
natural gas operations. 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, we have not provided any amount for these claims in
our financial statements at March 31, 2011.
Due to the nature of the Companys business, some
contamination of the real estate property owned or leased by the
Company is possible. Environmental site assessments of the
property would be necessary to adequately determine remediation
costs, if any. No accrual has been made other than the balance
noted above.
Title/lease disputes: Title and lease
disputes may arise in the normal course of the Companys
operations. These disputes are usually small but could result in
an increase or decrease in reserves once a final resolution to
the title dispute is made.
Other contingencies: The Company is
subject to legal proceedings, claims and liabilities arising in
the ordinary course of business. The outcome cannot be
reasonably estimated; however, in the opinion of management,
such litigation and claims will be resolved without material
adverse effect on the Companys financial position, results
of operations or cash flows. Accruals for losses associated with
litigation are made when losses are deemed probable and can be
reasonably estimated.
The Company has contingent commitments to pay an amount up to a
maximum of approximately $7.3 million for properties
acquired in 2008 and prior years. The additional purchase
consideration will be
F-60
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
paid only if certain product price conditions are met. The
Company cannot estimate the amounts that will be paid in the
future, if any, or the fiscal years in which such amounts could
become due.
Drilling rig: Included in the
Companys acquisition of Meridian was a contractual
obligation for the use of a drilling rig. Meridian and the
Company were not able to fully utilize this rig during the
contractual term; however, the Company was obligated for the
dayrate regardless of whether the rig was working or idle. The
operator, Orion Drilling, LP (Orion), sought other
parties to use the rig and agreed to credit Meridians and
the Companys obligation, based on revenues from third
parties who utilized the rig when it was not utilized under the
contract. The Company has provided approximately
$9.8 million for the liability under this drilling contract
in its financial statements at March 31, 2011. The drilling
rig contract terminated in February 2011.
The Company may grant title to a Company-owned rig to Orion, the
operator under the dayrate contract, in exchange for release of
all accrued liabilities under the rig contract and under a
similar rig contract which previously expired and was also
underutilized. 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 Company has an option to
settle all claims with Orion in cash, and retain title to the
rig. We are evaluating our options regarding transfer of title
to the rig.
At March 31, 2011, the rig is included in equipment at a
net book value of $9.9 million; current liabilities include
a total of $9.8 million for the accumulated obligation to
Orion.
|
|
11.
|
SIGNIFICANT
RISKS AND UNCERTAINTIES
|
The Companys business makes it vulnerable to changes in
wellhead prices of crude oil and natural gas. Such prices have
been volatile in the past and can be expected to be volatile in
the future. By definition, proved reserves are based on analysis
of current oil and natural gas prices. Price declines reduce the
estimated value of proved reserves and may increase annual
amortization expense (which is based on proved reserves). Price
declines may also result in impairments, or non-cash
write-downs, of the value of our oil and gas properties. The
Company mitigates a portion of this vulnerability by entering
into oil and natural gas price derivative contracts. See
Note 6.
AMIH and affiliates of Alta Mesa Holdings created a partnership
in September 2005, whereby the affiliates of Alta Mesa Holdings
were Class A limited partners and AMIH was a Class B
limited partner.
Management and Control: The business
and affairs of the Company are managed by the General Partner;
which is a wholly owned subsidiary of Alta Mesa Holdings, LP.
With certain exceptions, the General Partner may not be removed
except for the reasons of cause, which are defined
in the Alta Mesa Holdings, LP Partnership Agreement
(Partnership Agreement). The Class B limited
partner has certain approval rights, generally over capital
plans and significant transactions in the areas of finance,
acquisition, and divestiture.
Distribution and Income
Allocation: Prior to January 1, 2012,
net cash flow from operations is to be retained by the Company
to fund development, exploration, and acquisition. After
January 1, 2012, net cash flow from operations may be
distributed to the Class A and Class B Partners based
on a variable formula as defined in the Partnership Agreement.
The Class B Partner may require the General Partner to make
distributions; however, any distribution must be permitted under
the terms of our credit facility and our senior notes.
Distribution of net cash flow from a Liquidity Event is
distributed to the Class A and Class B Partners
according to a variable formula as defined in the Partnership
Agreement. A Liquidity Event is any event in which the Company
receives cash proceeds outside the ordinary course of the
Companys business. Further, after January 1, 2012,
the Class B Partners can, without consent of any other
partners, request that the General
F-61
ALTA MESA
HOLDINGS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Partner take action to cause the Company and its subsidiaries,
or the assets of the Company, to be sold to one or more third
parties.
|
|
13.
|
SUBSIDIARY
GUARANTORS
|
All of our wholly-owned subsidiaries are guarantors under the
terms of both our senior notes and our credit facility.
Our consolidated financial statements reflect the combined
financial position of these subsidiary guarantors. Our parent
company, Alta Mesa Holdings, LP has no independent operations,
assets, or liabilities. The guarantees are full and
unconditional and joint and several. Those subsidiaries which
are not wholly owned and are not guarantors are minor. There are
no restrictions on dividends, distributions, loans, or other
transfers of funds from the subsidiary guarantors to our parent
company.
Management has evaluated all events subsequent to the balance
sheet date of March 31, 2011 to May 16, 2011, which is
the date the consolidated financial statements were available
for issuance, and has determined that no events, other than the
acquisition described below, require disclosure.
As described in Note 9, Sydson Energy brought suit against
the Company in January 2011 for breach of contract and other
claims. Sydson is a joint interest partner of the Company in
many of the properties acquired from Meridian. Sydson is owned
by Michael Mayell, a former officer of Meridian. Mr. Mayell
individually owned interests in many of the Meridian properties
in addition to his ownership through Sydson. On April 21,
2011, the Company acquired 100% of Mr. Mayells and
Sydsons interests in all of the properties in which they
had shared interests with the Company. The terms of the
acquisition included release and settlement of all claims under
the Sydson litigation. Total proved reserves acquired were
approximately 5 Bcfe, primarily in South Louisiana, East
Texas, and the Eagle Ford Shale play. The total cost of the
acquisition was less than $30 million, which will be
allocated primarily to proved properties in the second quarter
of 2011.
F-62
To the Members of
Alta Mesa Holdings, LP and Subsidiaries
We have audited the accompanying statements of revenues and
direct operating expenses of the oil and gas properties
purchased by Alta Mesa Holdings, LP and Subsidiaries, from
Chesapeake Energy Corporation for the period January 1,
2009 through July 22, 2009 and for the fiscal twelve month
period ended December 31, 2008. These financial statements
are the responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards
generally accepted in the United States of America. Those
standards require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the statements of
revenues and direct operating expenses of the oil and gas
properties purchased by Alta Mesa Holdings, LP and Subsidiaries
from Chesapeake Energy Corporation for the period
January 1, 2009 through July 22, 2009 and for the
fiscal twelve month period ended December 31, 2008, in
conformity with accounting principles generally accepted in the
United States of America.
/s/ UHY LLP
Houston, Texas
April 8, 2011
F-63
STATEMENTS
OF REVENUES AND DIRECT OPERATING EXPENSES
OF THE OIL AND GAS PROPERTIES PURCHASED BY ALTA MESA
HOLDINGS, LP
AND SUBSIDIARIES FROM CHESAPEAKE ENERGY CORPORATION
|
|
|
|
|
|
|
|
|
|
|
January 1, 2009
|
|
|
Twelve Months Ended
|
|
|
|
through July 22, 2009
|
|
|
December 31, 2008
|
|
|
|
(Dollars in thousands)
|
|
|
Revenues
|
|
$
|
9,815
|
|
|
$
|
28,627
|
|
Direct Operating Expenses
|
|
|
(1,462
|
)
|
|
|
(2,223
|
)
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
8,353
|
|
|
$
|
26,404
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to the Statements of Revenues and Direct
Operating Expenses
F-64
OF THE
OIL AND GAS PROPERTIES PURCHASED BY ALTA MESA HOLDINGS, LP
AND SUBSIDIARIES FROM CHESAPEAKE ENERGY CORPORATION
|
|
NOTE 1
|
BASIS OF
PRESENTATION
|
On July 23, 2009, as part of an on-going lawsuit related to
preferential right issues with Chesapeake Energy Corporation
(Chesapeake) and operators Gastar Exploration Texas,
LP (Gastar) and Encana Oil and Gas Inc.
(Encana), Navasota Resources Ltd., LLP (the
Company), a wholly-owned subsidiary of Alta Mesa
Holdings, LP, entered into an agreement to acquire from
Chesapeake, interests in oil and gas properties (the
Properties) for approximately $41.7 million, with an
effective date of July 23, 2009. The accompanying
statements of revenues and direct operating expenses relate to
the operations of the oil and gas properties acquired by the
Company.
The statements of revenues and direct operating expenses
associated with the properties were derived from the accounting
records of Gastar and Encana. During the years presented, the
Properties were not accounted for or operated as a consolidating
entity or as a separate division by Chesapeake. Revenues and
direct operating expenses for the Properties included in the
accompanying statements represent the net collective working and
revenue interests to be acquired by the Company on the accrual
basis of accounting. The revenues and direct operating expenses
presented herein relate only to the interests in the producing
oil and natural gas properties which were acquired and do not
represent all of the oil and natural gas operations of
Chesapeake, other owners, or third party working interest
owners. Direct operating expenses include lease operating
expenses and production and other related taxes. General and
administrative expenses, depreciation, depletion and
amortization (DD&A) of oil and gas properties
and federal and state taxes have been excluded from direct
operating expenses in the accompanying statements of revenues
and direct operating expenses because the allocation of certain
expenses would be arbitrary and would not be indicative of what
such costs would have been had the Properties been operated as a
stand alone entity. Full separate financial statements prepared
in accordance with accounting principles generally accepted in
the United States of America do not exist for the Properties and
are not practicable to prepare in these circumstances. The
statements of revenues and direct operating expenses presented
are not indicative of the results of operations of the
Properties on a go forward basis due to the changes in the
business and omission of various operating expenses.
|
|
NOTE 2
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
Use of estimates: The preparation of
financial statements in conformity with accounting principles
generally accepted in the United States of America requires
management to make estimates and assumptions that affect
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Revenue recognition: The Company
records revenues when its products are delivered at a fixed or
determinable price, title has transferred and collectability is
reasonably assured.
|
|
NOTE 3
|
SUPPLEMENTARY
OIL AND GAS INFORMATION
(UNAUDITED)
|
Estimated
Net Quantities of Oil and Natural Gas Reserves
The following estimates of the net proved oil and natural gas
reserves of the properties, which are located entirely within
the United States of America, are based on evaluations prepared
by third-party reservoir engineers. Reserves were estimated in
accordance with guidelines established by the Securities and
Exchange Commission (SEC) and the Financial
Accounting Standards Board (FASB), which require
that reserve estimates be prepared under existing economic and
operating conditions with no provisions for price and cost
changes except by contractual arrangements. Reserve estimates
are inherently imprecise and estimates of new discoveries are
more imprecise than those of producing oil and gas properties.
Accordingly, reserve estimates are expected to change as
additional performance data becomes available.
F-65
NOTES TO
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF THE OIL AND GAS PROPERTIES PURCHASED BY ALTA MESA HOLDINGS,
LP
AND SUBSIDIARIES FROM CHESAPEAKE ENERGY
CORPORATION (Continued)
Estimated quantities of proved domestic gas reserves and changes
in quantities of proved developed and undeveloped reserves in
million cubic feet (MMcf) were as follows:
|
|
|
|
|
|
|
Natural
|
|
|
|
Gas (MMcf)
|
|
|
Proved reserves at December 31, 2007
|
|
|
8,356
|
|
Production
|
|
|
(1,993
|
)
|
Extensions and discoveries
|
|
|
13,220
|
|
Revisions in previous estimates
|
|
|
|
|
|
|
|
|
|
Proved reserves at December 31, 2008
|
|
|
19,583
|
|
Production
|
|
|
(2,148
|
)
|
Extensions and discoveries
|
|
|
14,306
|
|
Revisions in previous estimates
|
|
|
|
|
|
|
|
|
|
Proved reserves at July 22, 2009
|
|
|
31,741
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
December 31, 2007
|
|
|
8,356
|
|
December 31, 2008
|
|
|
19,583
|
|
July 22, 2009
|
|
|
31,741
|
|
Discounted
Future Net Cash Flows
A summary of the discounted future net cash flows relating to
proved natural gas reserves is shown below. Future net cash
flows are computed with guidelines established by the SEC and
FASB, using commodity prices and costs that relate to the
properties existing proved natural gas reserves.
The discounted future net cash flows related to proved natural
gas reserves for the period from January 1, 2009 through
July 22, 2009, the twelve months ended December 31,
2008 are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
January 1, 2009
|
|
|
Twelve Months Ended
|
|
|
|
through July 22, 2009
|
|
|
December 31, 2008
|
|
|
Future cash inflows
|
|
$
|
198,200
|
|
|
$
|
111,817
|
|
Less related future
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
34,980
|
|
|
|
19,734
|
|
Development costs
|
|
|
2,720
|
|
|
|
1,535
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
160,500
|
|
|
|
90,548
|
|
Ten percent annual discount for estimated timing of cash flows
|
|
|
76,042
|
|
|
|
42,899
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows
|
|
$
|
84,458
|
|
|
$
|
47,649
|
|
|
|
|
|
|
|
|
|
|
F-66
NOTES TO
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF THE OIL AND GAS PROPERTIES PURCHASED BY ALTA MESA HOLDINGS,
LP
AND SUBSIDIARIES FROM CHESAPEAKE ENERGY
CORPORATION (Continued)
Changes
in Discounted Future Net Cash Flows
A summary of the changes in the discounted future net cash flows
applicable to proved natural gas reserves follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
January 1, 2009
|
|
|
Twelve Months Ended
|
|
|
|
through July 22, 2009
|
|
|
December 31, 2008
|
|
|
Beginning of period
|
|
$
|
47,649
|
|
|
$
|
24,177
|
|
Revisions of previous estimates
|
|
|
|
|
|
|
|
|
Changes in prices and costs
|
|
|
4,736
|
|
|
|
12,785
|
|
Changes in quantities
|
|
|
(7
|
)
|
|
|
|
|
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related costs
|
|
|
38,546
|
|
|
|
32,958
|
|
Accretion of discount
|
|
|
4,765
|
|
|
|
2,418
|
|
Sales, net of production costs
|
|
|
(8,353
|
)
|
|
|
(26,404
|
)
|
Changes in rate of production and other
|
|
|
(2,878
|
)
|
|
|
1,715
|
|
|
|
|
|
|
|
|
|
|
Net change
|
|
|
36,809
|
|
|
|
23,472
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
$
|
84,458
|
|
|
$
|
47,649
|
|
|
|
|
|
|
|
|
|
|
F-67
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Thousands of dollars, except per share information)
|
|
|
|
(unaudited)
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
20,976
|
|
|
$
|
22,109
|
|
Price risk management activities
|
|
|
|
|
|
|
2
|
|
Interest and other
|
|
|
71
|
|
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,047
|
|
|
|
22,132
|
|
|
|
|
|
|
|
|
|
|
OPERATING COSTS AND EXPENSES:
|
|
|
|
|
|
|
|
|
Oil and natural gas operating
|
|
|
3,066
|
|
|
|
4,629
|
|
Severance and ad valorem taxes
|
|
|
1,772
|
|
|
|
1,635
|
|
Depletion and depreciation
|
|
|
7,397
|
|
|
|
11,763
|
|
General and administrative
|
|
|
4,517
|
|
|
|
3,369
|
|
Rig operations, net
|
|
|
1,442
|
|
|
|
|
|
Accretion expense
|
|
|
546
|
|
|
|
523
|
|
Impairment of long-lived assets
|
|
|
|
|
|
|
59,539
|
|
|
|
|
18,740
|
|
|
|
81,458
|
|
|
|
|
|
|
|
|
|
|
EARNINGS (LOSS) BEFORE OTHER EXPENSE & INCOME
TAXES
|
|
|
2,307
|
|
|
|
(59,326
|
)
|
|
|
|
|
|
|
|
|
|
OTHER EXPENSE:
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
1,966
|
|
|
|
1,634
|
|
|
|
|
|
|
|
|
|
|
EARNINGS (LOSS) BEFORE INCOME TAXES
|
|
|
341
|
|
|
|
(60,960
|
)
|
|
|
|
|
|
|
|
|
|
INCOME TAXES:
|
|
|
|
|
|
|
|
|
Current
|
|
|
1
|
|
|
|
1
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS (LOSS)
|
|
$
|
340
|
|
|
$
|
(60,961
|
)
|
|
|
|
|
|
|
|
|
|
NET EARNINGS (LOSS) PER SHARE:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
|
|
|
$
|
(0.66
|
)
|
Diluted
|
|
$
|
|
|
|
$
|
(0.66
|
)
|
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
92,476
|
|
|
|
92,451
|
|
Diluted
|
|
|
93,678
|
|
|
|
92,451
|
|
See notes to consolidated financial statements.
F-68
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Thousands of dollars)
|
|
|
|
(unaudited)
|
|
|
ASSETS
|
CURRENT ASSETS:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
7,851
|
|
|
$
|
5,273
|
|
Restricted cash
|
|
|
35
|
|
|
|
35
|
|
Accounts receivable, less allowance for doubtful accounts of
$110 [2010 and 2009]
|
|
|
11,028
|
|
|
|
12,185
|
|
Prepaid expenses and other
|
|
|
1,381
|
|
|
|
2,195
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
20,295
|
|
|
|
19,688
|
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, full cost method (including
$1,567 [2010] and $1,647 [2009] not subject to depletion)
|
|
|
1,891,818
|
|
|
|
1,890,079
|
|
Equipment and other
|
|
|
20,467
|
|
|
|
20,469
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,912,285
|
|
|
|
1,910,548
|
|
Less accumulated depletion and depreciation
|
|
|
1,754,669
|
|
|
|
1,747,274
|
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
157,616
|
|
|
|
163,274
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Other
|
|
|
106
|
|
|
|
168
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
106
|
|
|
|
168
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
178,017
|
|
|
$
|
183,130
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
7,241
|
|
|
$
|
6,136
|
|
Revenues and royalties payable
|
|
|
5,095
|
|
|
|
4,890
|
|
Due to affiliates
|
|
|
243
|
|
|
|
542
|
|
Accrued liabilities
|
|
|
8,877
|
|
|
|
10,109
|
|
Asset retirement obligations
|
|
|
5,626
|
|
|
|
4,570
|
|
Current maturities of long-term debt
|
|
|
88,512
|
|
|
|
93,666
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
115,594
|
|
|
|
119,913
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM DEBT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER:
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
18,880
|
|
|
|
19,253
|
|
Other
|
|
|
2,453
|
|
|
|
3,220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,333
|
|
|
|
22,473
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY:
|
|
|
|
|
|
|
|
|
Common stock, $0.01 par value (200,000,000 shares
authorized, 92,475,527 [2010 and 2009] issued)
|
|
|
925
|
|
|
|
925
|
|
Additional paid-in capital
|
|
|
535,449
|
|
|
|
535,443
|
|
Accumulated deficit
|
|
|
(495,284
|
)
|
|
|
(495,624
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
41,090
|
|
|
|
40,744
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY
|
|
$
|
178,017
|
|
|
$
|
183,130
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
F-69
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Thousands of dollars)
|
|
|
|
(unaudited)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Net earnings (loss)
|
|
$
|
340
|
|
|
$
|
(60,961
|
)
|
Adjustments to reconcile net earnings (loss) to net cash
provided by operating activities:
|
|
|
|
|
|
|
|
|
Depletion and depreciation
|
|
|
7,397
|
|
|
|
11,763
|
|
Impairment of long-lived assets
|
|
|
|
|
|
|
59,539
|
|
Amortization of other assets
|
|
|
61
|
|
|
|
304
|
|
Non-cash compensation
|
|
|
6
|
|
|
|
53
|
|
Non-cash gain on change in fair value of outstanding warrants
|
|
|
|
|
|
|
(641
|
)
|
Non-cash price risk management activities
|
|
|
|
|
|
|
(2
|
)
|
Accretion expense
|
|
|
546
|
|
|
|
523
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
|
|
|
|
4
|
|
Accounts receivable
|
|
|
1,157
|
|
|
|
3,927
|
|
Prepaid expenses and other
|
|
|
814
|
|
|
|
2,429
|
|
Due to/from affiliates
|
|
|
(299
|
)
|
|
|
89
|
|
Accounts payable
|
|
|
1,278
|
|
|
|
(3,448
|
)
|
Advances from non-operators
|
|
|
1
|
|
|
|
(3,376
|
)
|
Revenues and royalties payable
|
|
|
205
|
|
|
|
(951
|
)
|
Asset retirement obligations
|
|
|
(140
|
)
|
|
|
|
|
Other assets and liabilities
|
|
|
(1,869
|
)
|
|
|
(497
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
9,497
|
|
|
|
8,755
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Additions to property and equipment
|
|
|
(1,765
|
)
|
|
|
(15,009
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(1,765
|
)
|
|
|
(15,009
|
)
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Reductions to long-term debt
|
|
|
(5,154
|
)
|
|
|
(445
|
)
|
Reductions in notes payable
|
|
|
|
|
|
|
(1,573
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
|
(5,154
|
)
|
|
|
(2,018
|
)
|
|
|
|
|
|
|
|
|
|
NET CHANGE IN CASH AND CASH EQUIVALENTS
|
|
|
2,578
|
|
|
|
(8,272
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
5,273
|
|
|
|
13,354
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT END OF PERIOD
|
|
$
|
7,851
|
|
|
$
|
5,082
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
|
|
|
|
|
|
|
|
|
Increase (decrease) of Non-cash Activities:
|
|
|
|
|
|
|
|
|
Accrual of capital expenditures
|
|
$
|
(303
|
)
|
|
$
|
(2,826
|
)
|
ARO liability changes in estimates
|
|
$
|
277
|
|
|
$
|
522
|
|
See notes to consolidated financial statements.
F-70
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS
EQUITY
Three Months Ended March 31, 2010 and 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
Accumulated
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
Paid-In
|
|
|
Earnings
|
|
|
Comprehensive
|
|
|
Treasury Stock
|
|
|
|
|
|
|
Shares
|
|
|
Par Value
|
|
|
Capital
|
|
|
(Deficit)
|
|
|
Income (Loss)
|
|
|
Shares
|
|
|
Cost
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
|
(unaudited)
|
|
|
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
|
)
|
Stock-based compensation
|
|
|
25
|
|
|
|
|
|
|
|
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
53
|
|
Accumulated other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
227
|
|
|
|
|
|
|
|
|
|
|
|
227
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(60,961
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(60,961
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, March 31, 2009
|
|
|
93,070
|
|
|
$
|
948
|
|
|
$
|
538,614
|
|
|
$
|
(483,949
|
)
|
|
$
|
8,356
|
|
|
|
1,712
|
|
|
$
|
(3,099
|
)
|
|
$
|
60,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
92,475
|
|
|
$
|
925
|
|
|
$
|
535,443
|
|
|
$
|
(495,624
|
)
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
40,744
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
340
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
340
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, March 31, 2010
|
|
|
92,475
|
|
|
$
|
925
|
|
|
$
|
535,449
|
|
|
$
|
(495,284
|
)
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
41,090
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
F-71
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Thousands of dollars)
|
|
|
|
(unaudited)
|
|
|
Net earnings (loss) applicable to common stockholders
|
|
$
|
340
|
|
|
$
|
(60,961
|
)
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax, for unrealized
gains (losses) from hedging activities:
|
|
|
|
|
|
|
|
|
Unrealized holding gains (losses) arising during period(1)
|
|
|
|
|
|
|
3,798
|
|
Reclassification adjustments on settlement of contracts(2)
|
|
|
|
|
|
|
(3,571
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
227
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income (loss)
|
|
$
|
340
|
|
|
$
|
(60,734
|
)
|
|
|
|
|
|
|
|
|
|
(1) Net income tax (expense) benefit
|
|
$
|
|
|
|
$
|
|
|
(2) Net income tax (expense) benefit
|
|
$
|
|
|
|
$
|
|
|
See notes to consolidated financial statements.
F-72
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
|
|
1.
|
BASIS OF
PRESENTATION, AND GOING CONCERN
|
The consolidated financial statements reflect the accounts of
The Meridian Resource Corporation and its subsidiaries (the
Company or Meridian) after elimination
of all significant intercompany transactions and balances. The
financial statements should be read in conjunction with the
consolidated financial statements and notes thereto included in
the Companys Annual Report on
Form 10-K
for the year ended December 31, 2009, as filed with the
Securities and Exchange Commission (SEC).
The financial statements included herein as of March 31,
2010, and for the three month periods ended March 31, 2010
and 2009, are unaudited, and in the opinion of management, the
information furnished reflects all material adjustments,
consisting of normal recurring adjustments, necessary for a fair
presentation of financial position and of the results of
operations for the interim periods presented. Certain minor
reclassifications of prior period financial statements have been
made to conform to current reporting practices. The results of
operations for interim periods are not necessarily indicative of
results to be expected for a full year.
Merger. 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
would receive $0.33 per share of common stock, to be paid in
cash, and Alta Mesa would assume the Companys debts and
obligations. The Company would be merged into Merger Sub with
Merger Sub as the surviving entity. The merger was subject to
approval by holders of two thirds of the Companys
outstanding shares of common stock. The Company filed a proxy
statement regarding the proposed merger on February 8,
2010, in which the Companys board recommended that
shareholders vote in favor of the merger. At a shareholder
meeting held on May 10, 2010 where a vote was taken, the
merger was approved. The transaction was closed on May 13,
2010, at which time the Companys stock ceased to be
publicly traded and the Company was merged with and into Merger
Sub, assuming the name Alta Mesa Acquisition Sub, LLC. The
Companys shareholders immediately prior to the merger
ceased to have any rights as shareholders of the Company, and no
longer have an interest in the Companys future earnings or
growth (other than the right to receive consideration for their
shares under the Merger Agreement, or the right to an appraisal
of their shares under Texas law.) The debt under the
Companys credit facility, $82 million at the time,
was extinguished, and all other liabilities, including a
$5.3 million term note, were assumed by Merger Sub as of
the closing date. The Company has filed the appropriate forms
with the SEC to discontinue its reporting obligations, and the
stock has been delisted from the New York Stock Exchange. As of
May 13, 2010, Meridian is no longer a separate and
independent going concern.
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. No
adjustments related to the subsequent merger have been made.
|
|
2.
|
SIGNIFICANT
ACCOUNTING POLICIES
|
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
F-73
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the first quarter of 2009, and was subsequently contracted to a
third party at a lesser dayrate than the Companys
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.
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.
When the rig is used by Orion for work on third party wells in
which the Company has no economic or management interest,
TMRDs 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. Any such loss on a
contractual obligation is included in Rig operations,
net in the consolidated statements of operations. The
Companys 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 the three months ended
March 31, 2010 was $145,000. For the three months ended
March 31, 2009, although the Company was unable to fully
utilize the two rigs, rig operations were estimated to have
resulted in no profit or loss. Therefore no related expense was
recognized. The dayrate contract for the Company-owned rig
expired March 31, 2010; the dayrate contract for the other
rig continues to February 2011.
Depreciation of the owned rig was $221,000 for each of the three
month periods ended March 31, 2010 and 2009, respectively.
In the first quarter of 2009, $90,000 was capitalized to the
full cost pool, and the remainder was included in depletion and
depreciation expense on the consolidated statements of
operations. In the first quarter of 2010, the entire amount was
included in depletion and depreciation expense.
See Note 8 for additional information on the Companys
plans for potential disposition of the Company-owned rig and the
obligation under the remaining drilling contract and the lease
of the Company-owned rig.
Property
and Equipment
The Company uses the full cost method of accounting for its
investments in oil and natural gas properties. Capitalized costs
of proved oil and natural gas properties are depleted on a units
of production method using proved oil and natural gas reserves.
Costs depleted include net capitalized costs subject to
depletion and estimated future dismantlement, restoration, and
abandonment costs. 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 were zero and $2.6 million
for the three month periods ended March 31, 2010 and
March 31, 2009, respectively.
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.
F-74
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Fair
Value of Financial Instruments
The Companys 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 March 31, 2010 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. However, the merger transaction which closed in May 2010,
under which Merger Sub assumed all the liabilities and paid off
the $82 million outstanding balance under the credit
facility, in addition to a cash purchase of all of the
outstanding shares of the Company, indicates the underlying
collateral, the Companys oil and natural gas reserves, was
supportive of the full balance of the debt, and the carrying
value and fair value were similar. The carrying value of the
debt was $83 million at March 31, 2010. See
Note 6 for further details on the credit facility. The
Company also has a financing agreement with a fixed rate, the
rig note. The fair value of the rig note at March 31, 2010
is estimated as approximately $4 million; the corresponding
carrying value of the debt is $5.5 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 4 for further information on how fair
value for the rig was estimated. Our oil and gas price risk
hedging contracts are also financial instruments, recorded at
fair value; see Note 11.
Recent
Accounting Pronouncements
A standard to improve disclosures about fair value measurements
was issued by the Financial Accounting Standards Board (the
FASB) in January 2010. The additional disclosures
required include: (1) the different classes of assets and
liabilities measured at fair value, (2) the significant
inputs and techniques used to measure Level 2 and
Level 3 assets and liabilities for both recurring and
nonrecurring fair value measurements, (3) the gross
presentation of purchases, sales, issuance and settlements for
the rollforward of Level 3 activity and (4) the
transfers in and out of Levels 1 and 2. The Company adopted
the new disclosures in the first quarter of 2010.
|
|
3.
|
IMPAIRMENT
OF LONG-LIVED ASSETS
|
At the end of each quarter, the unamortized cost of oil and
natural gas properties, net of related deferred income taxes, is
limited to the sum of the estimated future after-tax net
revenues from proved properties using period-end prices, after
giving effect to cash flow hedging positions, discounted at 10%,
and the lower of cost or fair value of unproved properties
adjusted for related income tax effects. This is known as the
ceiling test.
Accordingly, based on March 31, 2009 pricing of $3.76 per
Mmbtu of natural gas and $49.66 per barrel of oil, the Company
recognized a non-cash impairment of $59.5 million of the
Companys oil and natural gas properties under the full
cost method of accounting during the first quarter of 2009.
Prices used in the ceiling test in the first quarter of 2010
were $3.99 per Mmbtu of natural gas and $69.64 per barrel of
oil. No impairment was required in the first quarter of 2010.
Due to the substantial volatility in oil and natural gas prices
and their effect on the carrying value of the Companys
proved oil and natural gas reserves, there can be no assurance
that future write-downs will not be required as a result of
factors that may negatively affect the present value of proved
oil and natural gas reserves and the carrying value of oil and
natural gas properties, including volatile oil and natural gas
prices, downward revisions in estimated proved oil and natural
gas reserve quantities, and unsuccessful drilling activities.
Based on March 31, 2010 prices for oil and natural gas, the
Company had an excess of the ceiling over our capitalized costs
of $17.4 million (pretax and aftertax). See Note 8 for
further information regarding the sensitivity of the ceiling to
changes in the prices of oil and natural gas.
F-75
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company performs impairment testing of its drilling rig each
quarter. At March 31, 2010, the carrying value of the rig
exceeded its estimated fair value (based on discounted cash
flows) by approximately $0.7 million. 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.
|
|
4.
|
FAIR
VALUE MEASUREMENT
|
The Company follows the FASB guidance 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.
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
Note 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 in the current period. 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 utilized 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 classified the fair values of all its derivative
contracts as Level 2. There are currently no derivative
contracts outstanding.
The fair value of the Companys General Partner Warrants
(see Note 9) was calculated using the Black-Scholes
option pricing model.
Assets
and liabilities measured at fair value on a recurring
basis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at
|
|
|
|
|
|
|
March 31, 2010 Using
|
|
|
|
|
|
|
Quoted
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices in
|
|
|
|
|
|
|
|
|
|
|
|
|
Active
|
|
|
Significant
|
|
|
Significant
|
|
|
|
|
|
|
Markets for
|
|
|
Other
|
|
|
Other
|
|
|
|
|
|
|
Identical
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
March 31,
|
|
|
Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
Description
|
|
2010
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
|
|
|
|
(Thousands of dollars)
|
|
|
General Partner Warrants(1)
|
|
$
|
412
|
|
|
|
|
|
|
$
|
412
|
|
|
|
|
|
|
|
|
(1) |
|
General Partner Warrants are more fully described in Note 9. |
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
F-76
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 no additions to asset retirement obligations
measured at fair value during the three months ended
March 31, 2010.
The Company estimates the fair value of its drilling rig
quarterly (see Note 3), based on the present value of
estimated cash flows from the rig, using managements best
estimates of utilization and dayrates. This is considered a
Level 3 fair value.
Below is the detail of accrued liabilities on the Companys
balance sheets as of March 31, 2010 and December 31,
2009 (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Capital expenditures
|
|
$
|
703
|
|
|
$
|
830
|
|
Operating expenses/taxes
|
|
|
3,182
|
|
|
|
4,072
|
|
Compensation
|
|
|
419
|
|
|
|
918
|
|
Interest and accrued bank fees
|
|
|
268
|
|
|
|
353
|
|
General partner warrants
|
|
|
412
|
|
|
|
412
|
|
Shell settlement (current portion)
|
|
|
1,878
|
|
|
|
1,003
|
|
Other
|
|
|
2,015
|
|
|
|
2,521
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
8,877
|
|
|
$
|
10,109
|
|
|
|
|
|
|
|
|
|
|
Credit Facility. The Company had 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 was
subject to borrowing base redeterminations and bore 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 were 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 were secured by pledges of
outstanding capital stock of the Companys subsidiaries and
by a first priority lien on not less than 75% (95% in the case
of an event of default) of its present value of proved oil and
natural gas properties. The Credit Facility also contained 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
Companys consolidated financial statements.
As of December 31, 2008, the Company was in default of two
of the covenants under the agreement, including one that
required 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
March 31, 2010. The Company was also in default of the
requirement that the Companys auditors opinion for
the current financial statements be without modification. Both
the Companys 2008 and 2009 audit reports from its
independent registered public accounting firm included a
going concern explanatory paragraph that expressed
substantial doubt about the Companys ability to continue
as a going concern. As a result of the defaults, the outstanding
Credit Facility balances of $87.5 million at
December 31,
F-77
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2009 and $83.0 million at March 31, 2010 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 covered in excess of 95% of the present value of proved
oil and natural gas properties.
The Credit Facility was 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 was 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 could redetermine the borrowing base to a
lower level if they determined that the Companys oil and
natural gas reserves, at the time of redetermination, were
inadequate to support the borrowing base then in effect. In the
event the redetermined borrowing base was less than outstanding
borrowings under the Credit Facility, the Credit Facility
required 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 (a $500,000 principal payment had been made in June 2009).
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 had 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.
The Bank Forbearance Agreement also modified the schedule of
borrowing base redeterminations from semi-annually to quarterly.
However, a subsequent amendment to the Bank Forbearance
Agreement provided a limited waiver postponing the next
borrowing base redetermination to the end of the forbearance
period.
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 was based on the prime interest
rate, 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 through April 2010. The additional
default interest was 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 were in arrears at either March 31, 2010
or December 31, 2009.
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; as of March 31, 2010, the
balance was reduced to $83.0 million, and as of May 4,
2010 the balance was $82.0 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
F-78
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 during 2009.
On December 22, 2009, the Company entered into the Merger
Agreement with Alta Mesa. The Eleventh Amendment to Forbearance
and Amendment Agreement (11th 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 and required the
Company to repay $1 million in principal to the Lenders per
month. On April 15, 2010, the Company entered the Twelfth
Amendment to Forbearance and Amendment Agreement, which extended
the deadline for shareholder vote to May 7, 2010 and
included an amendment fee of $208,000; on May 7, 2010, the
Company entered the Thirteenth Amendment to Forbearance and
Amendment Agreement which extended the deadline for consummation
of the transaction to May 14, 2010 (or to no later than
May 31, 2010 upon consent by the Lenders, based on
necessity for additional time to obtain shareholder or other
approvals); this final extension included an amendment fee of
$82,000. Total forbearance fees in the first quarter of 2010
were zero; forbearance fees of $290,000 will be recorded in the
second quarter of 2010.
On May 10, 2010, the merger proposal was approved by the
shareholders and the merger transaction was closed on
May 13, 2010. On that date, all debts under the Credit
Facility, including accrued interest and forbearance fees, were
extinguished.
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 was collateralized by
the drilling rig, as well as general corporate credit. The term
of the loan was 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 triggered a cross-default
under the rig note. The remedies available to CIT in the event
of default included acceleration of all principal and interest
payments. Accordingly, all indebtedness under the rig note,
$6.2 million at December 31, 2009 and
$5.5 million at March 31, 2010, has been classified as
current in the accompanying consolidated balance sheets.
On September 3, 2009, the Company entered into a
forbearance agreement with CIT (CIT Forbearance
Agreement.) The forbearance period under the CIT
Forbearance Agreement was extended several times, most recently
by the Fourth Amendment to Forbearance and Amendment Agreement
(4th Amendment). The forbearance period would end
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 4th Amendment
also provided CITs consent to the merger with Alta Mesa.
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 of 2009, a forbearance fee of approximately $50,000.
On May 13, 2010, the merger transaction with Alta Mesa was
closed, and the forbearance period ended. The note continued
with TMRD, and both Merger Sub and Alta Mesa Holdings, LP became
guarantors of the note.
F-79
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Companys effective income tax rate is near zero in the
first quarters of both 2009 and 2010. 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
realize its deferred tax assets, and therefore recorded a
valuation allowance in the fourth quarter of 2008 to the full
extent of all net deferred tax assets. The allowance has
subsequently been adjusted each quarter, including the first
quarters of 2009 and 2010, to maintain this complete offset of
all deferred tax assets. Thus, the tax expense or benefit
related to net income or loss recognized in the first quarter of
each of 2010 and 2009 was zero, and the effective tax rate for
those periods is 0%. There is no tax expense related to net
income for the first quarter of 2010, as tax loss carryforwards
are sufficient to absorb the income.
|
|
8.
|
COMMITMENTS
AND CONTINGENCIES
|
Default
under Credit Agreement
As described in Note 6, the Company has been in default
under the terms of the Credit Facility and the rig note since
December 31, 2008. As of December 31, 2009, and
continuing at March 31, 2010, the Company had obtained
forbearance from these Lenders under short-term agreements. The
credit defaults have subsequently been resolved by the closing
of the merger transaction on May 13, 2010. Consistent with
prior periods, the Company has not provided for this matter in
its financial statements at March 31, 2010 and
December 31, 2009, other than to reclassify all outstanding
debt as current at those dates.
Litigation
H. L. Hawkins litigation. In December
2004, the estate of H.L. Hawkins filed a claim against Meridian
for damages estimated to exceed several million
dollars for Meridians alleged gross negligence,
willful misconduct and breach of fiduciary duty under certain
agreements concerning certain wells and property in the S.W.
Holmwood and E. Lake Charles Prospects in Calcasieu Parish in
Louisiana, as a result of Meridians satisfying a prior
adverse judgment in favor of Amoco Production Company.
Mr. James Bond had been added as a defendant by Hawkins
claiming Mr. Bond, when he was General Manager of Hawkins,
did not have the right to consent, could not consent or breached
his fiduciary duty to Hawkins if he did consent to all actions
taken by Meridian. Mr. James T. Bond was employed by H.L.
Hawkins Jr. and his companies as General Manager until 2002. He
served on the Board of Directors of the Company from March 1997
to August 2004. After Mr. Bonds employment 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 Circuits decision in the Amoco
litigation. Meridian disagrees with Judge Bates ruling
but the Louisiana First Court of Appeal declined to hear
Meridians 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 Meridians actions were not
grossly negligent, but were within the business judgment rule.
Since Mr. Bonds 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 March 31, 2010.
F-80
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Title/lease disputes. Title and lease disputes
may arise in the normal course of the Companys operations.
These disputes are usually small but could result in an increase
or decrease in reserves once a final resolution to the title
dispute is made.
Environmental litigation. Various landowners
have sued Meridian (along with numerous other oil companies) in
lawsuits concerning several fields in which the Company has had
operations. The lawsuits seek injunctive relief and other
relief, including unspecified amounts in both actual and
punitive damages for alleged breaches of mineral leases and
alleged failure to restore the plaintiffs lands from
alleged contamination and otherwise from the Companys oil
and natural gas operations. In some of the lawsuits, Shell Oil
Company and SWEPI LP (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, which was
amended on April 15, 2010. Under the terms of the
settlement as amended, 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, which has now occurred), 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
Meridians 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 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. The settlement
becomes binding upon the first payment of $1 million, which
occurred in conjunction with the closing of the merger
transaction on May 13, 2010, and the transfer of the land
and overriding royalty interest. Merger Sub has assumed all of
the remaining obligations to Shell under the settlement
agreement.
Other than 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 March 31, 2010.
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
F-81
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
March 31, 2010.
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 Companys directors, Alta Mesa
Holdings, LP, and Alta Mesa Acquisition Sub, LLC. Leider alleged
that the Companys 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.
Effective on March 23, 2010, the parties executed a
Memorandum of Understanding (MOU) reflecting their
agreement in principle to settle the now-consolidated Leider
action. The MOU provides that the defendants deny all
liability. The proposed settlement was conditioned on, among
other things, approval of the merger by Meridians
shareholders, which has now occurred. Under the terms of the
proposed settlement, and upon approval by the Court, all claims
relating to the Merger Agreement as amended, the merger, and
disclosures related to the merger will be dismissed on behalf of
Meridians stockholders. As part of the proposed
settlement, the defendants have agreed not to oppose
plaintiffs counsels 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 parties have agreed to stay the litigation while the
settlement process is ongoing. The proposed settlement did not
affect the amount of merger consideration to be paid to
Meridians shareholders in the merger or change any other
terms of the merger or Merger Agreement as amended. The terms of
the MOU have been described in previous SEC filings. Expenses of
the proposed settlement were recorded in the first quarter of
2010.
Other
contingencies
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
March 31, 2010, 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 March 31, 2009,
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. No impairment was recorded in the first
quarter of 2010.
At March 31, 2010, we had a cushion (i.e., the excess of
the ceiling over capitalized costs) of approximately
$17.4 million (pretax and after-tax). A 10% increase in
prices would have increased the cushion by approximately
$27.9 million. A 10% decrease in prices would have
eliminated the cushion and resulted in an impairment write down
of approximately $10 million. Decreases in prices affecting
the end of subsequent
F-82
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
accounting periods, net of the effect of any hedging positions
the Company may have at the time, 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.
Drilling rigs. As described in Note 2,
Rig Operations, the Company continues to have a
significant contractual obligation for the use of a drilling
rig. The Companys capital expenditure plans no longer
include full use of this rig; however, the Company is obligated
for the dayrate regardless of whether the rig is working or
idle. The operator, Orion, has sought other parties to use the
rig and agreed to credit the Companys obligation, based on
revenues from third parties who utilize the rig when the Company
is unable to. Management cannot predict whether utilization of
the rig by third parties will be consistent, nor to what extent
it may offset obligations under the dayrate contract. The
Company has not provided any amount for any future losses on
this drilling contract in its financial statements at
March 31, 2010. The drilling contract will terminate in
February 2011.
The Company entered into a forbearance agreement with Orion
which may grant title to a company-owned rig to Orion, the
operator under the dayrate contract, in exchange for release of
all accrued and future liabilities under the rig contract and
under a similar rig contract now expired. 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 Company-owned
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.
At March 31, 2010, the rig is included in equipment at a
net book value of $4.4 million, and accounts payable
includes a total of $5.5 million in accrued unpaid invoices
from Orion for underutilization of both rigs, which is net of a
reduction of $1.2 million estimated as the Companys
share of profits on the rig it owns. The Company performs
impairment testing of the rig each quarter; see Note 3.
Merger
Subsequent to March 31, 2010, as described in Note 1,
the Company merged with and into Merger Sub, with Merger Sub as
the surviving entity as of May 13, 2010. In connection with
the consummation of the merger, each share of the Companys
common stock outstanding immediately prior to the merger was
converted into the right to receive $0.33 per share in cash.
Shares of the Company have ceased to be publicly traded. The
Companys shareholders immediately prior to the merger
ceased to have any rights as shareholders of the Company and no
longer have an interest in the Companys future earnings
and growth (other than the right to receive consideration for
their shares under the Merger Agreement, or the right to an
appraisal of their shares under Texas law.)
Subsequent to March 31, 2010, certain outstanding warrants
(see below, Warrants) were settled for a total of
approximately $431,000 with two members of the Companys
Board of Directors, who are also former officers.
Common
Stock
In March 2007, the Companys Board of Directors authorized
a share repurchase program; an amendment to the Credit Facility
agreement at that time increased the available limit for the
Companys repurchase of its common stock from
$1.0 million to $5.0 million annually, so long as the
Company was in compliance with
F-83
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
certain provisions of the Credit Facility. From March 2007, the
inception of the share repurchase program, through
March 31, 2010, the Company had repurchased 535,416 common
shares at a cost of $1,234,000, of which 501,300 shares
were reissued for 401(k) contributions, for contract services
and for compensation, and 34,116 were retired. The Bank
Forbearance Agreement prohibited any further repurchase of
Company stock; none was repurchased in either 2009 or in 2010.
General
Partner Warrants
As of March 31, 2010, 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. The number of shares of common stock purchasable upon the
exercise of each warrant and its corresponding exercise price
are subject to various anti-dilution adjustments.
Messrs. Reeves and Mayell, respectively, are the former
Chief Executive Officer and former Chief Operating Officer of
the Company.
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 companys 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
Companys 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 are made each
quarter, beginning in 2009. For the three month periods ended
March 31, 2010 and 2009, the Company recorded a gain (loss)
on the valuation of the warrants of zero and $641,000,
respectively. The gain in 2009 is included in General and
Administrative Expense.
There were 1,872,998 General Partner Warrants outstanding at
March 31, 2010, included in accrued liabilities at a total
fair value of $412,000. Fair value is based on the Black-Scholes
model for option pricing.
At the closing of the merger transaction, the warrants were
canceled and the holders of the warrants received approximately
$431,000 in total.
F-84
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table sets forth the computation of basic and
diluted net earnings (loss) per share (in thousands, except per
share):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
Net earnings (loss)
|
|
$
|
340
|
|
|
$
|
(60,961
|
)
|
Denominator:
|
|
|
|
|
|
|
|
|
Denominator for basic earnings per share
weighted-average shares outstanding
|
|
|
92,476
|
|
|
|
92,451
|
|
Effect of potentially dilutive common shares:
|
|
|
|
|
|
|
|
|
Warrants and stock rights(a)
|
|
|
1,202
|
|
|
|
NA
|
|
Employee and director stock options(a)
|
|
|
NA
|
|
|
|
NA
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted earnings per share
weighted-average shares outstanding and assumed conversions
|
|
|
93,678
|
|
|
|
92,451
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per share
|
|
$
|
|
|
|
$
|
(0.66
|
)
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share
|
|
$
|
|
|
|
$
|
(0.66
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The number of warrants excluded for the three months ended
March 31, 2009 totaled approximately 3.3 million. The
number of options excluded for that period totaled approximately
700,000. A total of 404,000 options were excluded for the three
months ended March 31, 2010, because the options
exercise price was greater than the average market price of the
common shares, which made them anti-dilutive. |
Warrants and stock options for which the exercise prices were
greater than the average market price of the Companys
common stock are excluded from the computation of diluted
earnings per share. All potentially dilutive shares, whether
from options or warrants, are excluded when there is an
operating loss, because inclusion of such shares would be
anti-dilutive.
|
|
11.
|
RISK
MANAGEMENT ACTIVITIES
|
Management
of Financial Risk
The Companys operating environment included 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 impacted revenue, and the
risk of interest rate movements, which impacted interest expense
from floating rate debt.
The Company has not historically utilized derivative contracts
or any other form of hedging against interest rate risk.
The Company utilized 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 were entered into
for trading purposes, and the Company generally holds each
instrument to maturity. The Companys commodity derivative
contracts were considered cash flow hedges under generally
accepted accounting principles.
F-85
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Oil
and Natural Gas Hedging Contracts
The Company has historically utilized derivative contracts to
hedge the sale of a portion of its future production. The
Companys objective was 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
considered some exposure to market pricing to be desirable, due
to the potential for favorable price movements, but preferred to
achieve a measure of stability and predictability over revenues
and cash flows by hedging some portion of production. All the
Companys hedging agreements expired in December 2009. All
of the Companys hedging agreements were executed by
affiliates of the Lenders under the Credit Facility and were
collateralized by the security interest the Lenders had in the
oil and natural gas assets of the Company. Due to the default
under the Credit Facility, the Lenders did not allow the Company
to enter into any additional hedging agreements. As a result,
the Companys oil and natural gas sales for the first
quarter of 2010 were unhedged, and there are no assets or
liabilities from price risk management as of March 31, 2010.
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 Companys commodity derivatives
were designated as cash-flow hedges and were stated at fair
value on the Consolidated Balance Sheets. See Note 4,
Fair Value Measurements for further information on
how fair values of derivative instruments are determined.
Changes in fair value, which occur due to commodity price
movements, were offset in Accumulated Other Comprehensive
Income. When the derivative contract or a portion of it matured,
the gain or loss was settled in cash and reclassified from
Accumulated Other Comprehensive Income to Revenues from Oil and
Natural Gas. Net settlements under hedging agreements increased
oil and natural gas revenues by zero and $3,571,000 for the
three months ended March 31, 2010 and 2009, 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 by
ASC 815, or if the forecasted transaction is no longer
expected to occur. Although the Company periodically recorded
gains or losses from hedge ineffectiveness, there were no losses
recorded due to cancellations or changes in expectations
regarding occurrence of the hedged transactions. The following
table provides information
F-86
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
regarding gains and losses related to derivative contracts, and
where these amounts are reflected within the Companys
financial statements (in thousands):
Effect of Derivative Contracts on the Consolidated Statements of
Operations
|
|
|
|
|
|
|
|
|
|
|
Location of Gain
|
|
For the Three Months Ended
|
|
|
|
(Loss) Within
|
|
March 31,
|
|
March 31,
|
|
Description
|
|
Financial Statements
|
|
2010
|
|
2009
|
|
|
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
|
|
|
|
|
3,798
|
|
Gain (loss) on derivative contracts reclassified from OCI to
earnings Commodities Contracts
|
|
Oil and
Natural Gas
Revenues
|
|
|
|
|
3,571
|
|
Gain (loss) due to hedging ineffectiveness reported in
earnings
|
|
|
|
|
|
|
|
|
Commodities Contracts
|
|
Revenues from
Price Risk
Management
Activities
|
|
|
|
|
2
|
|
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
|
|
As of March 31, 2010, the Company had no unrealized gains
or losses deferred in Accumulated Other Comprehensive Income.
|
|
12.
|
SHARE-BASED
COMPENSATION
|
Stock
Options
The Company records share-based compensation expense based on
the fair value of the share-based award determined at grant date
and recognized over the service period, which is generally the
vesting period of the award. Share-based compensation expense of
approximately $6,000 and $53,000 was recorded in the three month
periods ended March 31, 2010 and 2009, respectively.
Compensation paid in share-based awards included stock options
and non-vested shares granted to our employees and directors.
|
|
13.
|
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
F-87
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
difference between the estimated and final liability amounts.
The Company records gains or losses from settlements as
adjustments to the full cost pool.
The following table describes the change in the Companys
asset retirement obligations for the three months ended
March 31, 2010 (thousands of dollars):
|
|
|
|
|
Asset retirement obligation at December 31, 2009
|
|
$
|
23,823
|
|
Additional retirement obligations recorded in 2010
|
|
|
|
|
Settlements during 2010
|
|
|
(140
|
)
|
Revisions to estimates and other changes during 2010
|
|
|
277
|
|
Accretion expense for 2010
|
|
|
546
|
|
|
|
|
|
|
Asset retirement obligation at March 31, 2010
|
|
|
24,506
|
|
Less: current portion
|
|
|
5,626
|
|
|
|
|
|
|
Asset retirement, long-term, at March 31, 2010
|
|
$
|
18,880
|
|
|
|
|
|
|
The Companys revisions to estimates represent changes to
the expected amount and timing of payments to settle the asset
retirement obligations. These changes primarily result from
obtaining new information about the timing of our obligations to
plug the natural gas and oil wells and costs to do so.
Merger. On May 10, 2010, the Company held
a shareholder meeting and vote at which the merger with Alta
Mesa was approved. The transaction was closed on May 13,
2010 and the Company was merged with and into Merger Sub, with
Merger Sub as the surviving entity. In connection with the
consummation of the merger, each share of the Companys
common stock outstanding immediately prior to the merger was
converted into the right to receive $0.33 per share in cash.
Shares of the Company have ceased to be publicly traded. The
Companys shareholders immediately prior to the merger
ceased to have any rights as shareholders of the Company and no
longer have an interest in the Companys future earnings
and growth (other than the right to receive consideration for
their shares under the Merger Agreement, or the right to an
appraisal of their shares under Texas law.) The debt under the
Companys credit facility, $82 million at the time,
was extinguished, and all other liabilities, including a
$5.3 million term note, were assumed by Merger Sub.
The Company has filed the appropriate forms with the SEC to
discontinue its reporting obligations, and the stock has been
delisted from the New York Stock Exchange.
F-88
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 Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States 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 Companys ability to continue
as a going concern. Managements 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 Corporations 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 USA, LLP (formerly known as BDO Seidman, LLP)
Houston, Texas
April 15, 2010
F-89
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands, except per share data)
|
|
|
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.
F-90
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Thousands of dollars)
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
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.
F-91
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands of dollars)
|
|
|
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.
F-92
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS EQUITY
Years Ended December 31, 2007, 2008 and 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
Accumulated
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
Paid-In
|
|
|
Earnings
|
|
|
Comprehensive
|
|
|
Treasury Stock
|
|
|
|
|
|
|
Shares
|
|
|
Par Value
|
|
|
Capital
|
|
|
(Deficit)
|
|
|
Income (Loss)
|
|
|
Shares
|
|
|
Cost
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Balance, December 31, 2006
|
|
|
89,140
|
|
|
$
|
928
|
|
|
$
|
534,441
|
|
|
$
|
(219,279
|
)
|
|
$
|
4,707
|
|
|
|
|
|
|
$
|
|
|
|
$
|
320,797
|
|
Shares repurchased
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
501
|
|
|
|
(1,158
|
)
|
|
|
(1,158
|
)
|
Issuance of rights to common stock
|
|
|
|
|
|
|
5
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Companys 401(k) plan contribution
|
|
|
42
|
|
|
|
1
|
|
|
|
155
|
|
|
|
|
|
|
|
|
|
|
|
(157
|
)
|
|
|
390
|
|
|
|
546
|
|
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
|
)
|
Companys 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
F-93
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands of dollars)
|
|
|
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.
F-94
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
|
|
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
Companys $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 Companys default under
the debt agreements, which has been mitigated in the short term
by certain forbearance agreements, negatively impacts future
cash flow and the Companys 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 Companys ability to
continue as a going concern for a period longer than the next
twelve months. In addition, the accompanying report of the
Companys independent registered public accounting firm
includes a going concern explanatory paragraph that
expresses substantial doubt as to the Companys ability to
continue as a going concern.
For further information regarding bank debt and forbearance
agreements, see Note 5. For further information regarding
the Companys 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 Companys debts
and obligations. The Company would be merged into Alta Mesa
Acquisition Sub, LLC with the Merger Sub as the surviving
entity. The Companys stock would cease to be publicly
traded. The merger is subject to approval by holders of two
thirds of the Companys 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 Companys board recommended that shareholders vote in
favor of the merger. For further information on the proposed
merger, refer to the proxy statement.
The Companys 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.
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
Meridians conduct of business primarily to current
operations, and restrict Meridian from soliciting other offers
for the Company, although Meridian is entitled to consider
F-95
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 Mesas
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
Mesas 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 Companys
shareholders, upon payment of a termination fee of
$3 million to the Company. The terms of the Companys
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
Companys 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.
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
F-96
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
Companys 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 Companys 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 Companys 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. 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
F-97
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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,
TMRDs 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 Companys 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 Companys
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 Companys receivables are due from
oil and natural gas purchasers and other oil and natural gas
producing companies located in the United States. Accounts
receivable are generally not collateralized. Historically,
credit losses incurred on receivables of the Company have not
been significant.
The Company maintains its cash in bank deposit accounts which,
at times, may exceed federally insured limits. Accounts are
guaranteed by the Federal Deposit Insurance Corporation
(FDIC) up to $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
Meridian recognizes oil and natural gas revenue from its
interests in producing wells as oil and natural gas is produced
and sold from those wells (the sales method). Oil and natural
gas sold is not significantly different from the Companys
share of production. Accounts receivable includes accrued oil
and natural gas revenue receivables of approximately
$10.1 million and $10.2 million as of
December 31, 2009 and 2008, respectively.
F-98
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
customers outstanding trade receivable balance. Management
believes that the allowance for doubtful accounts is adequate;
however, actual write-offs may exceed the recorded allowance.
Hurricane
Damage Repairs
The expense of $1.5 million in 2008 is related to damages
incurred from hurricanes Ike and Gustav and is primarily related
to the Companys 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 Companys drilling rig. The
Companys 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 Companys 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
The Companys 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
F-99
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
Companys 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 Companys
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
Companys 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 Companys 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 hedges inception and on an ongoing basis,
whether the derivatives that are used in hedging transactions
are highly effective in offsetting changes in fair values or
cash flows of hedged items.
Changes in the fair value of a derivative that is highly
effective and that is designated and qualifies as a cash-flow
hedge are recorded in other comprehensive income, until earnings
are affected by the variability in cash flows of the designated
hedged item, 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, and 2007,
respectively. Gains and losses from hedge ineffectiveness are
presented as Price risk management activities in the
Consolidated Statements of Operations.
F-100
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 Companys 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.
F-101
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
FASBs 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
F-102
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
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 Entitys 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 companys 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 Companys 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
Meridians 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 Companys 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
(VIEs) 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
VIEs, rather than only when specific events occur. The
revised guidance also requires additional disclosures about
consolidated and unconsolidated VIEs, including their
impact on the companys risk exposure and its financial
statements. The revised guidance will be effective for financial
statements for annual and interim
F-103
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 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.
F-104
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table describes the change in the Companys
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
|
|
|
|
|
|
|
|
|
|
|
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 Companys 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 managements 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
F-105
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 Companys
proved oil and natural gas reserves, there can be no assurance
that future write-downs will not be required as a result of
factors that may negatively affect the present value of proved
oil and natural gas reserves and the carrying value of oil and
natural gas properties, including volatile oil and natural gas
prices, downward revisions in estimated proved oil and natural
gas reserve quantities and unsuccessful drilling activities.
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.
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 Companys
subsidiaries and by a first priority lien on not less than 75%
(95% in the case of an event of default) of its present value of
proved oil and natural gas properties. 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 Companys 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 Companys auditors opinion for
the current financial statements be without modification. Both
the Companys 2008 and 2009 audit reports from its
independent registered public accounting firm included a
going concern explanatory paragraph that expressed
substantial doubt about the Companys 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
Companys 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.
F-106
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 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 (11th 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 11th
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 11th 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 11th 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 Companys cash accounts.
F-107
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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,
$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 (4th 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 4th
Amendment also provides CITs 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
F-108
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 Companys 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 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 Mesas
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
Mesas 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 Companys 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 Companys 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,
F-109
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
H. L. Hawkins litigation. In December
2004, the estate of H.L. Hawkins filed a claim against Meridian
for damages estimated to exceed several million
dollars for Meridians alleged gross negligence,
willful misconduct and breach of fiduciary duty under certain
agreements concerning certain wells and property in the S.W.
Holmwood and E. Lake Charles Prospects in Calcasieu Parish in
Louisiana, as a result of Meridians satisfying a prior
adverse judgment in favor of Amoco Production Company.
Mr. James Bond had been added as a defendant by Hawkins
claiming Mr. Bond, when he was General Manager of Hawkins,
did not have the right to consent, could not consent or breached
his fiduciary duty to Hawkins if he did consent to all actions
taken by Meridian. Mr. James T. Bond was employed by H.L.
Hawkins Jr. and his companies as General Manager until 2002. He
served on the Board of Directors of the Company from March 1997
to August 2004. After Mr. Bonds employment 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 Circuits decision in the Amoco
litigation. Meridian disagrees with Judge Bates ruling
but the Louisiana First Court of Appeal declined to hear
Meridians 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 Meridians actions were not
grossly negligent, but were within the business judgment rule.
Since Mr. Bonds 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 Companys operations.
These disputes are usually small but could result in an increase
or decrease in reserves once a final resolution to the title
dispute is made.
Environmental litigation. Various landowners
have sued Meridian (along with numerous other oil companies) in
lawsuits concerning several fields in which the Company has had
operations. The lawsuits seek injunctive relief and other
relief, including unspecified amounts in both actual and
punitive damages for alleged breaches of mineral leases and
alleged failure to restore the plaintiffs lands from
alleged contamination and otherwise from the Companys oil
and natural gas operations. In some of the lawsuits, Shell Oil
Company and SWEPI LP (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.
F-110
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 Meridians 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 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 Companys directors, Alta Mesa
Holdings, LP, and Alta Mesa Acquisition Sub, LLC. Leider alleged
that the Companys 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 proposed
settlement is conditioned on, among other things, approval of
the merger by Meridians shareholders. Under the terms of
the proposed settlement, all claims relating to the Merger
Agreement and the merger will
F-111
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
be dismissed on behalf of Meridians stockholders. As part
of the proposed settlement, the defendants have agreed not to
oppose plaintiffs counsels 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 Meridians 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
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
Companys 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 Companys 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
F-112
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
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 Companys
share of profits on the rig it owns. The Company performs
impairment testing of the rig each quarter; see Note 4.
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
F-113
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
and the amounts used for income tax purposes. Significant
components of the Companys deferred tax assets and
liabilities are as follows (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
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
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
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
Companys 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):
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
AMT
|
|
Year of 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
|
|
|
|
|
|
|
|
|
|
|
F-114
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
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 Companys general partner warrants
(see Notes 2 and 10) was calculated using the
Black-Scholes option pricing model.
F-115
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Assets
and liabilities measured at fair value on a recurring
basis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at
|
|
|
|
|
December 31, 2009 Using
|
|
|
|
|
Quoted
|
|
|
|
|
|
|
|
|
Prices in
|
|
|
|
|
|
|
|
|
Active
|
|
Significant
|
|
Significant
|
|
|
|
|
Markets for
|
|
Other
|
|
Other
|
|
|
|
|
Identical
|
|
Observable
|
|
Unobservable
|
|
|
December 31,
|
|
Assets
|
|
Inputs
|
|
Inputs
|
Description
|
|
2009
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
|
|
|
(Thousands of dollars)
|
|
Assets from price risk management activities(1)
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
Liabilities from price risk management activities(1)
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
General partner warrants(2)
|
|
$
|
412
|
|
|
|
|
|
|
$
|
412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at
|
|
|
|
|
|
|
December 31, 2008 Using
|
|
|
|
|
|
|
Quoted
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices in
|
|
|
|
|
|
|
|
|
|
|
|
|
Active
|
|
|
Significant
|
|
|
Significant
|
|
|
|
|
|
|
Markets for
|
|
|
Other
|
|
|
Other
|
|
|
|
|
|
|
Identical
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
December 31,
|
|
|
Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
Description
|
|
2008
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
|
|
|
|
(Thousands of dollars)
|
|
|
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
Companys 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 managements 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
F-116
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
Under the terms of the Merger Agreement, all the Companys
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 Companys Board of Directors, who
are also former officers.
Common
Stock
In March 2007, the Companys Board of Directors authorized
a share repurchase program; an amendment to the credit agreement
at that time increased the available limit for the
Companys 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 Companys
consolidation in December 1990 and were a component of the total
consideration issued for various interests that
Messrs. Reeves and Mayell had as general partners in TMR,
Ltd., a predecessor entity of the Company. There are adequate
authorized unissued common stock shares that are required to be
issued upon conversion of the General Partner Warrants. The
Company is not required to redeem the General Partner Warrants
in cash.
F-117
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 companys 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
Companys 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 Companys 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,
F-118
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
F-119
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 Companys 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.
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 Companys 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 Companys 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 Companys 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 Companys 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 Companys cash
payments to each of Messrs. Reeves and Mayell, the Company
granted to each officer a matching deferral equal to 100% of the
amount deferred, 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
F-120
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
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
years activity actually included vesting of approximately
one-half of the prior years matching rights, and
non-vesting of approximately one-half of the current years
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
employees contribution up to 6.5% of annual compensation
subject to certain limitations as outlined in the Plan. In
addition, the Company may make discretionary contributions which
are allocable to participants in accordance
F-121
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
with the Plan. Total expense related to the Companys
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 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
participants 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 Companys
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 Companys properties to the extent the Company acquires
a mineral interest therein. The net profits interest for
Messrs. Reeves and Mayell applies to all properties on
which the Company 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.
F-122
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
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 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.
Managements 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.
F-123
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 Companys 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 Companys commodity
derivative contracts are considered cash flow hedges under
generally accepted accounting principles.
Oil
and Natural Gas Hedging Contracts
The Company has historically utilized derivative contracts to
hedge the sale of a portion of its future production. The
Companys 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
Companys hedging agreements expired in December 2009. All
of the Companys 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 Companys 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 Companys 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,
F-124
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
and losses related to derivative contracts, and where these
amounts are reflected within the Companys 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
|
|
Effect of Derivative Contracts on the Consolidated Balance
Sheets and the Consolidated Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of Gain
|
|
For the Year Ended
|
|
|
|
(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
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Companys derivative agreements
expired December 31, 2009.
F-125
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 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.
F-126
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 Companys 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. Mayells 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.
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.
F-127
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 Companys 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.
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants and stock options for which the exercise prices were
greater than the average market price of the Companys
common stock are excluded from the computation of diluted
earnings per share. Stock rights issued under the Companys
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
F-128
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 Companys
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
|
|
|
|
March 31
|
|
|
June 30
|
|
|
Sept. 30
|
|
|
Dec. 31
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
)
|
F-129
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Results of operations by quarter for the year ended
December 31, 2008 were (thousands of dollars, except per
share):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
|
|
March 31
|
|
|
June 30
|
|
|
Sept. 30
|
|
|
Dec. 31
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Companys reserves has been
prepared in accordance with the new guidance; management has
chosen not to provide information on probable and possible
reserves. The Companys 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
Meridians 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 Companys 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; total
proved reserves are the basis of depletion calculations.
F-130
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The reserve volumes and associated cash flows were prepared by
T. J. Smith & Company, Inc., independent reservoir
engineers. For further information on Mr. Smiths
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands of dollars)
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Thousands of dollars)
|
|
|
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.
F-131
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2009
|
|
|
2008
|
|
|
2007 & Prior
|
|
|
|
(Thousands of dollars)
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands of dollars)
|
|
|
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
F-132
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 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 Companys 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 Companys proved undeveloped reserves
(PUDs) 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 PUDs 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 PUDs 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.
F-133
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Increases to PUDs 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.
Approximately 11.5 Bcfe of our PUDs at
December 31, 2009 originated more than five years ago.
Certain PUDs 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 Companys hedged
transactions.
F-134
THE
MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-135
Independent
Auditors Report
To the Members of
Alta Mesa Holdings, LP and Subsidiaries
We have audited the accompanying statements of revenues and
direct operating expenses of the oil and gas properties
purchased by Alta Mesa Holdings, LP and Subsidiaries, from
Sydson Energy, Inc. and affiliates (Sydson) for the
period January 1, 2011 through March 31, 2011 and for
the fiscal twelve month period ended December 31, 2010.
These financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards
generally accepted in the United States of America. Those
standards require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the statements of
revenues and direct operating expenses of the oil and gas
properties purchased by Alta Mesa Holdings, LP and Subsidiaries
from Sydson for the period January 1, 2011 through
March 31, 2011 and for the fiscal twelve month period ended
December 31, 2010, in conformity with accounting principles
generally accepted in the United States of America.
/s/ UHY LLP
Houston, Texas
July 6, 2011
F-136
NOTES TO
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF THE OIL AND GAS PROPERTIES PURCHASED BY ALTA MESA HOLDINGS,
LP
AND SUBSIDIARIES FROM SYDSON ENERGY, INC. AND AFFILIATES
(In thousands)
|
|
NOTE 1
|
BASIS OF
PRESENTATION
|
On April 21, 2011, Alta Mesa Holdings, LP and Subsidiaries
(the Company) acquired interests in oil and gas
properties (the Properties) from Sydson Energy, Inc.
and affiliates (Sydson) for a purchase price of
$27.5 million. The accompanying statements of revenues and
direct operating expenses relate to the operations of the oil
and gas properties acquired by the Company.
The statements of revenues and direct operating expenses
associated with the properties were derived from the accounting
records of the Company, the operator of the properties. During
the periods presented, the Properties were not accounted for or
operated as a consolidating entity or as a separate division by
Sydson. Revenues and direct operating expenses for the
Properties included in the accompanying statements represent the
net collective working and revenue interests to be acquired by
the Company on the accrual basis of accounting. The revenues and
direct operating expenses presented herein relate only to the
interests in the producing oil and natural gas properties which
were acquired and do not represent all of the oil and natural
gas operations of Sydson, other owners, or third party working
interest owners. Direct operating expenses include lease
operating expenses and production and other related taxes.
General and administrative expenses, depreciation, depletion and
amortization (DD&A) of oil and gas properties
and federal and state taxes have been excluded from direct
operating expenses in the accompanying statements of revenues
and direct operating expenses because the allocation of certain
expenses would be arbitrary and would not be indicative of what
such costs would have been had the Properties been operated as a
stand alone entity. Full separate financial statements prepared
in accordance with accounting principles generally accepted in
the United States of America do not exist for the Properties and
are not practicable to prepare in these circumstances. The
statements of revenues and direct operating expenses presented
are not indicative of the results of operations of the
Properties on a go forward basis due to the changes in the
business and omission of various operating expenses.
|
|
NOTE 2
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
Use of estimates: The preparation of
financial statements in conformity with accounting principles
generally accepted in the United States of America requires
management to make estimates and assumptions that affect
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Revenue recognition: The Company
records revenues when its products are delivered at a fixed or
determinable price, title has transferred and collectability is
reasonably assured.
|
|
NOTE 3
|
SUPPLEMENTARY
OIL AND GAS INFORMATION (UNAUDITED)
|
Estimated
Net Quantities of Oil and Natural Gas Reserves
The following estimates of the net proved oil and natural gas
reserves of the properties, which are located entirely within
the United States of America, are based on evaluations prepared
by third-party reservoir engineers. Reserves were estimated in
accordance with guidelines established by the Securities and
Exchange Commission (SEC) and the Financial
Accounting Standards Board (FASB), which require
that reserve estimates be prepared under existing economic and
operating conditions with no provisions for price and cost
changes except by contractual arrangements. Reserve estimates
are inherently imprecise and estimates of new discoveries are
more imprecise than those of producing oil and gas properties.
Accordingly, reserve estimates are expected to change as
additional performance data becomes available.
F-138
NOTES TO
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF THE OIL AND GAS PROPERTIES PURCHASED BY ALTA MESA HOLDINGS,
LP
AND SUBSIDIARIES FROM SYDSON ENERGY, INC. AND
AFFILIATES (Continued)
Estimated quantities of proved reserves and changes in
quantities of proved developed and undeveloped reserves were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Natural Gas
|
|
|
Total
|
|
|
|
Oil (MBbls)
|
|
|
Gas (MMcf)
|
|
|
Liquids (MBbls)
|
|
|
(MMcfe)
|
|
|
Proved reserves at December 31, 2009
|
|
|
201
|
|
|
|
3,283
|
|
|
|
41
|
|
|
|
4,735
|
|
Production
|
|
|
(42
|
)
|
|
|
(392
|
)
|
|
|
(8
|
)
|
|
|
(692
|
)
|
Extensions and discoveries
|
|
|
215
|
|
|
|
156
|
|
|
|
2
|
|
|
|
1,458
|
|
Revisions in previous estimates
|
|
|
(137
|
)
|
|
|
256
|
|
|
|
12
|
|
|
|
(494
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves at December 31, 2010
|
|
|
237
|
|
|
|
3,303
|
|
|
|
47
|
|
|
|
5,007
|
|
Production
|
|
|
(11
|
)
|
|
|
(98
|
)
|
|
|
(2
|
)
|
|
|
(176
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves at March 31, 2011
|
|
|
226
|
|
|
|
3,205
|
|
|
|
45
|
|
|
|
4,831
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
201
|
|
|
|
3,283
|
|
|
|
41
|
|
|
|
4,735
|
|
December 31, 2010
|
|
|
237
|
|
|
|
3,303
|
|
|
|
47
|
|
|
|
5,007
|
|
March 31, 2011
|
|
|
226
|
|
|
|
3,205
|
|
|
|
45
|
|
|
|
4,831
|
|
Discounted
Future Net Cash Flows
A summary of the discounted future net cash flows relating to
proved reserves is shown below. Future net cash flows are
computed with guidelines established by the SEC and FASB, using
commodity prices and costs that relate to the properties
existing proved reserves.
The discounted future net cash flows related to proved reserves
are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, 2011
|
|
|
December 31, 2010
|
|
|
Future cash inflows
|
|
$
|
35,559
|
|
|
$
|
34,081
|
|
Less related future
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
9,563
|
|
|
|
9,173
|
|
Development costs
|
|
|
5,671
|
|
|
|
5,453
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
20,325
|
|
|
|
19,455
|
|
Ten percent annual discount for estimated timing of cash flows
|
|
|
6,044
|
|
|
|
4,149
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows
|
|
$
|
14,281
|
|
|
$
|
15,306
|
|
|
|
|
|
|
|
|
|
|
F-139
NOTES TO
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF THE OIL AND GAS PROPERTIES PURCHASED BY ALTA MESA HOLDINGS,
LP
AND SUBSIDIARIES FROM SYDSON ENERGY, INC. AND
AFFILIATES (Continued)
Changes
in Discounted Future Net Cash Flows
A summary of the changes in the discounted future net cash flows
applicable to proved reserves follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
January 1, 2011
|
|
|
Twelve Months Ended
|
|
|
|
through March 31, 2011
|
|
|
December 31, 2010
|
|
|
Beginning of period
|
|
$
|
15,306
|
|
|
$
|
9,476
|
|
Revisions of previous estimates
|
|
|
|
|
|
|
|
|
Changes in prices and costs
|
|
|
|
|
|
|
6,824
|
|
Changes in quantities
|
|
|
|
|
|
|
(1,243
|
)
|
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related costs
|
|
|
|
|
|
|
7,615
|
|
Accretion of discount
|
|
|
|
|
|
|
1,271
|
|
Sales, net of production costs
|
|
|
(1,025
|
)
|
|
|
(4,101
|
)
|
Changes in rate of production and other
|
|
|
|
|
|
|
(4,536
|
)
|
|
|
|
|
|
|
|
|
|
Net change
|
|
|
(1,025
|
)
|
|
|
5,830
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
$
|
14,281
|
|
|
$
|
15,306
|
|
|
|
|
|
|
|
|
|
|
F-140
Independent
Auditors Report
To the Members of
Alta Mesa Holdings, LP and Subsidiaries
We have audited the accompanying statements of revenues and
direct operating expenses of the oil and gas properties
purchased by Alta Mesa Holdings, LP and Subsidiaries, from Texas
Oil Distribution and Development, Inc. and affiliates
(TODD) for the period January 1, 2011 through
March 31, 2011 and for the fiscal twelve month period ended
December 31, 2010. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards
generally accepted in the United States of America. Those
standards require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the statements of
revenues and direct operating expenses of the oil and gas
properties purchased by Alta Mesa Holdings, LP and Subsidiaries
from TODD for the period January 1, 2011 through
March 31, 2011 and for the fiscal twelve month period ended
December 31, 2010, in conformity with accounting principles
generally accepted in the United States of America.
/s/ UHY LLP
Houston, Texas
July 6, 2011
F-141
NOTES TO
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF THE OIL AND GAS PROPERTIES PURCHASED BY ALTA MESA HOLDINGS,
LP
AND SUBSIDIARIES FROM TEXAS OIL DISTRIBUTION AND
DEVELOPMENT, INC. AND AFFILIATES
(In thousands)
|
|
NOTE 1
|
BASIS OF
PRESENTATION
|
On June 17, 2011, Alta Mesa Holdings, LP and Subsidiaries
(the Company) acquired interests in oil and gas properties (the
Properties) from Texas Oil Distribution and
Development, Inc. and affiliates (TODD) for a
purchase price of $22.5 million. The accompanying
statements of revenues and direct operating expenses relate to
the operations of the oil and gas properties acquired by the
Company.
The statements of revenues and direct operating expenses
associated with the properties were derived from the accounting
records of the Company, the operator of the Properties. During
the periods presented, the Properties were not accounted for or
operated as a consolidating entity or as a separate division by
TODD. Revenues and direct operating expenses for the Properties
included in the accompanying statements represent the net
collective working and revenue interests to be acquired by the
Company on the accrual basis of accounting. The revenues and
direct operating expenses presented herein relate only to the
interests in the producing oil and natural gas properties which
were acquired and do not represent all of the oil and natural
gas operations of TODD, other owners, or third party working
interest owners. Direct operating expenses include lease
operating expenses and production and other related taxes.
General and administrative expenses, depreciation, depletion and
amortization (DD&A) of oil and gas properties
and federal and state taxes have been excluded from direct
operating expenses in the accompanying statements of revenues
and direct operating expenses because the allocation of certain
expenses would be arbitrary and would not be indicative of what
such costs would have been had the Properties been operated as a
stand alone entity. Full separate financial statements prepared
in accordance with accounting principles generally accepted in
the United States of America do not exist for the Properties and
are not practicable to prepare in these circumstances. The
statements of revenues and direct operating expenses presented
are not indicative of the results of operations of the
Properties on a go forward basis due to the changes in the
business and omission of various operating expenses.
|
|
NOTE 2
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
Use of estimates: The preparation of
financial statements in conformity with accounting principles
generally accepted in the United States of America requires
management to make estimates and assumptions that affect
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Revenue recognition: The Company
records revenues when its products are delivered at a fixed or
determinable price, title has transferred and collectability is
reasonably assured.
|
|
NOTE 3
|
SUPPLEMENTARY
OIL AND GAS INFORMATION (UNAUDITED)
|
Estimated
Net Quantities of Oil and Natural Gas Reserves
The following estimates of the net proved oil and natural gas
reserves of the properties, which are located entirely within
the United States of America, are based on evaluations prepared
by third-party reservoir engineers. Reserves were estimated in
accordance with guidelines established by the Securities and
Exchange Commission (SEC) and the Financial
Accounting Standards Board (FASB), which require
that reserve estimates be prepared under existing economic and
operating conditions with no provisions for price and cost
changes except by contractual arrangements. Reserve estimates
are inherently imprecise and estimates of new discoveries are
more imprecise than those of producing oil and gas properties.
Accordingly, reserve estimates are expected to change as
additional performance data becomes available.
F-143
NOTES TO
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF THE OIL AND GAS PROPERTIES PURCHASED BY ALTA MESA HOLDINGS,
LP
AND SUBSIDIARIES FROM TEXAS OIL DISTRIBUTION AND
DEVELOPMENT, INC. AND
AFFILIATES (Continued)
Estimated quantities of proved reserves and changes in
quantities of proved developed and undeveloped reserves were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Natural Gas
|
|
|
Total
|
|
|
|
Oil (MBbls)
|
|
|
Gas (MMcf)
|
|
|
Liquids (MBbls)
|
|
|
(MMcfe)
|
|
|
Proved reserves at December 31, 2009
|
|
|
174
|
|
|
|
2,847
|
|
|
|
35
|
|
|
|
4,101
|
|
Production
|
|
|
(36
|
)
|
|
|
(340
|
)
|
|
|
(7
|
)
|
|
|
(598
|
)
|
Extensions and discoveries
|
|
|
186
|
|
|
|
135
|
|
|
|
2
|
|
|
|
1,263
|
|
Revisions in previous estimates
|
|
|
(119
|
)
|
|
|
223
|
|
|
|
11
|
|
|
|
(425
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves at December 31, 2010
|
|
|
205
|
|
|
|
2,865
|
|
|
|
41
|
|
|
|
4,341
|
|
Production
|
|
|
(9
|
)
|
|
|
(85
|
)
|
|
|
(2
|
)
|
|
|
(151
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves at March 31, 2011
|
|
|
196
|
|
|
|
2,780
|
|
|
|
39
|
|
|
|
4,190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
174
|
|
|
|
2,847
|
|
|
|
35
|
|
|
|
4,101
|
|
December 31, 2010
|
|
|
205
|
|
|
|
2,865
|
|
|
|
41
|
|
|
|
4,341
|
|
March 31, 2011
|
|
|
196
|
|
|
|
2,780
|
|
|
|
39
|
|
|
|
4,190
|
|
Discounted
Future Net Cash Flows
A summary of the discounted future net cash flows relating to
proved reserves is shown below. Future net cash flows are
computed with guidelines established by the SEC and FASB, using
commodity prices and costs that relate to the properties
existing proved reserves.
The discounted future net cash flows related to proved reserves
are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, 2011
|
|
|
December 31, 2010
|
|
|
Future cash inflows
|
|
$
|
30,845
|
|
|
$
|
29,562
|
|
Less related future
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
8,295
|
|
|
|
7,957
|
|
Development costs
|
|
|
4,919
|
|
|
|
4,730
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
17,631
|
|
|
|
16,875
|
|
Ten percent annual discount for estimated timing of cash flows
|
|
|
5,244
|
|
|
|
3,598
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows
|
|
$
|
12,387
|
|
|
$
|
13,277
|
|
|
|
|
|
|
|
|
|
|
F-144
NOTES TO
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF THE OIL AND GAS PROPERTIES PURCHASED BY ALTA MESA HOLDINGS,
LP
AND SUBSIDIARIES FROM TEXAS OIL DISTRIBUTION AND
DEVELOPMENT, INC. AND
AFFILIATES (Continued)
Changes
in Discounted Future Net Cash Flows
A summary of the changes in the discounted future net cash flows
applicable to proved reserves follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
January 1, 2011
|
|
|
Twelve Months Ended
|
|
|
|
through March 31, 2011
|
|
|
December 31, 2010
|
|
|
Beginning of period
|
|
$
|
13,277
|
|
|
$
|
8,220
|
|
Revisions of previous estimates
|
|
|
|
|
|
|
|
|
Changes in prices and costs
|
|
|
|
|
|
|
5,919
|
|
Changes in quantities
|
|
|
|
|
|
|
(1,078
|
)
|
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related costs
|
|
|
|
|
|
|
6,605
|
|
Accretion of discount
|
|
|
|
|
|
|
1,102
|
|
Sales, net of production costs
|
|
|
(890
|
)
|
|
|
(3,557
|
)
|
Changes in rate of production and other
|
|
|
|
|
|
|
(3,934
|
)
|
|
|
|
|
|
|
|
|
|
Net change
|
|
|
(890
|
)
|
|
|
5,057
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
$
|
12,387
|
|
|
$
|
13,277
|
|
|
|
|
|
|
|
|
|
|
F-145