Table of Contents
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
Washington, D.C. 20549
Form 10-K
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the fiscal year ended December 31, 2010 | ||
|
or
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||
|
o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the transition period from to | ||
Commission File Number:
000-50682
RAM Energy Resources,
Inc.
(Exact name of registrant as
specified in its charter)
|
Delaware
|
20-0700684 | |
|
(State or other jurisdiction
of incorporation or organization) |
(I.R.S. Employer Identification Number) |
|
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5100 East Skelly Drive, Suite 650 Tulsa, Oklahoma (Address of principal executive office) |
74135 (Zip Code) |
(918) 663-2800
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the
Act:
Common Stock, $.0001 par value
Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o No
þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Exchange
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports) and (2) has been subject
to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to
submit and post such
files). Yes o No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
“large accelerated filer,” “accelerated
filer” and “smaller reporting company” in
Rule 12b-2
of the Exchange Act. (Check one):
|
Large accelerated
filer o
|
Accelerated filer þ |
Non-accelerated
filer o (Do not check if a smaller reporting company) |
Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
As of March 16, 2011, there were outstanding
78,378,233 shares of registrant’s $.0001 par
value common stock. Based upon the closing price for the
registrant’s common stock on the NASDAQ Capital Market as
of June 30, 2010, the aggregate market value of shares of
common stock held by non-affiliates of the registrant was
approximately $85.0 million. Documents incorporated by
reference: The information called for by Part III is
incorporated by reference to the definitive proxy statement for
the Registrant’s 2011 annual meeting of stockholders, which
will be filed with the Securities and Exchange Commission, or
SEC, no later than 120 days after December 31, 2010.
RAM
ENERGY RESOURCES, INC.
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2010
TABLE OF CONTENTS
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2010
TABLE OF CONTENTS
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PART I
| Item 1. | Business |
Overview
We have included definitions of technical terms important to
an understanding of our business under “Glossary of Oil and
Natural Gas Terms.”
Unless the context otherwise requires, all references in this
report to “RAM Energy Resources,” “our,”
“us,” and “we” refer to RAM Energy
Resources, Inc. (formerly known as Tremisis Energy Acquisition
Corporation) and its subsidiaries, as a combined entity.
We were incorporated in Delaware on February 5, 2004. Our
operations are encompassed in our wholly owned primary
subsidiaries, RAM Energy, Inc. and RAM Operating Company, Inc.
and their respective subsidiaries. Our executive offices are
located at 5100 East Skelly Drive, Suite 650, Tulsa,
Oklahoma 74135
(918) 663-2800.
We also have offices in Plano and Houston, Texas.
We are an independent oil and natural gas company engaged in the
acquisition, development, exploitation, exploration and
production of oil and natural gas properties, primarily in
Texas, Louisiana and Oklahoma. Our producing properties are
located in highly prolific basins with long histories of oil and
natural gas operations. We have been active in our core
producing areas of Texas, Oklahoma and Louisiana since our
inception in 1987 and have grown through a balanced strategy of
acquisitions, development and exploratory drilling. We have
completed over 24 acquisitions of producing oil and natural gas
properties and related assets for an aggregate purchase price in
excess of $700.0 million. Through December 31, 2010,
we have drilled or participated in the drilling of 846 oil and
natural gas wells, approximately 94% of which were successfully
completed and produced hydrocarbons in commercial quantities.
Our management team has extensive technical and operating
expertise in all areas of our geographic focus.
On December 8, 2010, we completed the sale to Milagro
Producing, LLC, a privately owned company located in Houston,
Texas, of all of our oil and natural gas properties and related
assets located in the Boonsville and Newark East fields of Jack
and Wise Counties, Texas. The effective date of the sale was
October 1, 2010. The sale properties included all of our
Bend Conglomerate shallow gas properties and all of our North
Texas Barnett Shale properties, including both producing
properties and undeveloped leasehold. We received net cash
proceeds at closing of $42.3 million subject to customary
post-closing adjustments. As of December 31, 2010, net
proceeds including post-closing adjustments were
$41.0 million. Proved reserves from these properties
accounted for approximately 26.4 billion cubic feet
equivalent (Bcfe) of natural gas, natural gas liquids and oil,
or an estimated 13% of our year-end 2009 proved reserves of
204 Bcfe. Information as to our recent divestitures is set
forth under Note B to the Consolidated Financial Statements.
Our oil and natural gas assets are characterized by a
combination of developing and mature reserves and properties. We
have mature oil and mature natural gas reserves located
primarily in Wichita, Wilbarger and Starr Counties, Texas,
Pontotoc County, Oklahoma, and in several parishes in Louisiana.
As of December 31, 2010, our estimated net proved reserves
were 24.4 MMBoe, of which approximately 54% were crude oil,
36% were natural gas, and 10% were natural gas liquids, or NGLs.
The PV-10
Value of our proved reserves was approximately
$364.2 million based on benchmark prices of $79.43 per Bbl
of oil and $4.38 per Mcf of natural gas. The benchmark prices
reflect the unweighted arithmetic average of the
first-day-of-the-month
price for oil and natural gas during each month of 2010, as
required by SEC Release
No. 33-8995,
“Modernization of Oil and Gas Reporting,”
effective December 31, 2009. For more information regarding
our PV-10
Value, including a reconciliation to the standardized measure of
discounted future net cash flows relating to our estimated
proved reserves, see Item 2.
“Properties — Oil and Natural Gas
Reserves.” At December 31, 2010, our proved
developed reserves comprised 62% of our total proved reserves.
At December 31, 2010, we owned interests in approximately
4,100 wells and were the operator of leases upon which
approximately 3,200 of these wells are located. The
PV-10 Value
attributable to our interests in the properties we operate
represented approximately 98% of our aggregate
PV-10 Value
as of December 31,
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2010. We also own a drilling rig, various gathering systems, a
natural gas processing plant, service rigs and a supply company
that service our properties.
During the twelve months ended December 31, 2010, we
drilled or participated in the drilling of 70 wells on our
oil and natural gas properties, 62 of which were successfully
completed as producing wells, one of which was a dry hole well
and seven of which were either drilling or waiting to be
completed at the end of that period. For the twelve months ended
December 31, 2010, we generated Modified EBITDA of
$51.0 million from production averaging nearly 5,921 Boe
per day. For more information regarding our Modified EBITDA,
including a reconciliation to our net income (loss), see
Item 6. “Selected Financial Data.”
Our
Business Strategy and Strengths
Our primary objective is to enhance stockholder value by
increasing our net asset value, net reserves and cash flow per
share through acquisitions, development, exploitation,
exploration and divestiture of oil and natural gas properties.
Commencing June 2010, we initiated a comprehensive review of our
strategic alternatives to determine the future direction of the
Company. In the course of conducting this review, our
development capital expenditures slowed to a lower level than
originally projected. In late 2010, we decided to engage in
strategic sales of certain of our non-core assets and refinance
our indebtedness, as a result of which the pace of our
development capital expenditures increased once again. The
refinancing of our credit facility in March 2011 allows us to
continue the development and exploitation of our existing
properties and to pursue an increased exploration strategy while
searching out selective acquisitions. As in the past, we intend
to follow a balanced risk strategy by allocating capital
expenditures in a combination of lower risk development and
exploitation activities and higher potential exploration
prospects. We intend to pursue acquisitions during periods of
attractive acquisition values and emphasize development of our
reserves during periods of higher acquisition values. Key
elements of our business strategy include the following:
| • | Maintain a Policy of Capital Programs Funded Through Operating Cash Flow. In this continued period of financial industry uncertainty leading to more restrictive capital markets, we believe maintaining ample liquidity for capital drilling programs to be a critical component of our strategy. Our 2011 capital budget of $35.0 million is expected to be fully funded through operating cash flows. | |
| • | Concentrate on Our Existing Core Areas. We intend to focus a significant portion of our growth efforts in our existing core areas in Texas, Oklahoma and Louisiana. Our oil and natural gas properties in our core areas are characterized by long reserve lives and production histories in multiple oil and natural gas horizons. We have a diversified and promising reserve base. We believe our focus on and experience in our core areas may expose us to acquisition opportunities which may not be available to the entire industry. | |
| • | Develop and Exploit Existing Oil and Natural Gas Properties. Since inception our principal growth strategy has been to develop and exploit our acquired and discovered properties until we determine that it is no longer economically attractive to do so. As of December 31, 2010, we have identified over 400 development and extension drilling projects and more than 45 recompletion/workover projects on our existing properties and wells. We intend to continue our focus on workovers, recompletions and development capital expenditures in 2011. | |
| • | Complete Selective Acquisitions and Divestitures. We seek to acquire producing oil and natural gas properties, primarily in our core areas. Our experienced senior management team has developed our acquisition criteria designed to increase reserves, production and cash flow per share on an accretive basis. We will seek acquisitions of producing properties that will provide us with opportunities for reserve additions and increased cash flow through operating improvements, production enhancement and additional development and exploratory prospect generation opportunities. In addition, from time to time, we may engage in strategic divestitures when we believe our capital may be redeployed to higher return projects as was the case in 2010 when we disposed of over $50.0 million in assets. | |
| • | Maintain Emphasis on Exploration Activity to Build an Inventory of Opportunities. We are committed to maintaining our emphasis on exploration activities within the context of our balanced risk objectives. |
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| We are encouraged by our success in our Osage concession and plan to continue exploration in that area. We will continue to acquire, review and analyze 3-D seismic data to generate additional exploratory prospects. Since 2006, we have drilled 28 gross (12.9 net) exploratory wells and experienced an 82% success rate. Our exploration efforts utilize available geological and geophysical technologies to reduce our exploration and drilling risks and, therefore, maximize our probability of success. Combined with our continued emphasis on development capital expenditures, we believe these exploratory opportunities will provide a basis for structured growth as commodity prices improve in the future. |
We believe that the following strengths complement our business
strategy:
| • | Management Experience and Technical Expertise. Our key management and technical staff possess, on average, over 27 years of experience in the oil and natural gas industry, a substantial portion of which has been focused on operations in our core areas. We believe that the knowledge, experience and expertise of our staff will continue to support our efforts to enhance stockholder value. | |
| • | Balanced Oil and Natural Gas Production. At year-end 2010, approximately 54% of our estimated proved reserves were oil, 36% were natural gas and 10% were NGLs. We believe this balanced commodity mix, combined with our prudent use of derivative contracts, will provide sufficient diversification of sources of cash flow and will lessen the risk of significant and sudden decreases in revenue from localized or short-term commodity price movements. | |
| • | Operating Efficiency and Control. We currently operate wells that represent approximately 98% of our aggregate PV-10 Value at December 31, 2010. Our high degree of operating control allows us to control capital allocation and expenses and the timing of additional development and exploitation of our producing properties. | |
| • | Drilling Expertise and Success. Our management and technical staff have a long history of successfully drilling oil and natural gas wells. Through December 31, 2010, we drilled or have participated in the drilling of 846 oil and natural gas wells with over 94% success rate. We expect to continue to grow by utilizing our drilling expertise and developing and finding additional reserves, although our success rate may decline as we drill more exploratory wells. | |
| • | Ownership and Control of Service and Supply Assets. In our Electra/Burkburnett mature oil field, we own and control service and supply assets, including a drilling rig, service rigs, a supply company, gathering systems and other related assets. We believe that ownership and use of these assets for our own account provides us with a significant competitive advantage with respect to availability, lead-time and cost of these services. |
Glossary
of Oil and Natural Gas Terms
The definitions set forth below apply to the indicated terms as
used in this report. All volumes of natural gas referred to
herein are stated at the legal pressure base of the state or
area where the reserves exist and at 60 degrees Fahrenheit and
in most instances are rounded to the nearest major multiple.
Bbl. One stock tank barrel, or 42
U.S. gallons liquid volume, used herein in reference to
crude oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of natural gas.
Boe. Barrels of oil equivalent in which six
Mcf of natural gas equals one Bbl of oil.
Btu. British thermal unit, which is the heat
required to raise the temperature of a one-pound mass of water
from 58.5 to 59.5 degrees Fahrenheit.
Completion. The installation of permanent
equipment for the production of oil or natural gas or, in the
case of a dry hole, the reporting of abandonment to the
appropriate agency.
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Development well. A well drilled within the
proved areas of an oil or natural gas reservoir to the depth of
a stratigraphic horizon known to be productive.
Dry hole or well. A well found to be incapable
of producing hydrocarbons in sufficient quantities such that
proceeds from the sale of such production exceed production
expenses and taxes.
Exploratory well. A well drilled to find a new
field or to find a new reservoir in a field previously found to
be productive of oil or natural gas in another reservoir.
Field. An area consisting of a single
reservoir or multiple reservoirs all grouped on or related to
the same individual geological structural feature
and/or
stratigraphic condition.
Gross acres or gross wells. The total acres or
wells, as the case may be, in which a working interest is owned.
MBbls. One thousand barrels of crude oil or
other liquid hydrocarbons.
MBoe. One thousand Boe.
MMBoe. One million Boe.
Mcf. One thousand cubic feet of natural gas.
MMBbls. One million barrels of crude oil or
other liquid hydrocarbons.
MMBtu. One million Btus.
MMcf. One million cubic feet of natural gas.
Net acres or net wells. The sum of the
fractional working interests owned in gross acres or gross
wells, as the case may be.
Operator. The individual or company
responsible for the exploration, exploitation and production of
an oil or natural gas well or lease.
PV-10
Value. When used with respect to oil and natural
gas reserves, the estimated future gross revenues to be
generated from the production of proved reserves, net of
estimated production and future development costs, using the
prices provided in the reserve report and costs in effect as of
the date indicated, without giving effect to non-property
related expenses such as general and administrative expenses,
debt service and future income tax expenses or to depreciation,
depletion and amortization, discounted using an annual discount
rate of 10%.
Productive well. A well that is found to be
capable of producing hydrocarbons in sufficient quantities such
that proceeds from the sale of such production exceed production
expenses and taxes.
Proved developed producing reserves. Proved
developed reserves that are expected to be recovered from
completion intervals currently open in existing wells and
capable of production.
Proved developed reserves. Proved reserves
that are expected to be recovered from existing wellbores,
whether or not currently producing, without drilling additional
wells. Production of such reserves may require a recompletion.
Proved reserves. 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 estimation.
Proved undeveloped location. A site on which a
development well can be drilled consistent with spacing rules
for purposes of recovering proved undeveloped reserves.
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Proved undeveloped reserves. Proved reserves
that are expected to be recovered from new wells on undrilled
acreage or from existing wells where a relatively major
expenditure is required for recompletion.
Recompletion. The completion for production of
an existing wellbore in another formation from that in which the
well has been previously completed.
Reserve life. A ratio determined by dividing
our estimated existing reserves determined as of the stated
measurement date by production from such reserves for the prior
twelve month period.
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 individual and separate from other reservoirs.
3-D
seismic. The method by which a three dimensional
image of the earth’s subsurface is created through the
interpretation of reflection seismic data collected over a
surface grid.
3-D seismic
surveys allow for a more detailed understanding of the
subsurface than do conventional surveys and contribute
significantly to field appraisal, exploitation and production.
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.
Working interest. The operating interest that
gives the owner the right to drill, produce and conduct
operating activities on the property and a share of production.
Workover. Operations on a producing well to
restore or increase production.
FORWARD
LOOKING STATEMENTS
This report, including information included in, or incorporated
by reference from filings by us with the SEC, as well as
information contained in written material, press releases and
oral statements issued by us or on our behalf, contain, or may
contain, certain statements that are “forward-looking
statements” within the meaning of federal securities laws
that are subject to a number of risks and uncertainties, many of
which are beyond our control. This report modifies and
supersedes documents filed by us before this report. In
addition, certain information that we file with the SEC in the
future will automatically update and supersede information
contained in this report. All statements, other than statements
of historical fact, included or incorporated by reference in
this report, 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 report, the words
“could,” “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.
Forward-looking statements may include statements about our:
• business strategy;
• reserves;
• technology;
• financial strategy;
• oil and natural gas realized prices;
• timing and amount of future production of oil and natural
gas;
• the amount, nature and timing of capital expenditures;
• drilling of wells;
• competition and government regulations;
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• marketing of oil and natural gas;
• property acquisitions and divestitures;
• costs of developing our properties and conducting other
operations;
• general economic conditions;
• uncertainty regarding our future operating
results; and
• plans, objectives, expectations and intentions contained
in this report that are not historical.
All forward-looking statements speak only as of the date of this
report, and, except as required by law, we do not intend to
update any of these forward-looking statements to reflect
changes in events or circumstances that arise after the date of
this report. You should not place undue reliance on these
forward-looking statements. Although we believe that our plans,
intentions and expectations reflected in or suggested by the
forward-looking statements we make in this report are
reasonable, we can give no assurance that these plans,
intentions or expectations will be achieved. We disclose
important factors that could cause our actual results to differ
materially from our expectations under “Risk
Factors” and “Management’s Discussion and
Analysis of Financial Condition and Results of Operations”
and elsewhere in this report. These cautionary statements
qualify all forward-looking statements attributable to us or
persons acting on our behalf. The market data and certain other
statistical information used throughout this report are based on
independent industry publications, government publications or
other published independent sources. Some data are also based on
our good faith estimates. Although we believe these third-party
sources are reliable, we have not independently verified the
information and cannot guarantee its accuracy and completeness.
| Item 1A. | Risk Factors |
We face a variety of risks that are inherent in our business and
our industry, including operational, legal and regulatory risks.
The following are the known, material risks that could affect
our business and our results of operations.
Risks
Related to Our Business
The
volatility of oil and natural gas prices greatly affects our
profitability.
Our revenues, operating results, profitability, future rate of
growth and the carrying value of our oil and natural gas
properties depend primarily upon the prevailing prices for oil
and natural gas. Historically, oil and natural gas prices have
been volatile and are subject to fluctuations in response to
changes in supply and demand, market uncertainty and a variety
of additional factors that are beyond our control. Any
substantial decline in the price of oil and natural gas will
likely have a material adverse effect on our operations,
financial condition and level of expenditures for the
development of our oil and natural gas reserves, and may result
in further write-downs of the carrying values of our oil and
natural gas properties as a result of our use of the full cost
accounting method.
Wide fluctuations in oil and natural gas prices may result from
relatively minor changes in the supply of and demand for oil and
natural gas, market uncertainty and other factors that are
beyond our control, including:
| • | worldwide and domestic supplies of oil and natural gas; | |
| • | speculation in the price of commodities in the commodity futures market; | |
| • | weather conditions; | |
| • | the level of consumer demand; | |
| • | the price and availability of alternative fuels; | |
| • | the availability of drilling rigs and completion equipment; |
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| • | the availability of pipeline capacity; | |
| • | the price and volume of foreign imports; | |
| • | domestic and foreign governmental regulations and taxes; | |
| • | the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; | |
| • | political instability or armed conflict in oil-producing regions; and | |
| • | the overall economic environment. |
These factors and the volatility of the energy markets make it
extremely difficult to predict future oil and natural gas price
movements with any certainty.
Oil
and natural gas prices could decline to a point where it would
be uneconomic for us to sell our oil and natural gas at those
prices, which could result in a decision to shut in production
until the prices increase.
Our oil and natural gas properties will become uneconomic when
oil and natural prices decline to the point at which our
revenues are insufficient to recover our lifting costs. For
example, in 2010, our average lifting costs were approximately
$18.49 per Boe, or $3.08 per Mcfe. A market price decline below
that price would result in our having to shut in certain
production until prices increase.
A
decline of oil and natural gas prices or a prolonged period of
reduced oil and natural gas prices could result in a decrease in
our exploration and development expenditures, which could
negatively impact our future production.
We currently expect to have sufficient cash flows from
operations to meet our projected non-acquisition capital
expenditure needs for 2011. However, if oil and natural gas
prices decline or reduce to lower levels for a prolonged period
of time, we may be unable to continue to fund capital
expenditures at historical levels due to the decreased cash
flows that will result from such reduced oil and natural gas
prices. Additionally, a decline in oil and natural gas prices or
a prolonged period of lower oil and natural gas prices could
result in a reduction of our borrowing base under our credit
facilities, which will further reduce the availability of cash
to fund our operations. As a result, we may have to reduce our
capital expenditures in future years. A decrease in our capital
expenditures will likely result in a decrease in our production
levels.
Reduced
development capital expenditures in 2011 could result in
decreased production in 2012.
In 2010, our capital expenditures related to development and
exploitation activities were approximately $27.9 million.
For 2011, we have budgeted $23.0 million for capital
expenditures related to development and exploitation activities
and related geological and geophysical costs, an 18% decrease
over the prior year. This anticipated decline in capital
expenditures for development and exploitation activities could
result in a decrease in production in 2012 and possibly beyond,
unless our development and exploitation capital expenditures are
subsequently increased, we find increased productive reserves
through our exploration program or we acquire more production
through strategic acquisitions.
Continued
weakness in economic conditions or uncertainty in financial
markets may have material adverse impacts on our business that
we cannot predict.
U.S. and global economies and financial systems have
continued to experience turmoil and upheaval characterized by
extreme volatility in prices of securities, diminished liquidity
and credit availability, inability to access capital markets,
the bankruptcy, failure, collapse or sale of financial
institutions, continued high levels of unemployment, and an
unprecedented level of intervention by the U.S. federal
government and other governments. Although some portions of the
economy appear to have stabilized or even improved and there
have been signs of the beginning of recovery, the extent and
timing of a recovery, and whether it can be
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sustained, are uncertain. Continued weakness in the U.S. or
global economies could materially adversely affect our business
and financial condition. For example:
| • | the demand for oil and natural gas in the U.S. has declined and may remain at low levels or further decline if economic conditions remain weak, and continue to negatively impact our revenues, margins, profitability, operating cash flows, liquidity and financial condition; | |
| • | the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables; | |
| • | our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business, including for exploration and/or development of our reserves; and | |
| • | our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection. |
Oil prices have improved significantly in 2010 as compared to
2009 while natural gas prices continue to stagnate. Our
profitability is directly related to the prices we receive for
the sale of the oil and natural gas we produce. In early July
2008, commodity prices reached record levels in excess of
$140.00 per barrel for crude oil and $13.00 per Mcf for natural
gas. The 2008 year ended with market prices dropping to
$44.00 for crude oil and $4.00 for natural gas, a 69% to 73%
decline from the earlier highs. During 2009, market prices ended
at a high of approximately $72.00 for crude oil and $4.00 for
natural gas. As of December 31, 2010, crude oil prices
continued to rise to approximately $87.00 while natural gas
prices remained constant at approximately $4.00.
Our
success depends on acquiring or finding additional
reserves.
Our future success depends upon our ability to find, develop or
acquire additional oil and natural gas reserves that are
economically recoverable. Our proved reserves will generally
decline as reserves are produced, except to the extent that we
conduct successful exploration or development activities or
acquire properties containing proved reserves, or both. To
increase reserves and production, we must commence exploratory
drilling, undertake other replacement activities or utilize
third parties to accomplish these activities. There can be no
assurance, however, that we will have sufficient resources to
undertake these actions, that our exploratory projects or other
replacement activities will result in significant additional
reserves or that we will succeed in drilling productive wells at
low finding and development costs. Furthermore, although our
revenues may increase if prevailing oil and natural gas prices
increase significantly, our finding costs for additional
reserves could also increase.
In accordance with customary industry practice, we rely in part
on independent third party service providers to provide most of
the services necessary to drill new wells, including drilling
rigs and related equipment and services, horizontal drilling
equipment and services, trucking services, tubular goods,
fracing and completion services and production equipment. The
oil and natural gas industry has experienced significant
volatility in cost for these services in recent years and this
trend is expected to continue into the future. Any future cost
increases could significantly increase our development costs and
decrease the return possible from drilling and development
activities, and possibly render the development of certain
proved undeveloped reserves uneconomical.
The
actual quantities and present values of our proved oil and
natural gas reserves may be less than we have
estimated.
This report and other SEC filings by us contain estimates of our
proved oil and natural gas reserves and the estimated future net
revenues from those reserves. These estimates are based on
various assumptions, including assumptions required by the SEC
relating to oil and natural gas prices, drilling and operating
expenses, capital expenditures, taxes, timing of operations, and
availability of funds. The process of estimating oil and natural
gas reserves is complex. The process involves significant
decisions and assumptions in the evaluation of available
geological, geophysical, engineering, and economic data for each
reservoir. These estimates are dependent on many variables, and
therefore changes often occur as these variables evolve.
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Therefore, these estimates are inherently imprecise. For
example, total revisions of our previous reserve estimates
decreased proved reserves by 3.3 MMBoe or approximately 10%
of our reserves at the beginning of the year. The revisions
included a positive increase of 1.8 MMBoe or 5% of the
beginning of the year reserves caused by higher oil and gas
prices. This positive revision was offset by the downward
revision of 1.1 MMBoe caused by the transfer of proved
undeveloped to unproved categories as a result of changes to the
company development plans during 2010, and 4.0 MMBoe of the
downward revisions were mostly due to changes in well
performance in our gas properties in South Texas.
Actual future production, oil and natural gas prices, revenues,
production taxes, development expenditures, operating expenses,
and quantities of producible oil and natural gas reserves will
most likely vary from those estimated. Any significant variance
could materially affect the estimated quantities of and present
values related to proved reserves disclosed by us, and the
actual quantities and present values may be less than we have
previously estimated. In addition, we may adjust estimates of
proved reserves to reflect production history, results of
exploration and development activity, prevailing oil and natural
gas prices, costs to develop and operate properties, and other
factors, many of which are beyond our control. Our properties
may also be susceptible to hydrocarbon drainage from production
on adjacent properties.
As of December 31, 2010, approximately 38%, or
9.2 MMBoe, of our estimated proved reserves were proved
undeveloped, and approximately 7%, or 1.7 MMBoe, were
proved developed non-producing. In order to develop our proved
undeveloped reserves, we estimate approximately
$101.8 million of capital expenditures will be required.
Production revenues from proved developed non-producing reserves
will not be realized until sometime in the future and after some
investment of capital. In order to bring production on-line for
our proved developed non-producing reserves, we estimate capital
expenditures of approximately $8.3 million will be
required. The estimated abandonment costs associated with our
Louisiana production facilities make up the balance of our
anticipated capital expenditures. Although we have estimated our
reserves and the costs associated with these reserves in
accordance with industry standards, estimated costs may not be
accurate, development may not occur as scheduled and actual
results may not occur as estimated.
You should not assume that the
PV-10 Value
and standardized measure of discounted future net cash flows
included in this report represent the current market value of
our estimated proved oil and natural gas reserves. Management
has based the estimated discounted future net cash flows from
proved reserves on price and cost assumptions required by the
SEC, whereas actual future prices and costs may be materially
higher or lower. For example, our proved reserves and
PV-10 Values
as of December 31, 2010, were estimated using the
12-month
unweighted arithmetic average of the
first-day-of-the-month
price of $79.43 per Bbl of oil (NYMEX West Texas Intermediate
settle price) and $4.38 per Mcf of natural gas (Platts Henry Hub
spot price). We then adjust these base prices to reflect
appropriate basis, quality, and location differentials over that
period in estimating our proved reserves. During 2010, our
monthly average realized oil prices, excluding the effect of
hedging, were as high as $86.84 per Bbl and as low as $71.92 per
Bbl. For the same period, our monthly average realized natural
gas prices before hedging were as high as $5.72 per Mcf and as
low as $3.27 per Mcf. Many other factors will affect actual
future net cash flows, including:
| • | Amount and timing of actual production; | |
| • | Supply and demand for oil and natural gas; | |
| • | Curtailments or increases in consumption by oil purchasers and natural gas pipelines; and | |
| • | Changes in government regulations or taxes. |
The timing of production from oil and natural gas properties and
of related expenses affects the timing of actual future net cash
flows from proved reserves, and thus their actual present value.
Our actual future net cash flows could be less than the
estimated future net cash flows for purposes of computing
PV-10
Values. In addition, the ten percent discount factor required by
the SEC to be used to calculate
PV-10 Values
for reporting purposes is not necessarily the most appropriate
discount factor given actual interest rates, costs of capital,
and other risks to which our business and the oil and natural
gas industry in general are subject.
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We
expect to obtain a substantial portion of our funds for property
acquisitions and for the drilling and development of our oil and
natural gas properties through a combination of cash flows from
operations and borrowings. If such borrowed funds were not
available to us, or if the terms upon which such funds would be
available to us were unfavorable, our ability to acquire oil and
natural gas properties, the further development of our oil and
natural gas reserves, and our financial condition and results of
operations, could be adversely affected.
We expect to fund a substantial portion of our future property
acquisitions and our drilling and development operations with a
combination of cash flows from operations and borrowed funds. To
the extent such borrowed funds are not available to us at all,
or if the terms under which such funds would be available to us
would be unfavorable, our ability to acquire oil and natural gas
properties and the further development of our oil and natural
gas reserves could be adversely impacted. In such events, we may
be unable to replace our reserves of oil and natural gas which,
subsequently, could adversely affect our financial condition and
results of operations.
The
continued tightness in the financial and credit markets may
expose us to counterparty risk with respect to our sales of oil
and natural gas.
We sell our crude oil, natural gas and natural gas liquids to a
variety of purchasers. Some of these parties may not be as
creditworthy as we are and may experience liquidity
problems. Nonperformance by a trade creditor could result
in our incurring losses.
Operating
hazards and uninsured risks may result in substantial
losses.
Our operations are subject to all of the hazards and operating
risks inherent in drilling for, and the production of, oil and
natural gas, including the risk of fire, explosions, blow-outs,
pipe failure, abnormally pressured formations and environmental
hazards such as oil spills, gas leaks, ruptures or discharges of
toxic gases. The occurrence of any of these events could result
in substantial losses to us due to injury or loss of life,
severe damage to or destruction of property, natural resources
and equipment, pollution or other environmental damage,
clean-up
responsibilities, regulatory investigation and penalties and
suspension of operations. In accordance with customary industry
practice, we maintain insurance against some, but not all, of
these risks. There can be no assurance that any insurance will
be adequate to cover any losses or liabilities. We cannot
predict the continued availability of insurance, or its
availability at premium levels that justify its purchase. In
addition, we may be liable for environmental damage caused by
previous owners of properties purchased by us, which liabilities
would not be covered by our insurance.
Our
operations are subject to various governmental regulations that
require compliance that can be burdensome and
expensive.
Our operations are subject to various federal, state and local
governmental regulations that may be changed from time to time
in response to economic and political conditions. Matters
subject to regulation include discharge from drilling
operations, drilling bonds, reports concerning operations, the
spacing of wells, unitization and pooling of properties and
taxation. From time to time, regulatory agencies have imposed
price controls and limitations on production by restricting the
rate of flow of oil and natural gas wells below actual
production capacity to conserve supplies of oil and natural gas.
In addition, the production, handling, storage, transportation
and disposal of oil and natural gas, by-products thereof and
other substances and materials produced or used in connection
with oil and natural gas operations are subject to regulation
under federal, state and local laws and regulations primarily
relating to protection of human health and the environment.
These laws and regulations have continually imposed increasingly
strict requirements for water and air pollution control and
solid waste management, and compliance with these laws may cause
delays in the additional drilling and development of our
properties. Significant expenditures may be required to comply
with governmental laws and regulations applicable to us. We
believe the trend of more expansive and stricter environmental
legislation and regulations will continue. While historically we
have not experienced any material adverse effect from regulatory
delays, there can be no assurance that such delays will not
occur in the future.
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Unusual
weather patterns or natural disasters, whether due to climate
change or otherwise, could negatively impact our financial
condition.
Our business depends, in part, on normal weather patterns across
the United States. Natural gas demand and prices are
particularly susceptible to seasonal weather trends. Warmer than
usual winters can result in reduced demand and high season-end
storage volumes, which can depress prices to unacceptably low
levels. In addition, because a majority of our properties are
located in Texas, Louisiana and Oklahoma, our operations are
constantly at risk of extreme adverse weather conditions such as
hurricanes and tornadoes. Any unusual or prolonged adverse
weather patterns in our areas of operations or markets, whether
due to climate change or otherwise, could have a material and
adverse impact on our business, financial condition and cash
flow. In addition, our business, financial condition and cash
flow could be adversely affected if the businesses of our key
vendors, purchasers, contractors, suppliers or transportation
service providers were disrupted due to severe weather, such as
hurricanes or floods, whether due to climate change or otherwise.
Climate
change and government laws and regulations related to climate
change could negatively impact our financial
condition.
In addition to other climate-related risks set forth in this
“Risk Factors” section, we are and will be, directly
and indirectly, subject to the effects of climate change and
may, directly or indirectly, be affected by government laws and
regulations related to climate change. We cannot predict with
any degree of certainty what effect, if any, possible climate
change and new and developing government laws and regulations
related to climate change will have on our operations, whether
directly or indirectly. While we believe that it is difficult to
assess the timing and effect of climate change and pending
legislation and regulation related to climate change on our
business, we believe that climate change and government laws and
regulations related to climate change may affect, directly or
indirectly, (i) the cost of the equipment and services we
purchase, (ii) our ability to continue to operate as we
have in the past, including drilling, completion and operating
methods, (iii) the timeliness of delivery of the materials
and services we need and the cost of transportation paid by us
and our vendors and other providers of services,
(iv) insurance premiums, deductibles and the availability
of coverage, and (v) the cost of utility services,
particularly electricity, in connection with the operation of
our properties. In addition, climate change may increase the
likelihood of property damage and the disruption of our
operations, especially in coastal states. As a result, our
financial condition could be negatively impacted by significant
climate change and related governmental regulation, and that
impact could be material.
Regulation
and recent court decisions related to greenhouse gas emissions
could have an adverse effect on our operations and demand for
oil and natural gas.
The U.S. Congress has previously considered legislation to
reduce emissions of “greenhouse gases,” including
carbon dioxide, methane and nitrous oxide among others, which
some studies have suggested may be contributing to warming of
the earth’s atmosphere. However, legislation to reduce
greenhouse gases appears less likely in the near term. As a
result, near term regulation of greenhouse gases, if any, is
more likely to come from regulatory action by EPA or by the
several states that have already taken legal measures to reduce
emissions of greenhouse gases.
As a result of the U.S. Supreme Court’s decision on
April 2, 2007 in Massachusetts, et al. v. EPA, 549
U.S. 497 (2007), finding that greenhouse gases fall within
the Clean Air Act (“CAA”) definition of “air
pollutant,” the Environmental Protection Agency
(“EPA”) was required to determine whether emissions of
greenhouse gases “endanger” public health or welfare.
As a result, the EPA has adopted regulations requiring Clean Air
Act (“CAA”) permitting of greenhouse gas emissions
from stationary and mobile sources. On December 15, 2009,
EPA promulgated its final rule, “Endangerment and Cause or
Contribute Findings for Greenhouse Gases Under
Section 202(a) of the Clean Air Act,” finding that
(i) the current and projected emissions of six key
well-mixed greenhouse gases, including carbon dioxide and
methane, constitute a threat to public health and welfare, and
(ii) the combined emissions from motor vehicles cause and
contribute to the climate change problem which threatens public
health and welfare. These findings did not themselves impose any
requirements on industry or other entities, but were a
prerequisite to EPA’s adoption of greenhouse gas
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emission standards for motor vehicles. On May 7, 2010, EPA
and the Department of Transportation’s National Highway
Traffic and Safety Administration, or NHTSA, promulgated a final
action establishing a national program providing new standards
for certain motor vehicles to reduce greenhouse gas emissions
and improve fuel economy, with EPA adopting the standards under
the CAA, and NHTSA adopting the standards as Corporate Average
Fuel Economy standards under the Energy Policy and Conservation
Act. While these motor vehicle regulations do not directly
impact oil and natural gas production operations, the result of
these actions are significant in that they automatically trigger
application of certain CAA permit programs for stationary
greenhouse gas emissions sources, potentially including oil and
natural gas production operations. These programs, the
Prevention of Significant Deterioration (“PSD”) and
Title V Operating Permit programs, have historically
applied to sources of air pollutants “subject to
regulation” with emissions exceeding 100 and 250 tons
per year. To avoid the broad impact of such low permitting
thresholds for greenhouse gas emission sources, on June 3,
2010, EPA promulgated its “Prevention of Significant
Deterioration and Title V Greenhouse Gas Tailoring
Rule,” to add new higher thresholds of 75,000 tons per year
carbon dioxide equivalents
(“CO2e”)
for modifications and 100,000 tons per year
CO2e
for new sources.
Additionally, EPA has promulgated separate regulations requiring
greenhouse gas emission reporting from certain industry sectors,
including natural gas production. On October 30, 2009, EPA
promulgated a final mandatory greenhouse gas reporting rule
which will assist EPA in developing policy approaches to
greenhouse gas regulation. This reporting rule became effective
on December 29, 2009. On November 30, 2010, EPA
promulgated additional mandatory greenhouse gas reporting rules
that apply specifically to oil and natural gas production for
implementation in 2011.
Though under review by the D.C. Circuit, EPA’s rules
promulgated thus far have survived petitions for stay, and are
currently final and effective, and will remain so unless vacated
or remanded by the court, or unless Congress adopts legislation
preempting EPA’s regulatory authority to address greenhouse
gases under the CAA.
Beyond legislative and regulatory developments, there have been
several recent court cases impacting this area of risk related
to greenhouse gas emissions. The final decisions in these cases
may expose us to similar litigation risk.
The decisions in these cases may expose us, as potentially an
emitter of significant direct and indirect emission sources of
greenhouse gases, to similar litigation risk.
International treaties. Other nations have already agreed to
regulate emissions of greenhouse gases pursuant to the United
Nations Framework Convention on Climate Change, also known as
the “Kyoto Protocol,” an international treaty pursuant
to which participating countries (not including the United
States) agreed to reduce their emissions of greenhouse gases to
below 1990 levels by 2012. Though the 16th meeting of the
Council of the Parties in Mexico in November and December 2010
did not produce a legally binding final agreement, international
negotiations continue, with the participation of the United
States.
International developments, passage of state or federal climate
control legislation or other regulatory initiatives, the
implementation of regulations by EPA and analogous state
agencies that restrict emissions of greenhouse gases in areas in
which we conduct business, or further development of case law
allowing claims based upon greenhouse gas emissions, could have
an adverse effect on our operations and financial condition as a
result of material increases in operating and production costs
and litigation expense due to expenses associated with
monitoring, reporting, permitting and controlling greenhouse gas
emissions or litigating claims related to emissions of
greenhouse gases, and the demand for oil and natural gas and
increase the costs of our operations.
Potential
legislative and regulatory actions relating to Federal income
taxation and derivatives trading could increase our costs,
reduce our revenue and cash flow from oil and natural gas sales,
reduce our liquidity or otherwise alter the way we conduct our
business.
In 2009, 2010 and 2011, the administration of President Obama
made budget proposals which, if enacted into law by Congress,
would potentially increase and accelerate the payment of federal
income taxes by
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independent producers of oil and natural gas. Proposals have
included, but have not been not limited to, repealing the
expensing of intangible drilling costs, repealing the deduction
for the cost of qualified tertiary expenses, repealing the
exception to the passive loss limitation for working interests
in oil and natural gas properties, repealing the percentage
depletion allowance, repealing the manufacturing tax deduction
for oil and natural gas companies, and increasing the
amortization period of geological and geophysical expenses. In
2009 and 2010, legislation which would have implemented the
proposed changes was introduced but not enacted. It is unclear
whether legislation supporting any of the above described
proposals, or designed to accomplish similar objectives, will be
introduced or, if introduced, would be enacted into law or, if
enacted, how soon resulting changes would become effective.
However, the passage of any legislation designed to implement
changes in the U.S. federal income tax laws similar to the
changes included in the budget proposals offered by the White
House in 2009, 2010 and 2011 could eliminate certain tax
deductions currently available with respect to oil and gas
exploration and development, and any such changes (i) could
make it more costly for us to explore for and develop our oil
and natural gas resources and (ii) could negatively affect
our financial condition and results of operations. On
July 21, 2010, the President signed into law the “Wall
Street Transparency and Accountability Act of 2010” (the
“WSTA Act”) which directs the Federal Reserve to
create uniform standards for the management of certain risks
associated with, among other things, the trading of certain
derivatives over the counter (“OTC”). In recent years,
we have maintained an active price and basis protection hedging
program related to the oil and natural gas we produce.
Additionally, we have used the OTC market exclusively for our
oil and natural gas derivative contracts and have relied on our
hedging activities to manage the risk of low commodity prices
and to predict with greater certainty the cash flow from our
hedged production. While the manner in which the Federal Reserve
will implement the directives contained in the WSTA Act is
unclear, we anticipate such implementation may include the
imposition of clearing and standardization requirements for all
derivatives currently traded on the OTC and could restrict
trading positions in the energy futures markets. While the
ultimate impact on us of such changes, if implemented, is
unclear, we anticipate they may materially reduce our hedging
opportunities and could negatively affect our revenues and cash
flow during periods of low commodity prices.
Federal
and state legislation and regulatory initiatives relating to
hydraulic fracturing could result in increased costs and
additional operating restrictions or delays.
We utilize hydraulic fracturing as a means to enhance the
productive capability of our wells. Congress has previously
considered legislation to amend the federal Safe Drinking Water
Act to require the disclosure of chemicals used by the oil and
natural gas industry in the hydraulic fracturing process.
Hydraulic fracturing involves the injection of water, sand and
chemicals under pressure into rock formations to stimulate
natural gas production. Sponsors of bills previously proposed
before the Senate and House of Representatives have asserted
that chemicals used in the fracturing process could adversely
affect drinking water supplies. That proposed legislation would
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, these bills, if adopted, could repeal
the exemptions for hydraulic fracturing from the Safe Drinking
Water Act. These legislative efforts have halted while EPA
studies the issue of hydraulic fracturing in 2010, EPA initiated
a Hydraulic Fracturing Research Study to address concerns that
hydraulic fracturing may affect the safety of drinking water. As
part of that process, EPA requested and received information
from the major fracturing service providers regarding the
chemical composition of fluids, standard operating procedures
and the sites where they engage in hydraulic fracturing. In
February 2011, EPA released its Draft Plan to Study the
Potential Impacts of Hydraulic Fracturing on Drinking Water
Resources, proposing to study the lifecycle of hydraulic
fracturing fluid and providing a comprehensive list of chemicals
identified in fracturing fluid and flowback/produced water.
These developments, as well as increased scrutiny of hydraulic
fracturing activities by state authorities, may result in
additional levels of regulation or level of complexity with
respect to existing regulation at the federal and state levels
that could lead to operational delays or increased operating
costs and could result in additional regulatory burdens that
could make it more difficult to perform hydraulic fracturing,
which could result in limiting the productive capability of
future wells in which we likely would utilize hydraulic
fracturing and increase our costs of compliance and doing
business.
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We may
not be able to borrow the full amount of the borrowing base
under our revolving credit facilities because of the amount of
our Modified EBITDA. The inability to fully borrow funds up to
our borrowing base could reduce our capital
expenditures.
As of December 31, 2010, our borrowing base under our old
revolving credit facility was $145.0 million. As of the
same date, we had outstanding advances under the revolving
credit facility of $116.5 million, leaving an aggregate
availability under our revolver of $28.5 million. However,
because of the amount of our Modified EBITDA, the financial
covenants set forth in our old credit facility would have
limited us to additional borrowings under our revolving credit
facility as of December 31, 2010, of $23.7 million. On
March 14, 2011, we entered into a new revolving credit
facility with a borrowing base of $150.0 million. Based on
our Modified EBITDA for the four fiscal quarters ending
December 31, 2010, our borrowings would not have been
limited under the new revolving credit facility. Should our
Modified EBITDA decline, we may be unable to borrow funds up to
the full amount of our borrowing base. Our inability to borrow
the full amount of our borrowing base under our revolving credit
facility could reduce our current year capital expenditures if
we do not meet our goal of funding our 2011 capital expenditures
from our operating cash flow.
Our
method of accounting for investments in oil and natural gas
properties may result in a further impairment of asset value,
which could affect our stockholder equity and net profit or
loss.
We use the full cost method of accounting for our investment in
oil and natural gas properties. Under the full cost method of
accounting, all costs of acquisition, exploration and
development of oil and natural gas reserves are capitalized into
a “full cost pool.” Capitalized costs in the pool are
amortized and charged to operations using the
units-of-production
method based on the ratio of current production to total proved
oil and natural gas reserves. To the extent that such
capitalized costs, net of amortization, exceed the after tax
present value of estimated future net revenues from our proved
oil and natural gas reserves (using a 10% discount rate) at any
reporting date, such excess costs are charged to operations. We
incurred no impairment charge for 2010. In 2009, we recorded a
$47.6 million charge for the impairment of our oil and
natural gas properties. This amount was in addition to the
$269.4 million charge we recorded in 2008. These writedowns
are not reversible at a later date, even if the present value of
our proved oil and natural gas reserves increases as a result of
an increase in oil or natural gas prices. Further price declines
could result in additional impairments of asset value.
Properties
that we acquire may not produce as projected, and we may be
unable to identify liabilities associated with the properties or
obtain protection from sellers against them.
As part of our business strategy, we continually seek
acquisitions of oil and natural gas properties. The successful
acquisition of oil and natural gas properties requires
assessment of many factors, which are inherently inexact and may
be inaccurate, including the following:
| • | future oil and natural gas prices; | |
| • | the amount of recoverable reserves; | |
| • | future operating costs; | |
| • | future development costs; | |
| • | failure of titles to properties; | |
| • | costs and timing of plugging and abandoning wells; and | |
| • | potential environmental and other liabilities. |
Our assessment will not necessarily reveal all existing or
potential problems, nor will it permit us to become familiar
enough with the properties to assess fully their capabilities
and deficiencies. With respect to properties on which there is
current production, we may not inspect every well location,
potential well location or pipeline in the course of our due
diligence. Inspections may not reveal structural and
environmental problems such as pipeline corrosion or groundwater
contamination. We may not be able to obtain or recover
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on contractual indemnities from the seller for liabilities that
it created. We may be required to assume the risk of the
physical condition of the properties in addition to the risk
that the properties may not perform in accordance with our
expectations.
We
face intensive competition in our industry.
We operate in a highly competitive environment. We compete with
major and independent oil and natural gas companies, many of
whom have financial and other resources substantially in excess
of those available to us. These competitors may be better
positioned to take advantage of industry opportunities and to
withstand changes affecting the industry, such as fluctuations
in oil and natural gas prices and production, the availability
of alternative energy sources and the application of government
regulation.
Our
use of derivative contracts is subject to risks that our
counterparties may default on their contractual obligations to
us and may cause us to forego additional future profits or
result in our making cash payments.
Our use of derivative contracts could have the effect of
reducing our revenues and the value of our common stock. To
reduce our exposure to changes in the prices of oil and natural
gas, we have entered into and will in the future enter into
derivative contracts for a portion of our oil and natural gas
production. Our derivative contracts are subject to
mark-to-market
accounting treatment, which means that the change in the fair
market value of these instruments is reported as a non-cash item
in our statement of operations each quarter, which typically
result in significant variability in our net income. Derivative
contracts expose us to the risk of financial loss and may limit
our ability to benefit from increases in oil and natural gas
prices in some circumstances, including the following:
| • | the counterparty to the derivative contract may default on its contractual obligations to us; | |
| • | there is a widening of the price differentials between delivery points for our production and the delivery point assumed in the derivative contract; or | |
| • | our production is less than our hedged volumes. |
The ultimate settlement amount of these unrealized derivative
contracts is dependent on future commodity prices. We may incur
significant unrealized losses in the future from our use of
derivative contracts to the extent market prices increase and
our derivatives contracts remain in place. See
“Item 7A. Quantitative and Qualitative Disclosures
About Market Risk — Commodity Price Risk”
appearing elsewhere in this report.
To
service our indebtedness, we will require a significant amount
of cash. Our ability to generate cash depends on many factors
beyond our control, and any failure to meet our debt obligations
could harm our business, financial condition and results of
operations.
Our ability to make payments on our indebtedness and to fund
planned capital expenditures will depend on our ability to
generate cash from operations and other resources in the future.
This, to a certain extent, is subject to general economic,
financial, competitive, legislative, regulatory and other
factors that are beyond our control, including the prices that
we receive for oil and natural gas.
Our business may not generate sufficient cash flow from
operations and future borrowings may not be available to us in
an amount sufficient to enable us to pay our indebtedness or to
fund our other liquidity needs. If our cash flow and capital
resources are insufficient to fund our debt obligations, we may
be forced to sell assets, seek additional equity or debt capital
or restructure our debt. None of these remedies may, if
necessary, be effected on commercially reasonable terms, or at
all. In addition, any failure to make scheduled payments of
interest and principal on our outstanding indebtedness would
likely result in a reduction of our credit rating, which could
harm our ability to incur additional indebtedness on acceptable
terms. Our cash flow and capital resources may be insufficient
for payment of interest on and principal of our debt in the
future, which could cause us to default on our obligations and
could impair our liquidity.
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Restrictive
debt covenants could limit our growth and our ability to finance
our operations, fund our capital needs, respond to changing
conditions and engage in other business activities that may be
in our best interests.
Our credit agreements contain a number of significant covenants
that, among other things, restrict our ability to:
| • | dispose of assets; | |
| • | incur or guarantee additional indebtedness and issue certain types of preferred stock; | |
| • | pay dividends on our capital stock; | |
| • | create liens on our assets; | |
| • | enter into sale or leaseback transactions; | |
| • | enter into specified investments or acquisitions; | |
| • | repurchase, redeem or retire our capital stock or subordinated debt; | |
| • | merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries; | |
| • | engage in specified transactions with subsidiaries and affiliates; or | |
| • | pursue other corporate activities. |
We may be prevented from taking advantage of business
opportunities that arise because of the limitations imposed on
us by the restrictive covenants under our credit agreements.
Also, our credit agreements require us to maintain compliance
with specified financial ratios and satisfy certain financial
condition tests. Our ability to comply with these ratios and
financial condition tests may be affected by events beyond our
control and, as a result, we may be unable to meet these ratios
and financial condition tests. These financial ratio
restrictions and financial condition tests could limit our
ability to obtain future financings, make needed capital
expenditures, withstand a future downturn in our business or the
economy in general or otherwise conduct necessary corporate
activities. A decline in oil and natural gas prices, or a
prolonged period of oil and natural gas prices at lower levels,
could eventually result in our failing to meet one or more of
the financial covenants under our credit facilities, which could
require us to refinance or amend the facilities resulting in the
payment of consent fees or higher interest rates, or require us
to raise additional capital at an inopportune time or on terms
not favorable to us.
A breach of any of these covenants or our inability to comply
with the required financial ratios or financial condition tests
could result in a default under our credit agreements. A default
under our credit agreements, if not cured or waived, could
result in acceleration of all indebtedness outstanding under our
credit agreements. The accelerated debt would become immediately
due and payable. If that should occur, we may be unable to pay
all such debt or to borrow sufficient funds to refinance it.
Even if new financing were then available, it may not be on
terms that are acceptable to us.
Risks
Related to Our Common Stock
We do
not currently pay dividends on our common stock and do not
anticipate doing so in the future.
We intend to retain any future earnings to fund our operations;
therefore, we do not anticipate paying any cash dividends on our
common stock in the foreseeable future. Also, our credit
facilities do not permit us to pay dividends on our common stock.
Substantial
stock ownership by our executive officers, directors and other
affiliates may limit the ability of our non-affiliate
stockholders to influence the outcome of director elections and
other matters requiring stockholder approval.
Persons who are our officers and directors beneficially own
approximately 18% of our outstanding common stock. Accordingly,
our insiders will have significant influence in the election of
our directors and,
18
Table of Contents
therefore, our policies and direction. This concentration of
voting power could have the effect of delaying or preventing a
change in our control or discouraging a potential acquirer from
attempting to obtain control of us, which in turn could have a
material adverse effect on the market price of our common stock
or prevent our stockholders from realizing a premium over the
market price for their shares of common stock.
You
may experience dilution of your ownership interests due to the
future issuance of additional shares of our common stock, which
could have an adverse effect on our stock price.
We may in the future issue our previously authorized and
unissued securities, resulting in the dilution of the ownership
interests of our present stockholders. We are currently
authorized to issue 100,000,000 shares of common stock and
1,000,000 shares of preferred stock with such designations,
preferences and rights as determined by our board of directors.
As of December 31, 2010, we had outstanding
78,386,983 shares of common stock. In addition, we have
reserved an additional 1,960,271 shares for future issuance
to our directors, officers and employees as restricted stock or
stock option awards pursuant to our 2006 Long-Term Incentive
Plan. The potential issuance of such additional shares of common
stock may create downward pressure on the trading price of our
common stock. We may also issue additional shares of our common
stock or other securities that are convertible into or
exercisable for common stock in connection with future
acquisitions, future issuances of our securities for capital
raising purposes or for other business purposes. Future sales of
substantial amounts of our common stock, or the perception that
sales could occur, could have a material adverse effect on the
price of our common stock.
Certain
provisions of Delaware law, our certificate of incorporation and
bylaws could hinder, delay or prevent a change in control of our
company, which could adversely affect the price of our common
stock.
Certain provisions of Delaware law, our certificate of
incorporation and bylaws could have the effect of discouraging,
delaying or preventing transactions that involve an actual or
threatened change in control of our company. Delaware law
imposes restrictions on mergers and other business combinations
between us and any holder of 15% or more of our outstanding
common stock. In addition, our certificate of incorporation and
bylaws include the following provisions:
| • | Classified Board of Directors. Our board of directors is divided into three classes with staggered terms of office of three years each. The classification and staggered terms of office of our directors make it more difficult for a third party to gain control of our board of directors. At least two annual meetings of stockholders, instead of one, generally would be required to effect a change in a majority of the board of directors. | |
| • | Removal of Directors. Under Delaware law, directors that serve on a classified board, such as our directors, may be removed only for cause by the affirmative vote of the holders of at least a majority of the voting power of the outstanding shares of our capital stock entitled to vote. | |
| • | Number of Directors, Board Vacancies, Term of Office. Our certificate of incorporation and our bylaws provide that only the board of directors may set the number of directors. We have elected to be subject to certain provisions of Delaware law which vest in the board of directors the exclusive right, by the affirmative vote of a majority of the remaining directors, to fill vacancies on the board even if the remaining directors do not constitute a quorum. When effected, these provisions of Delaware law, which are applicable even if other provisions of Delaware law or the charter or bylaws provide to the contrary, also provide that any director elected to fill a vacancy shall hold office for the remainder of the full term of the class of directors in which the vacancy occurred, rather than the next annual meeting of stockholders as would otherwise be the case, and until his or her successor is elected and qualifies. | |
| • | Advance Notice Provisions for Stockholder Nominations and Proposals. Our bylaws require advance written notice for stockholders to nominate persons for election as directors at, or to bring other business before, any meeting of stockholders. This bylaw provision limits the ability of stockholders to make nominations of persons for election as directors or to introduce other proposals unless we are notified in a timely manner prior to the meeting. |
19
Table of Contents
| • | Amending the Bylaws. Our certificate of incorporation permits our board of directors to adopt, alter or repeal any provision of the bylaws or to make new bylaws. Our bylaws also may be amended by the affirmative vote of our stockholders. | |
| • | Authorized but Unissued Shares. Under our certificate of incorporation, our board of directors has authority to cause the issuance of preferred stock from time to time in one or more series and to establish the terms, preferences and rights of any such series of preferred stock, all without approval of our stockholders. Nothing in our certificate of incorporation precludes future issuances without stockholder approval of the authorized but unissued shares of our common stock. |
We
could issue shares of preferred stock which could be entitled to
dividend, liquidation and other special rights and preferences
not shared by holders of our common stock or which could have
anti-takeover effects.
We are authorized to issue up to 1,000,000 shares of
preferred stock, which shares may be issued from time to time in
one or more series as our board of directors, by resolution or
resolutions, may from time to time determine. The voting powers,
preferences and relative, participating, optional and other
special rights, and the qualifications, limitations or
restrictions thereof, if any, of each such series of our
preferred stock may differ from those of any and all other
series of preferred stock at any time outstanding, and, subject
to certain limitations of our certificate of incorporation and
Delaware law, our board of directors may fix or alter, by
resolution or resolutions, the designation, number, voting
powers, preferences and relative, participating, optional and
other special rights, and qualifications, limitations and
restrictions thereof, of each such series of our preferred
stock. The issuance of any such preferred stock could materially
adversely affect the rights of holders of our common stock and,
therefore, could reduce the value of our common stock.
In addition, specific rights granted to future holders of
preferred stock could be used to restrict our ability to merge
with, or sell our assets to, a third party. The ability of our
board of directors to issue preferred stock could discourage,
delay or prevent a takeover of us, thereby preserving our
control by the current stockholders.
| Item 1B. | Unresolved Staff Comments |
None.
| Item 2. | Properties |
As we concentrate our holdings into areas that align with our
objectives, we have determined to report our operations by
state. Our principal properties in Texas primarily consist of
the Electra/Burkburnett fields in Wichita and Wilbarger Counties
and the La Copita field in Starr County. Our principal
Oklahoma properties are the Northeast Fitts and Allen fields in
Pontotoc and Seminole Counties. In Louisiana, our most
significant property is the Lake Enfermer field in Lafourche
Parish. During 2010, we drilled 62 gross wells (54.0 net)
that were capable of production and experienced a success rate
of 99%.
The following table summarizes our estimated proved oil and gas
reserves by area as of December 31, 2010, and our average
daily production by area for calendar year 2010:
|
Average Daily |
Percent of |
|||||||||||||||||||||||
|
Production |
Oil |
Gas |
NGL |
Equivalent |
Proved |
|||||||||||||||||||
| Boe | MBbls | MMcf | MBbls | MBoe | Reserves | |||||||||||||||||||
|
Texas
|
3,893 | 6,903 | 31,158 | 2,126 | 14,222 | 58 | % | |||||||||||||||||
|
Oklahoma
|
1,296 | 5,523 | 4,236 | 111 | 6,340 | 26 | % | |||||||||||||||||
|
Louisiana
|
532 | 409 | 16,555 | — | 3,168 | 13 | % | |||||||||||||||||
|
Other
|
200 | 251 | 1,659 | 138 | 666 | 3 | % | |||||||||||||||||
| 5,921 | 13,086 | 53,608 | 2,375 | 24,396 | 100 | % | ||||||||||||||||||
Texas
Fields
The average daily production from our Texas fields was 3,893 Boe
per day (66% of our total daily production) in 2010, a decrease
of 15% over the previous year due to natural production declines
not offset by
20
Table of Contents
increased drilling. We drilled a total of 58 gross (51.1
net) wells in our Texas fields, all of which were completed as
wells capable of production. An additional three gross (3.0 net)
wells were drilled to their objective depth and awaiting
completion or pipeline connection at year end. As of
December 31, 2010, the proved reserves in our Texas fields
were 14.2 MMBoe and account for 58% of our total proved
reserves. Our most significant Texas fields are as follows:
Electra/Burkburnett Fields. We drilled a total
of 48 gross (48.0 net) wells during 2010 in our
Electra/Burkburnett fields in Wichita and Wilbarger Counties,
Texas and have drilled more than 347 wells in these fields
since November 1, 2004. We have budgeted $8.0 million
in 2011 to continue development of this field. We own our own
drilling rig and pulling units deployed exclusively for
operations in these fields, and employ approximately 91 field
personnel. We continue to focus on reducing operating costs in
these fields and are also working to improve production
performance through recompletions, workovers and improved water
injection performance. As of December 31, 2010, the
estimated proved reserves in these fields were 6.6 MMBoe
(27% of our total proved reserves).
South Texas. During 2010, our net daily
production from our South Texas properties averaged 1,355 Boe
per day and make up 27% (6.6 MMBoe) of our total proved
reserves. We drilled six gross (5.8 net) wells in our
La Copita field in Starr County, Texas during 2010. All
completions were successful with initial production rates up to
482 Boe per day from the Vicksburg formation. We are the
operator of all of the wells in our La Copita field. Due to
continued low natural gas prices, we have allocated only
$2.0 million of our 2011 non-acquisition capital budget to
South Texas.
Oklahoma
Fields
We produced an average of 1,296 Boe per day (22% of our total
daily production) from our Oklahoma fields in 2010, a decrease
of 19% over the previous year primarily due to natural
production declines and weather-related interruptions. We
drilled a total of three gross (2.9 net) wells in our Oklahoma
fields, all of which were completed as wells capable of
production. An additional three gross (2.8 net) wells were
drilled to their objective depth and awaiting completion or
pipeline connection at year end. As of December 31, 2010,
the proved reserves in our Oklahoma fields were 6.3 MMBoe
and account for 26% of our total proved reserves. Our most
significant Oklahoma fields are as follows:
Northeast Fitts and Allen Fields. During 2010,
we initiated the drilling of 3 gross (2.7 net) development
wells in our Northeast Fitts unit in Pontotoc County, Oklahoma.
No wells were drilled during 2009 in our Allen field of Pontotoc
and Seminole Counties. The Northeast Fitts field produces from
shallow McAlester and Hunton formations at depths less than
4,000 feet. We are the operator of the units and, as such,
control the pace of operations. The majority of our value in the
Northeast Fitts field is primarily a mature waterflood. Our
Allen Field has future behind-pipe and undeveloped opportunities
in shallow multi-pay reservoirs. The combined proved reserves
from these two areas are 5.6 MMBoe (23% of our total proved
reserves). We have budgeted $2.0 million for development
costs in our Northeast Fitts and Allen fields in 2010.
Louisiana
Fields
The average daily production from our Louisiana fields was 532
Boe per day (9% of our total daily production) in 2010, a
decrease of 6% over the previous year due to natural production
declines. We drilled a total of one gross (0.2 net) wells in our
Louisiana fields, which was non-productive. As of
December 31, 2010, the proved reserves in our Louisiana
fields were 3.2 MMBoe and account for 13% of our total
proved reserves.
21
Table of Contents
The following table summarizes our 2010 drilling activity:
| Developed | Exploratory | |||||||||||||||||||||||
|
Gross Wells |
Net Wells |
Completion |
Gross wells |
Net Wells |
Completion |
|||||||||||||||||||
| Drilled(1) | Drilled(1) | Rate (%) | Drilled | Drilled | Rate (%) | |||||||||||||||||||
|
Texas
|
57 | 50.1 | 100 | % | 1 | 1.0 | 100 | % | ||||||||||||||||
|
Oklahoma
|
1 | 0.9 | 100 | % | 2 | 2.0 | 100 | % | ||||||||||||||||
|
Louisiana
|
— | — | — | 1 | 0.2 | — | ||||||||||||||||||
|
Other
|
1 | — | 100 | % | — | — | — | |||||||||||||||||
| 59 | 51.0 | 100 | % | 4 | 3.2 | 75 | % | |||||||||||||||||
| (1) | Does not include seven gross (5.8 net) wells that were in the process of being completed at December 31, 2010, and does not include three gross (0.2 net) wells that were drilled in 2009 and waiting on pipeline connection. |
Development,
Exploitation and Exploration Programs
Development and Exploitation Program. Our
future production and performance depends to a large extent on
the successful development of our existing reserves of oil and
natural gas. We have identified multiple development projects on
our existing properties (substantially all of which are located
in our core areas), and these projects involve both the drilling
of development wells and extension wells. We are the operator of
leases covering approximately 2,500 of the wells capable of
production in which we own interests, and as such we are able to
control expenses, capital allocation and the timing of
development activities on these properties. We also own
interests in, and operate, approximately 700 injection wells.
During the year ended December 31, 2010, we drilled or
participated in the drilling of 62 gross (54.0 net)
development wells capable of production. Capital expenditures in
connection with these activities during this period aggregated
approximately $27.9 million.
Another determinant of future performance is the exploitation of
existing wells that can be recompleted or otherwise reworked to
extract additional hydrocarbons. We have identified
approximately 45 operated projects involving recompletions in
existing wells that we operate, all of which involve reserves
included in our proved reserves at December 31, 2010.
Exploration Program. Historically, an
important component of our strategy to expand our reserves and
production has been an active exploration program focused on
adding long-lived oil and natural gas reserves from our core
areas and other resource plays. We have obtained a concession in
Osage County, Oklahoma on over 56,000 acres with 100%
working interest. We have
3-D seismic
data covering approximately 16,000 acres and have obtained
permits for shooting approximately 20,000 additional acres.
During 2011, assuming the continuation of existing commodity
prices for oil and natural gas, we expect to conduct only
limited exploratory drilling, primarily on our Osage concession.
We have an experienced technical staff, including geologists,
landmen, engineers and other technical personnel devoted to
prospect generation and identification of potential drilling
locations. We seek to reduce exploration risk by exploring at
moderate depths that are deep enough to discover sizeable oil
and natural gas accumulations (generally less than
13,000 feet). Our established presence in our core areas
has provided our staff with substantial expertise. Many of our
exploration plays are based upon seismic data comparisons to our
existing producing fields. For exploration prospects we
generate, we typically will own a greater interest in these
projects than our drilling partners, if any, and will operate
the wells. As a result, we will be able to influence the areas
of exploration and the acquisition of leases, as well as the
timing and drilling of each well.
During the year ended December 31, 2010, we participated in
the drilling of four gross (3.2 net) exploratory wells. For
2011, we have budgeted $8.0 million for geological and
geophysical activities relating to exploitation and exploration
projects and $9.0 million for exploration, including
leasehold acquisition, seismic and exploratory drilling. We are
encouraged by the results of our Osage concession exploratory
project in 2010 and plan to increase our spending in 2011.
22
Table of Contents
Oil and
Natural Gas Reserves
Our proved reserve estimates for crude oil and natural gas were
prepared by Forrest A. Garb & Associates, an
independent petroleum engineering firm, in accordance with the
generally accepted petroleum engineering and evaluation
principles and most recent definitions and guidelines
established by the Securities and Exchange Commission
(“SEC”). A copy of Forrest A. Garb &
Associates’ summary reserve report is attached as an
exhibit to this report. All reserve definitions comply with the
definitions of
Rules 4-10
(a) (1)-(32) of SEC
Regulation S-X.
To determine our estimated proved reserves, and as required by
the SEC, we used the
12-month
unweighted arithmetic average of the
first-day-of-the-month
price for the months of January through December 2010 calculated
to be $4.38 per Mcf of natural gas and $79.43 per Bbl of oil.
These prices were held constant for the life of the properties
and adjusted for the appropriate market differentials.
As of December 31, 2010, our proved crude oil and natural
gas reserves and
PV-10 Value
are presented below by reserve category. All of our proved
reserves are located within the United States.
|
Oil |
Gas |
NGL |
Reserve |
PV-10 |
||||||||||||||||||||||||||||
| MBbl | MMcf | MBbl | MBoe | % | M$ | |||||||||||||||||||||||||||
|
Proved developed producing
|
8,087 | 24,134 | 1,358 | 13,467 | 55 | % | $ | 232,449 | ||||||||||||||||||||||||
|
Proved developed nonproducing
|
327 | 7,642 | 128 | 1,729 | 7 | % | $ | 26,903 | ||||||||||||||||||||||||
|
Proved undeveloped
|
4,672 | 21,832 | 889 | 9,200 | 38 | % | $ | 104,896 | ||||||||||||||||||||||||
|
Total proved
|
13,086 | 53,608 | 2,375 | 24,396 | 100 | % | $ | 364,248 | ||||||||||||||||||||||||
|
Developed
|
8,414 | 31,776 | 1,486 | 15,196 | $ | 259,352 | ||||||||||||||||||||||||||
|
% Developed
|
64 | % | 59 | % | 63 | % | 62 | % | 71 | % | ||||||||||||||||||||||
Our properties have a 13.7 year
reserve-to-production
ratio.
Proved
Undeveloped Reserves
At December 31, 2010, our total proved undeveloped reserves
were 9.2 MMBoe, comprised of 5.6 MMBbl of crude oil
and natural gas liquids and 21.8 Bcf of natural gas. As a
result of our 2010 development activities, we converted
approximately 760 MBoe, or 5%, of our 2009 proved
undeveloped reserves to proved developed. The capital costs to
develop these reserves were approximately $13.0 million.
Also during 2010, we drilled wells at 40 locations that did not
include proved reserves as of December 31, 2009. We did not
add any new proved undeveloped locations during 2010. Our
projected costs to develop our remaining proved undeveloped
reserves are $16.3 million in 2011, $36.0 million in
2012, $22.0 million in 2013, $15.7 million in 2014 and
$11.8 million in 2015.
Unproved
Reserves
The new SEC guidelines allow for the disclosure of probable and
possible reserves, which are unproved reserves. Disclosure of
unproved reserves is optional and we have elected not to
disclose any unproved reserves in this report.
Technologies
Used to Establish Additions to Reserve Estimates
The revised rules permit the use of reliable technologies that
have been field tested as evidence proven to establish with
“reasonable certainty” quantities of proved reserves.
They also permit assigning reserves to locations more than one
offset away from standard development spacing if reasonable
certainty can be established, and the estimates are economically
producible. We evaluated the potential use of reliable
technologies in connection with the preparation of our 2010
reserve estimates and have elected not to rely on the new rule
as a means of assigning proved or unproved reserves. We are,
however, actively using seismic interpretation to high grade our
potential drilling locations. In future filings, we may use
reliable technologies to assign reserves if the application can
prove with a high degree of confidence that the estimated
quantities can be recovered.
23
Table of Contents
Internal
Controls over Reserves Estimate
Our policies regarding internal controls over the recording of
reserves are structured to objectively and accurately estimate
our oil and gas reserve quantities and values in compliance with
SEC regulations. Responsibility for compliance in reserve
bookings is delegated to our reservoir engineering group, which
is led by our Senior Vice President of Operations.
Technical reviews are performed throughout the year by our
engineering and geologic staff who evaluate pertinent geological
and engineering data. This data in conjunction with economic
data and ownership information is used in making a determination
of proved reserve quantities. The reserve process is overseen by
our Vice President of Business Development. Our internal
reservoir engineering staff has an average experience of more
than 20 years in the area of reserve estimating and
reservoir evaluations. We have internal auditing guidelines and
controls in place to monitor the reservoir data and reporting
parameters used in preparing the year-end reserves. Technologies
and economic data used include updated production data, well
performance, formation logs, geological maps, reservoir pressure
tests and wellbore mechanical integrity information. Final
approval of the reserves is required by our Senior Vice
President of Operations.
Our reserve estimates are certified by the independent petroleum
engineering firm of Forrest A. Garb & Associates using
their own engineering assumptions and the economic data which we
provide. Forrest A. Garb & Associates is an
independent petroleum engineering consulting firm that provides
petroleum consulting services throughout the world. Forrest A.
Garb is chairman of the board of his firm, and is a registered
professional engineer with more than 50 years of practical
petroleum industry experience. The Forrest A. Garb &
Associates report is included as Exhibit 99.1.
In addition to third party reserve report preparation, our
reserves are reviewed by senior management and the Audit
Committee of our Board of Directors. Senior management, which
includes the President and Chief Executive Officer, the Senior
Vice President of Operations and the Senior Vice President and
Chief Financial Officer, is responsible for reviewing and
verifying that the estimate of proved reserves is reasonable,
complete, and accurate. The Audit Committee reviews the final
reserves estimate in conjunction with Forrest A.
Garb & Associates’ certified reserve report
letter. They may also meet with the key representative from
Forrest A. Garb & Associates to discuss their process
and findings.
Estimated quantities of proved reserves and future net revenues
are affected by oil and natural gas prices, which have
fluctuated widely in recent years. There are numerous
uncertainties inherent in estimating oil and natural gas
reserves and their values, including many factors beyond the
control of the producer. The reserve data set forth in this
report represent only estimates. Reservoir engineering is a
subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in an exact manner.
The accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates of different
engineers, including those used by us, may vary. In addition,
estimates of reserves are subject to revisions based upon actual
production, results of future development and exploration
activities, prevailing oil and natural gas prices, operating
costs and other factors, which revisions may be material. The
PV-10 Value
of our proved oil and natural gas reserves does not necessarily
represent the current or fair market value of such proved
reserves, and the 10% discount factor may not reflect current
interest rates, our cost of capital or any risks associated with
the development and production of our proved oil and natural gas
reserves. Proved reserves include proved developed and proved
undeveloped reserves.
24
Table of Contents
Reserve
Reconciliation
Our total proved reserve reconciliation starting at year-end
2009 and ending year-end 2010 is as follows:
|
Oil |
Gas |
NGL |
||||||||||||||
| MBbl | MMcf | MBbl | MBoe | |||||||||||||
|
Total proved
|
||||||||||||||||
|
As of December 31, 2009
|
14,067 | 89,227 | 4,983 | 33,922 | ||||||||||||
|
Extensions, discoveries and additions(a)
|
347 | 821 | 61 | 545 | ||||||||||||
|
Sales(b)
|
(174 | ) | (14,591 | ) | (2,004 | ) | (4,610 | ) | ||||||||
|
Production
|
(995 | ) | (4,816 | ) | (364 | ) | (2,161 | ) | ||||||||
|
Revisions of previous estimates(c)
|
(159 | ) | (17,033 | ) | (301 | ) | (3,300 | ) | ||||||||
|
As of December 31, 2010
|
13,086 | 53,608 | 2,375 | 24,396 | ||||||||||||
| (a) | We added 0.5 MMBoe in proved reserve extensions, discoveries and additions in 2010 primarily as a result of our development drilling in our Electra/Burkburnett field in North Texas and in our La Copita field in South Texas. A significant portion of these reserves is a result of drilling locations in our Electra/Burkburnett field that were not booked as proved locations at year-end 2009. The remainder of the extensions, discoveries and additions is primarily from wells drilled in South Texas not previously booked as proved and from an exploratory well in Osage County, Oklahoma. | |
| (b) | We divested 4.6 MMBoe of non-core natural gas assets in North Texas and Oklahoma during 2010. | |
| (c) | Total revisions of previous reserve estimates decreased proved reserves by 3.3 MMBoe or approximately 10% of our reserves at the beginning of the year. The revisions included a positive increase of 1.8 MMBoe or 5% of the beginning of the year reserves caused by higher oil and gas prices. This positive revision was offset by the downward revision of 1.1 MMBoe caused by the transfer of proved undeveloped to unproved categories as a result of changes to the company development plans during 2010, and 4.0 MMBoe of the downward revisions mostly due to changes in well performance in our gas properties in South Texas. |
Our proved developed reserves, total proved reserves, estimated
PV-10 Value
and prices used after the effects of market differentials by
year are as follows:
| As of December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
Reserve Data:
|
||||||||||||
|
Proved developed reserves:
|
||||||||||||
|
Oil (MBbls)
|
8,414 | 8,814 | 9,235 | |||||||||
|
Natural gas (MMcf)
|
31,776 | 46,159 | 57,635 | |||||||||
|
Natural gas liquids (MBbls)
|
1,486 | 2,788 | 2,705 | |||||||||
|
Total (MBoe)
|
15,196 | 19,295 | 21,546 | |||||||||
|
PV-10 Value
(in thousands)
|
$ | 259,352 | $ | 222,516 | $ | 233,061 | ||||||
| As of December 31, | ||||||||||||||||
| 2010 | 2009 | 2008 | ||||||||||||||
|
Total Proved reserves:
|
||||||||||||||||
|
Oil (MBbls)
|
13,086 | 14,067 | 14,285 | |||||||||||||
|
Natural gas (MMcf)
|
53,608 | 89,227 | 96,952 | |||||||||||||
|
Natural gas liquids (MBbls)
|
2,375 | 4,983 | 4,325 | |||||||||||||
|
Total (MBoe)
|
24,396 | 33,922 | 34,769 | |||||||||||||
|
PV-10 Value
(in thousands)
|
$ | 364,248 | $ | 336,053 | $ | 322,131 | ||||||||||
|
Prices used in calculating
PV-10 Value:
|
||||||||||||||||
|
$/Bbl (Oil)
|
$ | 76.80 | $ | 58.63 | $ | 44.15 | ||||||||||
|
$/Mcf
|
$ | 4.51 | $ | 3.76 | $ | 5.33 | ||||||||||
|
$/Bbl (NGL)
|
$ | 45.62 | $ | 31.03 | $ | 23.59 | ||||||||||
25
Table of Contents
The prices used in calculating the
PV-10 values
are net of the appropriate market differentials and are for the
economic life of the properties.
The following is a summary of the standardized measure of
discounted net cash flows using methodology provided for in
Topic 932 of the Accounting Standards
Codificationtm
(the “Codification”) implemented by the Financial
Accounting Standards Board (“FASB”), related to our
estimated proved oil and natural gas reserves. For these
calculations, estimated future cash flows from estimated future
production of proved reserves for the years ended
December 31, 2010 and 2009, were computed using benchmark
prices based on the unweighted arithmetic average of the
first-day-of-the-month
prices for oil and natural gas during each month of 2010, as
required by SEC Release
No. 33-8995,
“Modernization of Oil and Gas Reporting,”
effective December 31, 2009, while estimated cash flows in
the reserve reports at December 31, 2008, were based on oil
and natural gas spot prices as of the end of the period
presented. Future development and production costs attributable
to the proved reserves were estimated assuming that existing
conditions would continue over the economic lives of the
individual leases and costs were not escalated for the future.
Estimated future income tax expenses were calculated by applying
future statutory tax rates (based on the current tax law
adjusted for permanent differences and tax credits) to the
estimated future pretax net cash flows related to proved oil and
natural gas reserves, less the tax basis of the properties
involved. Future income tax expenses increased in 2010 because
net operating loss carryforward was used to offset capital gains
realized in the property divestitures and also due to a decrease
in net operating loss carryforwards related to Internal Revenue
Code Section 382 limitation by approximately
$17.0 million net operating loss adjustment, leaving less
net operating loss carryforward available for future years.
Additionally, future development costs are less than the
previous year. For further information regarding the
standardized measure of discounted net cash flows related to our
estimated proved oil and natural gas reserves for the years
ended December 31, 2010, 2009 and 2008, please review
Note M in the notes to our year-end 2010 financial
statements appearing elsewhere in this report. The standardized
measure of discounted future net cash flows relating to our
estimated proved oil and natural gas reserves at December 31 is
summarized as follows:
| Year Ended December 31, | ||||||||||||||||
| 2010 | 2009 | 2008 | ||||||||||||||
| (In thousands) | ||||||||||||||||
|
Future cash inflows
|
$ | 1,355,233 | $ | 1,314,714 | $ | 1,253,537 | ||||||||||
|
Future production costs
|
(548,638 | ) | (535,784 | ) | (472,191 | ) | ||||||||||
|
Future development costs
|
(117,860 | ) | (148,956 | ) | (145,086 | ) | ||||||||||
|
Future income tax expenses
|
(161,736 | ) | (123,943 | ) | (103,434 | ) | ||||||||||
|
Future net cash flows
|
526,999 | 506,031 | 532,826 | |||||||||||||
|
10% annual discount for estimated timing of cash flows
|
(248,952 | ) | (231,797 | ) | (248,373 | ) | ||||||||||
|
Standardized measure of discounted future net cash flows
|
$ | 278,047 | $ | 274,234 | $ | 284,453 | ||||||||||
We believe that the presentation of the
PV-10 value
is relevant and useful to investors because it presents the
discounted future net cash flows attributable to our proved
reserves prior to taking into account corporate future income
taxes, and it is a useful measure of evaluating the relative
monetary significance of our oil and natural gas properties.
Further, investors may utilize the measure as a basis for
comparison of the relative size and value of our reserves to
other companies. We use this measure when assessing the
potential return on investment related to our oil and natural
gas properties. However,
PV-10 value
is not a substitute for the standardized measure of discounted
future net cash flows. Our
PV-10 value
measure and the standardized measure of discounted future net
cash flows do not purport to present the fair value of our oil
and natural gas reserves as of the specified dates.
26
Table of Contents
The following table provides a reconciliation of our
PV-10 Value
to our standardized measure:
| At December 31, | ||||||||||||||||
| 2010 | 2009 | 2008 | ||||||||||||||
| (In thousands) | ||||||||||||||||
|
PV-10 Value
|
$ | 364,248 | $ | 336,053 | $ | 322,131 | ||||||||||
|
Future income taxes
|
(161,736 | ) | (123,943 | ) | (103,434 | ) | ||||||||||
|
Discount of future income taxes at 10% per annum
|
75,535 | 62,124 | 65,756 | |||||||||||||
|
Standardized Measure
|
$ | 278,047 | $ | 274,234 | $ | 284,453 | ||||||||||
In general, the volume of production from oil and natural gas
properties declines as reserves are depleted. Except to the
extent we acquire properties containing proved reserves or
conduct successful exploration and development activities, our
proved reserves will decline as reserves are produced. Our
future oil and natural gas production is, therefore, highly
dependent upon our level of success in finding or acquiring
additional reserves.
Net
Production, Unit Prices and Costs
The following table presents certain information with respect to
our oil and natural gas production and prices and costs
attributable to all oil and natural gas properties owned by us
for the periods shown. Average realized prices reflect the
actual realized prices received by us, before and after giving
effect to the results of our derivative contracts. Our
derivative contracts are financial, and our production of oil,
natural gas and NGLs, and the average realized prices we receive
from our production, are not affected by our derivative
contracts.
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
Production volumes:
|
||||||||||||
|
Oil (MBbls)
|
995 | 1,138 | 1,187 | |||||||||
|
Natural gas liquids (MBbls)
|
364 | 406 | 354 | |||||||||
|
Natural gas (MMcf)
|
4,816 | 5,994 | 6,082 | |||||||||
|
Total (MBoe)
|
2,161 | 2,542 | 2,554 | |||||||||
|
Average realized prices (before effects of derivative contracts):
|
||||||||||||
|
Oil (per Bbl)
|
$ | 76.95 | $ | 58.24 | $ | 98.59 | ||||||
|
Natural gas liquids (per Bbl)
|
38.89 | 27.26 | 50.24 | |||||||||
|
Natural gas (per Mcf)
|
4.21 | 3.47 | 7.87 | |||||||||
|
Total per Boe
|
51.36 | 38.62 | 71.52 | |||||||||
|
Effect of settlement of derivative contracts:
|
||||||||||||
|
Oil (per Bbl)
|
$ | (6.14 | ) | $ | 4.94 | $ | (8.84 | ) | ||||
|
Natural gas liquids (per Bbl)
|
— | — | — | |||||||||
|
Natural gas (per Mcf)
|
0.19 | 2.27 | — | |||||||||
|
Total per Boe
|
(2.40 | ) | 7.57 | (4.10 | ) | |||||||
|
Average realized prices (after effects of derivative contracts):
|
||||||||||||
|
Oil (per Bbl)
|
$ | 70.81 | $ | 63.18 | $ | 89.75 | ||||||
|
Natural gas liquids (per Bbl)
|
38.89 | 27.26 | 50.24 | |||||||||
|
Natural gas (per Mcf)
|
4.40 | 5.74 | 7.87 | |||||||||
|
Total per Boe
|
48.96 | 46.19 | 67.42 | |||||||||
|
Expenses (per Boe):
|
||||||||||||
|
Oil and natural gas production taxes
|
$ | 2.81 | $ | 2.09 | $ | 4.10 | ||||||
|
Oil and natural gas production expenses
|
15.68 | 14.73 | 14.89 | |||||||||
|
Amortization of full cost pool
|
12.11 | 12.06 | 17.89 | |||||||||
|
General and administrative
|
6.85 | 6.56 | 7.95 | |||||||||
|
Cash interest
|
8.32 | 5.28 | 10.11 | |||||||||
|
Cash taxes
|
0.18 | 0.12 | 0.27 | |||||||||
|
Impairment
|
— | 18.73 | 105.66 | |||||||||
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Fields containing 15% or more of total proved reserves at
December 31, 2010:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
La Copita:
|
||||||||||||
|
Production volumes:
|
||||||||||||
|
Oil (MBbls)
|
41 | 58 | 42 | |||||||||
|
Natural gas liquids (MBbls)
|
126 | 118 | 112 | |||||||||
|
Natural gas (MMcf)
|
1,682 | 1,586 | 1,670 | |||||||||
|
Total (MBoe)
|
447 | 441 | 433 | |||||||||
|
Average realized prices:
|
||||||||||||
|
Oil (per Bbl)
|
$ | 76.65 | $ | 58.41 | $ | 103.45 | ||||||
|
Natural gas liquids (per Bbl)
|
39.89 | 29.28 | 46.36 | |||||||||
|
Natural gas (per Mcf)
|
4.32 | 3.95 | 8.91 | |||||||||
|
Total per Boe
|
34.49 | 29.78 | 56.47 | |||||||||
|
Oil and natural gas production expenses (per Boe)
|
$ | 4.31 | $ | 3.62 | $ | 4.68 | ||||||
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
Electra/Burkburnett:
|
||||||||||||
|
Production volumes:
|
||||||||||||
|
Oil (MBbls)
|
471 | 537 | 560 | |||||||||
|
Natural gas liquids (MBbls)
|
41 | 70 | 91 | |||||||||
|
Natural gas (MMcf)
|
— | — | — | |||||||||
|
Total (MBoe)
|
512 | 607 | 651 | |||||||||
|
Average realized prices:
|
||||||||||||
|
Oil (per Bbl)
|
$ | 77.24 | $ | 57.99 | $ | 99.05 | ||||||
|
Natural gas liquids (per Bbl)
|
55.67 | 27.85 | 42.22 | |||||||||
|
Natural gas (per Mcf)
|
— | — | — | |||||||||
|
Total per Boe
|
75.49 | 54.51 | 91.15 | |||||||||
|
Oil and natural gas production expenses (per Boe)
|
$ | 28.21 | $ | 22.46 | $ | 22.71 | ||||||
Acquisition,
Development and Exploration Capital Expenditures
The following table presents information regarding our net costs
incurred in our acquisitions of proved and unproved properties,
and our development and exploration activities (in thousands):
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
Proved property acquisition costs
|
$ | 1,133 | $ | 1,311 | $ | 10,091 | ||||||
|
Unproved property acquisition costs
|
— | — | 2,691 | |||||||||
|
Development costs
|
27,850 | 28,239 | 57,084 | |||||||||
|
Exploration costs
|
4,552 | 321 | 14,857 | |||||||||
|
Total costs incurred
|
$ | 33,535 | $ | 29,871 | $ | 84,723 | ||||||
Finding
Costs
The following table sets forth the estimated proved reserves we
acquired or discovered, including revisions of previous
estimates, during each stated period. In calculating finding
costs, we include acquisition costs related to proved property
acquisitions, development costs, and exploration costs with
respect to
28
Table of Contents
exploratory wells drilled and completed. Most of our drilling in
2010 was in our mature fields on proved undeveloped properties,
which does not result in significant reserve additions. Because
in 2010 we had no significant acquisitions of producing
properties, discoveries were limited and no significant reserves
were added, our finding cost in 2010 was substantially greater
per Boe as compared to prior years. Our three-year average
finding cost was $15.62 per Boe.
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
Proved reserves acquired/discovered (MBoe)
|
545 | 3,957 | 4,984 | |||||||||
|
Total cost per Boe of reserves acquired/discovered
|
$ | 61.53 | $ | 7.55 | $ | 17.00 | ||||||
Producing
Wells
The following table sets forth the number of productive wells in
which we owned an interest as of December 31, 2010.
Productive wells consist of producing wells and wells capable of
production, including wells awaiting pipeline connections or
connection to production facilities. Wells that we complete in
more than one producing horizon are counted as one well.
| Gross | Net | |||||||
|
Oil
|
2,624 | 2,124.7 | ||||||
|
Natural gas
|
604 | 329.4 | ||||||
|
Total
|
3,228 | 2,454.1 | ||||||
Acreage
The following table sets forth our developed and undeveloped
gross and net leasehold acreage as of December 31, 2010:
| Gross | Net | |||||||
|
Developed
|
111,969 | 60,298 | ||||||
|
Undeveloped
|
178,782 | 59,671 | ||||||
|
Total
|
290,751 | 119,969 | ||||||
Approximately 44% of our net acreage was located in our core
areas as of December 31, 2010. Our undeveloped acreage
includes leased acres on which wells have not been drilled or
completed to a point that would permit the production of
commercial quantities of oil and natural gas, regardless of
whether or not such acreage is held by production or contains
proved reserves. A gross acre is an acre in which we own an
interest. A net acre is deemed to exist when the sum of
fractional ownership interests in gross acres equals one. The
number of net acres is the sum of the fractional interests owned
in gross acres.
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Table of Contents
Drilling
Activities
During the periods indicated, we drilled or participated in
drilling the following wells:
| Year Ended December 31, | ||||||||||||||||||||||||
| 2010(1) | 2009(2) | 2008(3) | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
|
Development wells:
|
||||||||||||||||||||||||
|
Productive
|
59 | 51 | 45 | 44 | 83 | 66.8 | ||||||||||||||||||
|
Non-productive
|
— | — | 1 | 0.9 | 1 | 0.2 | ||||||||||||||||||
|
Exploratory wells:
|
||||||||||||||||||||||||
|
Productive
|
3 | 3 | — | — | 6 | 5.1 | ||||||||||||||||||
|
Non-productive
|
1 | 0.2 | — | — | — | — | ||||||||||||||||||
|
Total
|
63 | 54.2 | 46 | 44.9 | 90 | 72.1 | ||||||||||||||||||
| (1) | Does not include seven gross (5.8 net) wells that were in the process of being completed at December 31, 2010, and does include three gross (0.2 net) wells that were drilled in 2009 and waiting on pipeline connection. | |
| (2) | Does not include three gross (0.16 net) wells that were in the process of being completed at December 31, 2009, and does not include two gross (one net) wells that were drilled in 2008 and waiting on pipeline connection. | |
| (3) | Does not include seven gross (5.8 net) wells that were in the process of being completed at December 31, 2008. |
Divestitures
On December 8, 2010, we completed the sale to Milagro
Producing, LLC, a privately owned company located in Houston,
Texas, of all of our oil and natural gas properties and related
assets located in the Boonsville and Newark East fields of Jack
and Wise Counties, Texas. The effective date of the sale was
October 1, 2010. The sale properties included all of our
Bend Conglomerate shallow gas properties and all of our North
Texas Barnett Shale properties, including both producing
properties and undeveloped leasehold. We received net cash
proceeds at closing of $42.3 million subject to customary
post-closing adjustments. As of December 31, 2010, net
proceeds including post-closing adjustments were
$41.0 million. Proved reserves from these properties
accounted for approximately 26.4 billion cubic feet
equivalent (Bcfe) of natural gas, natural gas liquids and oil,
or an estimated 13% of our year-end 2009 proved reserves of
204 Bcfe.
On December 30, 2010, we closed the sale of certain
non-operated natural gas properties located in eastern Oklahoma
for $8.0 million (prior to closing adjustments). The
effective date of the sale was December 1, 2010. Our full
cost pool at December 31, 2010 was reduced by the net
proceeds, including closing adjustments, of $7.8 million in
accordance with the full cost method of accounting. The proceeds
were used to reduce outstanding borrowings under our revolving
credit facility.
Oil and
Natural Gas Marketing and Derivative Activities
During the year ended December 31, 2010, Shell Trading (US)
Company, or STUSCO, accounted for $68.1 million, or 61%, of
our oil and natural gas revenue for that period. No other
purchaser accounted for 10% or more of our oil and natural gas
revenue during 2010. Our agreement with STUSCO covers all of our
North Texas oil production. Effective August 1, 2008
through January 31, 2009, our agreement provided for
payment, on a per barrel basis, of a price equal to
STUSCO’s posted price for North Texas Sweet plus a premium
of $3.25. Effective during the period February through June
2009, our contract price was revised to STUSCO North Texas
Sweet, plus or minus Platt’s P-Plus Posting, minus $1.50.
(Note: the P-Plus posted price is a fluctuating premium based on
the NYMEX front-month, second-month, and third-month rolls.
Shifts in the NYMEX forward curve are relative to fundamental
market conditions such as petroleum stock levels at
30
Table of Contents
Cushing and refinery demand.) For the period July 2009 through
June 2010, our contract price was revised to STUSCO’s
posted price for West Texas Intermediate (WTI) plus $0.80.
Effective for the period of July through December 2010, the
contract price was renegotiated to STUSCO WTI plus $1.30.
We are also subject to a crude purchase contract with STUSCO
covering all of our oil production in our Fitts and Allen fields
in Oklahoma. Effective January through February 2010, our
contract price was Sunoco’s posted price for Oklahoma Sweet
plus $0.25. Effective March through June 2010, our contract
price increased to Sunoco OK Sweet plus $0.85, and effective
July through December 2010, our price was renegotiated to Sunoco
OK Sweet plus $1.15.
There are other purchasers in the fields and such other
purchasers would be available to purchase our production should
our current purchaser discontinue operations. We have no reason
to believe that any such cessation is likely to occur.
To reduce exposure to fluctuations in oil and natural gas prices
and to achieve more predictable cash flow, we periodically
utilize various derivative strategies to manage the price
received for a portion of our future oil and natural gas
production. Our derivative strategies customarily involve the
purchase of put options to provide a price floor for our
production, put/call collars that establish both a floor and a
ceiling price to provide price certainty within a fixed range,
call options that establish a secondary floor above a put/call
collar ceiling, or swap arrangements that establish an
index-related price above which we pay the derivative
counterparty and below which we are paid by the derivative
counterparty. These contracts allow us to predict with greater
certainty the effective oil and natural gas prices to be
received for our production and benefit us when market prices
are less than the base floor prices or swap prices under our
derivative contracts. However, we will not benefit from market
prices that are higher than the ceiling or swap prices in these
contracts for our hedged production.
See “Item 7A. Quantitative and Qualitative
Disclosures About Market Risk” for further information
about our derivative positions at December 31, 2010.
Competition
The oil and natural gas industry is highly competitive. We
compete for the acquisition of oil and natural gas properties,
primarily on the basis of the price to be paid for such
properties, with numerous entities including major oil
companies, other independent oil and natural gas concerns and
individual producers and operators. Many of these competitors
are large, well-established companies and have financial and
other resources substantially greater than ours. Our ability to
acquire additional oil and natural gas properties and to
discover reserves in the future will depend upon our ability to
evaluate and select suitable properties and to consummate
transactions in a highly competitive environment.
Title to
Properties
We believe that we have satisfactory title to our properties in
accordance with standards generally accepted in the oil and
natural gas industry. As is customary in the oil and natural gas
industry, we make only a cursory review of title to farmout
acreage and to undeveloped oil and natural gas leases upon
execution of any contracts. Prior to the commencement of
drilling operations, a title examination is conducted and
curative work is performed with respect to significant defects.
To the extent title opinions or other investigations reflect
title defects, we, rather than the seller of the undeveloped
property, typically are responsible to cure any such title
defects at our expense. If we were unable to remedy or cure any
title defect of a nature such that it would not be prudent for
us to commence drilling operations on the property, we could
suffer a loss of our entire investment in the property. We have
obtained title opinions or reports on substantially all of our
producing properties. Prior to completing an acquisition of
producing oil and natural gas leases, we perform a title review
on a material portion of the leases. Our oil and natural gas
properties are subject to customary royalty interests, liens for
current taxes and other burdens that we believe do not
materially interfere with the use of or affect the value of such
properties.
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Table of Contents
Facilities
Our executive and operating offices are located at
Suite 650, Meridian Tower, 5100 E. Skelly Drive,
Tulsa, Oklahoma 74135 which we occupy under a lease with a
remaining term ending in January 2014, at an annual rental of
approximately $0.4 million, subject to escalations for
taxes and utilities. We also have an executive and operating
office at 4965 Preston Park Blvd., Suite 800, in Plano,
Texas, subject to a lease extending through 2013. Currently,
rent under the lease is approximately $0.7 million
annually. We have subleased a portion of our Plano office and
will receive approximately $0.1 million annually. We also
lease a small office in Houston, Texas. We believe that our
facilities are adequate for our current needs.
Regulation
General. Various aspects of our oil and gas
operations are subject to extensive and continually changing
regulation, as legislation affecting the oil and gas industry is
under constant review for amendment or expansion. Numerous
departments and agencies, both federal and state, are authorized
by statute to issue, and have issued, rules and regulations
binding upon the oil and gas industry and our individual members.
Regulation of Sales and Transportation of Natural
Gas. The Federal Energy Regulatory Commission, or
the FERC, regulates the transportation and sale for resale of
natural gas in interstate commerce pursuant to the Natural Gas
Act of 1938 and the Natural Gas Policy Act of 1978. In the past,
the federal government has regulated the prices at which natural
gas can be sold. While sales by producers of natural gas can
currently be made at uncontrolled market prices, Congress could
reenact price controls in the future. Our sales of natural gas
are affected by the availability, terms and cost of
transportation. The price and terms for access to pipeline
transportation are subject to extensive regulation and proposed
regulation designed to increase competition within the natural
gas industry, to remove various barriers and practices that
historically limited non-pipeline natural gas sellers, including
producers, from effectively competing with interstate pipelines
for sales to local distribution companies and large industrial
and commercial customers and to establish the rates interstate
pipelines may charge for their services. Similarly, the Oklahoma
Corporation Commission and the Texas Railroad Commission have
been reviewing changes to their regulations governing
transportation and gathering services provided by intrastate
pipelines and gatherers. While the changes being considered by
these federal and state regulators would affect us only
indirectly, they are intended to further enhance competition in
natural gas markets. We cannot predict what further action the
FERC or state regulators will take on these matters; however, we
do not believe that any actions taken will have an effect
materially different than the effect on other natural gas
producers with which we compete.
Additional proposals and proceedings that might affect the
natural gas industry are pending before Congress, the FERC,
state commissions and the courts. The natural gas industry
historically has been very heavily regulated; therefore, there
is no assurance that the less stringent regulatory approach
recently pursued by the FERC and Congress will continue.
Oil Price Controls and Transportation
Rates. Our sales of crude oil, condensate and
natural gas liquids are not currently regulated and are made at
market prices. The price we receive from the sale of these
products may be affected by the cost of transporting the
products to market.
Environmental. Our oil and natural gas
operations are subject to pervasive federal, state, and local
laws and regulations concerning the protection and preservation
of the environment (e.g., ambient air, and surface and
subsurface soils and waters), human health, worker safety,
natural resources and wildlife. These laws and regulations
affect virtually every aspect of our oil and natural gas
operations, including our exploration for, and production,
storage, treatment, and transportation of, hydrocarbons and the
disposal of wastes generated in connection with those
activities. These laws and regulations increase our costs of
planning, designing, drilling, installing, operating, and
abandoning oil and natural gas wells and appurtenant properties,
such as gathering systems, pipelines, and storage, treatment and
salt water disposal facilities.
In December 2009, the EPA promulgated a finding that serves as
the foundation under the Clean Air Act to issue other rules that
would result in federal greenhouse gas (“GHG”)
regulations and emissions limits under the Clean Air Act, even
without Congressional action. As part of this array of new
regulations, in
32
Table of Contents
September 2009 and December 2010, the EPA also promulgated a GHG
monitoring and reporting rule that requires certain parties,
including participants in the oil and gas industry, to monitor
and report their GHG emissions, including methane and carbon
dioxide, to the EPA. These regulations may apply to our
operations. The EPA has promulgated two other rules that would
regulate GHGs, one of which would regulate GHGs from stationary
sources, and which will likely affect sources in the oil and gas
exploration and production industry and pipeline industry.
The GHG reporting rule and the stationary source GHG permitting
rules to regulate the emissions of GHGs constitute federal
regulation of carbon dioxide emissions and other GHGs, and may
affect the outcome of other climate change lawsuits pending in
United States federal courts in a manner unfavorable to our
industry. See “Risk factors — Risks relating to
our business — Regulation related to greenhouse
gas emissions could have an adverse effect on our operations and
demand for oil and natural gas.”
We have expended and will continue to expend significant
financial and managerial resources to comply with applicable
environmental laws and regulations, including permitting
requirements. Our failure to comply with these laws and
regulations can subject us to substantial civil and criminal
penalties, claims for injury to persons and damage to properties
and natural resources, and
clean-up and
other remedial obligations. Although we believe that the
operation of our properties generally complies with applicable
environmental laws and regulations, the risks of incurring
substantial costs and liabilities are inherent in the operation
of oil and natural gas wells and appurtenant properties. We
could also be subject to liabilities related to the past
operations conducted by others at properties now owned by us,
without regard to any wrongful or negligent conduct by us.
We cannot predict what effect future environmental legislation
and regulation will have upon our oil and natural gas
operations. The possible legislative reclassification of certain
wastes generated in connection with oil and natural gas
operations as “hazardous wastes” would have a
significant impact on our operating costs, as well as the oil
and natural gas industry in general. The cost of compliance with
more stringent environmental laws and regulations, or the more
vigorous administration and enforcement of those laws and
regulations, could result in material expenditures by us to
remove, acquire, modify, and install equipment, store and
dispose of wastes, remediate facilities, employ additional
personnel, and implement systems to ensure compliance with those
laws and regulations. These accumulative expenditures could have
a material adverse effect upon our profitability and future
capital expenditures.
Regulation of Oil and Gas Exploration and
Production. Our exploration and production
operations are subject to various types of regulation at the
federal, state and local levels. Such regulations include
requiring permits and drilling bonds for the drilling of wells,
regulating the location of wells, the method of drilling and
casing wells, and the surface use and restoration of properties
upon which wells are drilled. Many states also have statutes or
regulations addressing conservation matters, including
provisions for the unitization or pooling of oil and natural gas
properties, the establishment of maximum rates of production
from oil and natural gas wells and the regulation of spacing,
plugging and abandonment of such wells. Some state statutes
limit the rate at which oil and natural gas can be produced from
our properties.
Employees
At December 31, 2010, we had 206 employees, of whom 42
were administrative, accounting or financial personnel and of
whom 164 were technical and operations personnel. Our
exploration staff includes three exploration geologists and six
landmen. Our future success will depend partially on our ability
to attract, retain and motivate qualified personnel. We are not
a party to any collective bargaining agreement and we have not
experienced any strikes or work stoppages. We consider our
relations with our employees to be satisfactory.
Available
Information
Copies of our Annual Report on
Form 10-K,
Quarterly Reports on
Form 10-Q,
Current Reports on
Form 8-K,
and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of
1934, as amended, are available free of charge through our
website (www.ramenergy.com) as soon as reasonably practicable
after we electronically file the material with, or furnish it
to, the SEC. Our SEC filings are
33
Table of Contents
also available from the SEC’s website at:
http://www.sec.gov.
The references to our website address do not constitute
incorporation by reference of the information contained on the
website and should not be considered part of this report.
| Item 3. | Legal Proceedings |
From time to time, we are a party to litigation or other legal
proceedings that we consider to be a part of the ordinary course
of our business. We are not currently involved in any legal
proceedings, nor are we a party to any pending or threatened
claims, that could reasonably be expected to have a material
adverse effect on our financial condition or results of
operations.
| Item 4. | Reserved |
PART II
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Market
for Common Stock
Our common stock is traded on the Nasdaq Capital Market under
the symbol RAME. The following table sets forth the range of
high and low closing bid prices for our common stock for the
periods indicated.
| Common Stock | ||||||||
| High | Low | |||||||
|
2011:
|
||||||||
|
First Quarter (through March 14, 2011)
|
$ | 2.45 | $ | 1.56 | ||||
|
2010:
|
||||||||
|
First Quarter
|
$ | 2.23 | $ | 1.40 | ||||
|
Second Quarter
|
2.30 | 1.49 | ||||||
|
Third Quarter
|
2.17 | 1.37 | ||||||
|
Fourth Quarter
|
1.92 | 1.38 | ||||||
|
2009:
|
||||||||
|
First Quarter
|
$ | 1.24 | $ | 0.40 | ||||
|
Second Quarter
|
1.09 | 0.68 | ||||||
|
Third Quarter
|
1.30 | 0.64 | ||||||
|
Fourth Quarter
|
2.24 | 1.41 | ||||||
|
2008:
|
||||||||
|
First Quarter
|
$ | 5.10 | $ | 4.42 | ||||
|
Second Quarter
|
6.73 | 4.80 | ||||||
|
Third Quarter
|
6.40 | 2.68 | ||||||
|
Fourth Quarter
|
2.75 | 0.74 | ||||||
Holders
As of March 7, 2011, there were 98 holders of record of our
common stock. We believe that at March 7, 2011, there were
5,921 beneficial holders of our common stock.
Dividends
It is the present intention of our board of directors to retain
all earnings, if any, for use in our business operations and,
accordingly, our board does not anticipate declaring any
dividends in the foreseeable future. In addition, our credit
facilities do not permit us to pay dividends on our common stock.
34
Table of Contents
Compensation
Plan Information
The following table provides information for all equity
compensation plans as of the fiscal year ended December 31,
2010, under which our equity securities were authorized for
issuance:
|
Number of Securities Remaining |
||||||||||||
|
Number of Securities to |
Weighted Average |
Available for Future Issuance |
||||||||||
|
be Issued Upon Exercise |
Exercise Price of |
Under Equity Compensation |
||||||||||
|
of Outstanding Options, |
Outstanding Options, |
Plans (Excluding Securities |
||||||||||
|
Warrants and Rights |
Warrants and Rights |
Reflected in Column (a)) |
||||||||||
|
Plan Category
|
(a) | (b) | (c) | |||||||||
|
Equity compensation plans approved by security holders(1)
|
— | — | 1,960,271 | (2) | ||||||||
|
Equity compensation plans not approved by security holders
|
— | — | — | |||||||||
|
Total
|
— | — | 1,960,271 | |||||||||
| (1) | Shares awarded under all above plans may be newly issued, from our treasury or acquired in the open market. | |
| (2) | This number reflects shares available for issuance under our 2006 Long-Term Incentive Plan as of December 31, 2010. |
35
Table of Contents
Stockholder
Return Performance Presentation
The following graph and table compare the cumulative
5-year total
return provided to our stockholders on our common stock
beginning December 31, 2005, through December 31,
2010, relative to the cumulative total returns of the Nasdaq
Composite index and the Dow Jones Wilshire MicroCap
Exploration & Production index. The comparison assumes
an investment of $100 (with reinvestment of all dividends) was
made in our common stock on December 31, 2005, and in each
of the indexes and its relative performance is tracked through
December 31, 2010. The identity of the 50+ companies
included in the Dow Jones Wilshire MicroCap
Exploration & Production Index will be provided upon
request.
COMPARISON
OF 5 YEAR CUMULATIVE TOTL RETURN*
Among RAM Energy Resources, Inc., the NASDAQ Composite Index
and a Peer Group
Among RAM Energy Resources, Inc., the NASDAQ Composite Index
and a Peer Group
| Year Ended December 31, | ||||||||||||||||||||
| 2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
|
RAM Energy Resources, Inc.
|
$ | 33 | $ | 37 | $ | 16 | $ | 91 | $ | 100 | ||||||||||
|
Nasdaq Composite
|
126 | 107 | 74 | 125 | 111 | |||||||||||||||
|
Dow Jones Wilshire MicroCap Exploration & Production
Index
|
64 | 41 | 30 | 67 | 83 | |||||||||||||||
36
Table of Contents
| Item 6. | Selected Financial Data |
We acquired RAM Energy, Inc. effective May 8, 2006, by the
merger of our wholly owned subsidiary with and into RAM Energy.
For accounting and financial reporting purposes, the merger was
accounted for as a reverse acquisition and, in substance, as a
capital transaction, because we had no active business
operations prior to consummation of the merger. Accordingly, for
accounting and financial reporting purposes, the RAM Energy
acquisition was treated as the equivalent of RAM Energy issuing
stock for our net monetary assets accompanied by a
recapitalization. Our net monetary assets have been stated at
their fair value, essentially equivalent to historical costs,
with no goodwill or other intangible assets recorded. The
accumulated deficit of RAM Energy has been carried forward.
Operations prior to the merger are those of RAM Energy.
We acquired Ascent Energy Inc. on November 29, 2007, by the
merger of our wholly owned subsidiary with and into Ascent. The
Ascent acquisition was accounted for under the purchase method
of accounting. Upon completion of the Ascent acquisition, Ascent
adopted the full cost method of accounting for exploration,
development and production of oil and natural gas.
The selected consolidated financial information presented below
should be read in conjunction with our consolidated financial
statements and the related notes, and “Management’s
Discussion and Analysis of Financial Condition and Results of
Operations” contained elsewhere in this report. Our
financial position and results of operations for 2010, 2009,
2008 and 2007 may not be comparative to other periods as a
result of certain divestitures and acquisitions, as more fully
described in our consolidated financial statements included
elsewhere in this report.
Selected
Financial Data
(In thousands, except share data)
(In thousands, except share data)
| Year Ended December 31, | ||||||||||||||||||||
| 2010 | 2009 | 2008 | 2007(1) | 2006 | ||||||||||||||||
|
Revenues and Other Operating Income:
|
||||||||||||||||||||
|
Oil sales
|
$ | 76,563 | $ | 66,281 | $ | 117,036 | $ | 55,000 | $ | 48,013 | ||||||||||
|
Natural gas sales
|
20,265 | 20,818 | 47,884 | 17,830 | 14,232 | |||||||||||||||
|
Natural gas liquids sales
|
14,156 | 11,068 | 17,770 | 9,047 | 5,770 | |||||||||||||||
|
Realized gains (losses) on derivatives
|
(5,193 | ) | 19,255 | (10,472 | ) | (2,669 | ) | (4,650 | ) | |||||||||||
|
Unrealized gains (losses) on derivatives
|
6,386 | (30,561 | ) | 33,257 | (10,056 | ) | 6,239 | |||||||||||||
|
Other
|
157 | 217 | 382 | 488 | 640 | |||||||||||||||
|
Total revenues and other operating income
|
112,334 | 87,078 | 205,857 | 69,640 | 70,244 | |||||||||||||||
|
Operating Expenses:
|
||||||||||||||||||||
|
Oil and natural gas production taxes
|
6,063 | 5,320 | 10,480 | 4,869 | 3,329 | |||||||||||||||
|
Oil and natural gas production expenses
|
33,891 | 37,455 | 38,030 | 21,574 | 18,266 | |||||||||||||||
|
Depreciation and amortization
|
27,225 | 31,650 | 46,512 | 18,948 | 13,252 | |||||||||||||||
|
Accretion expense
|
1,527 | 1,976 | 2,207 | 704 | 535 | |||||||||||||||
|
Impairment
|
— | 47,613 | 269,886 | — | — | |||||||||||||||
|
Share-based compensation
|
3,110 | 2,179 | 2,563 | 989 | 2,308 | |||||||||||||||
|
General and administrative, net of operator’s overhead fees
|
14,799 | 16,667 | 20,305 | 11,891 | 9,300 | |||||||||||||||
|
Total operating expenses
|
86,615 | 142,860 | 389,983 | 58,975 | 46,990 | |||||||||||||||
|
Operating income (loss)
|
25,719 | (55,782 | ) | (184,126 | ) | 10,665 | 23,254 | |||||||||||||
|
Other Income (Expense):
|
||||||||||||||||||||
|
Interest expense
|
(22,655 | ) | (18,590 | ) | (24,182 | ) | (20,757 | ) | (17,050 | ) | ||||||||||
|
Interest income
|
27 | 82 | 208 | 1,047 | 309 | |||||||||||||||
|
Other income (expense)
|
321 | (440 | ) | (13,536 | ) | (57 | ) | — | ||||||||||||
|
Income (Loss) Before Income Taxes
|
3,412 | (74,730 | ) | (221,636 | ) | (9,102 | ) | 6,513 | ||||||||||||
|
Income Tax Provision (Benefit)
|
995 | (16,347 | ) | (91,683 | ) | (7,852 | ) | 1,465 | ||||||||||||
|
Net income (loss)
|
$ | 2,417 | $ | (58,383 | ) | $ | (129,953 | ) | $ | (1,250 | ) | $ | 5,048 | |||||||
37
Table of Contents
| (1) | We acquired Ascent Energy Inc. in November 2007. |
Selected
Financial Data (continued)
(In thousands, except share data)
(In thousands, except share data)
| Year Ended December 31, | ||||||||||||||||||||
| 2010 | 2009 | 2008 | 2007(1) | 2006 | ||||||||||||||||
|
Cash dividends per share
|
$ | — | $ | — | $ | — | $ | — | $ | 0.02 | ||||||||||
|
Earnings (loss) per share:
|
||||||||||||||||||||
|
Basic
|
$ | 0.03 | $ | (0.75 | ) | $ | (1.80 | ) | $ | (0.03 | ) | $ | 0.16 | |||||||
|
Diluted
|
0.03 | (0.75 | ) | (1.80 | ) | (0.03 | ) | 0.16 | ||||||||||||
|
Weighted average shares outstanding:
|
||||||||||||||||||||
|
Basic
|
78,426,179 | 77,601,057 | 72,234,750 | 42,087,617 | 30,900,213 | |||||||||||||||
|
Diluted
|
78,426,179 | 77,601,057 | 72,234,750 | 42,087,617 | 32,119,169 | |||||||||||||||
|
Statement of Cash Flow Data
|
||||||||||||||||||||
|
Cash provided by (used in):
|
||||||||||||||||||||
|
Operating activities
|
$ | 37,875 | $ | 32,372 | $ | 74,454 | $ | 17,042 | $ | 29,660 | ||||||||||
|
Investing activities
|
14,970 | (23,921 | ) | (82,568 | ) | (241,192 | ) | (25,317 | ) | |||||||||||
|
Financing activities
|
(52,937 | ) | (8,486 | ) | 1,405 | 224,302 | 2,308 | |||||||||||||
|
Other Data
|
||||||||||||||||||||
|
Capital expenditures(2)
|
$ | 33,535 | $ | 29,871 | $ | 84,723 | $ | 344,795 | $ | 28,145 | ||||||||||
|
Modified EBITDA
|
50,969 | 58,287 | 103,641 | 42,352 | 33,419 | |||||||||||||||
| As of December 31, | ||||||||||||||||||||
| 2010 | 2009 | 2008 | 2007(1) | 2006 | ||||||||||||||||
|
Balance Sheet Data
|
||||||||||||||||||||
|
Total assets
|
$ | 265,001 | $ | 311,162 | $ | 403,964 | $ | 580,242 | $ | 161,725 | ||||||||||
|
Long-term debt, including current portion
|
197,092 | 246,167 | 250,696 | 335,747 | 132,237 | |||||||||||||||
|
Stockholders’ equity (deficit)
|
4,167 | (526 | ) | 57,840 | 98,698 | (27,895 | ) | |||||||||||||
| (1) | We acquired Ascent Energy Inc. in November 2007. | |
| (2) | Includes costs of acquisitions. |
Our Modified EBITDA is determined by adding the following to net
income (loss): interest expense, amortization and depreciation,
accretion, income taxes, share-based compensation, impairment
charges, settlement charges and unrealized gains (losses) on
derivatives. The table below reconciles Modified EBITDA to net
income (loss).
We present Modified EBITDA because we believe that it provides
useful information regarding our continuing operating results.
We rely on Modified EBITDA as a measure to review and assess our
operating performance with corresponding periods, and as an
assessment of our overall liquidity and our ability to meet our
debt service obligations.
We believe that Modified EBITDA is useful to investors to
provide disclosure of our operating results on the same basis as
that used by our management. We also believe that this measure
can assist investors in comparing our performance to that of
other companies on a consistent basis without regard to certain
items that do not directly affect our ongoing operating
performance or cash flows. Modified EBITDA, which is not a
financial measure under generally accepted accounting
principles, or GAAP, has limitations as an analytical tool, and
you should not consider it in isolation, or as a substitute for
net income, cash flows from operating activities and other
consolidated income or cash flows statement data prepared in
accordance with GAAP.
38
Table of Contents
Because of these limitations, Modified EBITDA should neither be
considered as a measure of discretionary cash available to us to
invest in the growth of our business, nor as a replacement for
net income. We compensate for these limitations by relying
primarily on our GAAP results and using Modified EBITDA as
supplemental information.
| Year Ended December 31, | ||||||||||||||||||||
| 2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Reconciliation of Modified EBITDA to net income (loss):
|
||||||||||||||||||||
|
Net income (loss)
|
$ | 2,417 | $ | (58,383 | ) | $ | (129,953 | ) | $ | (1,250 | ) | $ | 5,048 | |||||||
|
Plus: Interest expense
|
22,655 | 18,590 | 24,182 | 20,757 | 17,050 | |||||||||||||||
|
Plus: Amortization and depreciation expense
|
27,225 | 31,650 | 46,512 | 18,948 | 13,252 | |||||||||||||||
|
Plus: Accretion expense
|
1,527 | 1,976 | 2,207 | 704 | 535 | |||||||||||||||
|
Plus: Income tax expense (benefit)
|
995 | (16,347 | ) | (91,683 | ) | (7,852 | ) | 1,465 | ||||||||||||
|
Plus: Share-based compensation
|
3,110 | 2,179 | 2,563 | 989 | 2,308 | |||||||||||||||
|
Plus: Impairment charges
|
— | 47,613 | 269,886 | — | — | |||||||||||||||
|
Plus: Settlement charge
|
(574 | ) | 448 | 13,184 | — | — | ||||||||||||||
|
Plus: Unrealized (gain) loss on derivatives
|
(6,386 | ) | 30,561 | (33,257 | ) | 10,056 | (6,239 | ) | ||||||||||||
|
Modified EBITDA
|
$ | 50,969 | $ | 58,287 | $ | 103,641 | $ | 42,352 | $ | 33,419 | ||||||||||
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
General
We are an independent oil and natural gas company engaged in the
acquisition, development, exploitation, exploration and
production of oil and natural gas properties, primarily in
Texas, Louisiana and Oklahoma. Through our RAM Energy
subsidiary, we have been active in our core producing areas of
Texas, Louisiana and Oklahoma since 1987. Our management team
has extensive technical and operating expertise in all areas of
our geographic focus.
On December 8, 2010, we completed the sale to Milagro
Producing, LLC, a privately owned company located in Houston,
Texas, of all of our oil and natural gas properties and related
assets located in the Boonsville and Newark East fields of Jack
and Wise Counties, Texas. The effective date of the sale was
October 1, 2010. The sale properties included all of our
Bend Conglomerate shallow gas properties and all of our North
Texas Barnett Shale properties, including both producing
properties and undeveloped leasehold. We received net cash
proceeds at closing of $42.3 million subject to customary
post-closing adjustments. As of December 31, 2010, net
proceeds including post-closing adjustments were
$41.0 million. Proved reserves from these properties
accounted for approximately 26.4 billion cubic feet
equivalent (Bcfe) of natural gas, natural gas liquids and oil,
or an estimated 13% of our year-end 2009 proved reserves of
204 Bcfe. Information as to our recent divestitures is set
forth under Note B to the Consolidated Financial Statements.
Oil and natural gas prices have historically been volatile. In
2010, our average realized prices (before the impact of
derivative financial instruments) for oil and natural gas were
$76.95 per Bbl and $4.21 per Mcf, respectively, a significant
improvement over 2009 average realized prices of $58.24 per Bbl
and $3.47 per Mcf, respectively. A significant decline in annual
average prices for oil and natural gas began during the last
half of 2008. Spot natural gas prices declined to $5.71 per Mcf
on December 31, 2008, from $12.27 per Mcf on June 30,
2008, a decrease of approximately 53%. Oil prices in the last
six months of 2008 experienced a 68% decrease, declining to
$44.60 per Bbl on December 31, 2008, from $138.32 per Bbl
on June 30, 2008. Natural gas and oil prices continued to
decline into the first quarter of 2009. Prices improved in the
fourth quarter of 2009 for oil, increasing 28% to $73.36 per Bbl
compared to $57.56 in the 2008 period. Natural gas prices
continued to decline to $3.93 per Mcf in the fourth quarter of
2009 from $5.05 in the fourth quarter of
39
Table of Contents
2008, a 22% drop. It is impossible to predict the frequency,
duration or outcome of any volatile price movements or the
long-term impact on drilling and operating costs and the
impacts, whether favorable or unfavorable, to our results of
operations and liquidity. We continue to monitor operations and
planned capital budget expenditures as the economics of many
projects may diminish as a result of prolonged natural gas price
declines.
Critical
Accounting Policies
The preparation of our financial statements in conformity with
generally accepted accounting principles requires our management
to make estimates and assumptions that affect our reported
assets, liabilities and contingencies as of the date of the
financial statements and our reported revenues and expenses
during the related reporting period. Our actual results could
differ from those estimates. See Note A to our Consolidated
Financial Statements included in Item 8 of this report for
further discussions of our significant accounting policies and
recently adopted accounting standards.
We follow the full cost method of accounting for oil and natural
gas operations. Under this method all productive and
nonproductive costs incurred in connection with the acquisition,
exploration, and development of oil and natural gas reserves are
capitalized. No gains or losses are recognized upon the sale or
other disposition of oil and natural gas properties except in
transactions that would significantly alter the relationship
between capitalized costs and proved reserves. The costs of
unevaluated oil and natural gas properties are excluded from the
amortizable base until the time that either proven reserves are
found or it has been determined that such properties are
impaired. As properties become evaluated, the related costs
transfer to proved oil and natural gas properties using full
cost accounting.
Under the full cost method the net book value of oil and natural
gas properties, less related deferred income taxes, may not
exceed the estimated after-tax future net revenues from proved
oil and natural gas properties, discounted at 10% (the
“Ceiling Limitation”). In arriving at estimated future
net revenues, estimated lease operating expenses, development
costs, and certain production-related and ad valorem taxes are
deducted. In calculating future net revenues, prices and costs
are held constant indefinitely, except for changes that are
fixed and determinable by existing contracts. The net book value
is compared to the Ceiling Limitation on a quarterly and yearly
basis. The excess, if any, of the net book value above the
Ceiling Limitation is charged to expense in the period in which
it occurs and is not subsequently reinstated. At
December 31, 2008, the net book value of our oil and
natural gas properties exceeded the Ceiling Limitation resulting
in reduction in the carrying value of our oil and natural gas
properties by $269.4 million, or $171.6 million net of
tax, and at March 31, 2009, the net book value of our oil
and natural gas properties exceeded the Ceiling Limitation
resulting in reduction in the carrying value of our oil and
natural gas properties by $47.6 million, or
$30.3 million net of tax. We incurred no impairment charge
in 2010.
Estimates of our crude oil and natural gas reserves are prepared
by independent petroleum and geological engineers in accordance
with guidelines established by the SEC. Proved reserves,
estimated future net revenues and the present value of our
reserves are estimated based upon a combination of historical
data and estimates of future activity. There are numerous
uncertainties inherent in estimating quantities of proved crude
oil and natural gas reserves. Reserve estimates may be different
from the quantities of crude oil and natural gas that are
ultimately recovered. Estimates of proved crude oil and natural
gas reserves may significantly affect the amount at which oil
and natural gas properties are recorded and significantly affect
our amortization and depreciation expense.
On December 31, 2008, the SEC issued Release
No. 33-8995
amending its oil and natural gas reporting requirements for oil
and natural gas producing companies. Companies were not
permitted to comply at an earlier date. Among other things,
Release
No. 33-8995:
| • | Revises a number of definitions relating to proved oil and natural gas reserves to make them consistent with the Petroleum Resource Management System, which includes certain non-traditional resources in proved reserves; | |
| • | Permits the use of new technologies for determining proved oil and natural gas reserves; |
40
Table of Contents
| • | Requires the use of average prices for the trailing twelve-month period in the estimation of oil and natural gas reserve quantities and, for companies using the full cost method of accounting, in computing the Ceiling Limitation, in place of a single day price as of the end of the fiscal year; | |
| • | Permits the disclosure in filings with the SEC of probable and possible reserves and reserves sensitivity to changes in prices; | |
| • | Requires additional disclosures (outside of the financial statements) regarding the status of undeveloped reserves and changes in status of these from period to period; and | |
| • | Requires a discussion of the internal controls in place to assure objectivity in the reserve estimation process and disclosure of the technical qualifications of the technical person having primary responsibility for preparing the reserve estimates. |
Our independent petroleum engineers utilized the new procedures
in preparing the estimate of our proved reserves as of
December 31, 2009 and 2010, as reflected in this report.
Topic 410 of the Codification addresses financial accounting and
reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement
costs and amends Statement of Financial Accounting Standards
No. 19, now Topic 932 of the Codification. Topic 410
requires that the fair value of a liability for an asset
retirement obligation be recognized in the period in which it is
incurred if a reasonable estimate of fair value can be made, and
that the associated asset retirement costs be capitalized as
part of the carrying amount of the long-lived asset. We
determine our asset retirement obligation by calculating the
present value of the estimated cash flows related to the
liability.
As set forth in Topic 740 of the Codification, deferred income
taxes are recognized at each period end for the future tax
consequences of differences between the tax bases of assets and
liabilities and their financial reporting amounts based on tax
laws and statutory tax rates applicable to the periods in which
the differences are expected to affect taxable income. We
routinely assess the realizability of our deferred tax assets.
We consider future taxable income in making such assessments. If
we conclude that it is more likely than not that some portion or
all of the deferred tax assets will not be realized under
accounting standards, it is reduced by a valuation allowance.
However, despite our attempt to make an accurate estimate, the
ultimate utilization of our deferred tax assets is highly
dependent upon our actual production and the realization of
taxable income in future periods.
We account for our derivative arrangements as set forth in Topic
815 of the Codification. Topic 815 requires the accounting
recognition of all derivative instruments on the balance sheet
as either assets or liabilities measured at fair value. We may
or may not elect to designate a derivative instrument as a hedge
against changes in the fair value of an asset or a liability (a
“fair value hedge”) or against exposure to variability
in expected future cash flows (a “cash flow hedge”).
The accounting treatment for the changes in fair value of a
derivative instrument is dependent upon whether or not a
derivative instrument is a cash flow hedge or a fair value
hedge, and upon whether or not the derivative is designated by
us as a hedge. Changes in fair value of a derivative designated
as a cash flow hedge are recognized, to the extent the hedge is
effective, in other comprehensive income until the hedged item
is recognized in earnings. Changes in the fair value of a
derivative instrument designated as a fair value hedge, to the
extent the hedge is effective, have no effect on the statement
of operations due to the fact that changes in fair value of the
derivative offsets changes in the fair value of the hedged item.
Where hedge accounting is not elected or if a derivative
instrument does not qualify as either a fair value hedge or a
cash flow hedge, changes in the fair value are recognized in
earnings. We have not elected to designate our derivative
instruments as hedges as required by Topic 815 in order to
receive hedge accounting treatment. Accordingly, all gains and
losses on the derivative instrument have been recorded in
earnings.
During June 2008, the FASB issued authoritative guidance on
whether instruments granted in share-based payment transactions
are participating securities prior to vesting and, therefore,
need to be included in computing basic earnings per share. The
guidance was effective for fiscal years beginning after
December 15, 2008, and interim periods within those years.
Additionally, all prior period earnings per share must be
adjusted retrospectively. As our restricted stock awards granted
under our Long-Term Incentive Plan qualify as
41
Table of Contents
participating securities, we adopted the guidance during 2009,
which resulted in an increase in our basic and diluted weighted
average shares outstanding.
We account for share-based payments under authoritative
guidance, as set forth in Topic 718 of the Codification. Topic
718 requires all share-based payments to employees, including
grants of employee stock options, to be recognized in the
financial statements based on their fair values.
We account for uncertain tax positions under the guidance set
forth in Topic 740 of the Codification. This Topic prescribes
guidance for the financial statement recognition and measurement
of a tax position taken or expected to be taken in a tax return.
To recognize a tax position, the enterprise determines whether
it is more likely than not that the tax position will be
sustained upon examination, including resolution of any related
appeals or litigation, based solely on the technical merits of
the position. A tax position that meets the more likely than not
threshold is measured to determine the amount of benefit to be
recognized in the financial statements. The amount of tax
benefit recognized with respect to any tax position is measured
as the largest amount of benefit that is greater than
50 percent likely of being realized upon settlement.
New
Accounting Pronouncements
On December 31, 2008, the SEC issued Release
No. 33-8995,
“Modernization of Oil and Gas Reporting,” which
revises disclosure requirements for oil and gas companies. In
addition to changing the definition and disclosure requirements
for oil and gas reserves, the new rules change the requirements
for determining oil and gas reserve quantities. These rules
permit the use of new technologies to determine proved reserves
under certain criteria and allow companies to disclose their
probable and possible reserves. The new rules also require
companies to report the independence and qualifications of their
reserves preparer or auditor and file reports when a third party
is relied upon to prepare reserves estimates or conduct a
reserves audit. The new rules also require that oil and gas
reserves be reported and the full cost ceiling limitation be
calculated using a twelve-month average price rather than
period-end prices. The new rules are effective for annual
reports on
Form 10-K
for fiscal years ending on or after December 31, 2009.
Additionally, the FASB issued authoritative guidance on oil and
gas reserve estimation and disclosures, as set forth in Topic
932 of the Codification to align with the requirements of the
SEC’s revised rules. We implemented the new disclosure
requirements and the requirements for estimating reserves
related to our oil and natural gas operations effective
December 31, 2009, as disclosed in Note M to our
Consolidated Financial Statements.
In January 2009, the FASB issued guidance on fair value
disclosures to enhance disclosures surrounding the transfers of
assets in and out of Level 1 and Level 2, to present
more detail surrounding asset activity for Level 3 assets
and to clarify existing disclosure requirements. The new
guidance is set forth in Topic 820 of the Codification and is
effective for us beginning January 1, 2010. Additional
disclosure about purchases, sales, issuances, and settlement in
the roll forward of activity in Level 3 fair value
measurements is effective beginning January 1, 2011.
Adoption of the guidance on January 1, 2010 did not, and
adoption of the guidance on January 1, 2011 will not, have
any impact our financial position or statement of operations.
In February 2010, the FASB issued an update to authoritative
guidance, as set forth in Topic 855 of the Codification,
relating to subsequent events, which was effective upon the
issuance of the update. We adopted this authoritative guidance
during the first quarter of 2010. The update removes the
requirement for U.S. Securities and Exchange Commission
filers to disclose the date through which subsequent events have
been evaluated in both issued and revised financial statements.
The adoption of this update did not impact our financial
position or statement of operations other than removing the
disclosure.
In December 2010, the FASB issued an update to authoritative
guidance, as set forth in Topic 805 of the Codification,
relating to business combinations. This update provides
clarification requiring public companies that have completed
material acquisitions to disclose the revenue and earnings of
the combined business as if the acquisition took place at the
beginning of the comparable prior annual reporting period, and
also expands the supplemental pro forma disclosures to include a
description of the nature and amount of material, non-recurring
pro forma adjustments directly attributable to the business
combination included in the reported pro forma revenue and
earnings. We will be required to apply this guidance
prospectively for business
42
Table of Contents
combinations for which the acquisition date is on or after
January 1, 2011. We do not expect the adoption of this new
guidance to have a material impact on our financial position or
statement of operations.
Results
of Operations
Year
Ended December 31, 2010 Compared to the Year Ended
December 31, 2009
As we concentrate our holdings into areas that align with our
objectives, we have determined to report our operations by
state, rather than by field as was reported in previous years.
The following tables summarize our oil and natural gas
production volumes, average sale prices and comparisons for the
years ended December 31, 2010 and 2009:
| Texas | Oklahoma | Louisiana | Other | Total | ||||||||||||||||
|
Year Ended December 31, 2010
|
||||||||||||||||||||
|
Aggregate Net Production
|
||||||||||||||||||||
|
Oil (MBbls)
|
559 | 322 | 79 | 35 | 995 | |||||||||||||||
|
NGLs (MBbls)
|
341 | 10 | — | 13 | 364 | |||||||||||||||
|
Natural Gas (MMcf)
|
3,128 | 849 | 689 | 150 | 4,816 | |||||||||||||||
|
MBoe
|
1,421 | 473 | 194 | 73 | 2,161 | |||||||||||||||
|
Year Ended December 31, 2009
|
||||||||||||||||||||
|
Aggregate Net Production
|
||||||||||||||||||||
|
Oil (MBbls)
|
664 | 356 | 83 | 35 | 1,138 | |||||||||||||||
|
NGLs (MBbls)
|
375 | 15 | — | 16 | 406 | |||||||||||||||
|
Natural Gas (MMcf)
|
3,821 | 1,266 | 743 | 164 | 5,994 | |||||||||||||||
|
MBoe
|
1,676 | 582 | 207 | 77 | 2,542 | |||||||||||||||
|
Change in MBoe
|
(255 | ) | (109 | ) | (13 | ) | (4 | ) | (381 | ) | ||||||||||
|
Percentage Change in MBoe
|
(15.2 | )% | (18.7 | )% | (6.3 | )% | (5.2 | )% | (15.0 | )% | ||||||||||
|
Year Ended |
||||||||||||
| December 31, | ||||||||||||
| 2010 | 2009 | Increase | ||||||||||
|
Average sale prices:
|
||||||||||||
|
Oil (per Bbl)
|
$ | 76.95 | $ | 58.24 | 32.1 | % | ||||||
|
NGL (per Bbl)
|
$ | 38.89 | $ | 27.26 | 42.7 | % | ||||||
|
Natural gas (per Mcf)
|
$ | 4.21 | $ | 3.47 | 21.3 | % | ||||||
|
Per Boe
|
$ | 51.36 | $ | 38.62 | 33.0 | % | ||||||
Oil and natural gas sales increased $12.8 million, or 13%,
to $111.0 million for the year ended December 31,
2010, as compared to $98.2 million for the year ended
December 31, 2009. This increase was driven by commodity
price increases on a per Boe basis of 33% for the year ended
December 31, 2010, as compared to 2009.
Production volumes decreased 15% overall during the year ended
December 31, 2010, as compared to the year ended
December 31, 2009, primarily due to natural production
declines and weather-related interruptions. Production from our
Texas fields decreased by 255 MBoe in the current year.
Drilling activity in our Texas fields included 58 gross
(51.1 net) wells in 2010, all of which were completed as
producing wells, and three gross (3.0 net) wells in the process
of being completed at December 31, 2010. Production from
our Oklahoma fields decreased by 109 MBoe over the prior
year. Drilling activity in our Oklahoma fields included three
gross (2.9 net) wells, all of which were completed as producing,
and three gross (2.8 net) wells waiting on completion at
December 31, 2010. Production from our Louisiana fields
decreased by 13 MBoe over the prior year. Drilling activity
in our Louisiana fields included
43
Table of Contents
one gross (0.2 net) well, which was a dry hole, in 2010. Lower
development capital expenditures resulted in decreased
production in 2010 from natural production declines not offset
by increased drilling. After adjusting our 2010 production by
the contribution made by the properties sold in December 2010,
we expect production from our remaining properties to remain
relatively constant in 2011 with the exception of South Texas
which is mainly gas and will continue to have declining
production until prices improve.
The average realized sales price for oil was $76.95 per barrel
for the year ended December 31, 2010, an increase of 32%,
compared to $58.24 per barrel for 2009. The average realized
sales price for NGLs was $38.89 for the year ended
December 31, 2010, an increase of 43%, compared to $27.26
per barrel for 2009. The average realized sales price for
natural gas was $4.21 per Mcf for the year ended
December 31, 2010, an increase of 21%, compared to $3.47
per Mcf for 2009.
Realized and Unrealized Gain (Loss) from
Derivatives. For the year ended December 31,
2010, our gain from derivatives was $1.2 million compared
to a loss of $11.3 million for the year ended
December 31, 2009. Our gains and losses for these periods
were the net result of recording actual contract settlements,
the premiums paid for our derivative contracts, and unrealized
gains and losses attributable to
mark-to-market
values of our derivative contracts at the end of the periods.
The significant shift from 2009 to 2010 was primarily a result
of higher market prices in the 2010 period.
| Year Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
| (In thousands) | ||||||||
|
Contract settlements and premium costs:
|
||||||||
|
Oil
|
$ | (6,110 | ) | $ | 5,626 | |||
|
Natural gas
|
917 | 13,629 | ||||||
|
Realized gains (losses)
|
(5,193 | ) | 19,255 | |||||
|
Mark-to-market
gains (losses):
|
||||||||
|
Oil
|
4,817 | (23,724 | ) | |||||
|
Natural gas
|
1,569 | (6,837 | ) | |||||
|
Unrealized gains (losses)
|
6,386 | (30,561 | ) | |||||
|
Realized and unrealized gains (losses)
|
$ | 1,193 | $ | (11,306 | ) | |||
Oil and Natural Gas Production Taxes. Our oil
and natural gas production taxes were $6.1 million for the
year ended December 31, 2010, compared to $5.3 million
for the year ended December 31, 2009, due primarily to
higher commodity prices during the 2010 period. Production taxes
vary by state. Most are based on realized prices at the
wellhead, while Louisiana production tax is based on volumes for
natural gas and value for oil. As revenues or volumes from oil
and natural gas sales increase or decrease, production taxes on
these sales also increase or decrease directly. As a percentage
of oil and natural gas sales, oil and natural gas production
taxes were 5% for the year ended December 31, 2010 and 2009.
Oil and Natural Gas Production Expense. Our
oil and natural gas production expense was $33.9 million
for the year ended December 31, 2010, a decrease of
$3.6 million, or 10%, from the $37.5 million for the
year ended December 31, 2009, due primarily to cost-saving
measures implemented in 2010. For the year ended
December 31, 2010, our oil and natural gas production
expense was $15.68 per Boe compared to $14.73 per Boe for the
year ended December 31, 2009, an increase of 6%.
Depreciation and Amortization Expense. Our
depreciation and amortization expense decreased
$4.4 million, or 14%, for the year ended December 31,
2010, compared to the year ended December 31, 2009. The
decrease was a result of a decrease in production during 2010,
partially offset by a higher depletion rate per Boe. On an
equivalent basis, our amortization of the full-cost pool of
$26.2 million was $12.11 per Boe for the year ended
December 31, 2010, an increase of less than 1% per Boe
compared to $30.7 million, or $12.06 per Boe for the year
ended December 31, 2009.
44
Table of Contents
Accretion Expense. Topic 410 of the
Codification includes, among other things, the accounting for
asset retirement obligations. Accretion expense is a function of
changes in the discounted liability from period to period. We
recorded $1.5 million for the year ended December 31,
2010, compared to $2.0 million for the year ended
December 31, 2009.
Impairment Charge. For the year ended
December 31, 2010, we incurred no impairment charges. We
incurred a $47.6 million impairment on the carrying value
of our oil and gas properties for the year ended
December 31, 2009. The impairment of our oil and gas
properties was primarily due to a reduction in the tax affected
estimated present value of future net revenues, caused by
dramatic decline in natural gas prices, from our proved oil and
gas reserves between December 31, 2008, and March 31,
2009.
Share-Based Compensation. From time to time,
our board of directors grants restricted stock awards under our
2006 Long-Term Incentive Plan. Each of these grants vests in
equal increments over the vesting period provided for the
particular award. All currently unvested awards provide for
vesting periods of from one to five years. The share-based
compensation expense related to these grants is calculated using
the closing price per share on each of the grant dates and the
total share-based compensation on all these grants will be
recognized over their respective vesting periods. For the year
ended December 31, 2010, we recorded a total of
$3.1 million share-based compensation expense compared to
$2.2 million for the year ended December 31, 2009. The
increase in share-based compensation expense was primarily due
to additional grants and increased stock price during the 2010
period.
General and Administrative Expense. For the
year ended December 31, 2010, our general and
administrative expense was $14.8 million, compared to
$16.7 million for the year ended December 31, 2009, a
decrease of $1.9 million, or 11%. The decrease is primarily
due to decreased professional fees and lower employee-related
costs in 2010.
Interest Expense. We recorded interest expense
of $22.7 million for the year ended December 31, 2010,
compared to $18.6 million incurred during the previous
year. Interest rates were higher in 2010 compared to 2009 due to
the Second Amendment to our credit facility executed
June 26, 2009. Our blended interest rate was 8.0% during
2010 compared to 7.6% in the 2009 period. As a result of higher
interest rates for the period, our interest expense increased by
$4.1 million for the year ended December 31, 2010,
compared to 2009.
Other Income (Expense). Our other income was
$0.3 million in 2010 compared to other expense of
$0.4 million in 2009. For the year ended December 31,
2010, we reduced a contingency accrual by $0.6 million
related to settlement of pending litigation offset by a charge
relating to pipe inventory write-off. For the year ended
December 31, 2009, we recorded $0.4 million charge to
other expense primarily for expenses related to settlement of
pending litigation.
Income Taxes. For the year ended
December 31, 2010, we recorded an income tax provision of
$1.0 million on a pre-tax income of $3.4 million. The
income tax provision for 2010 included a $5.7 million
decrease to deferred tax assets under Section 382 of the
Internal Revenue Code related to net operating loss limitations
and a decrease in the valuation allowance of $6.6 million
for revisions to future taxable income projections. For the year
ended December 31, 2009, we recorded an income tax benefit
of $16.3 million on a pre-tax loss of $74.7 million.
Included in the income tax benefit for 2009 is an increase in
valuation allowance of $9.5 million to reflect our estimate
of reduced tax benefits expected to be realized from net
deferred tax assets of the company. The effective tax rates for
the year ended December 31, 2010 and 2009, were 29.2% and
21.9%, respectively.
45
Table of Contents
Year
Ended December 31, 2009 Compared to the Year Ended
December 31, 2008
The following tables summarize our oil and natural gas
production volumes (in thousands), average sale prices and
comparisons for the years ended December 31, 2009 and 2008:
| Texas | Oklahoma | Louisiana | Other | Total | ||||||||||||||||
|
Year Ended December 31, 2009
|
||||||||||||||||||||
|
Aggregate Net Production
|
||||||||||||||||||||
|
Oil (MBbls)
|
664 | 356 | 83 | 35 | 1,138 | |||||||||||||||
|
NGLs (MBbls)
|
375 | 15 | — | 16 | 406 | |||||||||||||||
|
Natural Gas (MMcf)
|
3,821 | 1,266 | 743 | 164 | 5,994 | |||||||||||||||
|
MBoe
|
1,676 | 582 | 207 | 77 | 2,542 | |||||||||||||||
|
Year Ended December 31, 2008
|
||||||||||||||||||||
|
Aggregate Net Production
|
||||||||||||||||||||
|
Oil (MBbls)
|
683 | 406 | 54 | 44 | 1,187 | |||||||||||||||
|
NGLs (MBbls)
|
338 | 14 | — | 2 | 354 | |||||||||||||||
|
Natural Gas (MMcf)
|
4,039 | 1,050 | 730 | 263 | 6,082 | |||||||||||||||
|
MBoe
|
1,693 | 595 | 176 | 90 | 2,554 | |||||||||||||||
|
Change in MBoe
|
(17 | ) | (13 | ) | 31 | (13 | ) | (12 | ) | |||||||||||
|
Percentage Change in MBoe
|
(1.0 | )% | (2.2 | )% | 17.6 | % | (14.4 | )% | (0.5 | )% | ||||||||||
|
Year Ended |
||||||||||||
| December 31, | ||||||||||||
| 2009 | 2008 | (Decrease) | ||||||||||
|
Average sale prices:
|
||||||||||||
|
Oil (per Bbl)
|
$ | 58.24 | $ | 98.59 | (40.9 | )% | ||||||
|
NGL (per Bbl)
|
$ | 27.26 | $ | 50.24 | (45.7 | )% | ||||||
|
Natural gas (per Mcf)
|
$ | 3.47 | $ | 7.87 | (55.9 | )% | ||||||
|
Per Boe
|
$ | 38.62 | $ | 71.52 | (46.0 | )% | ||||||
Oil and natural gas sales decreased $84.5 million, or 46%,
to $98.2 million for the year ended December 31, 2009,
as compared to $182.7 million for the year ended
December 31, 2008. This decrease was driven by commodity
price decreases, which on a per Boe basis declined 46% for the
year ended December 31, 2009, as compared to 2008.
Production volumes were essentially flat during the year ended
December 31, 2009, as compared to the year ended
December 31, 2008. Texas production included our Boonsville
and Barnett Shale fields, both in North Texas, which increased
by 67 MBoe and 74 MBoe, respectively, in 2009 as
compared to the prior year. Drilling activity in 2009 included
one gross (one net) well in Boonsville and two gross (0.4 net)
wells on our Tier 1 Barnett Shale acreage, with one gross
(0.4 net) well completed as a producing well and one gross (0.04
net) well in the process of being completed at December 31,
2009. Offsetting production declines included our
Electra/Burkburnett field in North Texas and our South Texas
field, which decreased by 44 MBoe and 59 MBoe,
respectively, in 2009 as compared to 2008 primarily as a result
of normal production declines and a reduced pace of drilling in
those fields. We drilled 39 gross (39.0 net) wells in
Electra/Burkburnett in 2009.
The average realized sales price for oil was $58.24 per barrel
for the year ended December 31, 2009, a decrease of 41%,
compared to $98.59 per barrel for 2008. The average realized
sales price for NGLs was $27.26 for the year ended
December 31, 2009, a decrease of 46%, compared to $50.24
per barrel for 2008. The average realized sales price for
natural gas was $3.47 per Mcf for the year ended
December 31, 2009, a decrease of 56%, compared to $7.87 per
Mcf for 2008.
Realized and Unrealized Gain (Loss) from
Derivatives. For the year ended December 31,
2009, our loss from derivatives was $11.3 million compared
to a gain of $22.8 million for the year ended
December 31,
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Table of Contents
2008. Our gains and losses for these periods were the net result
of recording actual contract settlements, the premiums paid for
our derivative contracts, and unrealized gains and losses
attributable to
mark-to-market
values of our derivative contracts at the end of the periods.
| Year Ended December 31, | ||||||||
| 2009 | 2008 | |||||||
| (In thousands) | ||||||||
|
Contract settlements and premium costs:
|
||||||||
|
Oil
|
$ | 5,626 | $ | (10,497 | ) | |||
|
Natural gas
|
13,629 | 25 | ||||||
|
Realized gains (losses)
|
19,255 | (10,472 | ) | |||||
|
Mark-to-market
gains (losses):
|
||||||||
|
Oil
|
(23,724 | ) | 26,590 | |||||
|
Natural gas
|
(6,837 | ) | 6,667 | |||||
|
Unrealized gains (losses)
|
(30,561 | ) | 33,257 | |||||
|
Realized and unrealized gains (losses)
|
$ | (11,306 | ) | $ | 22,785 | |||
Oil and Natural Gas Production Taxes. Our oil
and natural gas production taxes were $5.3 million for the
year ended December 31, 2009, compared to
$10.5 million for the year ended December 31, 2008,
due primarily to lower commodity prices during the 2009 period.
Production taxes vary by state. Most are based on realized
prices at the wellhead, while Louisiana production tax is based
on volumes for natural gas and value for oil. As revenues or
volumes from oil and natural gas sales increase or decrease,
production taxes on these sales also increase or decrease
directly. As a percentage of oil and natural gas sales, oil and
natural gas production taxes were 5% for the year ended
December 31, 2009, compared to 6% for the year ended
December 31, 2008.
Oil and Natural Gas Production Expense. Our
oil and natural gas production expense was $37.5 million
for the year ended December 31, 2009, a decrease of
$0.5 million, or 2%, from the $38.0 million for the
year ended December 31, 2008. For the year ended
December 31, 2009, our oil and natural gas production
expense was $14.73 per Boe compared to $14.89 per Boe for the
year ended December 31, 2008, essentially flat. As a
percentage of oil and natural gas sales, oil and natural gas
production expense was 38% for the year ended December 31,
2009, as compared to 21% for the year ended December 31,
2008. The increase is due to declining commodity prices in the
2009 period.
Depreciation and Amortization Expense. Our
depreciation and amortization expense decreased
$14.9 million, or 32%, for the year ended December 31,
2009, compared to the year ended December 31, 2008. The
decrease was a result of a lower amortization rate per Boe. On
an equivalent basis, our amortization of the full-cost pool of
$30.7 million was $12.06 per Boe for the year ended
December 31, 2009, a decrease per Boe of 33% compared to
$45.7 million, or $17.89 per Boe for the year ended
December 31, 2008. This rate decrease per Boe resulted from
lower capitalized costs subsequent to the asset impairment
writedowns in the fourth quarter of 2008 and the first quarter
of 2009.
Accretion Expense. Topic 410 of the
Codification includes, among other things, the accounting for
asset retirement obligations. Accretion expense is a function of
changes in the discounted liability from period to period. We
recorded $2.0 million for the year ended December 31,
2009, compared to $2.2 million for the year ended
December 31, 2008.
Impairment Charge. We incurred a
$47.6 million impairment on the carrying value of our oil
and gas properties for the year ended December 31, 2009, as
compared to $269.4 million for the year ended
December 31, 2008. We also incurred a $0.5 million
impairment on the carrying value of our inventory in 2008. The
impairment of our oil and gas properties was primarily due to a
reduction in the estimated present value of future net revenues
from our proved oil and gas reserves resulting from a
significant decline in commodity prices during the fourth
quarter of 2008.
47
Table of Contents
Share-Based Compensation. From time to time,
our board of directors grants restricted stock awards under our
2006 Long-Term Incentive Plan. Each of these grants vests in
equal increments over the vesting period provided for the
particular award. All currently unvested awards provide for
vesting periods of from one to five years. The share-based
compensation expense related to these grants is calculated using
the closing price per share on each of the grant dates and the
total share-based compensation on all these grants will be
recognized over their respective vesting periods. For the year
ended December 31, 2009, we recorded a total of
$2.2 million share-based compensation expense compared to
$2.6 million for the year ended December 31, 2008. The
decrease in share-based compensation expense was a result of the
accelerated vesting in the 2008 period of restricted stock
grants to John Cox, our senior vice president, who passed away
in March 2008.
General and Administrative Expense. For the
year ended December 31, 2009, our general and
administrative expense was $16.7 million, compared to
$20.3 million for the year ended December 31, 2008, a
decrease of $3.6 million, or 18%. The decrease is primarily
due to decreased professional fees and lower officer and
employee bonuses in 2009.
Interest Expense. We recorded interest expense
of $18.6 million for the year ended December 31, 2009,
compared to $24.2 million incurred during the previous
year. The decrease in interest expense was due to lower debt
balances for the 2009 period and lower effective interest rates
in the first half of 2009 compared to 2008, partially offset by
higher interest rates during the second half of 2009 due to the
Second Amendment to our credit facility executed June 26,
2009. Our debt was lower during 2009 because in the second
quarter of 2008, we used $86.6 million in realized net
proceeds from the exercise of 17,617,331 warrants in May 2008 to
pay down the term facility, and $9.4 million in cash to pay
down the revolver. Our blended interest rate was 7.6% during
2009 compared to 9.7% in the 2008 period. As a result of this
paydown and lower interest rates for the period, our interest
expense decreased by $5.6 million for the year ended
December 31, 2009, compared to 2008.
Other Expense. Our other expense was
$0.4 million in 2009 compared to $13.5 million in
2008. In 2008, we recorded a charge to other expense of
$13.5 million for litigation expense related to a legal
settlement. In September 2008, we entered into an agreement
pursuant to which we agreed to pay $16.0 million in
settlement of a pending class action lawsuit. We placed that
amount in escrow in October 2008 in anticipation of a final
court approved settlement in the second quarter of 2009. In
conjunction with our May 8, 2006 acquisition of RAM Energy,
the former stockholders of RAM Energy deposited in escrow
3,200,000 shares of their common stock to secure their
potential indemnity obligations to us, including any loss we
might sustain in this litigation or through an agreed
settlement. At December 31, 2008, we recorded a contingent
liability of $16.0 million for the settlement and a
receivable of $2.8 million representing the market value of
the escrow shares based on the closing price of $0.88 per share
on December 31, 2008. The $13.5 million charge to
other expense represents the difference between the settlement
liability and the value of the escrowed shares. On March 5,
2009, the court approved the settlement and on April 6,
2009, the settlement became final. We recorded a
$0.4 million charge to other expense in the first quarter
of 2009 representing the adjustment to fair market value of the
escrowed shares on the final settlement date of $0.74 per share.
Income Taxes. For the year ended
December 31, 2009, we recorded an income tax benefit of
$16.3 million on a pre-tax loss of $74.7 million. In
2009, we recorded an increase in valuation allowance of
$9.5 million to reflect our estimate of reduced tax
benefits expected to be realized from net deferred tax assets of
the company. For the year ended December 31, 2008, we
recorded an income tax benefit of $91.7 million on a
pre-tax loss of $221.6 million. Included in the income tax
benefit for 2008 is a $6.9 million decrease resulting from
the reversal of an uncertain tax position and related accrued
interest. The effective tax rate for the year ended
December 31, 2009 was 21.9%. Excluding the reversal of the
uncertain tax position, the effective tax rate was 38.3% for the
year ended December 31, 2008. The lower effective tax rate
in 2009 was a result of the increased valuation allowance, which
caused a decrease in deferred tax benefit.
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Table of Contents
Liquidity
and Capital Resources
As of December 31, 2010, we had $28.5 million of
nominal availability under our revolving credit facility;
however, because of the amount of our Modified EBITDA for the
preceding four fiscal quarters, the leverage ratio financial
covenant in our old credit facility limited us to
$23.7 million of additional borrowings as of
December 31, 2010. In March 2011, we entered into new
credit facilities including a $250.0 million first lien
revolving credit facility with an initial $150.0 million
borrowing base and a $75.0 million second lien term loan
facility. Under our new credit facilities, through
September 30, 2011, additional borrowings will not be
limited by the leverage ratio covenant in our revolving loan
agreement provided our Modified EBITDA for the preceding four
fiscal quarters exceeds $47.4 million. Our Modified EBITDA
for the four fiscal quarters ending December 31, 2010 was
$51.0 million. Management believes that borrowings
currently available to us under our credit facilities and
anticipated cash flows from operations will be sufficient to
satisfy our currently expected capital expenditures, working
capital, and debt service obligations through 2011. At
December 31, 2010, we had $197.1 million of
indebtedness outstanding, including $116.5 million under
our revolving credit facility, $80.2 million under our term
loan facility and $0.4 million in other indebtedness. As of
December 31, 2010, we had an accumulated deficit of
$214.9 million and a working capital deficit of
$12.4 million.
New Credit Facilities. In March 2011, we
entered into new credit facilities. The new facilities, which
replaced our previous facility, include a $250.0 million
first lien revolving credit facility and a $75.0 million
second lien term loan facility. SunTrust Bank is the
administrative agent for the revolving facility, and Guggenheim
Corporate Funding, LLC is the agent for the term loan facility.
The initial borrowing base under the revolving credit facility
at the closing is $150.0 million. Funds advanced under the
revolving credit facility may be paid down and re-borrowed
during the five-year term of the revolver, and initially bear
interest at LIBOR plus a margin ranging from 2.5% to 3.25% based
on a percentage of usage. The term loan portion of our credit
facility provides for payments of interest only during its
5.5-year term, with the initial interest rate being LIBOR plus
9.0% with a 2.0% LIBOR Floor, or if any period we elect to pay a
portion of the interest under our term loan “in kind,”
then the interest rate will be LIBOR plus 10.0% with a 2.0%
LIBOR floor, and with 7.0% of the interest amount paid in cash
and the remaining 3.0% paid in kind by being added to principal.
Advances under our credit facilities are secured by liens on
substantially all of our properties and assets. The credit
facilities contain representations, warranties and covenants
customary in transactions of this nature, including restrictions
on the payment of dividends on our capital stock and financial
covenants relating to current ratio, minimum interest coverage
ratio, maximum leverage ratio and a required ratio of asset
value to total indebtedness. We are required to maintain
commodity hedges on a rolling basis for the first 12 months
out with respect to not less than 60%, but not more than 85%,
and for the next 18 months out with respect to not less
than 50% but not more than 85%, of our projected quarterly
production volumes, until the leverage ratio is less than or
equal to 1.5 to 1.0. At December 31, 2010, our commodity
hedging represented approximately 56% of our projected
production volumes through June 30, 2013.
Our previous credit facility entered into November 2007 included
a $500.0 million credit facility with Guggenheim Corporate
Funding, LLC, for itself and on behalf of other institutional
lenders. This facility included a $250.0 million revolving
credit facility, a $200.0 million term loan facility, and
an additional $50.0 million available under the term loan
as requested by us and approved by the lenders. The entire
amount of the $200.0 million term loan was advanced at
closing. The borrowing base under our previous revolving credit
facility was $145.0 million at December 31, 2010.
Funds advanced under the revolving credit facility initially
bore interest at LIBOR plus a margin ranging from 1.25% to 2.0%
based on a percentage of usage. The term loan portion of our
credit facility initially provided for payments of interest only
during its five-year term, with the initial interest rate being
LIBOR plus 7.5%.
On June 26, 2009, we renegotiated certain terms of our
previous credit facility to provide us greater flexibility in
complying with certain of the financial covenants under the loan
agreement. In exchange for the added flexibility afforded by
these changes to the credit facility, we agreed to increase the
base cash interest rate on both the revolving credit facility
and the term loan credit facility by 1.0% per annum, establish a
LIBOR floor of 1.5% and pay an additional 2.75% per annum of
non-cash,
payment-in-kind,
or PIK, interest
49
Table of Contents
on the term portion of the facility. Accrued PIK interest was
added to the principal balance of the term loan on a monthly
basis and was paid in connection with the closing of the new
credit facilities in March 2011.
In May of 2008, we used $86.6 million in realized net
proceeds from the exercise of 17,617,331 warrants to pay down
the term facility to $113.4 million. In 2010 and 2009, we
used $33.8 million and $4.0 million, respectively, in
proceeds from asset sales to pay down the term facility. PIK
interest of $1.6 million was added to the term facility in
2009, and PIK interest of $3.0 million was added to the
term facility in 2010, bringing the balance to
$80.2 million at December 31, 2010.
Our ability to comply with the financial covenants in our new
credit facilities may be affected by events beyond our control
and, as a result, in future periods we may be unable to meet
these ratios and financial condition tests. These financial
ratio restrictions and financial condition tests could limit our
ability to obtain future financings, make needed capital
expenditures, withstand a future downturn in our business or the
economy in general or otherwise conduct necessary corporate
activities. A breach of any of these covenants or our inability
to comply with the required financial ratios or financial
condition tests could result in a default under our credit
facilities. A default, if not cured or waived, could result in
acceleration of all indebtedness outstanding under our credit
facilities. The accelerated debt would become immediately due
and payable. If that should occur, we may be unable to pay all
such debt or to borrow sufficient funds to refinance it. Even if
new financing were then available, it may not be on terms that
are acceptable to us. At December 31, 2010, we were in
compliance with all of the financial covenants under our credit
facility.
Cash Flow From Operating Activities. Our cash
flow from operating activities is comprised of three main items:
net income (loss), adjustments to reconcile net income to cash
provided (used) before changes in working capital, and changes
in working capital. For the year ended December 31, 2010,
our net income was $2.4 million, as compared to a net loss
of $58.4 million for the year ended December 31, 2009.
Adjustments (primarily non-cash items such as asset impairment
charge, depreciation and amortization, unrealized gain or loss
on derivatives, deferred income taxes and legal contingency
expense) were $35.5 million for the year ended
December 31, 2010, compared to $102.4 million for the
year of 2009, a decrease of $66.9 million. Asset impairment
charge, depreciation and amortization, legal contingency expense
and change in unrealized (gains) losses, offset by change in
deferred income taxes caused most of this decrease. Working
capital changes for the year ended December 31, 2010, were
a negative $0.05 million compared with negative changes of
$11.7 million for the year ended December 31, 2009.
For the year ended December 31, 2010, in total, net cash
provided by operating activities was $37.9 million compared
to $32.4 million of net cash provided by operations for the
previous year.
Cash Flow From Investing Activities. For the
year ended December 31, 2010, net cash provided by our
investing activities consisted of $49.4 million in proceeds
from sales of oil and natural gas properties and other
equipment, offset by $34.4 million in payments for oil and
gas properties and other equipment. For the year ended
December 31, 2009, net cash used in our investing
activities was $23.9 million. The change is primarily due
to property divestitures in 2010 in conjunction with the
execution of our strategic alternative initiative to reduce debt.
Cash Flow From Financing Activities. For the
year ended December 31, 2010, net cash used in our
financing activities was $52.9 million, compared to net
cash used of $8.5 million for the year ended
December 31, 2009. The cash used in 2010 included
$52.1 million in net payments on long-term debt and
$0.8 million for stock withheld to cover employee income
taxes on the vesting of stock under our 2006 Long-Term Incentive
Plan.
Capital
Commitments
During 2010, we had capital expenditures of $33.5 million
relating to our oil and natural gas operations, of which
$27.9 million was allocated to drilling new development
wells and recompletion operations in existing wells,
$4.5 million was for exploration costs, and
$1.1 million was for acquisition costs.
We have budgeted $35.0 million for non-acquisition capital
expenditures in 2011 related to:
| • | developmental drilling and recompletions ($18.0 million); |
50
Table of Contents
| • | exploration, including leasehold acquisition, seismic and exploratory drilling ($9.0 million); and | |
| • | geological, geophysical and contingencies ($8.0 million). |
In our 2011 non-acquisition capital budget, we have allocated
$8.0 million for continued development of our
Electra/Burkburnett area, $2.0 million for drilling on our
South Texas properties and $8.0 million for reworking and
production enhancement operations in our mature fields,
including our Fitts and Allen fields in Oklahoma.
The amount and timing of our capital expenditures for calendar
year 2011 may vary depending on a number of factors,
including prevailing market prices for oil and natural gas, the
favorable or unfavorable results of operations actually
conducted, projects proposed by third party operators on jointly
owned acreage, development by third party operators on adjoining
properties, rig and service company availability, and other
influences that we cannot predict.
Although we cannot provide any assurance, assuming successful
implementation of our strategy, including the future development
of our proved reserves and realization of our cash flows as
anticipated, we believe that cash flows from operations and the
availability under our revolving credit facility will be
sufficient to satisfy our budgeted non-acquisition capital
expenditures, working capital and debt service obligations for
2011. The actual amount and timing of our future capital
requirements may differ materially from our estimates as a
result of, among other things, changes in product pricing and
regulatory, technological and competitive developments. Sources
of additional financing available to us may include commercial
bank borrowings, vendor financing and the sale of equity or debt
securities. We cannot provide any assurance that any such
financing will be available on acceptable terms or at all.
The credit markets are undergoing significant volatility. Many
financial institutions have liquidity concerns, prompting
government intervention to mitigate pressure on the credit
markets. Our exposure to the current credit market crisis
includes our revolving credit facility, counterparty risks
related to our trade credit and risks related to our cash
investments.
Our new revolving credit facility matures in March 2016. Our
term loan facility matures in September 2016. Should the current
tightness in the credit markets continue, future extensions of
our credit facilities may contain terms that are less favorable
than those of our current credit facility.
Current market conditions also elevate the concern over our cash
deposits, which totaled approximately $0.04 million at
December 31, 2010, but fluctuate throughout the year, and
counterparty risks related to our trade credit. Our cash
accounts and deposits with any financial institution that exceed
the amount insured by the Federal Deposit Insurance Corporation
are at risk in the event one of these financial institutions
fails. We sell our crude oil, natural gas and NGLs to a variety
of purchasers. Some of these parties are not as creditworthy as
we are and may experience liquidity problems. Nonperformance by
a trade creditor could result in losses.
The table below sets forth our contractual cash obligations as
of December 31, 2010:
| Total | 2011 | 2012-2013 | 2014-2015 | and after | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Contractual Cash Obligations
|
||||||||||||||||||||
|
Long-term debt
|
$ | 197,092 | $ | 127 | $ | 167 | $ | 56 | $ | 196,742 | ||||||||||
|
Operating leases
|
3,462 | 1,189 | 2,213 | 60 | — | |||||||||||||||
|
Total contractual cash obligations
|
$ | 200,554 | $ | 1,316 | $ | 2,380 | $ | 116 | $ | 196,742 | ||||||||||
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
The carrying amounts reported in our consolidated balance sheets
for cash and cash equivalents, trade receivables and payables,
installment notes and variable rate long-term debt approximate
their fair values.
51
Table of Contents
Interest
Rate Sensitivity
We are exposed to changes in interest rates. Changes in interest
rates affect the interest earned on our cash and cash
equivalents and the interest rate paid on our borrowings. We
have not used interest rate derivative instruments to manage our
exposure to interest rate changes.
Our long-term debt as of December 31, 2010, is denominated
in U.S. dollars. Our debt has been issued at variable
rates, and as such, interest expense would be impacted by
interest rate shifts. Under our old credit facility, the impact
of a 100-basis point increase in LIBOR interest rates above the
then current floor of 1.5% would have resulted in an increase in
interest expense of $2.0 million annually based on the
$196.7 million balance of our credit facility as of
December 31, 2010. A 100-basis point decrease would have
had no effect on interest expense until the market rate of LIBOR
increased above the then current floor of 1.5%. The new
revolving credit facility entered into March 2011 is not subject
to LIBOR floors, and the impact of a 100-basis point increase in
LIBOR interest rates would have resulted in an increase in
interest expense of approximately $1.2 million annually
based on the $116.5 million balance of our revolver as of
December 31, 2010. LIBOR rates were less than 100-basis
points as of December 31, 2010, so any decrease in interest
rates would have resulted in a nominal decrease in interest
expense under our revolver as of December 31, 2010. The
term loan portion of our new credit facility includes a 2.0%
LIBOR floor. The impact of a 100-basis point increase in LIBOR
rates above our 2.0% floor would result in an increase in
interest expense under our term loan of $0.8 million
annually based on the $80.2 million balance of our term
loan as of December 31, 2010.
A 100-basis
point decrease would have no effect on interest expense under
our term loan until the LIBOR rate exceeds 2.0%.
Commodity
Price Risk
Our revenue, profitability and future growth depend
substantially on prevailing prices for oil and natural gas.
Prices also affect the amount of cash flow available for capital
expenditures and our ability to borrow and raise additional
capital. Lower prices may also reduce the amount of oil and
natural gas that we can economically produce. We currently sell
most of our oil and natural gas production under market price
contracts.
To reduce exposure to fluctuations in oil and natural gas prices
and to achieve more predictable cash flow, and as required by
our lenders, we utilize various derivative strategies to manage
the price received for a portion of our future oil and natural
gas production. We have not established derivatives that create
potential liability to us covering volumes in excess of our
expected production.
Our derivative positions at December 31, 2010, consisting
of put/call “collars” and put options, also called
“bare floors” as they provide a floor price without a
corresponding ceiling, are shown in the following table:
| Crude Oil (Bbls) | Natural Gas (Mmbtu) | |||||||||||||||||||||||||||||||||||
| Floors | Ceilings | Floors | Ceilings | |||||||||||||||||||||||||||||||||
|
Per |
Per |
Per |
Per |
|||||||||||||||||||||||||||||||||
| Day(1) | Price | Day(1) | Price |
Months Covered
|
Day(1) | Price | Day(1) | Price |
Months Covered
|
|||||||||||||||||||||||||||
|
Collars
|
||||||||||||||||||||||||||||||||||||
|
2011
|
1,921 | $ | 80.00 | 1,921 | $ | 105.00 | April — December | 6,219 | $ | 5.00 | 6,219 | $ | 9.48 | January — September | ||||||||||||||||||||||
|
2012
|
995 | $ | 80.00 | 995 | $ | 105.00 | January — June | — | $ | — | — | $ | — | |||||||||||||||||||||||
| Bare Floors | Bare Floors | |||||||||||||||||||
|
Per |
Per |
|||||||||||||||||||
| Day(1) | Price |
Months Covered
|
Day(1) | Price |
Months Covered
|
|||||||||||||||
|
Year
|
||||||||||||||||||||
|
2011
|
1,177 | $ | 60.00 | January — September | 1,841 | $ | 4.18 | October — December | ||||||||||||
|
2012
|
— | $ | — | 2,486 | $ | 4.25 | January — March | |||||||||||||
| (1) | Per day amounts are calculated based on a 365-day year for 2011 and on a 366-day year for 2012. |
52
Table of Contents
Based on December 31, 2010, NYMEX forward curves of natural
gas and crude oil futures prices, adjusted for volatility by
67.5 basis points, we would expect to receive future cash
payments of $1.1 million under our natural gas and crude
oil derivative arrangements as they mature. If future prices of
natural gas and crude oil were to decline by 10%, we would
expect to receive future cash payments under our natural gas and
crude oil derivative arrangements of $7.0 million, and if
future prices were to increase by 10%, we would pay future cash
payments of $5.6 million.
53
Table of Contents
| Item 8. | Financial Statements and Supplementary Data |
INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS
| Page | ||||
|
RAM Energy Resources, Inc.
|
||||
| 55 | ||||
| 56 | ||||
| 57 | ||||
| 58 | ||||
| 59 | ||||
| 61 | ||||
54
Table of Contents
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
RAM Energy Resources, Inc.
We have audited the accompanying consolidated balance sheets of
RAM Energy Resources, Inc. (a Delaware corporation) and
subsidiaries (the “Company”) as of December 31,
2010 and 2009, and the related consolidated statements of
operations, stockholders’ equity (deficit) and cash flows
for each of the three years in the period ended
December 31, 2010. These consolidated financial statements
are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audits to obtain
reasonable assurance about whether the consolidated financial
statements are free of material misstatement. An audit 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 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 presently fairly, in all material respects, the
consolidated financial position of RAM Energy Resources, Inc.
and subsidiaries at December 31, 2010 and 2009, and the
consolidated results of their operations and their cash flows
for each of the three years in the period ended
December 31, 2010, in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note A to the consolidated financial
statements, in 2009, the Company adopted SEC Release
33-8995 and
the amendments to ASC Topic 932, “Extractive
Industries — Oil and Gas,” resulting from ASU
2010-03
(collectively, the Modernization Rules).
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of RAM Energy Resources, Inc. and
subsidiaries’ internal control over financial reporting as
of December 31, 2010, based on criteria established in
Internal Control — Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated March 16, 2011
expressed an unqualified opinion on the effective operation of
internal control over financial reporting.
/s/ UHY
LLP
Houston, Texas
March 16, 2011
55
Table of Contents
RAM
Energy Resources, Inc.
(In
thousands, except share and per share amounts)
| As of December 31, | ||||||||
| 2010 | 2009 | |||||||
|
ASSETS
|
||||||||
|
CURRENT ASSETS:
|
||||||||
|
Cash and cash equivalents
|
$ | 37 | $ | 129 | ||||
|
Accounts receivable:
|
||||||||
|
Oil and natural gas sales, net of allowance of $50 ($50 at
December 31, 2009)
|
9,797 | 12,585 | ||||||
|
Joint interest operations, net of allowance of $479 ($641 at
December 31, 2009)
|
631 | 1,303 | ||||||
|
Other, net of allowance of $48 ($48 at December 31, 2009)
|
155 | 193 | ||||||
|
Derivative assets
|
1,340 | — | ||||||
|
Prepaid expenses
|
1,657 | 1,970 | ||||||
|
Deferred tax asset
|
3,526 | 3,531 | ||||||
|
Inventory
|
3,382 | 3,900 | ||||||
|
Other current assets
|
4 | 27 | ||||||
|
Total current assets
|
20,529 | 23,638 | ||||||
|
PROPERTIES AND EQUIPMENT, AT COST:
|
||||||||
|
Proved oil and natural gas properties and equipment, using full
cost accounting
|
689,472 | 702,502 | ||||||
|
Other property and equipment
|
10,072 | 9,337 | ||||||
| 699,544 | 711,839 | |||||||
|
Less accumulated depreciation, amortization and impairment
|
(489,634 | ) | (462,541 | ) | ||||
|
Total properties and equipment
|
209,910 | 249,298 | ||||||
|
OTHER ASSETS:
|
||||||||
|
Deferred tax asset
|
31,001 | 31,573 | ||||||
|
Deferred loan costs, net of accumulated amortization of $5,012
($2,924 at December 31, 2009)
|
2,609 | 4,697 | ||||||
|
Other
|
952 | 1,956 | ||||||
|
Total assets
|
$ | 265,001 | $ | 311,162 | ||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) | ||||||||
|
CURRENT LIABILITIES:
|
||||||||
|
Accounts payable:
|
||||||||
|
Trade
|
$ | 17,149 | $ | 15,697 | ||||
|
Oil and natural gas proceeds due others
|
9,414 | 10,113 | ||||||
|
Other
|
452 | 636 | ||||||
|
Accrued liabilities:
|
||||||||
|
Compensation
|
1,948 | 2,664 | ||||||
|
Interest
|
2,448 | 2,933 | ||||||
|
Income taxes
|
699 | 655 | ||||||
|
Other
|
10 | 10 | ||||||
|
Derivative liabilities
|
— | 4,471 | ||||||
|
Asset retirement obligations
|
639 | 711 | ||||||
|
Long-term debt due within one year
|
127 | 126 | ||||||
|
Total current liabilities
|
32,886 | 38,016 | ||||||
|
DERIVATIVE LIABILITIES
|
203 | 358 | ||||||
|
LONG-TERM DEBT
|
196,965 | 246,041 | ||||||
|
ASSET RETIREMENT OBLIGATIONS
|
30,770 | 26,363 | ||||||
|
OTHER LONG-TERM LIABILITIES
|
10 | 10 | ||||||
|
COMMITMENTS AND CONTINGENCIES
|
— | 900 | ||||||
|
STOCKHOLDERS’ EQUITY (DEFICIT):
|
||||||||
|
Common stock, $0.0001 par value, 100,000,000 shares
authorized, 82,597,829 and 80,748,674 shares issued,
78,386,983 and 76,951,883 shares outstanding at
December 31, 2010 and 2009, respectively
|
8 | 8 | ||||||
|
Additional paid-in capital
|
226,042 | 222,979 | ||||||
|
Treasury stock — 4,210,846 shares
(3,796,791 shares at December 31, 2009) at cost
|
(6,976 | ) | (6,189 | ) | ||||
|
Accumulated deficit
|
(214,907 | ) | (217,324 | ) | ||||
|
Stockholders’ equity (deficit)
|
4,167 | (526 | ) | |||||
|
Total liabilities and stockholders’ equity (deficit)
|
$ | 265,001 | $ | 311,162 | ||||
The accompanying notes are an integral part of these
consolidated financial statements.
56
Table of Contents
RAM
Energy Resources, Inc.
(In
thousands, except share and per share amounts)
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
REVENUES AND OTHER OPERATING INCOME:
|
||||||||||||
|
Oil and natural gas sales
|
||||||||||||
|
Oil
|
$ | 76,563 | $ | 66,281 | $ | 117,036 | ||||||
|
Natural gas
|
20,265 | 20,818 | 47,884 | |||||||||
|
NGLs
|
14,156 | 11,068 | 17,770 | |||||||||
|
Total oil and natural gas sales
|
110,984 | 98,167 | 182,690 | |||||||||
|
Realized gains (losses) on derivatives
|
(5,193 | ) | 19,255 | (10,472 | ) | |||||||
|
Unrealized gains (losses) on derivatives
|
6,386 | (30,561 | ) | 33,257 | ||||||||
|
Other
|
157 | 217 | 382 | |||||||||
|
Total revenues and other operating income
|
112,334 | 87,078 | 205,857 | |||||||||
|
OPERATING EXPENSES:
|
||||||||||||
|
Oil and natural gas production taxes
|
6,063 | 5,320 | 10,480 | |||||||||
|
Oil and natural gas production expenses
|
33,891 | 37,455 | 38,030 | |||||||||
|
Depreciation and amortization
|
27,225 | 31,650 | 46,512 | |||||||||
|
Accretion expense
|
1,527 | 1,976 | 2,207 | |||||||||
|
Impairment
|
— | 47,613 | 269,886 | |||||||||
|
Share-based compensation
|
3,110 | 2,179 | 2,563 | |||||||||
|
General and administrative, overhead and other expenses, net of
operator’s overhead fees
|
14,799 | 16,667 | 20,305 | |||||||||
|
Total operating expenses
|
86,615 | 142,860 | 389,983 | |||||||||
|
Operating income (loss)
|
25,719 | (55,782 | ) | (184,126 | ) | |||||||
|
OTHER INCOME (EXPENSE):
|
||||||||||||
|
Interest expense
|
(22,655 | ) | (18,590 | ) | (24,182 | ) | ||||||
|
Interest income
|
27 | 82 | 208 | |||||||||
|
Other income (expense)
|
321 | (440 | ) | (13,536 | ) | |||||||
|
INCOME (LOSS) BEFORE INCOME TAXES
|
3,412 | (74,730 | ) | (221,636 | ) | |||||||
|
INCOME TAX PROVISION (BENEFIT)
|
995 | (16,347 | ) | (91,683 | ) | |||||||
|
Net income (loss)
|
$ | 2,417 | $ | (58,383 | ) | $ | (129,953 | ) | ||||
|
BASIC INCOME (LOSS) PER SHARE
|
$ | 0.03 | $ | (0.75 | ) | $ | (1.80 | ) | ||||
|
BASIC WEIGHTED AVERAGE SHARES OUTSTANDING
|
78,426,179 | 77,601,057 | 72,234,750 | |||||||||
|
DILUTED INCOME (LOSS) PER SHARE
|
$ | 0.03 | $ | (0.75 | ) | $ | (1.80 | ) | ||||
|
DILUTED WEIGHTED AVERAGE SHARES OUTSTANDING
|
78,426,179 | 77,601,057 | 72,234,750 | |||||||||
The accompanying notes are an integral part of these
consolidated financial statements.
57
Table of Contents
RAM
Energy Resources, Inc.
Consolidated Statements of Stockholders’ Equity (Deficit)
Years ended December 31, 2010, 2009, and 2008
(In thousands, except share amounts)
Consolidated Statements of Stockholders’ Equity (Deficit)
Years ended December 31, 2010, 2009, and 2008
(In thousands, except share amounts)
|
Additional |
Stockholders’ |
|||||||||||||||||||||||||||
| Common Stock |
Paid-In |
Treasury Stock |
Accumulated |
Equity |
||||||||||||||||||||||||
| Shares | Amount | Capital | Shares | Amount | Deficit | (Deficit) | ||||||||||||||||||||||
|
BALANCE, January 1, 2008
|
60,842,836 | $ | 6 | $ | 131,625 | 889,666 | $ | (3,945 | ) | $ | (28,988 | ) | $ | 98,698 | ||||||||||||||
|
Long term incentive plan grants
|
1,104,800 | — | — | — | — | — | — | |||||||||||||||||||||
|
Long term incentive plan forfeitures
|
(141,393 | ) | — | — | — | — | — | — | ||||||||||||||||||||
|
Net loss
|
— | — | — | — | — | (129,953 | ) | (129,953 | ) | |||||||||||||||||||
|
Warrants exercised
|
17,617,331 | 2 | 86,612 | — | — | — | 86,614 | |||||||||||||||||||||
|
Repurchase of stock
|
— | — | — | 1,774 | (82 | ) | — | (82 | ) | |||||||||||||||||||
|
Share-based compensation
|
— | — | 2,563 | — | — | — | 2,563 | |||||||||||||||||||||
|
BALANCE, December 31, 2008
|
79,423,574 | 8 | 220,800 | 891,440 | (4,027 | ) | (158,941 | ) | 57,840 | |||||||||||||||||||
|
Long term incentive plan grants
|
1,343,000 | — | — | — | — | — | — | |||||||||||||||||||||
|
Long term incentive plan forfeitures
|
(17,900 | ) | — | — | — | — | — | — | ||||||||||||||||||||
|
Net loss
|
— | — | — | — | — | (58,383 | ) | (58,383 | ) | |||||||||||||||||||
|
Repurchase of stock
|
— | — | — | 21,541 | (28 | ) | — | (28 | ) | |||||||||||||||||||
|
Receipt of common stock for settlement of contingent receivable
|
— | — | — | 2,883,810 | (2,134 | ) | — | (2,134 | ) | |||||||||||||||||||
|
Share-based compensation
|
— | — | 2,179 | — | — | — | 2,179 | |||||||||||||||||||||
|
BALANCE, December 31, 2009
|
80,748,674 | 8 | 222,979 | 3,796,791 | (6,189 | ) | (217,324 | ) | (526 | ) | ||||||||||||||||||
|
Long term incentive plan grants
|
1,871,655 | — | — | — | — | — | — | |||||||||||||||||||||
|
Long term incentive plan forfeitures
|
(22,500 | ) | — | — | — | — | — | — | ||||||||||||||||||||
|
Net income
|
— | — | — | — | — | 2,417 | 2,417 | |||||||||||||||||||||
|
Repurchase of stock
|
— | — | — | 414,055 | (787 | ) | — | (787 | ) | |||||||||||||||||||
|
Share-based compensation
|
— | — | 3,063 | — | — | — | 3,063 | |||||||||||||||||||||
|
BALANCE, December 31, 2010
|
82,597,829 | $ | 8 | $ | 226,042 | 4,210,846 | $ | (6,976 | ) | $ | (214,907 | ) | $ | 4,167 | ||||||||||||||
The accompanying notes are an integral part of these
consolidated financial statements.
58
Table of Contents
RAM
Energy Resources, Inc.
(In
thousands)
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
OPERATING ACTIVITIES:
|
||||||||||||
|
Net income (loss)
|
$ | 2,417 | $ | (58,383 | ) | $ | (129,953 | ) | ||||
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities-
|
||||||||||||
|
Depreciation and amortization
|
27,225 | 31,650 | 46,512 | |||||||||
|
Amortization of deferred loan costs
|
2,088 | 1,642 | 1,197 | |||||||||
|
Non-cash interest
|
3,086 | 1,605 | — | |||||||||
|
Accretion expense
|
1,527 | 1,976 | 2,207 | |||||||||
|
Impairment
|
— | 47,613 | 269,886 | |||||||||
|
Unrealized (gain) loss on derivatives, net of premium
amortization
|
(1,498 | ) | 32,147 | (31,762 | ) | |||||||
|
Deferred income tax provision (benefit)
|
577 | (16,865 | ) | (92,595 | ) | |||||||
|
Other expense (income)
|
(574 | ) | 448 | 13,184 | ||||||||
|
Share-based compensation
|
3,110 | 2,179 | 2,563 | |||||||||
|
Loss (gain) on disposal of other property, equipment and
subsidiary
|
(38 | ) | 35 | 180 | ||||||||
|
Undistributed losses on investment
|
— | — | 165 | |||||||||
|
Changes in operating assets and liabilities, net of acquisitions-
|
||||||||||||
|
Accounts receivable
|
3,704 | (650 | ) | 4,168 | ||||||||
|
Prepaid expenses, inventory and other assets
|
1,857 | 905 | (4,283 | ) | ||||||||
|
Derivative premiums
|
(4,468 | ) | (1,781 | ) | (2,288 | ) | ||||||
|
Accounts payable and proceeds due others
|
543 | (10,641 | ) | 14,606 | ||||||||
|
Accrued liabilities and other
|
(1,527 | ) | (15,387 | ) | (3,124 | ) | ||||||
|
Restricted cash
|
— | 16,000 | (16,000 | ) | ||||||||
|
Income taxes payable
|
44 | 256 | 231 | |||||||||
|
Asset retirement obligations
|
(198 | ) | (377 | ) | (440 | ) | ||||||
|
Total adjustments
|
35,458 | 90,755 | 204,407 | |||||||||
|
Net cash provided by operating activities
|
37,875 | 32,372 | 74,454 | |||||||||
|
INVESTING ACTIVITIES:
|
||||||||||||
|
Payments for oil and natural gas properties and equipment
|
(33,535 | ) | (29,871 | ) | (84,723 | ) | ||||||
|
Proceeds from sales of oil and natural gas properties
|
49,366 | 6,120 | 2,950 | |||||||||
|
Payments for other property and equipment
|
(865 | ) | (604 | ) | (1,275 | ) | ||||||
|
Proceeds from sales of other property and equipment
|
4 | 434 | 23 | |||||||||
|
Proceeds from sale of subsidiary, net of cash
|
— | — | 308 | |||||||||
|
Acquisition of Ascent, net of cash acquired
|
— | — | 35 | |||||||||
|
Other investments
|
— | — | 114 | |||||||||
|
Net cash provided by (used in) investing activities
|
14,970 | (23,921 | ) | (82,568 | ) | |||||||
|
FINANCING ACTIVITIES:
|
||||||||||||
|
Payments on long-term debt
|
(98,490 | ) | (36,156 | ) | (175,306 | ) | ||||||
|
Proceeds from borrowings on long-term debt
|
46,340 | 30,022 | 90,253 | |||||||||
|
Payments for deferred loan costs
|
— | (2,324 | ) | (74 | ) | |||||||
|
Stock repurchased
|
(787 | ) | (28 | ) | (82 | ) | ||||||
|
Warrants exercised
|
— | — | 86,614 | |||||||||
|
Net cash provided by (used in) financing activities
|
(52,937 | ) | (8,486 | ) | 1,405 | |||||||
|
DECREASE IN CASH AND CASH EQUIVALENTS
|
(92 | ) | (35 | ) | (6,709 | ) | ||||||
|
CASH AND CASH EQUIVALENTS, beginning of year
|
129 | 164 | 6,873 | |||||||||
|
CASH AND CASH EQUIVALENTS, end of year
|
$ | 37 | $ | 129 | $ | 164 | ||||||
The accompanying notes are an integral part of these
consolidated financial statements.
59
Table of Contents
RAM
Energy Resources, Inc.
Consolidated
Statements of Cash Flows (continued)
(In
thousands)
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
SUPPLEMENTAL CASH FLOW INFORMATION:
|
||||||||||||
|
Cash paid for income taxes
|
$ | 380 | $ | 303 | $ | 682 | ||||||
|
Cash paid for interest
|
$ | 17,988 | $ | 13,428 | $ | 25,813 | ||||||
|
DISCLOSURE OF NON CASH INVESTING AND FINANCING ACTIVITIES:
|
||||||||||||
|
Asset retirement obligations
|
$ | 3,006 | $ | (4,724 | ) | $ | 787 | |||||
|
Receipt of common stock for settlement of contingent receivable
|
$ | — | $ | 2,134 | $ | — | ||||||
The accompanying notes are an integral part of these
consolidated financial statements.
60
Table of Contents
RAM
Energy Resources, Inc.
December 31,
2010 and 2009
| A — | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, ORGANIZATION AND BASIS OF PRESENTATION |
| 1. | Nature of Operations and Organization |
On May 8, 2006, Tremisis Energy Acquisition Corporation, or
Tremisis, acquired RAM Energy, Inc., or RAM Energy, through the
merger of a subsidiary of Tremisis into RAM Energy. The merger
was accomplished pursuant to the terms of an Agreement and Plan
of Merger dated October 20, 2005, as amended, among
Tremisis, its subsidiary, RAM Energy and the stockholders of RAM
Energy. Upon completion of the merger, RAM Energy became a
wholly-owned subsidiary of Tremisis and Tremisis changed its
name to RAM Energy Resources, Inc. (the “Company”).
Tremisis was formed in February 2004 to effect a merger, capital
stock exchange, asset acquisition or other similar business
combination with an unidentified operating business in either
the energy or the environmental industry. Prior to the
consummation of the merger, Tremisis did not engage in an active
trade or business. Prior to the merger, RAM Energy was a
privately held, independent oil and natural gas company engaged
in the acquisition, exploration, exploitation and development of
oil and natural gas properties and the production of oil and
natural gas.
The merger was accounted for as a reverse acquisition. Because
Tremisis had no active business operations prior to consummation
of the merger, the merger has been accounted for as a
recapitalization of RAM Energy and RAM Energy has been treated
as the acquirer and continuing reporting entity for accounting
purposes. The assets and liabilities of Tremisis have been
stated at historical cost, and added to those of RAM Energy.
On November 29, 2007, the Company acquired Ascent Energy
Inc., an acquisition that significantly increased the size of
the Company.
The Company operates exclusively in the upstream segment of the
oil and gas industry with activities including the drilling,
completion, and operation of oil and gas wells. The Company
conducts the majority of its operations in the states of Texas,
Louisiana and Oklahoma.
| 2. | Basis of Presentation |
The consolidated financial statements include the accounts of
the Company and its wholly-owned subsidiaries. All significant
intercompany balances and transactions have been eliminated.
| 3. | Properties and Equipment |
The Company follows the full cost method of accounting for oil
and natural gas operations. Under this method all productive and
nonproductive costs incurred in connection with the acquisition,
exploration, and development of oil and natural gas reserves are
capitalized. No gains or losses are recognized upon the sale or
other disposition of oil and natural gas properties except in
transactions that would significantly alter the relationship
between capitalized costs and proved reserves. The costs of
unevaluated oil and natural gas properties are excluded from the
amortizable base until the time that either proven reserves are
found or it has been determined that such properties are
impaired. As properties become evaluated, the related costs
transfer to proved oil and natural gas properties using full
cost accounting. All capitalized costs were included in the
amortization base as of December 31, 2010 and 2009.
Under the full cost method the net book value of oil and natural
gas properties, less related deferred income taxes, may not
exceed the estimated after-tax future net revenues from proved
oil and natural gas properties, discounted at 10% (the
“Ceiling Limitation”). In arriving at estimated future
net revenues, estimated lease operating expenses, development
costs, and certain production-related and ad valorem taxes are
deducted.
61
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
In calculating future net revenues, prices and costs are held
constant indefinitely, except for changes that are fixed and
determinable by existing contracts. The net book value is
compared to the Ceiling Limitation on a quarterly and yearly
basis. The excess, if any, of the net book value above the
Ceiling Limitation is charged to expense in the period in which
it occurs and is not subsequently reinstated. At
December 31, 2010, the net book value of the Company’s
oil and natural gas properties did not exceed the Ceiling
Limitation. At March 31, 2009, the net book value of the
Company’s oil and natural gas properties exceeded the
Ceiling Limitation resulting in a reduction in the carrying
value of the Company’s oil and natural gas properties of
$47.6 million. The after-tax effect of this reduction was
$30.3 million. At December 31, 2009, the net book
value of the Company’s oil and natural gas properties did
not exceed the Ceiling Limitation. At December 31, 2008,
the net book value of the Company’s oil and natural gas
properties exceeded the Ceiling Limitation resulting in a
reduction in the carrying value of the Company’s oil and
natural gas properties by $269.4 million. The after-tax
effect of this reduction in 2008 was $171.6 million.
Additionally, during the Company’s assessment of its
materials and supplies inventory it determined the book value of
inventory exceeded the market value of the materials and
supplies inventory at December 31, 2008. The assessment
resulted in an impairment of $0.5 million for the year
ended December 31, 2008.
The Company has capitalized internal costs of approximately
$3.1 million, $3.2 million and $5.0 million for
the years ended December 31, 2010, 2009, and 2008,
respectively. Such capitalized costs include salaries and
related benefits of individuals directly involved in the
Company’s acquisition, exploration and development
activities based on the percentage of their time devoted to such
activities.
Other property and equipment consists principally of furniture
and equipment and leasehold improvements. Other property and
equipment and related accumulated depreciation and amortization
are relieved upon retirement or sale and the gain or loss is
included in operations. Renewals and replacements that extend
the useful life of property and equipment are treated as capital
additions. Accumulated depreciation of other property and
equipment at December 31, 2010 and 2009 is approximately
$6.7 million and $5.8 million, respectively.
In accordance with authoritative guidance on accounting for the
impairment or disposal of long-lived assets, as set forth in
Topic 360 of the Accounting Standards
Codificationtm
(the “Codification”) implemented by the Financial
Accounting Standards Board (the “FASB”), the Company
assesses the recoverability of the carrying value of its non-oil
and gas long-lived assets when events occur that indicate an
impairment in value may exist. An impairment loss is indicated
if the sum of the expected undiscounted future net cash flows is
less than the carrying amount of the assets. If this occurs, an
impairment loss is recognized for the amount by which the
carrying amount of the assets exceeds the estimated fair value
of the asset.
| 4. | Depreciation and Amortization |
All capitalized costs of oil and natural gas properties and
equipment, including the estimated future costs to develop
proved reserves, are amortized using the
unit-of-production
method based on total proved reserves. Depreciation of other
equipment is computed on the straight-line method over the
estimated useful lives of the assets, which range from three to
twenty years. Amortization of leasehold improvements is computed
based on the straight-line method over the term of the
associated lease or estimated useful life, whichever is shorter.
| 5. | Natural Gas Sales and Gas Imbalances |
The Company follows the entitlement method of accounting for
natural gas sales, recognizing as revenues only its net interest
share of all production sold. Any amount attributable to the
sale of production in excess of or less than the Company’s
net interest is recorded as a gas balancing asset or liability.
At December 31, 2010 and 2009, the Company’s gas
imbalances were immaterial.
62
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
| 6. | Cash Equivalents |
All highly liquid unrestricted investments with a maturity of
three months or less when purchased are considered to be cash
equivalents.
| 7. | Credit and Market Risk |
The Company sells oil and natural gas to various customers and
participates with other parties in the drilling, completion and
operation of oil and natural gas wells. Joint interest and oil
and natural gas sales receivables related to these operations
are generally unsecured. In 2010, 2009, and 2008 approximately
61%, 61% and 53%, respectively, of total revenues were to one
customer. The Company provides an allowance for doubtful
accounts for certain purchasers and certain joint interest
owners’ receivable balances when the Company believes the
receivable balance may not be collected. Accounts receivable are
presented net of the related allowance for doubtful accounts.
In 2010 and 2009 the Company had cash deposits in certain banks
that at times exceeded the maximum insured by the Federal
Deposit Insurance Corporation. The Company monitors the
financial condition of the banks and has experienced no losses
on these accounts.
| 8. | Deferred Loan Costs |
Deferred loan costs are stated at cost net of amortization
computed using the straight-line method over the term of the
related loan agreement, which approximates the interest method.
In March 2011, the Company entered into new credit facilities,
which replaced the $500.0 million facility in place at
December 31, 2010. See
Note C-2.
In accordance with Topic 470 of the Codification, the Company
will be required to expense $1.3 million of existing
deferred loan costs during the first quarter of 2011 upon
retirement of the existing debt. The remaining deferred loan
costs and the deferred loan costs incurred to issue the new
facilities will be amortized over the term of the related new
loan.
| 9. | General and Administrative Expense |
The Company receives fees for the operation of jointly owned oil
and natural gas properties and records such reimbursements as
reductions of general and administrative expense. Such fees
totaled approximately $0.6 million, $0.6 million and
$0.5 million for the years ended December 31, 2010,
2009, and 2008, respectively.
| 10. | 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 the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could
differ from those estimates. Estimates and assumptions that, in
the opinion of management of the Company, are significant
include oil and natural gas reserves, amortization relating to
oil and natural gas properties, asset retirement obligations,
contingent litigation settlements, derivative instrument
valuations and income taxes. The Company evaluates its estimates
and assumptions on a regular basis. Estimates are based on
historical experience and various other assumptions that are
believed to be reasonable under the circumstances, the results
of which form the basis for making judgments about the carrying
values of assets and liabilities that are not readily apparent
from other sources. Actual results may differ from these
estimates used in preparation of the Company’s financial
statements. In addition, alternatives can exist among various
accounting methods. In such cases, the choice of accounting
method can have a significant impact on reported amounts.
63
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
| 11. | Oil and Natural Gas Reserves Estimates |
Independent petroleum and geological engineers prepare estimates
of the Company’s oil and natural gas reserves. Proved
reserves, estimated future net revenues and the present value of
the Company’s reserves are estimated based upon a
combination of historical data and estimates of future activity.
Consistent with Securities and Exchange Commission’s
(“SEC”) requirements, the Company has based its
estimate of proved reserves on spot prices on the date of the
estimate for periods prior to December 31, 2009. However,
in accordance with the SEC’s Release
No. 33-8995,
“Modernization of Oil and Gas Reporting,” and Topic
932 of the Codification, at December 31, 2009 and for
subsequent periods, the Company calculates its estimate of
proved reserves using a twelve month average price, calculated
as the unweighted arithmetic average of the
first-day-of-the-month
price for each period within the twelve-month period prior to
the end of the reporting period. The reserve estimates are used
in the assessment of the Company’s Ceiling Limitation and
in calculating depletion, depreciation and amortization.
Significant assumptions are required in the valuation of proved
oil and natural gas reserves which, as described herein, may
affect the amount at which oil and natural gas properties are
recorded. Actual results could differ materially from these
estimates.
| 12. | Fair Value of Financial Instruments |
Cash and cash equivalents, trade receivables and payables,
and installment notes: The carrying amounts
reported on the consolidated balance sheets approximate fair
value due to the short-term nature of these instruments.
Credit facilities: The carrying amount
reported on the consolidated balance sheets approximates fair
value because this debt instrument carries a variable interest
rate based on market interest rates.
Derivative contracts: The carrying amount
reported on the consolidated balance sheets is the estimated
fair value of the Company’s derivative instruments. See
Notes I and J.
| 13. | Reclassifications |
Certain reclassifications of previously reported amounts for
2009 and 2008 have been made to conform to the 2010
presentation. These reclassifications had no effect on net
income or loss or cash flows from operating, investing or
financing activities.
| 14. | Derivatives |
The Company recognizes all derivative instruments as either
assets or liabilities in the balance sheet at fair value in
accordance with authoritative guidance as set forth in Topic 815
of the Codification.
The Company entered into numerous derivative contracts to reduce
the impact of oil and natural gas price fluctuations and as
required by the terms of its credit facilities (see Notes C
and J). The Company did not designate these transactions as
hedges. Accordingly, all gains and losses on the derivative
instruments during 2010, 2009 and 2008 have been recorded in the
statements of operations.
| 15. | Income (Loss) per Common Share |
Basic and diluted income (loss) per share is computed by
dividing net earnings (loss) by the weighted average number of
common shares outstanding for the period. A reconciliation of
net income (loss) and
64
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
weighted average shares used in computing basic and diluted net
income (loss) per share are as follows for the years ended
December 31 (in thousands, except per share amounts):
| 2010 | 2009 | 2008 | ||||||||||
|
Net income (loss)
|
$ | 2,417 | $ | (58,383 | ) | $ | (129,953 | ) | ||||
|
Weighted average shares — basic
|
78,426,179 | 77,601,057 | 72,234,750 | |||||||||
|
Dilutive effect of warrants
|
— | — | — | |||||||||
|
Weighted average shares — dilutive
|
78,426,179 | 77,601,057 | 72,234,750 | |||||||||
|
Basic income (loss) per share
|
$ | 0.03 | $ | (0.75 | ) | $ | (1.80 | ) | ||||
|
Diluted income (loss) per share
|
$ | 0.03 | $ | (0.75 | ) | $ | (1.80 | ) | ||||
| 16. | Asset Retirement Obligations |
Authoritative guidance, set forth in Topic 410 of the
Codification, addresses financial accounting and reporting for
obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. The
authoritative guidance requires that the fair value of a
liability for an asset retirement obligation be recognized in
the period in which it is incurred if a reasonable estimate of
fair value can be made, and that the associated asset retirement
costs be capitalized as part of the carrying amount of the
long-lived asset. The Company determines its asset retirement
obligation on its oil and gas properties by calculating the
present value of the estimated cash flows related to the
estimated liability. Periodic accretion of the discount of the
estimated liability on the Company’s oil and natural gas
properties is recorded in the income statement.
The Company recorded the following activity related to the asset
retirement obligations for the years ended December 31,
2010 and 2009 (in thousands):
| 2010 | 2009 | |||||||
|
Liability for asset retirement obligations, beginning of year
|
$ | 27,074 | $ | 30,199 | ||||
|
Accretion expense
|
1,527 | 1,976 | ||||||
|
Change in estimates
|
3,475 | (4,498 | ) | |||||
|
Obligations for wells acquired and wells drilled
|
191 | 864 | ||||||
|
Obligations for wells sold or retired
|
(858 | ) | (1,467 | ) | ||||
|
Liability for asset retirement obligations, end of year
|
31,409 | 27,074 | ||||||
|
Less: current asset retirement obligation
|
639 | 711 | ||||||
|
Long-term asset retirement obligations
|
$ | 30,770 | $ | 26,363 | ||||
| 17. | Income Taxes |
The Company accounts for income taxes under the liability method
as prescribed by authoritative guidance set forth in Topic 740
of the Codification. Deferred tax liabilities and assets are
determined based on the difference between the financial
statement and tax basis of assets and liabilities using enacted
rates expected to be in effect during the year in which the
basis differences reverse. The realizability of deferred tax
assets are evaluated quarterly and a valuation allowance is
provided if it is more likely than not that the deferred tax
assets will not give rise to future benefits in the
Company’s tax returns.
65
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
| 18. | Uncertain Tax Positions |
The Company follows guidance in Topic 740 of the Codification
for its accounting for uncertain tax positions. Topic 740
prescribes guidance for the financial statement recognition and
measurement of a tax position taken or expected to be taken in a
tax return. To recognize a tax position, the Company determines
whether it is more-likely-than-not that the tax position will be
sustained upon examination, including resolution of any related
appeals or litigation, based solely on the technical merits of
the position. A tax position that meets the more-likely-than-not
threshold is measured to determine the amount of benefit to be
recognized in the financial statements. The amount of tax
benefit recognized with respect to any tax position is measured
as the largest amount of benefit that is greater than
50 percent likely of being realized upon settlement.
A rollforward of activity from January 1, 2008 follows (in
thousands):
|
Uncertain Tax Positions:
|
||||
|
Balance as of December 31, 2007
|
$ | 6,855 | ||
|
Additions for tax positions of prior periods
|
127 | |||
|
Decreases in tax positions in prior period
|
— | |||
|
Settlements
|
— | |||
|
Additions based on tax positions related to the current year
|
— | |||
|
Lapse of statute of limitations
|
(6,982 | ) | ||
|
Balance as of December 31, 2008
|
$ | — | ||
|
Additions for tax positions of prior periods
|
— | |||
|
Decreases in tax positions in prior period
|
— | |||
|
Settlements
|
— | |||
|
Additions based on tax positions related to the current year
|
— | |||
|
Lapse of statute of limitations
|
— | |||
|
Balance as of December 31, 2009
|
$ | — | ||
|
Additions for tax positions of prior periods
|
— | |||
|
Decreases in tax positions in prior period
|
— | |||
|
Settlements
|
— | |||
|
Additions based on tax positions related to the current year
|
— | |||
|
Lapse of statute of limitations
|
— | |||
|
Balance as of December 31, 2010
|
$ | — | ||
The Company has no liability for unrecognized tax benefits
recorded as of December 31, 2010 and 2009, and there was no
change to the Company’s unrecognized tax benefits during
the year ended December 31, 2010. Accordingly, there is no
amount of unrecognized tax benefits that, if recognized, would
affect the effective tax rate and there is no amount of interest
or penalties currently recognized in the statement of operations
or statement of financial position as of December 31, 2010.
In addition, the Company does not believe that there are any
positions for which it is reasonably possible that the total
amounts of unrecognized tax benefits will significantly increase
or decrease within the next twelve months. The amount of
interest related to unrecognized tax benefits which was
decreased due to expirations of applicable statutes of
limitations was $0.1 million during the year ended
December 31, 2008. The Company recognizes related interest
and penalties as a component of income tax expense.
Tax years open for audit by federal tax authorities and for
state tax authorities as of December 31, 2010 are the years
ended December 31, 2007, 2008, 2009 and 2010. Tax years
ending prior to 2007 are open for
66
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
audit to the extent that net operating losses generated in those
years are being carried forward or utilized in an open year.
| 19. | New Accounting Pronouncements |
On December 31, 2008, the SEC issued Release
No. 33-8995,
“Modernization of Oil and Gas Reporting,” which
revises disclosure requirements for oil and gas companies. In
addition to changing the definition and disclosure requirements
for oil and gas reserves, the new rules change the requirements
for determining oil and gas reserve quantities. These rules
permit the use of new technologies to determine proved reserves
under certain criteria and allow companies to disclose their
probable and possible reserves. The new rules also require
companies to report the independence and qualifications of their
reserves preparer or auditor and file reports when a third party
is relied upon to prepare reserves estimates or conduct a
reserves audit. The new rules also require that oil and gas
reserves be reported and the full cost ceiling limitation be
calculated using a twelve-month average price rather than
period-end prices. The new rules are effective for annual
reports on
Form 10-K
for fiscal years ending on or after December 31, 2009.
Additionally, the FASB issued authoritative guidance on oil and
gas reserve estimation and disclosures, as set forth in Topic
932 of the Codification to align with the requirements of the
SEC’s revised rules. The Company implemented the new
disclosure requirements and the requirements for estimating
reserves related to the Company’s oil and natural gas
operations effective December 31, 2009 as disclosed in
Note M.
In January 2009, the FASB issued guidance on fair value
disclosures to enhance disclosures surrounding the transfers of
assets in and out of Level 1 and Level 2, to present
more detail surrounding asset activity for Level 3 assets
and to clarify existing disclosure requirements. The new
guidance is set forth in Topic 820 of the Codification and is
effective for the Company beginning January 1, 2010.
Additional disclosure about purchases, sales, issuances, and
settlement in the roll forward of activity in Level 3 fair
value measurements is effective beginning January 1, 2011.
Adoption of the guidance on January 1, 2010 did not, and
adoption of the guidance on January 1, 2011 will not, have
any impact the Company’s financial position or statement of
operations.
In February 2010, the FASB issued an update to authoritative
guidance, as set forth in Topic 855 of the Codification,
relating to subsequent events, which was effective upon the
issuance of the update. The Company adopted this authoritative
guidance during the first quarter of 2010. The update removes
the requirement for U.S. Securities and Exchange Commission
filers to disclose the date through which subsequent events have
been evaluated in both issued and revised financial statements.
The adoption of this update did not impact the Company’s
financial position or statement of operations other than
removing the disclosure.
In December 2010, the FASB issued an update to authoritative
guidance, as set forth in Topic 805 of the Codification,
relating to business combinations. This update provides
clarification requiring public companies that have completed
material acquisitions to disclose the revenue and earnings of
the combined business as if the acquisition took place at the
beginning of the comparable prior annual reporting period, and
also expands the supplemental pro forma disclosures to include a
description of the nature and amount of material, non-recurring
pro forma adjustments directly attributable to the business
combination included in the reported pro forma revenue and
earnings. The Company will be required to apply this guidance
prospectively for business combinations for which the
acquisition date is on or after January 1, 2011. The
Company does not expect the adoption of this new guidance to
have a material impact on its financial position or statement of
operations.
| 20. | Subsequent Events |
In March 2011, the Company entered into new credit facilities.
The facilities, which replaced the Company’s previous
$500.0 million facility, include a $250.0 million
first lien revolving credit facility with an initial
$150.0 million borrowing base and a $75.0 million
second lien term loan facility. See Note C for
67
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
additional discussion on the new credit facilities. See
Note A-8
for additional discussion on treatment of deferred loan costs
related to the refinancing.
The Company evaluates events and transactions after the balance
sheet date but before the financial statements are filed with
the U.S. Securities and Exchange Commission. No events
other than those described in these notes, have occurred that
have required disclosure.
| B — | SIGNIFICANT DIVESTITURES |
| 1. | North Texas Barnett Shale & Boonsville Divestitures |
On December 8, 2010, the Company closed the sale on all of
its oil and natural gas properties and related assets located in
the Boonsville and Newark East fields of Jack and Wise Counties
in Texas to Milagro Producing, LLC for $43.7 million (prior
to closing adjustments). The effective date under the agreement
was October 1, 2010. In accordance with the full cost
method of accounting, the Company did not record a gain or loss
on the sale. The full cost pool at December 31, 2010 was
reduced by the net proceeds, including closing adjustments, of
$41.0 million. Proceeds of $16.0 million were used to
reduce the outstanding balance on the Company’s revolving
credit facility and the remaining net proceeds were used to
reduce the outstanding balance on the Company’s term loan.
See Note C.
| 2. | Eastern Oklahoma Divestiture |
On December 30, 2010, the Company closed the sale on
certain non-operated natural gas properties located in eastern
Oklahoma for $8.0 million (prior to closing adjustments).
The effective date under the agreement was December 1,
2010. The full cost pool at December 31, 2010 was reduced
by the net proceeds, including closing adjustments, of
$7.8 million in accordance with the full cost method of
accounting. The proceeds were used to reduce outstanding
borrowings under the Company’s revolving credit facility.
See Note C.
C —
LONG-TERM DEBT
Long-term debt at December 31 consists of the following (in
thousands):
| 2010 | 2009 | |||||||
|
Credit facility
|
$ | 196,521 | $ | 245,730 | ||||
|
Accrued
payment-in-kind
interest
|
221 | 262 | ||||||
|
Installment loan agreements
|
350 | 175 | ||||||
| 197,092 | 246,167 | |||||||
|
Less amount due within one year
|
127 | 126 | ||||||
| $ | 196,965 | $ | 246,041 | |||||
The amounts of required principal payments as of
December 31, 2010, are as follows (in thousands):
|
2011
|
$ | 127 | ||
|
2012
|
104 | |||
|
2013
|
63 | |||
|
2014
|
34 | |||
|
2015
|
22 | |||
|
2016
|
196,742 | |||
| $ | 197,092 | |||
68
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
| 1. | Senior Notes |
In February 1998, the Company completed the sale of
$115.0 million of 11.5% Senior Notes due 2008 in a
public offering of which $28.4 million remained outstanding
at December 31, 2007. These notes were retired at maturity
on February 15, 2008 using proceeds from the Company’s
revolving credit facility.
| 2. | Credit Facilities |
Credit Facilities. In November 2007, in
conjunction with the Ascent acquisition, the Company entered
into a $500.0 million credit facility with Guggenheim
Corporate Funding, LLC, for itself and on behalf of other
institutional lenders. The facility included a
$250.0 million revolving credit facility and a
$200.0 million term loan facility and an additional
$50.0 million available under the term loan as requested by
the Company and approved by the lenders. The initial amount of
the $200.0 million term loan was advanced at closing. The
borrowing base under the revolving credit facility initially was
set at $175.0 million, a portion of which was advanced at
the closing of the Ascent acquisition. Borrowings under the
facility were used to refinance RAM Energy’s existing
indebtedness, fund the cash requirements in connection with the
closing of the Ascent acquisition, and for working capital and
other general corporate purposes. Funds advanced under the
revolving credit facility initially bore interest at LIBOR plus
a margin ranging from 1.25% to 2.0% based on a percentage of
usage. The term loan provided for payments of interest only
during its term, with the initial interest rate being LIBOR plus
7.5%. Effective September 30, 2010, the borrowing base was
redetermined at $165.0 million based on the value of the
Company’s proved reserves at June 30, 2010. As a
result of the reduction in collateral, represented by the North
Texas Barnett Shale and Boonsville asset sale, the
Company’s borrowing base of $165.0 million was reset
at $145.0 million as of December 31, 2010. The Eastern
Oklahoma asset sale had no impact on the Company’s
borrowing base. See Note B.
Advances under the facility were secured by liens on
substantially all properties and assets of the Company and its
subsidiaries. The loan agreement contained representations,
warranties and covenants customary in transactions of this
nature. During May 2008, the Company reduced its outstanding
balance on the term facility by $86.6 million of net
proceeds, which it realized upon the exercise of 17,617,331
warrants. See Note F.
On June 26, 2009, the Company entered into the Second
Amendment to the credit facility. The Second Amendment amended
certain definitions and certain financial and negative covenant
terms providing greater flexibility for the Company through the
remaining term of the facility. Additionally, the Second
Amendment increased the interest rates applicable to borrowings
under both the revolver and term loans. Advances under the
revolver bore interest at LIBOR, with a minimum LIBOR rate, or
“floor,” of 1.5%, plus a margin ranging from 2.25% to
3.0% based on a percentage of usage. The term loan bore interest
at LIBOR, also with a floor of 1.5%, plus a margin of 8.5%, and
an additional 2.75% of
payment-in-kind
interest that was added to the term loan principal balance on a
monthly basis and paid at maturity. The Company was in
compliance with all of its covenants in the credit facility at
December 31, 2010. At December 31, 2010,
$116.5 million was outstanding under the revolving credit
facility and $80.2 million was outstanding under the term
facility, including $0.2 million accrued
payment-in-kind
interest.
In March 2011, the Company entered into new credit facilities.
The new facilities, which replaced the Company’s previous
facility, include a $250.0 million first lien revolving
credit facility and a $75.0 million second lien term loan
facility. SunTrust Bank is the administrative agent for the
revolving facility, and Guggenheim Corporate Funding, LLC is the
agent for the term loan facility. The initial borrowing base
under the revolving credit facility at the closing is
$150.0 million. Funds advanced under the revolving credit
facility may be paid down and re-borrowed during the five-year
term of the revolver, and initially bear interest at LIBOR plus
a margin ranging from 2.5% to 3.25% based on a percentage of
usage. The term loan portion of the Company’s credit
facility provides for payments of interest only during its
5.5-year term, with the initial interest rate being LIBOR plus
9.0% with a 2.0% LIBOR floor, or if any period we elect to pay a
portion of
69
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
the interest under our term loan “in kind,” then the
interest rate will be LIBOR plus 10.0% with a 2.0% LIBOR floor,
and with 7.0% of the interest amount paid in cash and the
remaining 3.0% paid in kind by being added to principal. Due to
refinancing of the Company’s outstanding debt prior to the
issuance of the financial statements, the current portion of
existing debt at December 31, 2010 is considered long-term.
The new credit facilities contain representations, warranties
and covenants customary in transactions of this nature,
including restrictions on the payment of dividends on our
capital stock and financial covenants relating to current ratio,
minimum interest coverage ratio, maximum leverage ratio and a
required ratio of asset value to total indebtedness. The Company
is required to maintain commodity hedges on a rolling basis for
the first 12 months out with respect to not less than 60%,
but not more than 85%, and for the next 18 months out with
respect to not less than 50% but not more than 85%, of projected
quarterly production volumes, until the leverage ratio is less
than or equal to 1.5 to 1.0.
| D — | LEASES |
The Company leases office space and certain equipment under
non-cancelable operating lease agreements that expire on various
dates through 2014. Approximate future minimum lease payments
for operating leases at December 31, 2010 are as follows
(in thousands):
|
Year Ending December 31,
|
||||
|
2011
|
$ | 1,189 | ||
|
2012
|
1,165 | |||
|
2013
|
1,048 | |||
|
2014
|
58 | |||
|
2015
|
2 | |||
| $ | 3,462 | |||
Rent expense of approximately $1.3 million,
$1.3 million, and $1.2 million was incurred under
operating leases in the years ended December 31, 2010,
2009, and 2008, respectively. In 2010, the Company
sub-leased a
portion of its leased office space for the duration of the
operating lease agreement. Approximate future minimum lease
receipts for the
sub-lease at
December 31, 2010 are $0.1 million, $0.2 million
and $0.1 million for 2011, 2012 and 2013, respectively.
| E — | DEFINED CONTRIBUTION PLAN |
The Company sponsors a 401(k) defined contribution plan for the
benefit of substantially all of its employees. The plan allows
eligible employees to contribute up to 100% of their annual
compensation, not to exceed the maximum amount permitted by IRS
regulations. Employer contributions to the plan are
discretionary. The Company provided matching contributions to
the plan in 2010, 2009, and 2008 of $0.7 million,
$0.7 million and $0.6 million, respectively.
F — CAPITAL
STOCK
On May 8, 2006, the shareholders of the Company approved
the Company’s 2006 Long-Term Incentive Plan (the
“Plan”), effective upon the consummation of the
Company’s acquisition by merger of RAM Energy. Under the
terms of the Plan, at such time as restricted stock awards vest,
the grantee has the right to request the Company to repurchase,
at the closing market price of the Company’s common stock
as of the vesting date, the number of vested shares necessary to
satisfy minimum income tax withholding requirements. Pursuant to
this provision, since inception of the Plan in 2006, the Company
has repurchased, upon vesting, a total of 587,861 shares of
common stock at an average price of $2.84 per share. The shares
purchased by the Company are held as treasury shares.
70
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
On February 13, 2007, the Company completed a public
offering in which it issued 7,500,000 shares of its common
stock, priced at $4.00 per share. Net proceeds of the offering
were $27.4 million and were used to provide additional
working capital for general corporate purposes, including
acquisition, development, exploitation and exploration of oil
and natural gas properties, and reduction of indebtedness.
On November 29, 2007, the Company acquired Ascent in
exchange for the issuance of 18,783,344 shares of common
stock, warrants to purchase 6,200,000 shares of common
stock at an exercise price of $5.00 per share, exercisable on or
prior to May 11, 2008, and $202.8 million in cash,
including direct acquisition costs.
The Company had outstanding warrants to purchase
18,848,800 shares of its common stock (including the
warrants issued in connection with the Ascent acquisition) at an
exercise price of $5.00 per share, of which 17,617,331 were
exercised prior to the May 12, 2008 expiration date,
resulting in net proceeds to the Company of $86.6 million.
Proceeds of the exercise were used to pay down the term loan
portion of the Company’s credit facility. The remaining
1,231,469 warrants expired and are no longer outstanding.
The Company had outstanding options to purchase up to
275,000 units at any time on or prior to May 11, 2009
at an exercise price of $9.90 per unit, with each unit
consisting of one share of the Company’s common stock and
two warrants. All of the unit purchase options expired
unexercised.
G —
INCOME TAXES
The (provision) benefit for income taxes is comprised of (in
thousands):
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
Current
|
$ | (418 | ) | $ | (518 | ) | $ | (912 | ) | |||
|
Deferred
|
(577 | ) | 16,865 | 92,595 | ||||||||
|
(Provision) benefit for income tax
|
$ | (995 | ) | $ | 16,347 | $ | 91,683 | |||||
The provision for income taxes differs from the amount computed
by applying the statutory federal income tax rate to income
before provision for income taxes. The significant differences
between pre-tax book income and taxable book income relate to
non-deductible personal expenses, meals and entertainment
expenses, state income taxes, change in valuation allowance,
Section 382 net operating loss limitations and
previously unrecognized tax benefits.
71
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
The sources and tax effects of the differences are as follows
(in thousands):
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
Income tax benefit (expense) at the federal statutory rate (34%)
|
$ | (1,160 | ) | $ | 25,408 | $ | 75,356 | |||||
|
State income tax benefit, net of federal benefit
|
(124 | ) | (508 | ) | 6,033 | |||||||
|
Meals and entertainment expense
|
(25 | ) | (27 | ) | (102 | ) | ||||||
|
Non-deductible dues
|
(69 | ) | 12 | (33 | ) | |||||||
|
Previously unrecognized tax benefits
|
— | — | 11,613 | |||||||||
|
Interest on previously unrecognized tax benefits
|
— | — | (127 | ) | ||||||||
|
Reduction in deferred tax asset for Section 382 net
operating loss limitations
|
(5,731 | ) | — | — | ||||||||
|
Change in valuation allowance
|
6,572 | (7,433 | ) | (2,234 | ) | |||||||
|
Share-based compensation
|
(393 | ) | (559 | ) | (119 | ) | ||||||
|
Other
|
(65 | ) | (546 | ) | 1,296 | |||||||
|
Income tax benefit (provision)
|
$ | (995 | ) | $ | 16,347 | $ | 91,683 | |||||
The Company’s income tax benefit was computed based on the
federal statutory rate and the average state statutory rates,
net of the related federal benefit. Deferred income taxes
reflect the net tax effects of temporary differences between the
carrying amounts of assets and liabilities for financial
reporting purposes and the amounts used for income tax purposes.
72
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
Significant components of the Company’s deferred tax assets
and liabilities are as follows (in thousands):
| December 31, | ||||||||
| 2010 | 2009 | |||||||
|
Deferred tax assets:
|
||||||||
|
Current:
|
||||||||
|
Derivative liabilities
|
$ | 2,298 | $ | 2,226 | ||||
|
Accrued expenses and other
|
1,873 | 2,675 | ||||||
|
Total current deferred tax assets
|
$ | 4,171 | $ | 4,901 | ||||
|
Valuation allowance
|
(445 | ) | (1,138 | ) | ||||
|
Net current deferred tax assets
|
$ | 3,726 | $ | 3,763 | ||||
|
Noncurrent:
|
||||||||
|
Depreciable/depletable property, plant and equipment
|
$ | 13,268 | $ | 3,024 | ||||
|
Net operating loss carryforward
|
20,254 | 36,644 | ||||||
|
Accrued liabilities and other
|
1,381 | 1,688 | ||||||
|
Total noncurrent deferred tax assets
|
$ | 34,903 | $ | 41,356 | ||||
|
Valuation allowance
|
(3,723 | ) | (9,603 | ) | ||||
|
Net noncurrent deferred tax assets
|
$ | 31,180 | $ | 31,753 | ||||
|
Deferred tax liabilities:
|
||||||||
|
Current:
|
||||||||
|
Prepaid expenses and other
|
$ | (200 | ) | $ | (232 | ) | ||
|
Total current deferred tax liability
|
(200 | ) | (232 | ) | ||||
|
Noncurrent:
|
||||||||
|
Depreciable/depletable property, plant and equipment
|
$ | — | $ | — | ||||
|
Other
|
(179 | ) | (180 | ) | ||||
|
Total noncurrent deferred tax liabilities
|
$ | (179 | ) | $ | (180 | ) | ||
|
Net deferred tax liability
|
$ | (379 | ) | $ | (412 | ) | ||
|
Net deferred tax asset
|
$ | 34,527 | $ | 35,104 | ||||
As of December 31, 2010, the Company has net operating loss
carryforwards of approximately $129.1 million for federal
income tax reporting purposes, the majority of which were an
inherited attribute from the Ascent acquisition during 2007. If
not used, the net operating losses will generally expire between
2020 and 2029. The majority of these net operating loss
carryforwards are subject to the ownership change limitation
provisions of Section 382 of the Internal Revenue Code.
Based on the value of Ascent at the time of the acquisition, and
the annual limitation on utilization of losses imposed by
Section 382, and other increases for anticipated recognized
built-in gains, it is estimated that approximately
$82.6 million of these net operating losses will expire
without being utilized; accordingly, no deferred tax asset has
been established for the amount of net operating losses that are
not expected to be utilized under the applicable provisions of
the tax law prior to their expiration. In addition, the Company
has generated net operating loss carryforwards for state income
tax purposes, which the Company believes will more likely than
not be realized during the relevant carryforward periods;
however, such amounts have not been separately disclosed in the
financial statements as the Company does not believe that these
net operating losses are material to the amounts presented
herein.
73
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
A valuation allowance has been established with respect to the
portion of the deferred tax asset associated with its net
operating losses for which the Company currently does not
reasonably believe under the deferred tax asset realization
criteria set forth in Topic 740 that it will more likely than
not realize a benefit in future periods. During the year ended
December 31, 2010, the Company recorded a decrease in the
valuation allowance of $6.6 million.
| H — | COMMITMENTS AND CONTINGENCIES |
The Company is involved in legal proceedings and litigation in
the ordinary course of business. In the opinion of management,
the outcome of such matters will not have a material adverse
effect on the Company’s financial position or results of
operations.
| I — | FAIR VALUE MEASUREMENTS |
The Company measures the fair value of its derivative
instruments according to the fair value hierarchy, as set forth
in Topic 820 of the Codification. Topic 820 establishes a fair
value hierarchy that prioritizes the inputs to valuation
techniques used to measure fair value. The hierarchy assigns the
highest priority to unadjusted quoted prices in active markets
for identical assets or liabilities (“Level 1”)
and the lowest priority to unobservable inputs
(“Level 3”). Level 2 measurements are inputs
that are observable for assets or liabilities, either directly
or indirectly, other than quoted prices included within
Level 1. The fair value measurement of the Company’s
net derivative assets as of December 31, 2010 was
$1.1 million and of its net derivative liabilities as of
December 31, 2009 was $4.8 million, based on
Level 2 criteria. See Note J.
At December 31, 2010, the carrying value of cash,
receivables and payables reflected in the Company’s
consolidated financial statements approximates fair value due to
their short-term nature. Additionally, the carrying value of the
Company’s long-term debt under the credit facility
approximates fair value because the credit facility carries a
variable interest rate based on market interest rates. See
Note C for discussion of long-term debt.
| J — | DERIVATIVE CONTRACTS |
The Company periodically utilizes various hedging strategies to
manage the price received for a portion of its future oil and
natural gas production to reduce exposure to fluctuations in oil
and natural gas prices and to achieve a more predictable cash
flow.
During 2010, 2009 and 2008, the Company entered into numerous
derivative contracts to manage the impact of oil and natural gas
price fluctuations and as required by the terms of its credit
facility.
The Company did not designate these transactions as hedges.
Accordingly, all gains and losses on the derivative instruments
during 2010, 2009 and 2008 have been recorded in the statements
of operations.
The Company’s derivative positions at December 31,
2010, consisting of put/call “collars” and put
options, also called “bare floors” as they provide a
floor price without a corresponding ceiling, are shown in the
following table:
74
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
| Crude Oil (Bbls) | Natural Gas (Mmbtu) | |||||||||||||||||||||||||||||||||||
| Floors | Ceilings | Floors | Ceilings | |||||||||||||||||||||||||||||||||
|
Collars
|
Per Day(1) | Price | Per Day(1) | Price |
Months Covered
|
Per Day(1) | Price | Per Day(1) | Price |
Months Covered
|
||||||||||||||||||||||||||
|
2011
|
1,921 | $ | 80.00 | 1,921 | $ | 105.00 | April — December | 6,219 | $ | 5.00 | 6,219 | $ | 9.48 | January — September | ||||||||||||||||||||||
|
2012
|
995 | $ | 80.00 | 995 | $ | 105.00 | January — June | — | — | — | — | |||||||||||||||||||||||||
| Bare Floors | Bare Floors | |||||||||||||||||||
|
Year
|
Per Day(1) | Price |
Months Covered
|
Per Day(1) | Price |
Months Covered
|
||||||||||||||
|
2011
|
1,177 | $ | 60.00 | January — September | 1,841 | $ | 4.18 | October — December | ||||||||||||
|
2012
|
— | — | 2,486 | $ | 4.25 | January — March | ||||||||||||||
| (1) | Per day amounts are calculated based on a 365-day year for 2011 and on a 366-day year for 2012. |
The Company estimates the fair value of its derivative
instruments based on published forward commodity price curves as
of the date of the estimate, less discounts to recognize present
values. The Company estimated the fair value of its derivatives
using a pricing model which also considered market volatility,
counterparty credit risk and additional criteria in determining
discount rates. See Note I. The discount rate used in the
discounted cash flow projections was based on published LIBOR
rates, Eurodollar futures rates and interest swap rates. The
counterparty credit risk was determined by calculating the
difference between the derivative counterparty’s bond rate
and published bond rates. The Company incorporates its credit
risk when the derivative position is a liability by using its
LIBOR spread rate.
Gross fair values of the Company’s derivative instruments,
prior to netting of assets and liabilities subject to a master
netting arrangement, as of December 31, 2010 and 2009 and
the consolidated statements of operations for the years ended
December 31, 2010, 2009 and 2008 are as follows (in
thousands):
CONSOLIDATED
BALANCE SHEETS
| Fair Value as of December 31, | ||||||||||
|
Gross Assets and Liabilities
|
Balance Sheet Location
|
2010 | 2009 | |||||||
|
Current Assets — Derivative assets
|
Current Assets — Derivative assets | $ | 1,904 | $ | — | |||||
|
Current Assets — Derivative assets
|
Current Liabilities — Derivative liabilities | — | 413 | |||||||
|
Other Assets — Derivative assets
|
Long-Term Liabilities — Derivative liabilities | 207 | 200 | |||||||
|
Current Liabilities — Derivative liabilities
|
Current Assets — Derivative assets | (564 | ) | — | ||||||
|
Current Liabilities — Derivative liabilities
|
Current Liabilities — Derivative liabilities | — | (4,884 | ) | ||||||
|
Long-Term Liabilities — Derivative liabilities
|
Long-Term Liabilities — Derivative liabilities | (410 | ) | (558 | ) | |||||
|
Total Derivatives Not Designated as Hedging Instruments
|
$ | 1,137 | $ | (4,829 | ) | |||||
75
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
CONSOLIDATED
STATEMENTS OF OPERATIONS
| Years Ended December 31, | ||||||||||||
|
Location
|
2010 | 2009 | 2008 | |||||||||
|
Revenue — Unrealized gains (losses) on derivatives
|
$ | 6,386 | $ | (30,561 | ) | $ | 33,257 | |||||
|
Revenue — Realized gains (losses) on derivatives
|
$ | (5,193 | ) | $ | 19,255 | $ | (10,472 | ) | ||||
| K — | LIQUIDITY |
As of December 31, 2010, the Company had an accumulated
deficit of $214.9 million and a working capital deficit of
$12.4 million. Management believes that borrowings
currently available to the Company under the Company’s
credit facilities and anticipated cash flows from operations
will be sufficient to satisfy its currently expected capital
expenditures, working capital, and debt service obligations
through 2011. The actual amount and timing of future capital
requirements may differ materially from estimates as a result
of, among other things, changes in product pricing and
regulatory, technological and competitive developments. Sources
of additional financing may include commercial bank borrowings,
vendor financing and the sale of oil and natural gas properties
or equity or debt securities. Management cannot assure that any
such financing will be available on acceptable terms or at all.
| L — | SHARE-BASED COMPENSATION |
The Company accounts for share-based payment accruals under
authoritative guidance on stock compensation, as set forth in
Topic 718 of the Codification. The guidance requires all
share-based payments to employees, including grants of employee
stock options, to be recognized in the financial statements
based on their fair values.
On May 8, 2006, the Company’s stockholders approved
its 2006 Long-Term Incentive Plan (the “Plan”). The
Company reserved a maximum of 2,400,000 shares of its
common stock for issuances under the Plan. The Plan includes a
provision that, at the request of a grantee, the Company may
repurchase shares to satisfy the grantee’s federal and
state income tax and other payroll withholding requirements. All
repurchased shares will be held by the Company as treasury
stock. On May 8, 2008, the Plan was amended to increase the
maximum authorized number of shares to be issued under the Plan
from 2,400,000 to 6,000,000. On May 3, 2010, the Plan was
amended to increase the maximum authorized number of shares to
be issued under the Plan from 6,000,000 to 7,400,000. As of
December 31, 2010, a maximum of 1,960,271 shares of
common stock remained reserved for issuance under the Plan.
The number of shares repurchased and their weighted average
prices for the three year period ended December 31, 2010
were as follows:
| Shares Repurchased | ||||||||
|
Weighted Average |
||||||||
|
Year Ended
|
Number | Closing Price | ||||||
|
December 31, 2008
|
20,549 | $ | 3.98 | |||||
|
December 31, 2009
|
21,541 | $ | 1.33 | |||||
|
December 31, 2010
|
414,055 | $ | 1.90 | |||||
76
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
A summary of the status of the non-vested shares as of
December 31, 2010, and changes during the three year period
ended December 31, 2010, is presented below:
|
Weighted- |
||||||||
|
Average |
||||||||
|
Grant-Date |
||||||||
|
Nonvested Shares
|
Shares | Fair Value | ||||||
|
Nonvested at January 1, 2008
|
802,686 | $ | 4.28 | |||||
|
Granted
|
1,104,800 | $ | 4.84 | |||||
|
Vested
|
(297,849 | ) | $ | 4.95 | ||||
|
Forfeited
|
(141,393 | ) | $ | 5.03 | ||||
|
Nonvested at December 31, 2008
|
1,468,244 | $ | 4.79 | |||||
|
Granted
|
1,343,000 | $ | 0.95 | |||||
|
Vested
|
(429,351 | ) | $ | 4.81 | ||||
|
Forfeited
|
(17,900 | ) | $ | 1.20 | ||||
|
Nonvested at December 31, 2009
|
2,363,993 | $ | 2.64 | |||||
|
Granted
|
1,871,655 | $ | 1.99 | |||||
|
Vested
|
(1,557,476 | ) | $ | 2.65 | ||||
|
Forfeited
|
(22,500 | ) | $ | 2.27 | ||||
|
Nonvested at December 31, 2010
|
2,655,672 | $ | 2.17 | |||||
Each grant vests in equal increments over periods ranging from
eight months to five years from the date of grant. At the
request of certain of the grantees, the Company repurchased a
portion of the vested shares at the closing market price of the
Company’s common stock as of the vesting date, to satisfy
the requesting grantees’ federal and state income tax and
other payroll withholding requirements. The repurchased shares
were held by the Company as treasury stock at December 31,
2010.
As of December 31, 2010, the Company had $5.1 million
of unrecognized share-based compensation related to awards
granted under the Plan. That cost is expected to be recognized
over a weighted-average period of two years. The related
compensation expense recognized during the years ended
December 31, 2010, 2009 and 2008 was $3.1 million,
$2.2 million and $2.6 million, respectively.
In March 2008, John L. Cox, a senior executive officer of the
Company passed away. On April 4, 2008, the Compensation
Committee of the Company’s Board of Directors approved the
immediate vesting in full of all restricted shares held by
Mr. Cox at the time of his death. The number of shares
vested totaled 95,336, and the Company recognized
$0.4 million of share-based compensation related to the
vesting of these shares in April 2008.
| M — | SUPPLEMENTARY OIL AND NATURAL GAS RESERVE INFORMATION (UNAUDITED) |
The Company has interests in oil and natural gas properties that
are principally located in Texas, Louisiana and Oklahoma. The
Company does not own or lease any oil and natural gas properties
outside the United States of America.
The Company retains independent engineering firms to provide
year-end estimates of the Company’s future net recoverable
oil, natural gas and natural gas liquids reserves. Estimated
proved net recoverable reserves as shown below include only
those quantities that can be expected to be commercially
recoverable. Estimated reserves for the year ended
December 31, 2010 and 2009 were computed using benchmark
prices based on the unweighted arithmetic average of the
first-day-of-the-month
prices for oil and natural gas during each month of 2010 and
2009, as required by SEC Release
No. 33-8995
“Modernization of Oil and Gas
77
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
Reporting,” effective December 31, 2009, while
estimated reserves for the years ended December 31, 2008
were based on oil and natural gas spot prices as of the end of
the period presented. Costs were estimated using costs in effect
at the balance sheet dates under existing regulatory practices
and with conventional equipment and operating methods.
Proved developed reserves represent only those reserves expected
to be recovered through existing wells. Proved undeveloped
reserves include those reserves expected to be recovered from
new wells on undrilled acreage or from existing wells on which a
relatively major expenditure is required for re-completion.
Capitalized costs relating to oil and natural gas producing
activities and related accumulated depreciation and amortization
at December 31 are summarized as follows (in thousands):
| 2010 | 2009 | 2008 | ||||||||||
|
Proved oil and natural gas properties
|
$ | 689,472 | $ | 702,502 | $ | 683,341 | ||||||
|
Unevaluated oil and natural gas properties
|
— | — | — | |||||||||
|
Accumulated depreciation, amortization and impairment
|
(482,886 | ) | (456,720 | ) | (378,445 | ) | ||||||
| $ | 206,586 | $ | 245,782 | $ | 304,896 | |||||||
Costs incurred in oil and natural gas producing activities for
the years ended December 31 are as follows (in thousands, except
per equivalent oil barrel):
| 2010 | 2009 | 2008 | ||||||||||
|
Acquisition of proved properties
|
$ | 1,133 | $ | 1,311 | $ | 10,091 | ||||||
|
Acquisition of unproved properties
|
— | — | 2,691 | |||||||||
|
Development costs
|
27,850 | 28,239 | 57,084 | |||||||||
|
Exploration costs
|
4,552 | 321 | 14,857 | |||||||||
|
Additional asset retirement obligation
|
191 | 864 | 2,051 | |||||||||
| $ | 33,726 | $ | 30,735 | $ | 86,774 | |||||||
|
Amortization rate per equivalent oil barrel
|
$ | 12.11 | $ | 12.06 | $ | 17.89 | ||||||
78
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
Net quantities of proved and proved developed reserves of oil
and natural gas, including condensate and natural gas liquids,
are summarized as follows:
|
Natural Gas |
||||||||||||
|
Crude Oil |
Natural Gas |
Liquids |
||||||||||
|
(Thousand |
(Million |
(Thousand |
||||||||||
| Barrels) | Cubic Feet) | Barrels) | ||||||||||
|
December 31, 2007
|
19,544 | 93,358 | 4,271 | |||||||||
|
Extensions and discoveries
|
631 | 18,647 | 1,071 | |||||||||
|
Sales of reserves in place
|
(85 | ) | (701 | ) | — | |||||||
|
Purchases of reserves in place
|
151 | 135 | — | |||||||||
|
Revisions of previous estimates
|
(4,769 | ) | (8,405 | ) | (663 | ) | ||||||
|
Production
|
(1,187 | ) | (6,082 | ) | (354 | ) | ||||||
|
December 31, 2008
|
14,285 | 96,952 | 4,325 | |||||||||
|
Extensions and discoveries
|
1,771 | 10,070 | 508 | |||||||||
|
Sales of reserves in place
|
(15 | ) | (3,808 | ) | — | |||||||
|
Purchases of reserves in place
|
— | — | — | |||||||||
|
Revisions of previous estimates
|
(836 | ) | (7,993 | ) | 556 | |||||||
|
Production
|
(1,138 | ) | (5,994 | ) | (406 | ) | ||||||
|
December 31, 2009
|
14,067 | 89,227 | 4,983 | |||||||||
|
Extensions and discoveries
|
347 | 821 | 61 | |||||||||
|
Sales of reserves in place
|
(174 | ) | (14,591 | ) | (2,004 | ) | ||||||
|
Purchases of reserves in place
|
— | — | — | |||||||||
|
Revisions of previous estimates
|
(159 | ) | (17,033 | ) | (301 | ) | ||||||
|
Production
|
(995 | ) | (4,816 | ) | (364 | ) | ||||||
|
December 31, 2010
|
13,086 | 53,608 | 2,375 | |||||||||
|
Proved developed reserves:
|
||||||||||||
|
December 31, 2008
|
9,235 | 57,635 | 2,705 | |||||||||
|
December 31, 2009
|
8,814 | 46,159 | 2,788 | |||||||||
|
December 31, 2010
|
8,414 | 31,776 | 1,486 | |||||||||
The Company added 0.5 million barrels of oil equivalent in
proved reserve extensions and discoveries in 2010 as a result of
development drilling in its Electra/Burkburnett field in North
Texas and in its La Copita field in South Texas. A
significant portion of these reserves is a result of drilling
locations in its Electra/Burkburnett field that were not booked
as proved locations at year-end 2009. The remainder of the
extensions and discoveries in 2010 is primarily from wells
drilled in South Texas not previously booked as proved and from
a discovery well in Osage County, Oklahoma. Sales of reserves in
place during 2010 were primarily due to sales of assets during
December 2010 of the Company’s North Texas Barnett Shale
and Boonsville properties and certain non-operated natural gas
properties located in eastern Oklahoma. The revisions of
previous reserve estimates decreased proved reserves by
3.3 million barrels of oil equivalent or approximately 10%
of proved reserves at the beginning of the year. The revisions
included a positive increase of 1.8 million barrels of oil
equivalent caused by higher oil and gas prices. This positive
revision was offset by a downward revision of 1.1 million
barrels of oil equivalent caused by the transfer of proved
undeveloped to unproved categories as a result of changes to the
Company’s development plans during 2010, and
4.0 million barrels of oil equivalent of the downward
revisions were mostly due to changes in well performance in the
Company’s gas properties in South Texas. The Company added
3.9 million barrels of oil equivalent in proved
79
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
reserve extensions and discoveries in 2009, primarily as a
result of success in development drilling in the La Copita
field of South Texas and the mature oil area of
Electra/Burkburnett in North Texas. Extensions and discoveries
in 2008 were due to upgrading probable and possible locations to
the proved undeveloped category and from drilling many wells
that were not carried as proved prior to being drilled.
Impact of
Implementation of New Oil and Gas Rules Effective
December 31, 2009
Implementation of the SEC’s updated rules using
first-day-of-the-month
average prices for 2009 resulted in the use of lower prices at
December 31, 2009 for both oil and gas than would have
resulted under the previous rules using year-end 2009 pricing.
Use of
12-month
average pricing at December 31, 2009 as required by the
updated rules resulted in a decrease in proved reserves of
approximately 3,692 thousand barrels of oil equivalent, when
compared to reserves prepared under the previous rules. In
addition, at December 31, 2009, the new proved undeveloped
reserves rules resulted in a reduction of proved reserves of
approximately 750 barrels of oil due to the SEC’s new
five-year scheduling rule. The majority of the reserves
reclassified out of proved reserves were associated with smaller
secondary reserve waterflood projects.
Standardized
Measure
The following is a summary of a standardized measure of
discounted net cash flows related to the Company’s proved
oil and natural gas reserves. For these calculations, estimated
future cash flows from estimated future production of proved
reserves for the year ended December 31, 2010 and 2009 were
computed using benchmark prices based on the unweighted
arithmetic average of the
first-day-of-the-month
prices for oil and natural gas during each month of 2009, as
required by SEC Release
No. 33-8995,
“Modernization of Oil and Gas Reporting,” effective
December 31, 2009, while estimated cash flows for the years
ended December 31, 2008 were based on oil and natural gas
spot prices as of the end of the period presented. Future
development and production costs attributable to the proved
reserves were estimated assuming that existing conditions would
continue over the economic lives of the individual leases and
costs were not escalated for the future. Estimated future income
tax expenses were calculated by applying future statutory tax
rates (based on the current tax law adjusted for permanent
differences and tax credits) to the estimated future pretax net
cash flows related to proved oil and natural gas reserves, less
the tax basis of the properties involved.
The Company cautions against using this data to determine the
fair value of its oil and natural gas properties. To obtain the
best estimate of fair value of the oil and natural gas
properties, forecasts of future economic conditions, varying
discount rates, and consideration of other than proved reserves
would have to be incorporated into the calculation. In addition,
there are significant uncertainties inherent in estimating
quantities of proved reserves and in projecting rates of
production that impair the usefulness of the data.
The standardized measure of discounted future net cash flows
relating to proved oil and natural gas reserves at December 31
are summarized as follows (in thousands):
| 2010 | 2009 | 2008 | ||||||||||
|
Future cash inflows
|
$ | 1,355,233 | $ | 1,314,714 | $ | 1,253,537 | ||||||
|
Future production costs
|
(548,638 | ) | (535,784 | ) | (472,191 | ) | ||||||
|
Future development costs
|
(117,860 | ) | (148,956 | ) | (145,086 | ) | ||||||
|
Future income tax expenses
|
(161,736 | ) | (123,943 | ) | (103,434 | ) | ||||||
|
Future net cash flows
|
526,999 | 506,031 | 532,826 | |||||||||
|
10% annual discount for estimated timing of cash flows
|
(248,952 | ) | (231,797 | ) | (248,373 | ) | ||||||
|
Standardized measure of discounted future net cash flows
|
$ | 278,047 | $ | 274,234 | $ | 284,453 | ||||||
80
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
The following are the principal sources of change in the
standardized measure of discounted future net cash flows of the
Company for each of the three years in the period ended December
31 (in thousands):
| 2010 | 2009 | 2008 | ||||||||||
|
Standardized measure of discounted future net cash flows at
beginning of year
|
$ | 274,234 | $ | 284,453 | $ | 598,395 | ||||||
|
Changes during the year:
|
||||||||||||
|
Sales and transfers of oil and natural gas produced, net of
production costs
|
(71,028 | ) | (55,393 | ) | (134,180 | ) | ||||||
|
Net changes in prices and production costs
|
119,370 | 1,272 | (538,042 | ) | ||||||||
|
Extensions and discoveries, less related costs
|
13,888 | 31,264 | 77,239 | |||||||||
|
Development costs incurred and revisions
|
15,656 | 28,602 | (2,973 | ) | ||||||||
|
Sales of reserves in place
|
(25,267 | ) | (5,598 | ) | (5,143 | ) | ||||||
|
Purchases of reserves in place
|
— | — | 3,494 | |||||||||
|
Revisions of previous quantity estimates
|
(58,029 | ) | (18,323 | ) | (81,073 | ) | ||||||
|
Net change in income taxes
|
(24,382 | ) | (24,245 | ) | 275,581 | |||||||
|
Accretion of discount
|
33,605 | 32,202 | 91,155 | |||||||||
|
Net change
|
3,813 | (10,219 | ) | (313,942 | ) | |||||||
|
Standardized measure of discounted future net cash flows at end
of year
|
$ | 278,047 | $ | 274,234 | $ | 284,453 | ||||||
Prices used in computing these calculations of future cash flows
from estimated future production of proved reserves were $76.80,
$58.63, and $44.15 per barrel of oil at December 31, 2010,
2009, and 2008, respectively, $4.51, $3.76, and $5.33 per
thousand cubic feet of natural gas at December 31, 2010,
2009, and 2008, respectively and $45.62, $31.03, and $23.59 per
barrel of natural gas liquids at December 31, 2010, 2009,
and 2008, respectively.
N —
QUARTERLY DATA (UNAUDITED)
| 2010 — Quarter Ended | ||||||||||||||||
| December 31, | September 30, | June 30, | March 31, | |||||||||||||
| (In thousands except per share data) | ||||||||||||||||
|
Net revenue
|
$ | 25,362 | $ | 27,083 | $ | 28,968 | $ | 30,921 | ||||||||
|
Net operating expenses
|
22,244 | 21,068 | 22,237 | 21,066 | ||||||||||||
|
Operating income
|
3,118 | 6,015 | 6,731 | 9,855 | ||||||||||||
|
Interest expense
|
(5,539 | ) | (5,767 | ) | (5,714 | ) | (5,635 | ) | ||||||||
|
Interest income
|
3 | 20 | 2 | 2 | ||||||||||||
|
Other income (expense)
|
28 | (268 | ) | 570 | (9 | ) | ||||||||||
|
Income (loss) before income taxes
|
(2,390 | ) | — | 1,589 | 4,213 | |||||||||||
|
Income tax provision (benefit)
|
1,904 | (1,564 | ) | (1,140 | ) | 1,795 | ||||||||||
|
Net income (loss)
|
$ | (4,294 | ) | $ | 1,564 | $ | 2,729 | $ | 2,418 | |||||||
|
Basic net income (loss) applicable to common stockholders per
common share
|
$ | (0.05 | ) | $ | 0.02 | $ | 0.03 | $ | 0.03 | |||||||
|
Diluted net income (loss) applicable to common stockholders per
common share
|
$ | (0.05 | ) | $ | 0.02 | $ | 0.03 | $ | 0.03 | |||||||
81
Table of Contents
RAM
Energy Resources, Inc.
Notes to
consolidated financial
statements — (Continued)
| 2009 — Quarter Ended | ||||||||||||||||
| December 31, | September 30, | June 30, | March 31, | |||||||||||||
| (In thousands except per share data) | ||||||||||||||||
|
Net revenue
|
$ | 25,516 | $ | 25,131 | $ | 10,419 | $ | 26,012 | ||||||||
|
Net operating expenses
|
23,357 | 24,300 | 23,061 | 72,142 | ||||||||||||
|
Operating income (loss)
|
2,159 | 831 | (12,642 | ) | (46,130 | ) | ||||||||||
|
Interest expense
|
(5,820 | ) | (5,561 | ) | (3,601 | ) | (3,608 | ) | ||||||||
|
Interest income
|
13 | 40 | 9 | 20 | ||||||||||||
|
Other expense
|
89 | 10 | (106 | ) | (433 | ) | ||||||||||
|
Loss before income taxes
|
(3,559 | ) | (4,680 | ) | (16,340 | ) | (50,151 | ) | ||||||||
|
Income tax provision (benefit)
|
9,062 | (1,561 | ) | (3,055 | ) | (20,793 | ) | |||||||||
|
Net loss
|
$ | (12,621 | ) | $ | (3,119 | ) | $ | (13,285 | ) | $ | (29,358 | ) | ||||
|
Basic net loss applicable to common stockholders per common share
|
$ | (0.16 | ) | $ | (0.04 | ) | $ | (0.18 | ) | $ | (0.38 | ) | ||||
|
Diluted net loss applicable to common stockholders per common
share
|
$ | (0.16 | ) | $ | (0.04 | ) | $ | (0.18 | ) | $ | (0.38 | ) | ||||
82
Table of Contents
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
No items to report.
| Item 9A. | Controls and Procedures |
Conclusion
Regarding the Effectiveness of Disclosure Controls and
Procedures
Disclosure Controls and Procedures. We
maintain controls and procedures designed to ensure that
information required to be disclosed in the reports we file with
the U.S. Securities and Exchange Commission
(“SEC”), is recorded, processed, summarized and
reported within the time periods specified in the rules and
forms of the SEC and that such information is accumulated and
communicated to our management, including our Chief Executive
Officer and Chief Financial Officer, as appropriate, to allow
for timely decisions regarding required disclosure.
Our management, including our Chief Executive Officer and Chief
Financial Officer, does not expect that our disclosure controls
or our internal controls over financial reporting will prevent
all errors and all fraud. A control system, no matter how well
conceived and operated, can provide only reasonable, not
absolute, assurance that the objectives of the control system
are met. Further, the design of a control system must reflect
the fact that there are resource constraints, and the benefits
of controls must be considered relative to their costs. Because
of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all
control issues and instances of fraud, if any, within the
Company have been detected. These inherent limitations include
the realities that judgments in decision-making can be faulty,
and that simple errors or mistakes can occur. Additionally,
controls can be circumvented by the individual acts of some
persons, by collusion of two or more people, or by management
override of the control. The design of any system of controls
also is based, in part, upon certain assumptions about the
likelihood of future events, and there can be no assurance that
any design will succeed in achieving its stated goals under all
potential future conditions. Over time, controls may become
inadequate because of changes in conditions, or the degree of
compliance with the policies or procedures may deteriorate.
Because of the inherent limitations in a cost-effective control
system, misstatements due to error or fraud may occur and not be
detected. We monitor our disclosure controls and internal
controls and make modifications as necessary; our intent in this
regard is that the disclosure controls and the internal controls
will be maintained as systems change and conditions warrant.
An evaluation of the effectiveness of the design and operation
of our disclosure controls and procedures (as defined in
Rule 13a-15(e)
or
Rule 15d-15(e)
of the Securities Exchange Act) was performed as of the end of
the period covered by this report. This evaluation was performed
by our management, with the participation of our Chief Executive
Officer and Chief Financial Officer. Based on this evaluation,
our Chief Executive Officer and Chief Financial Officer
concluded that these controls and procedures were effective at
December 31, 2010.
Management’s Annual Report on Internal Control over
Financial Reporting. Our management is
responsible for establishing and maintaining effective internal
control over financial reporting as defined in
Rules 13a-15(f)
and
15-d15(f)
under the Securities Exchange Act of 1934. Our internal control
over financial reporting is designed to provide reasonable
assurance to our management and Board of Directors regarding the
preparation and fair presentation of published financial
statements. Our internal controls are designed to provide
reasonable assurance that our assets are protected from
unauthorized use and that transactions are executed in
accordance with established authorizations and properly
recorded. The internal controls are supported by written
policies and are complemented by a staff of competent business
process owners supported by competent and qualified external
resources used to assist in testing the operating effectiveness
of our internal control over financial reporting.
Our management, including our Chief Executive Officer and Chief
Financial Officer, assessed the effectiveness of our internal
control over financial reporting as of December 31, 2010.
In making this assessment, management used the criteria set
forth by the Committee of Sponsoring Organizations of the
Treadway Commission (“COSO”) in Internal
Control — Integrated Framework. Our management
concluded that the design and operations of our internal control
over financial reporting at December 31, 2010, were
83
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effective and provide reasonable assurance the books and records
accurately reflect the transactions of the Company.
There was no change in our internal control over financial
reporting during the year ended December 31, 2010, that
materially affected, or is reasonably likely to materially
affect, our internal control over financial reporting.
The effectiveness of our internal control over financial
reporting has been audited by UHY LLP, an independent registered
public accounting firm, as stated in their report which is
included herein.
|
/s/ Larry E. Lee Larry E. Lee Chairman, President and Chief Executive Officer March 16, 2011 |
/s/ G. Les Austin G. Les Austin Senior Vice President and Chief Financial Officer March 16, 2011 |
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REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
RAM Energy Resources, Inc.
We have audited RAM Energy Resources, Inc. (a Delaware
corporation) and subsidiaries’ internal control over
financial reporting as of December 31, 2010, based on
criteria established in Internal Control —
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The
Company’s management is responsible for maintaining
effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over
financial reporting. Our responsibility is to express an opinion
on the Company’s internal control over financial reporting
based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audits to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exist, testing and evaluating the
design and operating effectiveness of internal control and
performing such other procedures as we considered necessary in
the circumstances. We believe that our audit provides a
reasonable basis for our opinion.
A company’s internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, RAM Energy Resources, Inc. and subsidiaries
maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2010, based on
criteria established in Internal Control —
Integrated Framework issued by COSO.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of RAM Energy Resources, Inc. and
subsidiaries as of December 31, 2010 and 2009, and the
related consolidated statements of operations,
stockholders’ equity (deficit), and cash flows for each of
the three years in the period ended December 31, 2010, and
our report dated March 16, 2011, expressed an unqualified
opinion on those consolidated financial statements.
/s/ UHY
LLP
Houston, Texas
March 16, 2011
85
Table of Contents
| Item 9B. | Other Information |
No items to report.
PART III
| Item 10. | Directors, Executive Officers and Corporate Governance |
We have adopted a code of ethics that applies to all directors,
officers and employees, including our principal executive
officer and principal accounting officer. A copy of our code of
ethics is available on our website at www.ramenergy.com.
We intend to disclose any amendments to or waivers of our code
of ethics by posting the required information on our website,
www.ramenergy.com, or by filing a
Form 8-K
within the required time periods.
The information required by this item will be set forth in our
Definitive Proxy Statement on Schedule 14A relating to our
2011 Annual Meeting, which will be filed with the Securities and
Exchange Commission pursuant to Regulation 14A under the
Securities Exchange Act of 1934, as amended, (the “Proxy
Statement”). The Proxy Statement relates to a meeting of
stockholders involving the election of directors and the
portions therefrom required to be set forth in this
Form 10-K
by this item are incorporated herein by reference pursuant to
General Instruction G(3) to
Form 10-K.
| Item 11. | Executive Compensation |
The information required by this item will be set forth in the
Proxy Statement. The Proxy Statement relates to a meeting of
stockholders involving the election of directors and the
portions therefrom required to be set forth in this
Form 10-K
by this item are incorporated herein by reference pursuant to
General Instruction G(3) to
Form 10-K.
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The information required by this item will be set forth in the
Proxy Statement. The Proxy Statement relates to a meeting of
stockholders involving the election of directors and the
portions therefrom required to be set forth in this
Form 10-K
by this item are incorporated herein by reference pursuant to
General Instruction G(3) to
Form 10-K.
| Item 13. | Certain Relationships and Related Transactions and Director Independence |
The information required by this item will be set forth in the
Proxy Statement. The Proxy Statement relates to a meeting of
stockholders involving the election of directors and the
portions therefrom required to be set forth in this
Form 10-K
by this item are incorporated herein by reference pursuant to
General Instruction G(3) to
Form 10-K.
| Item 14. | Principal Accountant Fees and Services |
The information required by this item will be set forth in the
Proxy Statement. The Proxy Statement relates to a meeting of
stockholders involving the election of directors and the
portions therefrom required to be set forth in this
Form 10-K
by this item are incorporated herein by reference pursuant to
General Instruction G(3) to
Form 10-K.
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Table of Contents
PART IV
| Item 15. | Exhibits and Financial Statement Schedules |
(a) (1) The following consolidated financial
statements of RAM Energy Resources, Inc. are included in
Item 8:
RAM
Energy Resources, Inc.
|
Report of Independent Registered Public Accounting Firm
|
55 | |||
|
Consolidated Balance Sheets as of December 31, 2010 and 2009
|
56 | |||
|
Consolidated Statements of Operations for the years ended
December 31, 2010, 2009 and 2008
|
57 | |||
|
Consolidated Statements of Stockholders’ Equity (Deficit)
for the years ended December 31, 2010, 2009 and 2008
|
58 | |||
|
Consolidated Statements of Cash Flows for the years ended
December 31, 2010, 2009 and 2008
|
59 | |||
|
Notes to Consolidated Financial Statements
|
61 |
All other schedules have been omitted since the required
information is not present, or not present in amounts sufficient
to require submission of the schedule, or because the
information required is included in the consolidated financial
statements or notes thereto.
(a) (3) Exhibits
The following exhibits are filed as a part of this report:
|
Exhibit
|
Description
|
Method of Filing
|
||||
| 3 | .1 | Amended and Restated Certificate of Incorporation of the Registrant. | (1) [3.1] | |||
| 3 | .2 | Amended and Restated Bylaws of the Registrant. | (8) [3.2] | |||
| 10 | .1 | Form of Registration Rights Agreement among the Registrant and the Initial Stockholders. | (2) [10.9] | |||
| 10 | .1.1 | Amendment to Registration Rights Agreement among this Registrant and the Founders dated May 8, 2006. | (1) [10.9.1] | |||
| 10 | .2 | Employment Agreement between Registrant and Larry E. Lee dated May 8, 2006.* | (1) [10.15] | |||
| 10 | .2.1 | First Amendment to Employment Agreement between Registrant and Larry E. Lee dated October 18, 2006.* | (5) [10.1] | |||
| 10 | .2.2 | Second Amendment to Employment Agreement of Larry E. Lee dated February 25, 2008.* | (10) [10.6.2] | |||
| 10 | .6.3 | Third Amendment to Employment Agreement of Larry E. Lee dated December 30, 2008.* | (13) [10.6.3] | |||
| 10 | .2.4 | Fourth Amendment to Employment Agreement of Larry E. Lee dated March 24, 2009.* | (14) [10.6.4] | |||
| 10 | .2.5 | Fifth Amendment to Employment Agreement of Larry E. Lee dated March 17, 2010.* | (17) [10.6.5] | |||
| 10 | .2.6 | Sixth Amendment to Employment Agreement of Larry E. Lee dated March 8, 2011.* | (21) [10.2.6] | |||
| 10 | .3 | Escrow Agreement by and among the Registrant, Larry E. Lee and Continental Stock Transfer & Trust Company dated May 8, 2006. | (1) [10.16] | |||
| 10 | .4 | Registration Rights Agreement among Registrant and the investors signatory thereto dated May 8, 2006.* | (1) [10.7] | |||
| 10 | .5 | Form of Registration Rights Agreement among the Registrant and the Investors party thereto. | (3) [10.17] | |||
| 10 | .6 | Agreement between RAM and Shell Trading-US dated February 1, 2006. | (1) [10.22] | |||
| 10 | .7 | Agreement between RAM and Targa dated January 30, 1998. | (1) [10.23] | |||
87
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|
Exhibit
|
Description
|
Method of Filing
|
||||
| 10 | .7.1 | Amendment to Agreement between RAM Energy and Targa dated effective as of April 1, 2006, filed as an exhibit to Registrant’s Form 8-K dated June 5, 2006, and incorporated by reference herein. | (6) [10.23.1] | |||
| 10 | .8 | Long-Term Incentive Plan of the Registrant. Included as Annex C of the Registrant’s Definitive Proxy Statement (No. 000-50682), dated April 12, 2006, and incorporated by reference herein.* | (4) [Annex C] | |||
| 10 | .8.1 | First Amendment to the RAM Energy Resources, Inc. 2006 Long-Term Incentive Plan effective May 8, 2008.* | (11) [Exhibit A] | |||
| 10 | .8.2 | Second Amendment to the RAM Energy Resources, Inc. 2006 Long-Term Incentive Plan effective May 3, 2010.* | (18) [10.8.2] | |||
| 10 | .9 | Deferred Bonus Compensation Plan of RAM Energy, Inc. dated as of April 21, 2004.* | (7) [10.14] | |||
| 10 | .10 | Loan Agreement dated November 29, 2007, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders. | (9) [10.1] | |||
| 10 | .10.1 | First Amendment to Loan Agreement dated February 6, 2009, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders. | (15) [10.17.1] | |||
| 10 | .10.2 | Second Amendment to Loan Agreement dated June 26, 2009, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders. | (16) [10.17.2] | |||
| 10 | .10.3 | Third Amendment to Loan Agreement dated November 29, 2010, effective December 3, 2010, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders. | (20) [10.8.3] | |||
| 10 | .11 | Description of Compensation Arrangement with G. Les Austin.* | (12) [10.18] | |||
| 10 | .11.1 | First Amendment to Employment Agreement of G. Les Austin dated December 30, 2008.* | (13) [10.18.1] | |||
| 10 | .12 | Change in Control Separation Benefit Plan of Ram Energy Resources, Inc. and Participating Subsidiaries. | (15) [10.19] | |||
| 10 | .13 | Purchase and Sale Agreement dated October 29, 2010, by and between RWG Energy, Inc., as Seller, and Milagro Producing, LLC, as Buyer. | (19) [10.13] | |||
| 10 | .14 | Revolving Credit Agreement dated March 14, 2011 among RAM Energy Resources, Inc., as Borrower, SunTrust Bank, as Administrative Agent, Capital One, N.A., as Syndication Agent, and the financial institutions named therein as the Lenders | ** | |||
| 10 | .15 | Second Lien Term Loan Agreement dated March 14, 2011 among RAM Energy Resources, Inc., as Borrower, Guggenheim Corporate Funding, LLC, as Administrative Agent, and the financial institutions named therein as the Lenders | ** | |||
| 21 | .1 | Subsidiaries of the Registrant. | ** | |||
| 23 | .1 | Consent of UHY LLP. | ** | |||
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|
Exhibit
|
Description
|
Method of Filing
|
||||
| 23 | .2 | Consent of Forrest A. Garb & Associates, Inc. | ** | |||
| 31 | .1 | Rule 13(A) — 14(A) Certification of our Principal Executive Officer. | ** | |||
| 31 | .2 | Rule 13(A) — 14(A) Certification of our Principal Financial Officer. | ** | |||
| 32 | .1 | Section 1350 Certification of our Principal Executive Officer. | ** | |||
| 32 | .2 | Section 1350 Certification of our Principal Financial Officer. | ** | |||
| 99 | .1 | Report of Forrest A. Garb & Associates, Inc. | ** | |||
| * | Management contract or compensatory plan or arrangement. | |
| ** | Filed herewith. |
| (1) | Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on May 12, 2006, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (2) | Filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (SEC File No. 333-113583) as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (3) | Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on October 26, 2005, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (4) | Included as an annex to the Registrant’s Definitive Proxy Statement (No. 000-50682), dated April 12, 2006, as the annex letter indicated in brackets and incorporated by reference herein. | |
| (5) | Filed as an exhibit to the Registrant’s Current Report on Form 8-K on October 20, 2006, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (6) | Filed as an exhibit to the Registrant’s Current Report on Form 8-K on June 5, 2006, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (7) | Filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (SEC File No. 333-138922) as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (8) | Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on February 2, 2007, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (9) | Filed as an exhibit to Registrant’s Form 8-K dated November 29, 2007, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (10) | Filed as an exhibit to Registrant’s Form 8-K dated February 26, 2008, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (11) | Filed as an exhibit to Registrant’s Definitive Proxy Statement (No. 000-50682), dated April 14, 2008, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (12) | Filed as an exhibit to Registrant’s Form 10-Q dated May 9, 2008, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (13) | Filed as an exhibit to Registrant’s Form 8-K dated January 5, 2009, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (14) | Filed as an exhibit to Registrant’s Form 8-K dated March 25, 2009, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (15) | Filed as an exhibit to Registrant’s Annual Report on Form 10-K filed on March 12, 2009, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (16) | Filed as an exhibit to Registrant’s Form 8-K filed July 2, 2009, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (17) | Filed as an exhibit to Registrant’s Form 8-K filed March 18, 2010, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (18) | Filed as an exhibit to Registrant’s Form 8-K filed May 7, 2010, as the exhibit number indicated in brackets and incorporated by reference herein. |
89
Table of Contents
| (19) | Filed as an exhibit to Registrant’s Form 8-K filed November 2, 2010, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (20) | Filed as an exhibit to Registrant’s Form 8-K filed December 8, 2010, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (21) | Filed as an exhibit to Registrant’s Form 8-K filed March 10, 2011, as the exhibit number indicated in brackets and incorporated by reference herein. |
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Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized, in the City of Tulsa, State of
Oklahoma, on March 16, 2011.
RAM ENERGY RESOURCES, INC.
| By |
/s/ Larry
E. Lee
|
Larry E. Lee,
Chairman of the Board, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed by the following persons in
the capacities indicated, on March 16, 2011.
|
Signature
|
Title
|
|||
|
/s/ Larry
E. Lee Larry E. Lee |
Chairman of the Board, President and Chief Executive Officer and Director (Principal Executive Officer) | |||
|
/s/ G.
Les Austin G. Les Austin |
Senior Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) | |||
|
/s/ Sean
P. Lane Sean P. Lane |
Director | |||
|
/s/ Gerald
R. Marshall Gerald R. Marshall |
Director | |||
|
/s/ John
M. Reardon John M. Reardon |
Director | |||
91
Table of Contents
INDEX TO
EXHIBITS
|
Exhibit
|
Description
|
Method of Filing
|
||||
| 3 | .1 | Amended and Restated Certificate of Incorporation of the Registrant. | (1) [3.1] | |||
| 3 | .2 | Amended and Restated Bylaws of the Registrant. | (8) [3.2] | |||
| 10 | .1 | Form of Registration Rights Agreement among the Registrant and the Initial Stockholders. | (2) [10.9] | |||
| 10 | .1.1 | Amendment to Registration Rights Agreement among this Registrant and the Founders dated May 8, 2006. | (1) [10.9.1] | |||
| 10 | .2 | Employment Agreement between Registrant and Larry E. Lee dated May 8, 2006.* | (1) [10.15] | |||
| 10 | .2.1 | First Amendment to Employment Agreement between Registrant and Larry E. Lee dated October 18, 2006.* | (5) [10.1] | |||
| 10 | .2.2 | Second Amendment to Employment Agreement of Larry E. Lee dated February 25, 2008.* | (10) [10.6.2] | |||
| 10 | .6.3 | Third Amendment to Employment Agreement of Larry E. Lee dated December 30, 2008.* | (13) [10.6.3] | |||
| 10 | .2.4 | Fourth Amendment to Employment Agreement of Larry E. Lee dated March 24, 2009.* | (14) [10.6.4] | |||
| 10 | .2.5 | Fifth Amendment to Employment Agreement of Larry E. Lee dated March 17, 2010.* | (17) [10.6.5] | |||
| 10 | .2.6 | Sixth Amendment to Employment Agreement of Larry E. Lee dated March 8, 2011.* | (21) [10.2.6] | |||
| 10 | .3 | Escrow Agreement by and among the Registrant, Larry E. Lee and Continental Stock Transfer & Trust Company dated May 8, 2006. | (1) [10.16] | |||
| 10 | .4 | Registration Rights Agreement among Registrant and the investors signatory thereto dated May 8, 2006.* | (1) [10.7] | |||
| 10 | .5 | Form of Registration Rights Agreement among the Registrant and the Investors party thereto. | (3) [10.17] | |||
| 10 | .6 | Agreement between RAM and Shell Trading-US dated February 1, 2006. | (1) [10.22] | |||
| 10 | .7 | Agreement between RAM and Targa dated January 30, 1998. | (1) [10.23] | |||
| 10 | .7.1 | Amendment to Agreement between RAM Energy and Targa dated effective as of April 1, 2006, filed as an exhibit to Registrant’s Form 8-K dated June 5, 2006, and incorporated by reference herein. | (6) [10.23.1] | |||
| 10 | .8 | Long-Term Incentive Plan of the Registrant. Included as Annex C of the Registrant’s Definitive Proxy Statement (No. 000-50682), dated April 12, 2006, and incorporated by reference herein.* | (4) [Annex C] | |||
| 10 | .8.1 | First Amendment to the RAM Energy Resources, Inc. 2006 Long-Term Incentive Plan effective May 8, 2008.* | (11) [Exhibit A] | |||
| 10 | .8.2 | Second Amendment to the RAM Energy Resources, Inc. 2006 Long-Term Incentive Plan effective May 3, 2010.* | (18) [10.8.2] | |||
| 10 | .9 | Deferred Bonus Compensation Plan of RAM Energy, Inc. dated as of April 21, 2004.* | (7) [10.14] | |||
| 10 | .10 | Loan Agreement dated November 29, 2007, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders. | (9) [10.1] | |||
Table of Contents
|
Exhibit
|
Description
|
Method of Filing
|
||||
| 10 | .10.1 | First Amendment to Loan Agreement dated February 6, 2009, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders. | (15) [10.17.1] | |||
| 10 | .10.2 | Second Amendment to Loan Agreement dated June 26, 2009, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders. | (16) [10.17.2] | |||
| 10 | .10.3 | Third Amendment to Loan Agreement dated November 29, 2010, effective December 3, 2010, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders. | (20) [10.8.3] | |||
| 10 | .11 | Description of Compensation Arrangement with G. Les Austin.* | (12) [10.18] | |||
| 10 | .11.1 | First Amendment to Employment Agreement of G. Les Austin dated December 30, 2008.* | (13) [10.18.1] | |||
| 10 | .12 | Change in Control Separation Benefit Plan of Ram Energy Resources, Inc. and Participating Subsidiaries. | (15) [10.19] | |||
| 10 | .13 | Purchase and Sale Agreement dated October 29, 2010, by and between RWG Energy, Inc., as Seller, and Milagro Producing, LLC, as Buyer. | (19) [10.13] | |||
| 10 | .14 | Revolving Credit Agreement dated March 14, 2011 among RAM Energy Resources, Inc., as Borrower, SunTrust Bank, as Administrative Agent, Capital One, N.A., as Syndication Agent, and the financial institutions named therein as the Lenders | ** | |||
| 10 | .15 | Second Lien Term Loan Agreement dated March 14, 2011 among RAM Energy Resources, Inc., as Borrower, Guggenheim Corporate Funding, LLC, as Administrative Agent, and the financial institutions named therein as the Lenders | ** | |||
| 21 | .1 | Subsidiaries of the Registrant. | ** | |||
| 23 | .1 | Consent of UHY LLP. | ** | |||
| 23 | .2 | Consent of Forrest A. Garb & Associates, Inc. | ** | |||
| 31 | .1 | Rule 13(A) — 14(A) Certification of our Principal Executive Officer. | ** | |||
| 31 | .2 | Rule 13(A) — 14(A) Certification of our Principal Financial Officer. | ** | |||
| 32 | .1 | Section 1350 Certification of our Principal Executive Officer. | ** | |||
| 32 | .2 | Section 1350 Certification of our Principal Financial Officer. | ** | |||
| 99 | .1 | Report of Forrest A. Garb & Associates, Inc. | ** | |||
| * | Management contract or compensatory plan or arrangement. | |
| ** | Filed herewith. | |
| (1) | Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on May 12, 2006, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (2) | Filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (SEC File No. 333-113583) as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (3) | Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on October 26, 2005, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (4) | Included as an annex to the Registrant’s Definitive Proxy Statement (No. 000-50682), dated April 12, 2006, as the annex letter indicated in brackets and incorporated by reference herein. |
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| (5) | Filed as an exhibit to the Registrant’s Current Report on Form 8-K on October 20, 2006, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (6) | Filed as an exhibit to the Registrant’s Current Report on Form 8-K on June 5, 2006, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (7) | Filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (SEC File No. 333-138922) as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (8) | Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on February 2, 2007, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (9) | Filed as an exhibit to Registrant’s Form 8-K dated November 29, 2007, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (10) | Filed as an exhibit to Registrant’s Form 8-K dated February 26, 2008, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (11) | Filed as an exhibit to Registrant’s Definitive Proxy Statement (No. 000-50682), dated April 14, 2008, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (12) | Filed as an exhibit to Registrant’s Form 10-Q dated May 9, 2008, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (13) | Filed as an exhibit to Registrant’s Form 8-K dated January 5, 2009, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (14) | Filed as an exhibit to Registrant’s Form 8-K dated March 25, 2009, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (15) | Filed as an exhibit to Registrant’s Annual Report on Form 10-K filed on March 12, 2009, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (16) | Filed as an exhibit to Registrant’s Form 8-K filed July 2, 2009, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (17) | Filed as an exhibit to Registrant’s Form 8-K filed March 18, 2010, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (18) | Filed as an exhibit to Registrant’s Form 8-K filed May 7, 2010, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (19) | Filed as an exhibit to Registrant’s Form 8-K filed November 2, 2010, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (20) | Filed as an exhibit to Registrant’s Form 8-K filed December 8, 2010, as the exhibit number indicated in brackets and incorporated by reference herein. | |
| (21) | Filed as an exhibit to Registrant’s Form 8-K filed March 10, 2011, as the exhibit number indicated in brackets and incorporated by reference herein. |
