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EX-99 - EXHIBIT 99 - ARENA RESOURCES INC | arena_10k123109ex99.htm |
EX-31.1 - EXHIBIT 31.1 - ARENA RESOURCES INC | arena_10k123109ex311.htm |
EX-23.1 - EXHIBIT 23.1 - ARENA RESOURCES INC | arena_10k123109ex231.htm |
EX-31.2 - EXHIBIT 31.2 - ARENA RESOURCES INC | arena_10k123109ex312.htm |
EX-32.1 - EXHIBIT 32.1 - ARENA RESOURCES INC | arena_10k123109ex321.htm |
EX-23.2 - EXHIBIT 23.2 - ARENA RESOURCES INC | arena_10k123109ex232.htm |
EX-32.2 - EXHIBIT 32.2 - ARENA RESOURCES INC | arena_10k123109ex322.htm |
United
States Securities and Exchange Commission
Washington,
D.C. 20549
Form
10-K
(Mark
One)
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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
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For
the fiscal year ended December 31, 2009
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Or
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¨
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Transition
Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
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For
the transition period from ___________to ___________
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_____________________________
Commission
file number 001-31657
_____________________________
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Arena
Resources, Inc.
(Exact
name of registrant as specified in its
charter)
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Nevada
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73-1596109
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(State
or other jurisdiction of incorporation or organization)
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(I.R.S.
Employer Identification Number)
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6555
South Lewis Avenue
Tulsa,
Oklahoma
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74136
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(Address
of principal executive offices)
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(Zip
Code)
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(918)
747-6060
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(Registrant’s
telephone number, including area code)
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____________________________
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Securities
registered under Section 12(b) of the Exchange Act:
Title of Each Class
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Name of Each Exchange On Which
Registered
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Common
- $0.001 Par Value
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New
York Stock Exchange
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Securities
registered under Section 12(g) of the Exchange 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 þ No ¨
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or 15(d) of the Act. Yes ¨ 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 Exchange Act 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 ¨
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 during the preceding
12 months (or for such shorter period that the registrant was required to submit
and post such files). ¨ Yes ¨ No þ Not
Applicable
1
Indicate
by check mark if disclosure of delinquent filers in response to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to
the best of registrant’s knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. ¨
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer or a non-accelerated filer.
Large
accelerated filer þ Accelerated
filer ¨ Non-accelerated filer ¨
Indicate
by check mark whether the registrant is shell company (as defined in Rule 12b-2
of the Act). Yes ¨ No þ
As of
June 30, 2009, the aggregate market value of the common voting stock held by
non-affiliates of the issuer, based upon the closing stock price of $31.85 per
share, was approximately $1,195,116,500.
As of
March 1, 2010, the issuer had outstanding 38,793,963 shares of common stock
($0.001 par value).
2
TABLE
OF CONTENTS
PART
I
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Page
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Item
1
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Business
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4
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Item
1A
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Risk
Factors
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8
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Item
1B
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Unresolved
Staff Comments
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14
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Item
2
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Properties
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14
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Item
3
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Legal
Proceedings
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25
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Item
4
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Submission
of Matters to a Vote of Security Holders
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25
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PART
II
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Item
5
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Market
for Registrant's Common Equity, Related Stockholder
Matters
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27
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and
Issuer Purchases of Equity Securities
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Item
6
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Selected
Financial Data
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28
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Item
7
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Management's
Discussion and Analysis of Financial Condition
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28
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and
Results of Operations
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Item
7A
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Quantitative
and Qualitative Disclosures About Market Risk
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36
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Item
8
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Financial
Statements and Supplementary Data
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36
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Item
9
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Changes
in and Disagreement's With Accountants on Accounting
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36
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and
Financial Disclosure
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Item
9A
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Controls
and Procedures
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37
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Item
9B
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Other
Information
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39
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PART
III
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Item
10
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Directors,
Executive Officers and Corporate Governance
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40
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Item
11
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Executive
Compensation
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43
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Item
12
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Security
Ownership of Certain Beneficial Owners and Management
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49
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and
Related Stockholder Matters
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Item
13
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Certain
Relationships and Related Transactions, and Director
Independence
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51
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Item
14
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Principal
Accounting Fees and Services
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51
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PART
IV
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Item
15
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Exhibits
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52
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3
Forward
Looking Statements
All
statements, other than statements of historical fact included in this Annual
Report on Form 10-K (herein, “Annual 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 Annual 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. All forward-looking statements speak
only as of the date of this Annual 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 Annual 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,” “Management’s Discussion
and Analysis of Financial Condition and Results of Operations” and elsewhere in
this Annual Report. These cautionary statements qualify all forward-looking
statements attributable to us or persons acting on our behalf.
Unless
the context otherwise requires, references in this Annual Report to “Arena,”
“we,” “us,” “our” or “ours” refer to Arena Resources, Inc.
PART
I
Item
1: Business
General
Arena Resources, Inc. was incorporated
in Nevada on August 31, 2000. Our principal executive offices are located at
6555 South Lewis Avenue, Tulsa, Oklahoma 74136, and our telephone number is
(918) 747-6060. Our Internet website can be found at
www.arenaresourcesinc.com. Our annual reports 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 Exchange
Act of 1934 will be available through our Internet website as soon as reasonably
practical after we electronically file such material with, or furnish it to, the
Securities and Exchange Commission.
We are
engaged in oil and natural gas acquisition, exploration, development and
production, with activities currently in Oklahoma, Texas, New Mexico and
Kansas. Our focus will be on developing our existing properties,
while continuing to pursue acquisitions of oil and gas properties with upside
potential.
Business
Development
Between
our inception in August 2000 through 2004, we built our asset base and achieved
growth primarily through property acquisitions. Beginning in 2005,
while we continued to grow through acquisition, we shifted our focus to growth
through development of our existing properties. From our inception
through December 31, 2009, we have increased our proved reserves to
approximately 69.5 million Boe (barrel of oil equivalent). As of
December 31, 2009, our estimated proved reserves had a pre-tax PV10 (present
value of future net revenues before income taxes discounted at 10%) of
approximately $1.12 billion and a Standardized Measure of Discounted Future Net
Cash Flows of approximately $754.2 million. The difference between
these two amounts is the effect of income taxes. The Company presents
the pre-tax PV-10 value, which is a non-GAAP financial measure, because it is a
widely used industry standard which we believe is useful to those who may review
this Annual Report when comparing our asset base and performance to other
comparable oil and gas exploration and production companies. We spent
approximately $485.6 million on acquisitions and capital projects during 2007,
2008 and 2009.
4
We have a
portfolio of oil and natural gas reserves, with approximately 86% of our proved
reserves consisting of oil and approximately 14% consisting of natural gas. Of
those reserves approximately 33% of our proved reserves are classified as proved
developed producing, or “PDP,” approximately 5% of our proved reserves are
classified as proved developed behind pipe, or “PDBP,” and approximately 62% are
classified as proved undeveloped, or “PUD.”
Competitive
Business Conditions
We
operate in a highly competitive environment for acquiring properties, marketing
oil and natural gas and securing trained personnel. Some of our competitors
possess and employ financial resources substantially greater than ours and some
of our competitors employ more technical personnel. These factors can
be particularly important in the areas in which we operate. Those
companies may be able to pay more for productive oil and natural gas properties
and exploratory prospects and to evaluate, bid for and purchase a greater number
of properties and prospects than what our financial or technical resources
permit. Our ability to acquire additional properties and to find and develop
reserves in the future will depend on our ability to identify, evaluate and
select suitable properties and to consummate transactions in a highly
competitive environment. Also, there is substantial competition for capital
available for investment in the oil and natural gas industry.
The
actual price range of crude oil is largely established by major crude oil
purchasers and commodities trading. Pricing for natural gas is based
on regional supply and demand conditions. To this extent we believe
we receive oil and gas prices comparable to other producers. There is
little risk in our ability to sell all our current production at current prices
with a reasonable profit margin. The risk of domestic overproduction
at current prices is not deemed significant. We view our primary
pricing risk to be related to a potential decline in prices to a level which
could render our current production uneconomical.
We are presently committed to use the
services of the existing gathering systems of the companies that purchase our
natural gas production. This commitment is tied to existing natural
gas purchase contracts associated with our production This commitment
potentially gives such gathering companies certain short-term relative
monopolistic powers to set gathering and transportation costs, because obtaining
the services of an alternative gathering company would require substantial
additional costs (since an alternative gathering company would be required to
lay new pipeline and/or obtain new rights of way to any lease from which we are
selling production). We are not subject to third party gathering
systems for our oil production. Some of our oil production is sold
through a third party pipeline which has no regional competition. All
other oil production is transported by the oil purchaser by trucks with
competitive trucking costs in the area.
Major
Customers
We
principally sell our oil and natural gas production to end users, marketers and
other purchasers that have access to nearby pipeline facilities. In areas where
there is no practical access to pipelines, oil is trucked to storage facilities.
Our marketing of oil and natural gas can be affected by factors beyond our
control, the effects of which cannot be accurately predicted. For fiscal year
2009, sales to three customers, Navajo Refining Company, ConocoPhillips and DCP
Midstream, LP, represented 75%, 13% and 8% of oil and gas revenues,
respectively. At December 31, 2009, these customers represented 74%,
14% and 7% of our accounts receivable. However, we believe that the
loss of these customers would not materially impact our business, because we
could readily find other purchasers for our oil and gas as
produced.
5
Delivery
Commitments
As of
December 31, 2009, we are not committed to providing a fixed quantity of oil or
gas under any existing contracts.
Governmental
Regulations
Regulation
of Transportation of Oil
Sales of
crude oil, condensate and natural gas liquids are not currently regulated and
are made at negotiated prices. Nevertheless, Congress could reenact price
controls in the future.
Our sales
of crude oil are affected by the availability, terms and cost of
transportation. The transportation of oil in common carrier pipelines
is also subject to rate regulation. The Federal Energy Regulatory
Commission, or the FERC, regulates interstate oil pipeline transportation rates
under the Interstate Commerce Act. Intrastate oil pipeline
transportation rates are subject to regulation by state regulatory
commissions. The basis for intrastate oil pipeline regulation, and
the degree of regulatory oversight and scrutiny given to intrastate oil pipeline
rates, varies from state to state.
Insofar
as effective interstate and intrastate rates are equally applicable to all
comparable shippers, we believe that the regulation of oil transportation rates
will not affect our operations in any way that is of material difference from
those of our competitors. Further, interstate and intrastate common
carrier oil pipelines must provide service on a non-discriminatory
basis. Under this open access standard, common carriers must offer
service to all shippers requesting service on the same terms and under the same
rates. When oil pipelines operate at full capacity, access is
governed by pro-rationing provisions set forth in the pipelines’ published
tariffs. Accordingly, we believe that access to oil pipeline
transportation services generally will be available to us to the same extent as
to our competitors.
Regulation
of Transportation and Sale of Natural Gas
Historically,
the transportation and sale for resale of natural gas in interstate commerce
have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas
Policy Act of 1978 and regulations issued under those Acts by the FERC. In the
past, the federal government has regulated the prices at which natural gas could
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.
Since
1985, the FERC has endeavored to make natural gas transportation more accessible
to natural gas buyers and sellers on an open and non-discriminatory basis. The
FERC has stated that open access policies are necessary to improve the
competitive structure of the interstate natural gas pipeline industry and to
create a regulatory framework that will put natural gas sellers into more direct
contractual relations with natural gas buyers by, among other things, unbundling
the sale of natural gas from the sale of transportation and storage
services. Although the FERC’s orders do not directly regulate natural
gas producers, they are intended to foster increased competition within all
phases of the natural gas industry.
We cannot
accurately predict whether the FERC’s actions will achieve the goal of
increasing competition in markets in which our natural gas is
sold. Therefore, we cannot provide any assurance that the less
stringent regulatory approach established by the FERC will continue. However, we
do not believe that any action taken will affect us in a way that materially
differs from the way it affects other natural gas producers.
Intrastate
natural gas transportation is subject to regulation by state regulatory
agencies. The basis for intrastate regulation of natural gas transportation and
the degree of regulatory oversight and scrutiny given to intrastate natural gas
pipeline rates and services varies from state to state. Insofar as such
regulation within a particular state will generally affect all intrastate
natural gas shippers within the state on a comparable basis, we believe that the
regulation of similarly situated intrastate natural gas transportation in any
states in which we operate and ship natural gas on an intrastate basis will not
affect our operations in any way that is of material difference from those of
our competitors.
6
Regulation
of Production
The
production of oil and natural gas is subject to regulation under a wide range of
local, state and federal statutes, rules, orders and regulations. Federal, state
and local statutes and regulations require permits for drilling operations,
drilling bonds and reports concerning operations. All of the states in which we
own and operate properties have regulations governing conservation matters,
including provisions for the unitization or pooling of oil and natural gas
properties, the establishment of maximum allowable rates of production from oil
and natural gas wells, the regulation of well spacing, and plugging and
abandonment of wells. The effect of these regulations is to limit the amount of
oil and natural gas that we can produce from our wells and to limit the number
of wells or the locations at which we can drill, although we can apply for
exceptions to such regulations or to have reductions in well spacing. Moreover,
each state generally imposes a production or severance tax with respect to the
production and sale of oil, natural gas and natural gas liquids within its
jurisdiction.
The
failure to comply with these rules and regulations can result in substantial
penalties. Our competitors in the oil and natural gas industry are subject to
the same regulatory requirements and restrictions that affect our
operations.
Environmental
Compliance and Risks
Our oil and natural gas exploration,
development and production operations are subject to stringent federal, state
and local laws and regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection. Historically,
most of the environmental regulation of oil and gas production has been left to
state regulatory boards or agencies in those jurisdictions where there is
significant gas and oil production, with limited direct regulation by such
federal agencies as the Environmental Protection Agency. However,
while we believe this generally to be the case for our production activities in
Oklahoma, Texas, New Mexico and Kansas, there are various regulations issued by
the Environmental Protection Agency (“EPA”) and other governmental agencies that
would govern significant spills, blow-outs, or uncontrolled
emissions.
In
Oklahoma, Texas, New Mexico and Kansas specific oil and gas regulations apply to
the drilling, completion and operations of wells, and the disposal of waste oil
and salt water. There are also procedures incident to the plugging
and abandonment of dry holes or other non-operational wells, all as governed by
the applicable governing state agency.
At the federal level, among the more
significant laws and regulations that may affect our business and the oil and
gas industry are: The Comprehensive Environmental Response,
Compensation and Liability Act of 1980, also known as “CERCLA” or “Superfund;
the Oil Pollution Act of 1990; the Resource Conservation and Recovery Act, also
known as “RCRA,”; the Clean Air Act; Federal Water Pollution Control Act of
1972, or the Clean Water Act; and the Safe Drinking Water Act of
1974.
Compliance with these regulations may
constitute a significant cost and effort for us. No specific
accounting for environmental compliance has been maintained or projected by us
at this time. We are not presently aware of any environmental
demands, claims, or adverse actions, litigation or administrative proceedings in
which either we or our acquired properties are involved in or subject to, or
arising out of any predecessor operations.
In the
event of a breach of environmental regulations, these environmental regulatory
agencies have a broad range of alternative or cumulative remedies which
include: ordering a clean-up of any spills or waste material and
restoration of the soil or water to conditions existing prior to the
environmental violation; fines; or enjoining further drilling, completion or
production activities. In certain egregious situations the agencies
may also pursue criminal remedies against us or our principal
officers.
7
Current
Employees
As of
December 31, 2009, we had 120 full-time employees, including 48 employed by
Arena Drilling Company, a wholly owned subsidiary. Our employees are not
represented by any labor union. We consider our relations with our employees to
be satisfactory and have never experienced a work stoppage or
strike.
We retain
certain engineers, geologists, landmen, pumpers and other personnel on a
contract or fee basis as necessary for our operations.
Item
1A. Risk
Factors
The
following risks and uncertainties may affect our performance, results of
operations and the trading price of our common stock.
Risks
Relating to the Oil and Natural Gas Industry and Our Business
A
substantial or extended decline in oil and natural gas prices may adversely
affect our business, financial condition or results of operations and our
ability to meet our capital expenditure obligations and financial
commitments.
The price
we receive for our oil and natural gas production heavily influences our
revenue, profitability, access to capital and future rate of growth. Oil and
natural gas are commodities and, therefore, their prices are subject to wide
fluctuations in response to relatively minor changes in supply and demand.
Historically, the markets for oil and natural gas have been volatile. These
markets will likely continue to be volatile in the future. The prices we receive
for our production, and the levels of our production, depend on numerous factors
beyond our control. These factors include, but are not limited to, the
following:
• changes in global supply
and demand for oil and natural gas;
• the actions of the
Organization of Petroleum Exporting Countries, or OPEC;
• the price and quantity of
imports of foreign oil and natural gas;
• political conditions,
including embargoes, in or affecting other oil-producing activity;
• the level of global oil
and natural gas exploration and production activity;
• the level of global oil
and natural gas inventories;
• weather
conditions;
• technological advances
affecting energy consumption; and
• the price and availability
of alternative fuels.
Lower oil
and natural gas prices may not only decrease our revenues on a per unit basis
but also may reduce the amount of oil and natural gas that we can produce
economically. Lower prices will also negatively impact the value of our proved
reserves. A substantial or extended decline in oil or natural gas prices may
materially and adversely affect our future business, financial condition,
results of operations, liquidity or ability to finance planned capital
expenditures.
8
A
substantial percentage of our proven properties are undeveloped; therefore the
risk associated with our success is greater than would be the case if the
majority of our properties were categorized as proved developed
producing.
Because a
substantial percentage of our proven properties are proved undeveloped
(approximately 62%) or proved developed behind pipe (approximately 5%), we will
require significant additional capital to develop such properties before they
may become productive. Further, because of the inherent uncertainties associated
with drilling for oil and gas, some of these properties may never be developed
to the extent that they result in positive cash flow. Even if we are successful
in our development efforts, it could take several years for a significant
portion of our undeveloped properties to be converted to positive cash
flow.
While our
current business plan is to fund the development costs with cash flow from our
other producing properties, if such cash flow is not sufficient we may be forced
to seek alternative sources for cash, through the issuance of additional equity
or debt securities, increased borrowings or other means.
Approximately
23% of our proven reserves depend upon secondary recovery techniques to
establish production.
Approximately
twenty-three percent (23%) of our reserves for the year ended December 31, 2009
are associated with secondary recovery projects that are either in the initial
stage of implementation or are scheduled for implementation. We
anticipate that secondary recovery will be attempted by the use of waterflood of
these reserves, and the exact project initiation dates and, by the very nature
of waterflood operations, the exact completion dates of such projects are
uncertain. In addition, the reserves associated with these secondary
recovery projects, as with any reserves, are estimates only, as the success of
any development project, including these waterflood projects, cannot be
ascertained in advance. If we are not successful in developing a
significant portion of our reserves associated with secondary recovery methods,
it could have a negative impact on our earnings and our stock
price.
Drilling
for and producing oil and natural gas are high risk activities with many
uncertainties that could adversely affect our business, financial condition or
results of operations.
Our
future success will depend on the success of our exploitation, exploration,
development and production activities. Our oil and natural gas exploration and
production activities are subject to numerous risks beyond our control;
including the risk that drilling will not result in commercially viable oil or
natural gas production. Our decisions to purchase, explore, develop or otherwise
exploit prospects or properties will depend in part on the evaluation of data
obtained through geophysical and geological analyses, production data and
engineering studies, the results of which are often inconclusive or subject to
varying interpretations. Please read “—Reserve estimates depend on many
assumptions that may turn out to be inaccurate” (below) for a discussion of the
uncertainty involved in these processes. Our cost of drilling, completing and
operating wells is often uncertain before drilling commences. Overruns in
budgeted expenditures are common risks that can make a particular project
uneconomical. Further, many factors may curtail, delay or cancel drilling,
including the following:
• delays imposed by or
resulting from compliance with regulatory requirements;
• pressure or irregularities
in geological formations;
• shortages of or delays in
obtaining equipment and qualified personnel;
• equipment failures or
accidents;
• adverse weather
conditions;
• reductions in oil and
natural gas prices;
• title problems;
and
• limitations in the market
for oil and natural gas.
9
If
our assessments of recently purchased properties are materially inaccurate, it
could have significant impact on future operations and earnings.
We
have aggressively expanded our base of producing properties. The successful
acquisition of producing properties requires assessments of many factors, which
are inherently inexact and may be inaccurate, including the following:
• the amount of recoverable
reserves;
• future oil and natural gas
prices;
• estimates of operating
costs;
• estimates of future
development costs;
• estimates of the costs and
timing of plugging and abandonment; and
• potential environmental
and other liabilities.
Our
assessment will not 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. As noted previously, we plan to undertake further
development of our properties through the use of cash flow from existing
production. Therefore, a material deviation in our assessments of these factors
could result in less cash flow being available for such purposes than we
presently anticipate, which could either delay future development operations
(and delay the anticipated conversion of reserves into cash), or cause us to
seek alternative sources to finance development activities.
Decreases
in oil and natural gas prices may require us to take write-downs of the carrying
values of our oil and natural gas properties, potentially requiring earlier than
anticipated debt repayment and negatively impacting the trading value of our
securities.
Accounting
rules require that we review periodically the carrying value of our oil and
natural gas properties for possible impairment. Based on specific market factors
and circumstances at the time of prospective impairment reviews, and the
continuing evaluation of development plans, production data, economics and other
factors, we may be required to write down the carrying value of our oil and
natural gas properties. Because our properties serve as collateral for advances
under our existing credit facilities, a write-down in the carrying values of our
properties could require us to repay debt earlier than we would otherwise be
required. A write-down could also constitute a non-cash charge to earnings. It
is likely the cumulative effect of a write-down could also negatively impact the
trading price of our securities.
Reserve
estimates depend on many assumptions that may turn out to be inaccurate. Any
material inaccuracies in these reserve estimates or underlying assumptions will
materially affect the quantities and present value of our reserves.
The
process of estimating oil and natural gas reserves is complex. It requires
interpretations of available technical data and many assumptions, including
assumptions relating to economic factors. Any significant inaccuracies in these
interpretations or assumptions could materially affect the estimated quantities
and present value of our reported reserves.
In order
to prepare our estimates, we must project production rates and timing of
development expenditures. We must also analyze available geological,
geophysical, production and engineering data. The extent, quality and
reliability of this data can vary. The process also requires economic
assumptions about matters such as oil and natural gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds.
Therefore, estimates of oil and natural gas reserves are inherently
imprecise.
Actual
future production, oil and natural gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and natural
gas reserves most likely will vary from our estimates. Any significant variance
could materially affect the estimated quantities and present value of our
reported reserves. In addition, we may adjust estimates of proved reserves to
reflect production history, results of exploration and development, prevailing
oil and natural gas prices and other factors, many of which are beyond our
control.
10
You
should not assume that the present value of future net revenues from our
reported proved reserves is the current market value of our estimated oil and
natural gas reserves. In accordance with SEC requirements, we generally base the
estimated discounted future net cash flows from our proved reserves on prices
and costs on the date of the estimate. Actual future prices and costs may differ
materially from those used in the present value estimate. If future values
decline or costs increase it could negatively impact our ability to finance
operations, and individual properties could cease being commercially viable,
affecting our decision to continue operations on producing properties or to
attempt to develop properties. All of these factors would have a negative impact
on earnings and net income, and most likely the trading price of our securities.
These factors could also result in the acceleration of debt repayment and a
reduction in our borrowing base under our credit facilities.
Prospects
that we decide to drill may not yield oil or natural gas in commercially viable
quantities.
Our
prospects are in various stages of evaluation, ranging from prospects that are
currently being drilled, to prospects that will require substantial additional
seismic data processing and interpretation. There is no way to predict in
advance of drilling and testing whether any particular prospect will yield oil
or natural gas in sufficient quantities to recover drilling or completion costs
or to be economically viable. This risk may be enhanced in our situation, due to
the fact that a significant percentage (62%) of our proved reserves is currently
proved undeveloped reserves. The use of seismic data and other technologies and
the study of producing fields in the same area will not enable us to know
conclusively prior to drilling whether oil or natural gas will be present or, if
present, whether oil or natural gas will be present in commercial quantities. We
cannot assure you that the analogies we draw from available data from other
wells, more fully explored prospects or producing fields will be applicable to
our drilling prospects.
We
may incur substantial losses and be subject to substantial liability claims as a
result of our oil and natural gas operations.
We are
not insured against all risks. Losses and liabilities arising from uninsured and
underinsured events could materially and adversely affect our business,
financial condition or results of operations. Our oil and natural gas
exploration and production activities are subject to all of the operating risks
associated with drilling for and producing oil and natural gas, including the
possibility of:
•
environmental hazards, such as uncontrollable flows of oil, natural gas, brine,
well fluids, toxic gas or other pollution into the environment, including
groundwater and shoreline contamination;
• abnormally
pressured formations;
• mechanical
difficulties, such as stuck oil field drilling and service tools and casing
collapse;
• fires
and explosions;
• personal
injuries and death; and
• natural
disasters.
Any of
these risks could adversely affect our ability to conduct operations or result
in substantial losses to our company. We may elect not to obtain insurance if we
believe that the cost of available insurance is excessive relative to the risks
presented. In addition, pollution and environmental risks generally are not
fully insurable. If a significant accident or other event occurs and is not
fully covered by insurance, then it could adversely affect us.
11
We
are subject to complex laws that can affect the cost, manner or feasibility of
doing business.
Exploration,
development, production and sale of oil and natural gas are subject to extensive
federal, state, local and international regulation. We may be required to make
large expenditures to comply with governmental regulations. Matters subject to
regulation include:
• discharge permits for
drilling operations;
• drilling
bonds;
• reports concerning
operations;
• the spacing of
wells;
• unitization and pooling of
properties; and
• taxation.
Under
these laws, we could be liable for personal injuries, property damage and other
damages. Failure to comply with these laws also may result in the suspension or
termination of our operations and subject us to administrative, civil and
criminal penalties. Moreover, these laws could change in ways that substantially
increase our costs. Any such liabilities, penalties, suspensions, terminations
or regulatory changes could materially adversely affect our financial condition
and results of operations.
Our
operations may incur substantial liabilities to comply with the environmental
laws and regulations.
Our oil
and natural gas operations are subject to stringent federal, state and local
laws and regulations relating to the release or disposal of materials into the
environment or otherwise relating to environmental protection. These laws and
regulations may require the acquisition of a permit before drilling commences,
restrict the types, quantities and concentration of substances that can be
released into the environment in connection with drilling and production
activities, limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas, and impose substantial
liabilities for pollution resulting from our operations. Failure to comply with
these laws and regulations may result in the assessment of administrative, civil
and criminal penalties, incurrence of investigatory or remedial obligations or
the imposition of injunctive relief. Changes in environmental laws and
regulations occur frequently, and any changes that result in more stringent or
costly waste handling, storage, transport, disposal or cleanup requirements
could require us to make significant expenditures to maintain compliance, and
may otherwise have a material adverse effect on our results of operations,
competitive position or financial condition as well as the industry in general.
Under these environmental laws and regulations, we could be held strictly liable
for the removal or remediation of previously released materials or property
contamination regardless of whether we were responsible for the release or if
our operations were standard in the industry at the time they were
performed.
If
our indebtedness increases, it could reduce our financial
flexibility.
We have a
$150 million credit facility in place with a current borrowing base of $75
million and the structure in place to increase that borrowing base an additional
$75 million. As of December 31, 2009, no amount was outstanding on
our credit facility. If in the future we utilize this facility, the
level of our indebtedness could affect our operations in several ways, including
the following:
|
•
a
significant portion of our cash flow could be used to service the
indebtedness,
|
|
•
a
high level of debt would increase our vulnerability to general adverse
economic and industry
conditions,
|
|
•
the
covenants contained in our credit facility limit our ability to borrow
additional funds, dispose of assets, pay dividends and make certain
investments,
|
|
•
a
high level of debt could impair our ability to obtain additional financing
in the future for working capital, capital expenditures, acquisitions,
general corporate or other
purposes.
|
12
In
addition, our bank borrowing base is subject to semi-annual redeterminations. We
could be forced to repay a portion of our bank borrowings due to
redeterminations of our borrowing base. If we are forced to do so, we may not
have sufficient funds to make such repayments. If we do not have sufficient
funds and are otherwise unable to negotiate renewals of our borrowings or
arrange new financing, we may have to sell significant assets. Any such sale
could have a material adverse effect on our business and financial
results.
Unless
we replace our oil and natural gas reserves, our reserves and production will
decline, which would adversely affect our cash flows and income.
Unless we
conduct successful development, exploitation and exploration activities or
acquire properties containing proved reserves, our proved reserves will decline
as those reserves are produced. Producing oil and natural gas reservoirs
generally are characterized by declining production rates that vary depending
upon reservoir characteristics and other factors. Our future oil and natural gas
reserves and production, and, therefore our cash flow and income, are highly
dependent on our success in efficiently developing and exploiting our current
reserves and economically finding or acquiring additional recoverable reserves.
If we are unable to develop, exploit, find or acquire additional reserves to
replace our current and future production, our cash flow and income will decline
as production declines, until our existing properties would be incapable of
sustaining commercial production.
If
our access to markets is restricted, it could negatively impact our production,
our income and ultimately our ability to retain our leases.
Market
conditions or the unavailability of satisfactory oil and natural gas
transportation arrangements may hinder our access to oil and natural gas markets
or delay our production. The availability of a ready market for our oil and
natural gas production depends on a number of factors, including the demand for
and supply of oil and natural gas and the proximity of reserves to pipelines and
terminal facilities. Our ability to market our production depends in substantial
part on the availability and capacity of gathering systems, pipelines and
processing facilities owned and operated by third parties. Our failure to obtain
such services on acceptable terms could materially harm our
business.
Currently,
the majority of our production is sold to marketers and other purchasers that
have access to nearby pipeline facilities. However, as we begin to further
develop our properties, we may find production in areas with limited or no
access to pipelines, thereby necessitating delivery by other means, such as
trucking, or requiring compression facilities. Such restrictions on our ability
to sell our oil or natural gas have several adverse affects, including higher
transportation costs, fewer potential purchasers (thereby potentially resulting
in a lower selling price) or, in the event we were unable to market and sustain
production from a particular lease for an extended time, possibly causing us to
lose a lease due to lack of production.
Hedging
transactions may limit our potential gains.
In order
to reduce commodity price uncertainty and increase cash flow predictability
relating to the marketing of our crude oil and natural gas, we enter into crude
oil and natural gas price hedging arrangements with respect to a portion of our
expected production. Our hedges, consisting of a series of contracts, are
limited in duration, usually for periods of one to three years. While intended
to reduce the effects of volatile crude oil and natural gas prices, such
transactions may limit our potential gains if crude oil and natural gas prices
rise over the price established by the arrangements.
13
Risks
Relating to Our Common Stock
We
have no plans to pay dividends on our common stock. You may not receive funds
without selling your shares.
We do not
anticipate paying any cash dividends on our common stock in the foreseeable
future. We currently intend to retain future earnings, if any, to finance the
expansion of our business. Our future dividend policy is within the discretion
of our board of directors and will depend upon various factors, including our
business, financial condition, results of operations, capital requirements and
investment opportunities. In addition, our credit facility prohibits us from
paying dividends.
Provisions
under Nevada law could delay or prevent a change in control of our company,
which could adversely affect the price of our common stock.
While we do not believe that we
currently have any provisions in our organizational documents that could prevent
or delay a change in control of our company (such as provisions calling for a
staggered board of directors, or the issuance of stock with super-majority
voting rights), the existence of some provisions under Nevada law could delay or
prevent a change in control of our company, which could adversely affect the
price of our common stock. Nevada law imposes some restrictions on mergers and
other business combinations between us and any holder of 10% or more of our
outstanding common stock.
Item
1B: Unresolved Staff
Comments
None.
Item
2: Properties
General
Background
From our
inception in August 2000 through 2004, we built our asset base and achieved
growth primarily through property acquisitions. Beginning in 2005,
while we have continued to grow through acquisition, we have shifted our focus
to growth through development of our existing properties.
As of
December 31, 2009, our estimated proved reserves had a pre-tax PV10 value of
approximately $1.12 billion and a Standardized Measure of Discounted Future Cash
Flows of approximately $754.2 million, approximately 80% of which relate to our
properties in Texas, approximately 15% of which relate to our properties located
in New Mexico, approximately 4% relate to our properties in Oklahoma and less
than 1% relate to our properties in Kansas. We spent approximately $485.6
million on acquisitions and capital projects during 2007, 2008 and
2009. We expect to further develop these properties through
additional drilling. We will closely manage our capital expenditures
to our cash flow. As commodity prices change we will consider
the resulting impact on our cash flow and adjust our capital expenditures up or
down accordingly. We have maintained a strong current cash position
with no long-term debt; we will continue to seek acquisition opportunities that
complement our core assets.
14
The
following table summarizes our total net proved reserves, pre-tax PV10 value and
Standardized Measure of Discounted Future Net Cash Flows as of December 31,
2009.
Geographic
Area
|
Oil
(Bbl)
|
Natural
Gas (Mcf)
|
Total
(Boe)
|
Pre-Tax
PV10 Value
|
Standardized
Measure of Discounted Future Net Cash Flows
|
|||||||||||||||
New
Mexico
|
9,012,390 | 7,979,726 | 10,342,345 | $ | 185,626,509 | $ | 123,864,486 | |||||||||||||
Texas
|
47,973,061 | 47,946,793 | 55,964,193 | 877,877,087 | 592,237,629 | |||||||||||||||
Oklahoma
|
2,730,061 | 228,959 | 2,768,221 | 57,048,503 | 37,116,698 | |||||||||||||||
Kansas
|
- | 1,059,210 | 176,535 | 805,401 | 1,014,944 | |||||||||||||||
Total
|
59,715,512 | 57,214,688 | 69,251,294 | $ | 1,121,357,500 | $ | 754,233,757 | |||||||||||||
Proved Reserves
Our
69,251,294 Boe of proved reserves, which consist of approximately 86% oil and
14% natural gas, are summarized below as of December 31, 2009, on a net pre-tax
PV10 value and Standardized Measure of Discounted Future Net Cash Flows basis.
Our reserve estimates have not been filed with any Federal authority or agency
(other than the SEC).
As of
December 31, 2009, our Texas proved reserves had a net pre-tax PV10 value of
$877.9 million and Standardized Measure of Discounted Future Net Cash Flows of
$592.2 million, our proved reserves in New Mexico had a net pre-tax PV10 value
of $185.6 million and Standardized Measure of Discounted Future Net Cash Flows
of $123.9 million, our proved reserves in Oklahoma had a net pre-tax PV10 value
of $57.0 million and a Standardized Measure of Discounted Future Net Cash Flows
of $37.1 million and our proved reserves in Kansas had a net pre-tax PV10 value
of $0.8 million and a Standardized Measure of Discounted Future Net Cash Flows
of $1.0 million.
As of
December 31, 2009, approximately 33% of the proved reserves have been classified
as proved developed producing, or “PDP”. Proved developed behind
pipe, or “PDBP” reserves constitute approximately 5% and proved undeveloped, or
“PUD”, reserves constitute approximately 62%, of the proved reserves as of
December 31, 2009.
Total proved reserves had a net pre-tax
PV10 value as of December 31, 2009 of approximately $1.12 billion and a
Standardized Measure of Discounted Future Net Cash Flows of approximately $754.2
million, 35.1% or $394.0 million and $265.7 million, respectively, of which is
associated with the PDP reserves. An additional $69.5 million and $46.6 million,
respectively, is associated with the PDBP reserves, or 6.2% of total proved
reserves’ pre-tax PV10 value. The remaining $657.9 million and $441.9
million, respectively, is associated with PUD reserves.
Proved
Reserves Disclosures
Recent SEC Rule-Making Activity.
In December 2008, the SEC announced that it had approved revisions
to modernize the oil and gas reserve reporting disclosures. The new disclosure
requirements include provisions that:
·
|
Introduce
a new definition of oil and gas producing activities. This new definition
allows companies to include in their reserve base volumes from
unconventional resources. Such unconventional resources include bitumen
extracted from oil sands and oil and gas extracted from coal beds and
shale formations.
|
·
|
Report
oil and gas reserves using an unweighted average price using the prior
12-month period, based on the closing prices on the first day of each
month, rather than year-end prices.
|
15
·
|
Permit
companies to disclose their probable and possible reserves on a voluntary
basis. In the past, proved reserves were the only reserves allowed in the
disclosures. We have chosen not to make disclosure under these
categories.
|
·
|
Requires
companies to provide additional disclosure regarding the aging of proved
undeveloped reserves.
|
·
|
Permit
the use of reliable technologies to determine proved reserves if those
technologies have been demonstrated empirically to lead to reliable
conclusions about reserves volumes.
|
·
|
Replace
the existing “certainty” test for areas beyond one offsetting drilling
unit from a productive well with a “reasonable certainty”
test.
|
·
|
Require
additional disclosures regarding the qualifications of the chief technical
person who oversees the company’s overall reserve estimation process.
Additionally, disclosures regarding internal controls over reserve
estimation, as well as a report addressing the independence and
qualifications of its reserves preparer or auditor will be
mandatory.
|
We
adopted the rules effective December 31, 2009.
The new
rule does not allow for prior-year reserve information to be restated, so all
information related to periods prior to 2009 is presented consistent with prior
SEC rules for the estimation of proved reserves.
Internal Controls Over Reserves
Estimates. Our reserves estimates are prepared internally by our
Reservoir/Acquisitions Manager and our Reservoir Studies Manager in compliance
with SEC definitions and guidance and in accordance with generally accepted
petroleum engineering principles. Our Reservoir/Acquisitions Manager
holds a Bachelor of Science in Petroleum Engineering and has over thirty (30)
years of industry experience in property evaluations and reserves estimates
preparation. Our Reservoir Studies Manager holds a Bachelor of
Science and Master of Science in Petroleum Engineering and has over 37 years of
industry experience in reservoir engineering, property evaluations, and reserves
estimates preparation. Our reserves estimates are prepared by
examination and evaluation of production data, production decline curves,
reservoir pressure data, logs, geological data, and offset
analogies. Our reserves estimates are reviewed and approved by our
Operations Vice President and our President/Chief Executive
Officer. Our Chief Financial Officer reviews the reserves estimates
to assure compliance with SEC reporting requirements.
We engage third-party petroleum
consulting firms to audit all of our reserves. See the Third-Party
Reserves Audit report in exhibits.
Proved Undeveloped Reserves –
Our reserve estimates as of December 31, 2009 include 43.4 million BOE as
proved undeveloped reserves. As of December 31, 2008, our reserve
estimates included 40.6 BOE as proved undeveloped reserves. Following
is a description of the changes in our PUD reserves from December 31, 2008 to
December 31, 2009.
Conversion
of approximately 5.2 million BOE of reserve from PUD to PDP or PDBP through
capital expenditures of approximately $58.4 million.
Downward
revision of approximately 8.6 million BOE as a result of commodity price changes
and revisions of estimates due to performance.
16
Recording
of approximately 16.6 million BOE in new PUD reserves as a result of
acquisitions and our continuing development of additional acreage.
Our
proved reserves as of December 31, 2009 are summarized in the table
below.
Oil (Bbl)
|
Gas (Mcf)
|
Total (Boe)
|
%
of Total Proved
|
Pre-tax
PV10 (In thousands)
|
Standardized
Measure of Discounted Future Net Cash Flows (In thousands)
|
Future
Capital Expenditures (In thousands)
|
||||||||||||||||||||||
New
Mexico:
|
||||||||||||||||||||||||||||
PDP
|
3,116,024 | 4,420,485 | 3,852,772 | 6 | % | $ | 53,780 | $ | 35,886 | $ | - | |||||||||||||||||
PDBP
|
1,456,110 | 1,274,437 | 1,668,516 | 2 | % | $ | 34,653 | 23,123 | 2,735 | |||||||||||||||||||
PUD
|
4,440,256 | 2,284,804 | 4,821,057 | 7 | % | $ | 97,194 | 64,855 | 40,215 | |||||||||||||||||||
Total
Proved:
|
9,012,390 | 7,979,726 | 10,342,345 | 15 | % | $ | 185,627 | $ | 123,864 | $ | 42,950 | |||||||||||||||||
Texas:
|
||||||||||||||||||||||||||||
PDP
|
14,920,662 | 18,859,572 | 18,063,924 | 26 | % | $ | 332,309 | $ | 224,184 | $ | - | |||||||||||||||||
PDBP
|
1,243,307 | 2,589,005 | 1,674,808 | 2 | % | $ | 34,795 | 23,474 | 10,236 | |||||||||||||||||||
PUD
|
31,809,092 | 26,498,216 | 36,225,461 | 52 | % | $ | 510,773 | 344,580 | 483,567 | |||||||||||||||||||
Total
Proved:
|
47,973,061 | 47,946,793 | 55,964,193 | 80 | % | $ | 877,877 | $ | 592,238 | $ | 493,803 | |||||||||||||||||
Oklahoma:
|
||||||||||||||||||||||||||||
PDP
|
408,803 | 99,760 | 425,430 | 1 | % | $ | 7,084 | $ | 4,609 | $ | - | |||||||||||||||||
PUD
|
2,321,258 | 129,199 | 2,342,791 | 3 | % | $ | 49,965 | 32,508 | 6,270 | |||||||||||||||||||
Total
Proved:
|
2,730,061 | 228,959 | 2,768,221 | 4 | % | $ | 57,049 | $ | 37,117 | $ | 6,270 | |||||||||||||||||
Kansas:
|
||||||||||||||||||||||||||||
PDP
|
- | 1,059,210 | 176,535 | 1 | % | $ | 805 | $ | 1,015 | $ | - | |||||||||||||||||
Total
Proved:
|
- | 1,059,210 | 176,535 | 1 | % | $ | 805 | $ | 1,015 | $ | - | |||||||||||||||||
Total:
|
||||||||||||||||||||||||||||
PDP
|
18,445,489 | 24,439,027 | 22,518,661 | 33 | % | $ | 393,978 | $ | 265,694 | $ | - | |||||||||||||||||
PDBP
|
2,699,417 | 3,863,442 | 3,343,324 | 5 | % | 69,448 | 46,597 | 12,971 | ||||||||||||||||||||
PUD
|
38,570,606 | 28,912,219 | 43,389,309 | 62 | % | 657,932 | 441,943 | 530,052 | ||||||||||||||||||||
Total
Proved:
|
59,715,512 | 57,214,688 | 69,251,294 | 100 | % | $ | 1,121,358 | $ | 754,234 | $ | 543,023 |
17
Estimated
Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed
Reserves
The following table indicates projected
reserves that we currently estimate will be converted from proved undeveloped or
proved developed non-producing to proved developed, as well as the estimated
costs per year involved in such development.
Year
|
Estimated
Oil
Reserves
Developed
(Bbls)
|
Estimated
Gas
Reserves
Developed
(Mcf)
|
Total
Boe
|
Estimated
Development Costs
|
||||||||||||
2010
|
15,262,194 | 12,262,170 | 17,305,889 | $ | 153,627,173 | |||||||||||
2011
|
11,963,553 | 8,237,414 | 13,336,455 | 179,091,886 | ||||||||||||
2012
|
9,818,416 | 9,494,082 | 11,400,763 | 182,626,316 | ||||||||||||
2013
|
2,166,220 | 1,343,823 | 2,390,191 | 19,897,500 | ||||||||||||
Remaining
|
2,059,640 | 1,438,172 | 2,299,335 | 7,780,000 | ||||||||||||
41,270,023 | 32,775,661 | 46,732,633 | $ | 543,022,875 | ||||||||||||
Production
Our
estimated average daily production for the month of December, 2009, is
summarized below. These tables indicate the percentage of our estimated December
2009 average daily production of 7,254 Boe/d attributable to each state and to
oil versus natural gas production.
State
|
Average
Daily
Production
|
Oil
|
Natural
Gas
|
|||||||||
Texas
|
88.23 | % | 75.48 | % | 12.75 | % | ||||||
New
Mexico
|
8.73 | % | 7.09 | % | 1.65 | % | ||||||
Oklahoma
|
2.26 | % | 2.16 | % | 0.10 | % | ||||||
Kansas
|
0.77 | % | 0.00 | % | 0.77 | % | ||||||
Total
|
100.00 | % | 84.73 | % | 15.27 | % | ||||||
Summary
of Oil and Natural Gas Properties and Projects
Significant
New Mexico Operations
East Hobbs San Andres Unit – Lea
County, New Mexico. In May, 2004 we acquired an 82.24% working
interest and a 67.60% net revenue interest in this lease. The
property has been in continuous production since that time. “Net
revenue interest” is the owner’s percentage share of the monthly income realized
from the sale of a well’s produced oil and gas. The net revenue
interest is a lesser number as compared to the working interest, due to the
mineral owner royalty and other overriding royalties on the well. The
lease contains approximately 920 acres, all held by production, on which there
are 31 producing wells. We believe the property has additional
potential through waterflooding. A waterflood operation is a method
of secondary recovery in which water is injected into the reservoir formation to
displace residual oil. The water from injection wells physically
sweeps the displaced oil to adjacent production wells. These
estimates are included in our estimates of PUD potential.
18
Humphrey Queen Unit – Lea County,
New Mexico. We acquired a 100% working interest and a 75.08%
net revenue interest in this mature waterflood in December, 2007. The
property contains 16 producing wells and approximately 760 acres, all held by
production. We believe the property can support activities to drill
12 additional PUD wells, which are included in our reserve
estimates.
Langlie Mattix Queen Unit – Lea
County, New Mexico. We acquired a 100% working interest and a
75.09% net revenue interest in this mature waterflood property in December,
2007. The property has 16 producing wells on approximately 1,040
acres, all held by production. We believe the property can support
activity to drill 14 additional PUD wells, which are included in our reserve
estimates.
South Leonard Queen Unit – Lea
County, New Mexico. We acquired a 100% working interest
and a 75.09% net revenue interest in this mature waterflood in December,
2007. The property contains seven producing wells on approximately
680 acres with all of the acreage being held by production. We
believe the property can support activity to drill four additional PUD wells,
which are included in our reserve estimates.
North Benson Queen Unit – Eddy
County, New Mexico. We acquired a 100% working interest and a
69.44% net revenue interest in this mature waterflood property in October,
2003. The property has 27 producing wells and contains approximately
1,800 acres, all held by production. We have reactivated the
waterflood by constructing a new water supply system, building new injection
facilities, and returning previously idle water injection wells to
service. We think the property can support workovers in existing
wells to open additional zones and drilling 28 additional wells which are
included as PUD in our reserve estimate.
Red Lake Unit – Eddy County, New
Mexico. In October, 2007 we acquired a 100% working interest
and an 80.56% net revenue interest in this property. The lease has 16
producing wells on approximately 1,090 acres, all held by
production. We believe the property can support activity to drill
three additional PUD wells, which are included in our reserve
estimates.
Phillips Lea, Hale State, State 36
and Corbin 35 leases – Lea County, New Mexico. In June, 2008
we acquired a 100% working interest with net revenue interests ranging from
80.31% to 82.81% in these leases. The leases have 16 producing wells
on approximately 800 acres, all held by production. We think the
property can support workovers in existing wells to open new zones in existing
wells and drilling 10 additional wells which are included as PUD in our reserve
estimate.
Significant Texas
Operations
Fuhrman Mascho leases – Andrews
County, Texas. In December 2004 we acquired a 100% working
interest and a 75% net revenue interest in these leases. Throughout
2005 through 2009 we acquired working and net revenue interests in additional
producing leases and acquired additional undeveloped acreage in and around our
Fuhrman Mascho leases. The working interests range from 20-100% and
the net revenue interests range from 16-80%. In total, we now own 46,888 acres,
with 35,246 acres developed and held by production and the remaining 11,642
acres being undeveloped. We believe the Fuhrman Mascho leases contain
considerable remaining potential drilling. Our reserve estimate
includes 941 PUD wells. Our reserve estimates include potential
development expenditures.
Y6 lease – Fisher County,
Texas. We acquired a 100% working interest and an 80% net
revenue interest in this partially developed waterflood property in June,
2001. There are 15 producing wells on approximately 1,697 acres,
which is held by production. We believe the property can support
activity to drill four additional PUD wells, which are included in our reserve
estimates.
19
Significant
Oklahoma Operations
Ona Morrow Sand Unit – Cimarron and
Texas Counties, Oklahoma. We acquired a 100% working interest
and an 81.32% net revenue interest in this waterflood property in June,
2001. There are 13 producing wells on approximately 2,120 acres,
which is held by production. We believe the property can support
three additional PUD wells, which are included in our estimate of
PUD.
Midwell, Appleby, Smaltz, and Hanes
Leases – Cimarron County, Oklahoma. We acquired a 100% working
interest and an 80% net revenue interest in these leases in September,
2002. The leases contain 11 wells on approximately 2,280 acres, which
is held by production. We believe the leases contain PUD potential
from waterflood operations and six PUD wells, which are included in our estimate
of PUD. We began implementing the waterflood operations and will
continue those efforts.
Acreage
The
following table summarizes gross and net developed and undeveloped acreage at
December 31, 2009 by region (net acreage is our percentage ownership of gross
acreage). Acreage in which our interest is limited to royalty and overriding
royalty interests is excluded.
|
Developed
Acreage
|
|
Undeveloped
Acreage
|
|
Total
Acreage
|
|||||||
|
|
|
|
|
|
|
|
|||||
Gross | Net | Gross | Net | Gross | Net | |||||||
New
Mexico
|
9,850
|
9,038
|
-
|
-
|
9,850
|
9,038
|
||||||
Texas
|
34,569
|
33,923
|
16,116
|
14,411
|
50,685
|
48,335
|
||||||
|
||||||||||||
Oklahoma
|
5,529
|
5,046
|
-
|
-
|
5,529
|
5,046
|
||||||
|
||||||||||||
Kansas
|
5,200
|
5,200
|
0
|
0
|
5,200
|
5,200
|
||||||
|
||||||||||||
Total
|
55,148
|
53,206
|
16,116
|
14,411
|
71,264
|
67,618
|
||||||
|
|
|
|
|
|
Production
History
The following table presents the
historical information about our produced natural gas and oil
volumes.
Year
Ended December 31,
|
||||||||
2007
|
2008
|
2009
|
||||||
Oil
production (Bbls)
|
1,316,025
|
2,018,335
|
2,004,498
|
|||||
Natural
gas production (Mcf)
|
1,503,611
|
1,911,713
|
2,172,790
|
|||||
Total
production (Boe)
|
1,566,627
|
2,336,954
|
2,366,630
|
|||||
Daily
production (Boe/d)
|
4,292
|
6,385
|
6,484
|
|||||
Average
sales price:
|
||||||||
Oil
(per Bbl)
|
$ 66.89
|
$ 94.16
|
$ 57.51
|
|||||
Natural
gas (per Mcf)
|
8.02
|
9.84
|
5.04
|
|||||
Total
(per Boe)
|
63.89
|
89.37
|
53.34
|
|||||
Average
production cost (per Boe)
|
$ 7.34
|
$ 7.63
|
$ 6.57
|
|||||
Average
production taxes (per Boe)
|
3.61
|
4.50
|
2.73
|
The
average oil sales price amounts above are calculated by dividing revenue from
oil sales by the volume of oil sold, in Bbl. The average gas sales
price amounts above are calculated by dividing revenue from gas sales by the
volume of gas sold, in Mcf. The total average sales price amounts are
calculated by dividing total revenues by total volume sold, in
Boe. The average production costs above are calculated by dividing
production costs by total production in Boe.
20
Productive
Wells
The
following table presents our ownership at December 31, 2009, in productive oil
and natural gas wells by region (a net well is our percentage ownership of a
gross well).
Oil
Wells
|
Gas
wells
|
Total
Wells
|
||||||||||
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||
New
Mexico
|
194
|
173
|
-
|
-
|
194
|
173
|
||||||
Texas
|
893
|
876
|
-
|
-
|
893
|
876
|
||||||
Oklahoma
|
36
|
32
|
-
|
-
|
36
|
32
|
||||||
Kansas
|
-
|
-
|
10
|
10
|
10
|
10
|
||||||
Total
|
1,123
|
1,080
|
10
|
10
|
1,133
|
1,090
|
Drilling
Activity
The following table represents our
drilling activity for the years ended December 31, 2007, 2008 and
2009:
2007
|
2008
|
2009
|
||||||||
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||
Productive
development wells
|
||||||||||
Texas
|
133
|
130
|
223
|
219
|
176
|
173
|
||||
Oklahoma
|
1
|
1
|
-
|
-
|
-
|
-
|
||||
New
Mexico
|
-
|
-
|
1
|
1
|
5
|
4
|
||||
Total
productive development wells
|
134
|
131
|
224
|
220
|
181
|
177
|
||||
Dry
development wells
|
-
|
-
|
-
|
-
|
-
|
-
|
||||
Total
development wells
|
134
|
131
|
224
|
220
|
181
|
177
|
||||
Productive
exploratory wells
|
-
|
-
|
-
|
-
|
-
|
-
|
||||
Dry
exploratory wells
|
||||||||||
Texas
|
-
|
-
|
-
|
-
|
1
|
1
|
||||
Total
dry exploratory wells
|
-
|
-
|
-
|
-
|
1
|
1
|
||||
Total
exploratory wells
|
-
|
-
|
-
|
-
|
-
|
-
|
||||
Total
productive wells
|
134
|
131
|
224
|
220
|
181
|
177
|
||||
Total
dry wells
|
-
|
-
|
-
|
-
|
1
|
1
|
||||
Total
wells drilled
|
134
|
131
|
224
|
220
|
182
|
178
|
As of December 31, 2009, we were in the
process of drilling five wells with an additional fourteen wells in various
stages of completion, all in Texas. While we have small working
interest partners in three of these wells, we own the majority of the working
interest; therefore this information is correct for both gross and net
wells.
21
Cost
Information
We conduct our oil and natural gas
activities entirely in the United States. As noted previously in the table
appearing under “Production History”, our average production costs, per Boe,
were $7.34 in 2007, $7.63 in 2008 and $6.57 in 2009 and our average production
taxes, per BOE, were $3.61 in 2007, $4.50 in 2008 and $2.73 in 2009. These
amounts are calculated by dividing our total production costs or total
production taxes by our total volume sold, in Boe.
Costs incurred for property
acquisition, exploration and development activities during the years ended
December 31, 2007, 2008 and 2009 are shown below.
For
the Years Ended December 31,
|
||||||||||||
2007
(1)
|
2008
|
2009
|
||||||||||
Acquisition
of proved properties
|
$ | 53,554,064 | $ | 16,782,225 | $ | 3,942,103 | ||||||
Acquisition
of unproved properties
|
542,650 | - | - | |||||||||
Exploration
costs
|
- | - | - | |||||||||
Development
costs
|
113,084,344 | 190,584,617 | 107,064,257 | |||||||||
Total
Costs Incurred
|
$ | 167,181,058 | $ | 207,366,842 | $ | 111,006,360 |
(1) The amount shown for 2007 for acquisition of proved properties is net of proceeds received from the sale of our interest in the West San Andres property.
Reserve
Quantity Information
Our estimates of proved reserves and
related valuations were based on internal reports and audited by Williamson
Petroleum Consultants, Inc. independent petroleum engineers. The
estimates of proved reserves are inherently imprecise and are continually
subject to revision based on production history, results of additional
exploration and development, price changes and other factors.
Our oil and natural gas reserves are
attributable solely to properties within the United States. A summary of the
changes in quantities of proved (developed and undeveloped) oil and natural gas
reserves is shown below.
22
Natural
Gas
|
||||||
Oil
(Bbls)
|
(Mcf)
|
|||||
Balance,
December 31, 2006
|
36,064,273
|
42,424,199
|
||||
Purchase
of minerals in place
|
7,021,972
|
4,330,246
|
||||
Extensions
and discoveries
|
6,016,660
|
6,852,346
|
||||
Production
|
(1,316,023
|
) |
(1,503,611
|
) | ||
Revisions
of estimates
|
(373,560
|
) |
(4,028,218
|
) | ||
|
||||||
Balance,
December 31, 2007
|
47,413,322
|
48,074,962
|
||||
Purchase
of minerals in place
|
3,638,095
|
2,364,908
|
||||
Extensions
and discoveries
|
9,547,981
|
11,391,853
|
||||
Production
|
(2,018,335
|
) |
(1,911,713
|
) | ||
Revisions
of estimates
|
(2,735,806
|
) |
(1,115,348
|
) | ||
|
||||||
Balance,
December 31, 2008
|
55,845,257
|
58,804,662
|
||||
Purchase
of minerals in place
|
1,589,141
|
2,791,611
|
||||
Extensions
and discoveries
|
14,360,492
|
13,605,184
|
||||
Production
|
(2,004,498
|
) |
(2,172,790
|
) | ||
Revisions
of estimates
|
(10,074,880
|
) |
(15,813,979
|
) | ||
|
||||||
Balance,
December 31, 2009
|
59,715,512
|
57,214,688
|
||||
|
Our
proved oil and natural gas reserves are shown below.
For
the Years Ended December 31,
|
||||||||
2007
|
2008
|
2009
|
||||||
Oil
(Bbls)
|
||||||||
Developed
|
14,951,794
|
20,231,477
|
21,144,906
|
|||||
Undeveloped
|
32,461,428
|
35,613,780
|
38,570,606
|
|||||
Total
|
47,413,222
|
55,845,257
|
59,715,512
|
|||||
Natural
Gas (Mcf)
|
||||||||
Developed
|
30,783,255
|
28,659,033
|
28,302,469
|
|||||
Undeveloped
|
17,291,707
|
30,145,629
|
28,912,219
|
|||||
Total
|
48,074,962
|
58,804,662
|
57,214,688
|
|||||
Total
(Boe)
|
||||||||
Developed
|
20,082,337
|
25,007,982
|
25,861,985
|
|||||
Undeveloped
|
35,343,379
|
40,638,052
|
43,389,309
|
|||||
Total
|
55,425,716
|
65,646,034
|
69,251,294
|
|||||
Standardized
Measure of Discounted Future Net Cash Flows
Our
standardized measure of discounted future net cash flows relating to proved oil
and natural gas reserves and changes in the standardized measure as described
below were prepared in accordance with generally accepted accounting principles.
23
Future
income tax expenses are calculated by applying appropriate year-end tax rates to
future pre-tax net cash flows relating to proved oil and natural gas reserves,
less the tax basis of properties involved. Future income tax expenses give
effect to permanent differences, tax credits and loss carryforwards relating to
the proved oil and natural gas reserves. Future net cash flows are discounted at
a rate of 10% annually to derive the standardized measure of discounted future
net cash flows. This calculation procedure does not necessarily result in an
estimate of the fair market value or the present value of our oil and natural
gas properties.
The standardized measure of discounted
future net cash flows relating to the proved oil and natural gas reserves are
shown below.
December
31,
|
2009
|
2008
|
2007
|
|||||||||
Future
cash flows
|
$ | 3,721,873,750 | $ | 2,391,888,946 | $ | 4,634,645,500 | ||||||
Future
production costs
|
(902,963,847 | ) | (716,121,604 | ) | (790,284,047 | ) | ||||||
Future
development costs
|
(543,022,875 | ) | (330,672,457 | ) | (321,485,125 | ) | ||||||
Future
income taxes
|
(746,548,080 | ) | (394,800,287 | ) | (1,254,982,170 | ) | ||||||
Future
net cash flows
|
1,529,338,948 | 950,294,598 | 2,267,894,158 | |||||||||
10%
annual discount for estimated timing of cash flows
|
(775,105,191 | ) | (489,607,688 | ) | (991,727,804 | ) | ||||||
Standardized
Measure of Discounted Cash Flows
|
$ | 754,233,757 | $ | 460,686,910 | $ | 1,276,166,354 |
The changes in the standardized measure
of discounted future net cash flows relating to the proved oil and natural gas
reserves are shown below.
|
2009
|
2008
|
2007
|
|||||||||
Beginning
of the year
|
$ | 460,686,910 | $ | 1,276,166,354 | $ | 545,439,675 | ||||||
Purchase
of minerals in place
|
28,329,307 | 41,597,736 | 325,058,027 | |||||||||
Extensions,
discoveries and improved recovery, less related costs
|
253,485,559 | 129,110,323 | 297,610,301 | |||||||||
Development
costs incurred during the year
|
107,237,470 | 190,631,820 | 113,109,335 | |||||||||
Sales
of oil and gas produced, net of production costs
|
(110,697,316 | ) | (190,374,853 | ) | (82,949,751 | ) | ||||||
Accretion
of discount
|
48,058,341 | 131,684,244 | 69,291,660 | |||||||||
Net
changes in price and production costs
|
619,543,318 | (1,526,963,575 | ) | 592,749,069 | ||||||||
Net
change in estimated future development costs
|
6,550,757 | (22,637,628 | ) | (111,175,136 | ) | |||||||
Revision
of previous quantity estimates
|
(447,110,784 | ) | 293,723,576 | (7,424,163 | ) | |||||||
Revision
of estimated timing of cash flows
|
(35,543,586 | ) | (409,158,356 | ) | (62,546,312 | ) | ||||||
Net
change in income taxes
|
(176,306,219 | ) | 546,907,269 | (402,996,351 | ) | |||||||
End
of the Year
|
$ | 754,233,757 | $ | 460,686,910 | $ | 1,276,166,354 |
Management’s
Business Strategy Related to Properties
Our goal
is to increase stockholder value by investing in oil and gas projects with
attractive rates of return on capital employed. We plan to achieve this goal by
exploiting and developing our existing oil and natural gas properties and
pursuing acquisitions of additional properties. Specifically, we have focused,
and plan to continue to focus, on the following:
Developing and Exploiting Existing
Properties. We believe that there is significant
value to be created by drilling the identified undeveloped opportunities on our
properties. We own interests in a total of 58,092 gross (43,607 net)
developed acres and operate essentially all of the net pre-tax PV10 value of our
proved undeveloped reserves. In addition, as of December 31, 2009, we
owned interests in approximately 13,172 gross undeveloped acres (9,879
net). We believe that our current and future cash flow will enable us
to undertake the exploitation of our properties through additional drilling
activities. We will closely manage our capital expenditures to
our cash flow. As commodity prices change we will consider the
resulting impact on our cash flow and adjust our capital expenditures
accordingly, be it up or down.
24
Pursuing Profitable
Acquisitions. We have historically pursued
acquisitions of properties that we believe to have exploitation and development
potential comparable to our existing inventory of drilling
locations. We have developed and refined an acquisition program
designed to increase reserves and complement our existing core
properties. We have an experienced team of management and engineering
professionals who identify and evaluate acquisition opportunities, negotiate and
close purchases and manage acquired properties. While our emphasis in
2010 and beyond is anticipated to focus on the further development of our
existing properties, we will continue to look for acquisition opportunities with
existing cash flow from production and future development
potential.
Controlling Costs through Efficient
Operation of Existing Properties. We operate
essentially 100% of the pre-tax PV10 value of our total proved reserves, which
we believe enables us to better manage expenses, capital allocation and the
decision-making processes related to our exploitation and exploration
activities. For the year ended December 31, 2009, our oil and gas production
costs per Boe averaged $6.57, our oil and gas production taxes per Boe averaged
$2.73 and general and administrative costs averaged $5.68 per Boe
produced.
Other
Properties and Commitments
Our principal executive offices are in
a company owned building in Tulsa, Oklahoma. This office building has
approximately 16,000 square feet. Additionally, we own the building
in Hobbs, New Mexico which serves as our primary field office. This
office building has approximately 7,500 square feet. We also own an
office building in Andrews, Texas for the operation of our wholly-owned
subsidiary Arena Drilling Company and for use by additional Arena Resources
field personnel. This office building has approximately 6,000 square
feet. At December 31, 2009, we were expanding the office in Andrews
by an additional 5,000 up to 11,000 square feet. Subsequent to year
end the expansion was completed and the additional space will be used by Arena
Resources field personnel. Lastly, we are currently leasing
approximately 1,869 square feet of space in Midland, Texas. Our
Midland office is maintained for the purchase of developed and undeveloped
leaseholds and for land department support. We believe the office
space will be adequate for our current operations as well as allowing for
continued growth.
Item
3: Legal
Proceedings
In the
ordinary course of business, we may be, from time to time, a claimant or a
defendant in various legal proceedings. We do not presently have any
material litigation pending or threatened.
Item
4: Submission of Matters to a
Vote of Security Holders
Our annual shareholders’ meeting was
held on December 11, 2009. The shareholder’s re-elected Messrs.
Stanley M. McCabe, Lloyd T. Rochford, Clayton E. Woodrum, Anthony B. Petrelli
and Carl F. Fiddner as Directors with terms ending in 2010. The
shareholders approved an amendment to the Company’s executive stock option plan
to increase the number of shares of Common Stock that may be granted under the
plan from 5,500,000 to 6,000,000. The shareholders also approved a
restricted stock award plan that will use shares from that same pool available
for grant as restricted stock awards. The following reflects the
votes cast for each matter voted on at the annual meeting:
25
Votes
for
|
Votes
against
|
Abstain
|
|||
Lloyd
T. Rochford
|
33,035,317
|
2,797,173
|
-
|
||
Stanley
M. McCabe
|
27,834,068
|
7,998,422
|
-
|
||
Clayton
E. Woodrum
|
27,820,843
|
8,011,647
|
-
|
||
Anthony
B. Petrelli
|
33,734,756
|
2,097,734
|
-
|
||
Carl
H. Fiddner
|
33,733,780
|
2,098,710
|
-
|
||
Amendment
to stock option plan
|
23,285,445
|
9,184,761
|
3,362,284
|
||
Restricted
stock award plan
|
21,516,700
|
10,958,283
|
3,357,507
|
26
PART
II
Item
5:
|
Market for
Registrant’s Common Stock, Related Stockholder Matters and Issuer
Purchases of
Equity
Securities
|
Market
for our Common Stock
Our
common stock is been traded on the New York Stock Exchange, under the symbol
“ARD”. The following table shows the high and low sales prices for
each quarter during the last two years.
Period
|
High Sale
|
Low Sale
|
||||||
1st
Quarter 2008
|
$ | 44.17 | $ | 29.25 | ||||
2nd
Quarter 2008
|
57.60 | 38.00 | ||||||
3rd
Quarter 2008
|
56.59 | 32.47 | ||||||
4th
Quarter 2008
|
39.03 | 17.63 | ||||||
1st
Quarter 2009
|
$ | 31.51 | $ | 18.62 | ||||
2nd
Quarter 2009
|
38.04 | 26.03 | ||||||
3rd
Quarter 2009
|
36.06 | 27.57 | ||||||
4th
Quarter 2009
|
45.24 | 32.76 | ||||||
1st
Quarter 2010 (through March 1, 2010)
|
$ | 45.06 | $ | 38.34 |
Record
Holders
As of February 23, 2010, there are
approximately 30,521 holders of record of our common stock. As of
February 23, 2010, 532,606 shares, or approximately 1.4%, of the 38,793,963
shares issued and outstanding as of such date are held by management or
affiliated parties.
Dividend
Policy
We have not paid any dividends on our
common stock during the last three years, and we do not anticipate paying any
cash dividends on our common stock in the foreseeable future. We currently
intend to retain future earnings, if any, to finance the expansion of our
business. Our future dividend policy is within the discretion of our board of
directors and will depend upon various factors, including our results of
operations, financial condition, capital requirements and investment
opportunities. In addition, our credit facility prohibits us from paying
dividends.
Securities
Authorized for Issuance Under Equity Compensation Plans
In March
2003, our board of directors adopted an executive stock option plan which was
subsequently approved by our shareholders at our annual meeting in July 2003,
and which has been subsequently amended by votes of our
shareholders. Additionally, in December 2009 the shareholders
approved a restricted stock award plan. Information regarding these
plan and the options and stock that have been granted under this plan may be
found in this Annual Report under Part III, Items 10 and 11.
Issuer
Repurchases
We did not make any repurchases of our
equity securities during the quarter ending December 31, 2009.
27
Item
6: Selected Financial
Data
The
selected consolidated financial information set forth below is derived from our
consolidated balance sheets and statements of operations as of and for the years
ended December 31, 2009, 2008, 2007, 2006 and 2005. The data set
forth below should be read in conjunction with “Management’s Discussion and
Analysis of Financial Condition and Results of Operations” and the consolidated
financial statements and related notes thereto included in this Annual
Report.
For
the Year Ended December 31,
|
||||||||||||||||||||
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||||||||
Statement
of Operations Data:
|
||||||||||||||||||||
Revenues
|
$ | 126,240,777 | $ | 208,858,645 | $ | 100,089,698 | $ | 59,760,117 | $ | 25,843,077 | ||||||||||
Cost
of revenues
|
21,999,046 | 28,351,514 | 17,156,338 | 9,960,178 | 5,772,225 | |||||||||||||||
Realized
loss (gain) on oil derivative
|
(14,884,846 | ) | 4,275,330 | 932,361 | - | - | ||||||||||||||
Depreciation,
depletion and amortization
|
8,957,641 | 29,789,794 | 17,968,062 | 7,900,099 | 2,781,504 | |||||||||||||||
Accretion
|
410,926 | 309,402 | 190,904 | 127,132 | 102,585 | |||||||||||||||
General
and administrative
|
13,453,384 | 13,557,202 | 7,815,721 | 3,617,309 | 1,365,590 | |||||||||||||||
Net
income
|
42,294,179 | 83,617,201 | 34,441,939 | 23,267,968 | 9,460,683 | |||||||||||||||
Basic
income per common share
|
$ | 1.10 | $ | 2.28 | $ | 1.07 | $ | 0.83 | $ | 0.42 | ||||||||||
Diluted
income per common share
|
1.09 | 2.20 | 1.02 | 0.77 | 0.38 | |||||||||||||||
As
of December 31,
|
||||||||||||||||||||
2009 | 2008 | 2007 | 2006 | 2005 | ||||||||||||||||
Balance
Sheet Data:
|
||||||||||||||||||||
Current
assets
|
$ | 80,655,878 | $ | 89,530,137 | $ | 30,823,214 | $ | 14,674,345 | $ | 7,673,860 | ||||||||||
Oil
and gas properties subject to amortization
|
661,453,134 | 548,714,235 | 339,887,859 | 171,708,200 | 69,770,685 | |||||||||||||||
Total
assets
|
657,554,954 | 591,684,775 | 350,980,663 | 176,312,978 | 74,421,907 | |||||||||||||||
Total
current liabilities
|
18,256,893 | 19,789,547 | 19,216,475 | 14,995,870 | 6,737,806 | |||||||||||||||
Total
long-term liabilities
|
116,631,301 | 89,599,767 | 73,953,223 | 41,273,056 | 8,919,826 | |||||||||||||||
Total
Stockholders Equity
|
522,666,730 | 482,295,461 | 257,810,965 | 120,044,052 | 58,728,755 |
Item
7: Management’s Discussion and
Analysis of Financial Condition and Results of
Operations
Introduction
The
following discussion and analysis should be read in conjunction with our
accompanying financial statements and the notes to those financial statements
included elsewhere in this Annual Report. The following discussion includes
forward-looking statements that reflect our plans, estimates and beliefs. Our
actual results could differ materially from those discussed in these
forward-looking statements. Factors that could cause or contribute to such
differences include, but are not limited to, those discussed below and elsewhere
in this Annual Report.
Overview
We are
engaged in oil and natural gas acquisition, exploration and exploitation
activities in the states of Oklahoma, Texas, New Mexico and Kansas. Over the
last six years, we have emphasized the acquisition of properties that provided
current production and upside potential through further
development.
We have
increased our reserves significantly by investing approximately $111 million in
acquisitions and development in 2009, following total capital expenditures of
approximately $207.4 million in 2008 and $167.2 million in 2007.
We will
closely manage our capital expenditures to our cash flow. As
commodity prices change we will consider the resulting impact on our cash flow
and adjust our capital expenditures accordingly, be it up or down. We
also intend to continue seeking acquisition opportunities which compliment our
current portfolio. We could draw on our credit facility or funds
derived from future equity transactions for future acquisitions.
28
Our
business plan has involved increasing our base of proven reserves until we have
acquired a sufficient core to enable us to utilize cash from existing production
to fund further development activities. When we originated our
business plan we believed this would allow us to lessen our risks, including
risks associated with borrowing funds to undertake exploration activities at an
earlier time. We increased our base of proven properties and
initiated development activities as oil and natural gas prices
increased.
While our
focus has shifted to include more development activity, we plan to continue our
strategy of acquiring producing properties with additional development,
exploitation and exploration potential. Our focus has been on
acquiring operated properties (i.e. properties with respect to which we serve as
the operator on behalf of all joint interest owners) so that we can better
control the timing and implementation of capital spending.
Our revenue, profitability and future
growth rate depend substantially on factors beyond our control, such as
economic, political and regulatory developments and competition from other
sources of energy. Oil and natural gas prices historically have been volatile
and may fluctuate widely in the future. Sustained periods of low prices for oil
or natural gas could materially and adversely affect our financial position, our
results of operations, the quantities of oil and natural gas reserves that we
can economically produce and our access to capital.
In a worst case scenario, future
drilling operations could be largely unsuccessful, oil and gas prices could
further decline and/or other factors beyond our control could cause us to
greatly modify or substantially curtail our development plans, which could
negatively impact our earnings, cash flow and most likely the trading price of
our securities, as well as the acceleration of debt repayment and a reduction in
our borrowing base under our credit facilities.
29
Results
of Operations
The following table sets forth selected
operating data for the periods indicated:
For
the Years Ended December 31,
|
||||||||||||
2007
|
2008
|
2009
|
||||||||||
Net
production:
|
||||||||||||
Oil
(Bbls)
|
1,316,025 | 2,018,335 | 2,004,498 | |||||||||
Natural
gas (Mcf)
|
1,503,612 | 1,911,713 | 2,172,791 | |||||||||
Net
sales:
|
||||||||||||
Oil
|
$ | 88,025,225 | $ | 190,050,617 | $ | 115,284,731 | ||||||
Natural
gas
|
12,064,473 | 18,808,028 | 10,956,046 | |||||||||
Average
sales price:
|
||||||||||||
Oil
(per Bbl)
|
$ | 66.82 | $ | 94.16 | $ | 57.51 | ||||||
Natural
gas (per Mcf)
|
8.02 | 9.84 | 5.04 | |||||||||
Production
costs and expenses
|
||||||||||||
Oil
and gas production costs
|
$ | 11,500,461 | $ | 17,833,144 | $ | 15,543,461 | ||||||
Production
taxes
|
5,655,877 | 10,518,370 | 6,455,585 | |||||||||
Realized
loss (gain) on oil derivative
|
932,361 | 4,275,330 | (14,884,846 | ) | ||||||||
Depreciation,
depletion and amortization expense
|
17,968,062 | 29,789,794 | 38,957,461 | |||||||||
Accretion
expense
|
190,904 | 309,402 | 410,926 | |||||||||
General
and administrative expenses
|
7,815,721 | 13,557,202 | 13,453,384 |
30
Year
Ended December 31, 2009 Compared to Year Ended December 31, 2008
Oil and natural gas
sales. Oil and natural gas sales revenue decreased
approximately $82.6 million to $126.2 million in 2009. Oil sales
decreased $74.8 million and natural gas sales decreased $7.8 million. The oil
sales decrease was caused by a 39% decrease in the average realized per barrel
oil price from $94.16 in 2008 to $57.51 in 2009 and a reduction in sales volume
of 13,837 barrels in 2009. These per barrel amounts are calculated by
dividing revenue from oil sales by the volume of oil sold, in
barrels. The natural gas sales decrease was caused by a 49% decrease
in the average realized per Mcf gas price from $9.84 in 2008 to $5.04 in 2009,
partially offset by an increase in the sales volume of 261,078 Mcf. These per
Mcf amounts are calculated by dividing revenue from gas sales by the volume of
gas sold, in Mcf. The volume increase for natural gas primarily
resulted from development of our existing properties in 2009.
Oil and gas production
costs. Our aggregate oil and gas production costs
decreased from $17,833,144 in 2008 to $15,543,461, and decreased on a Boe basis
from $7.63 in 2008 to $6.57 in 2009. These per Boe amounts are
calculated by dividing our total production costs by our total volume sold, in
Boe. This decrease in the aggregate and on a per Boe basis was the
result of lower average costs for services and equipment.
Oil and gas production
taxes. Oil and gas production taxes as a
percentage of oil and natural gas sales were 5.04% during 2008 and increased
slightly to 5.11% in 2009. Production taxes vary from state to
state. Therefore, these taxes are likely to vary in the future
depending on the mix of production we generate from various states, and on the
possibility that any state may raise its production tax.
Realized loss (gain) on oil
derivative. Realized loss (gain) on oil derivative
changed from a loss of $4,275,330 in 2008 to a gain of $14,884,846 in
2009. This change is the result of significantly lower prices for the
majority of 2009 as compared to 2008.
Depreciation, depletion and
amortization. Our depreciation, depletion and
amortization expense increased by $9,269,371 to $39,368,567 in
2009. The increase was a result of an increase in the average
depreciation, depletion and amortization rate from $12.88 per Boe during 2008 to
$16.63 per Boe during 2009. These per Boe amounts are calculated by
dividing our total depreciation, depletion and amortization expense by our total
volume sold, in Boe. The increased depreciation, depletion and
amortization were the result of an increase in estimated future development
costs.
General and administrative
expenses. General and administrative expenses
remained relatively steady, decreasing by $103,818 to $13, 452,384 during
2009. This decrease was primarily related to a decrease in compensation expense
related to our stock option plan, partially offset by increases in other areas,
such as insurance and taxes and fees.
Interest
income. Interest income decreased $470,947 to
$828,992 in 2009. The decrease was primarily due to lower interest rates between
periods.
Interest
expense. Interest expense decreased $1,145,456 to
$0 in 2009. The decrease was due to not having any amounts outstanding on our
credit facility during 2009.
Income tax
expense. Our effective tax rate was 37% during
2008 and 37% during 2009.
Net
income. Net income decreased from $83,617,201 for
2008 to $42,294,179 for 2009. The primary reason for this decrease was the lower
average crude oil and natural gas prices received between periods.
31
Year
Ended December 31, 2008 Compared to Year Ended December 31, 2007
Oil and natural gas
sales. Oil and natural gas sales revenue increased
approximately $108.8 million to $208.9 million in 2008. Oil sales
increased $102.1 million and natural gas sales increased $6.7 million. The oil
sales increase was caused by a sales volume increase of 702,310 barrels in 2008,
and a 41% increase in the average realized per barrel oil price from $66.82 in
2007 to $94.16 in 2008. These per barrel amounts are calculated by
dividing revenue from oil sales by the volume of oil sold, in
barrels. The natural gas sales increase was caused by a sales volume
increase of 408,102 Mcf in 2008, and a 23% increase in the average realized per
barrel oil price from $8.02 in 2007 to $9.84 in 2008. These per Mcf amounts are
calculated by dividing revenue from gas sales by the volume of gas sold, in
Mcf. The volume increase for crude oil and natural gas primarily
resulted from development of our existing properties in 2008.
Oil and gas production
costs. Our aggregate oil and gas production costs
increased from $11,500,461 in 2007 to $17,833,144, and increased on a Boe basis
from $7.34 in 2007 to $7.63 in 2008. These per Boe amounts are
calculated by dividing our total production costs by our total volume sold, in
Boe. This aggregate increase was the result of the drilling of new wells
in 2008 and cost increases. The increase on a per Boe basis is
attributable to rising rates for labor and services.
Oil and gas production
taxes. Oil and gas production taxes as a
percentage of oil and natural gas sales were 5.65% during 2007 and decreased to
5.04% in 2008. Production taxes vary from state to
state. Therefore, these taxes are likely to vary in the future
depending on the mix of production we generate from various states, and on the
possibility that any state may raise its production tax.
Realized loss on oil
derivative. Realized loss on oil derivative
increased from $932,361 in 2007 to $4,275,330 in 2008. This increase
is the result of commodity price increases during most of 2008.
Depreciation, depletion and
amortization. Our depreciation, depletion and
amortization expense increased by $11,940,230 to $30,099,196 in
2008. The increase was a result of an increase in the average
depreciation, depletion and amortization rate from $11.59 per Boe during 2007 to
$12.88 per Boe during 2008. These per Boe amounts are calculated by
dividing our total depreciation, depletion and amortization expense by our total
volume sold, in Boe. The increased depreciation, depletion and
amortization were the result of increased sales volume and an increase in
estimated future development costs.
General and administrative
expenses. General and administrative expenses
increased by $5,741,481 to $13,557,202 during 2008. This increase was primarily
related to increases in compensation expense associated with an increase in
personnel required to administer our growth and compensation expense related to
our stock option plan.
Interest
income. Interest income increased $414,949 to
$1,299,939 in 2008. The increase was due to higher cash balances during periods
of the year in 2008.
Interest
expense. Interest expense decreased $266,064 to
$1,145,456 in 2008. The increase was due to lower amounts of debt being
outstanding during periods of the year in 2008.
Income tax
expense. Our effective tax rate was 37% during
2008 and 38% during 2007.
Net
income. Net income increased from $34,441,939 for
2007 to $83,617,201 for 2008. The primary reasons for this increase include
higher crude oil and natural gas prices between periods and an increase in
volumes sold, partially offset by higher oil and gas production costs, oil and
gas production taxes and general and administrative expenses due to our
growth.
32
Liquidity
and Capital Resources
Historical
Financing. We have historically funded our
operations through cash available from operations, and from equity offerings of
our stock and warrants in 2007 and 2008.
Credit
Facility. In June 2009, we entered into an amended and
restated credit agreement that provides for a credit facility of $150 million
with a borrowing base of $75 million with the structure in place to increase
that borrowing base an additional $75 million. The new facility has
an interest rate grid with a range of LIBOR plus 2.25% to 3.25%, depending upon
our level of utilization of the credit facility with the total interest rate to
be charged being no less than 4.00%. All other terms and conditions
that existed under our prior credit facility remained the same. As of
December 31, 2009, we were in compliance with all covenants and did not have any
amount outstanding under this credit facility.
Cash
Flows. Our primary sources of cash have been cash
flows from operations and equity offerings. During the three years
ended December 31, 2009, we generated $349,504,656 from operating activities and
financed $222,388,933 through proceeds from the sale of stock and warrants and
exercise of warrants and options. We primarily used this cash generation to fund
our capital expenditures and development aggregating $497,777,217 over the three
years end December 31, 2009. At December 31, 2009, we had cash on
hand of $63,635,078 and working capital of $62,398,985, compared to December 31,
2008 when our cash was $58,489,574 and working capital of
$69,740,590.
We
continually evaluate our capital needs and compare them to our capital
resources. We will closely manage our capital expenditures to our cash
flow. As commodity prices change we will consider the resulting
impact on our cash flow and adjust our capital expenditures accordingly, be it
up or down. The level of capital expenditures is largely
discretionary, and the amount of funds devoted to any particular activity may
increase or decrease significantly depending on available opportunities,
commodity prices, cash flows and development results, among others.
Schedule of Contractual
Obligations. The following table summarizes our future
estimated lease payments for periods subsequent to December 31,
2009. This lease pertains to an office building in Midland, Texas and
involves approximately 1,869 square feet of space.
Year
|
Lease
Obligation
|
|||
2010
|
20,715 | |||
2011
|
21,649 | |||
2012
|
22,584 | |||
2013
|
19,469 | |||
$ | 84,417 |
Off-Balance Sheet Financing Arrangements
As of December 31, 2009 we had no
off-balance sheet financing arrangements.
Critical
Accounting Policies and Estimates
Our
discussion of financial condition and results of operations is based upon the
information reported in our financial statements. The preparation of these
statements requires us to make assumptions and estimates that affect the
reported amounts of assets, liabilities, revenues and expenses as well as the
disclosure of contingent assets and liabilities at the date of our financial
statements. We base our assumptions and estimates on historical experience and
other sources that we believe to be reasonable at the time. Actual results may
vary from our estimates due to changes in circumstances, weather, politics,
global economics, mechanical problems, general business conditions and other
factors. Our significant accounting policies are detailed in Note 1 to our
financial statements included in this Annual Report. We have outlined below
certain of these policies as being of particular importance to the portrayal of
our financial position and results of operations and which require the
application of significant judgment by our management.
33
Revenue
Recognition. We predominantly derive our revenue
from the sale of produced crude oil and natural gas. Revenue is recorded in the
month the product is delivered to the purchaser. We receive payment from one to
three months after delivery. At the end of each month, we estimate the amount of
production delivered to purchasers and the price we will receive. Variances
between our estimated revenue and actual payment are recorded in the month the
payment is received; however, differences have been insignificant.
Full Cost Method of
Accounting. We account for our oil and natural gas
operations using the full cost method of accounting. Under this method, all
costs associated with property acquisition, exploration and development of oil
and gas reserves are capitalized. Costs capitalized include acquisition costs,
geological and geophysical expenditures, lease rentals on undeveloped properties
and cost of drilling and equipping productive and non-productive
wells. Drilling costs include directly related overhead costs. All of
our properties are located within the continental United States.
Oil and Natural Gas Reserve
Quantities. Reserve quantities and the related
estimates of future net cash flows affect our periodic calculations of depletion
and impairment of our oil and natural gas properties. Proved oil and natural gas
reserves are the estimated quantities of crude oil, natural gas and natural gas
liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future periods from known reservoirs under
existing economic and operating conditions. Reserve quantities and future cash
flows included in this Annual Report are prepared in accordance with guidelines
established by the SEC and FASB. The accuracy of our reserve estimates is a
function of:
·
|
the
quality and quantity of available data;
|
·
|
the
interpretation of that data;
|
·
|
the
accuracy of various mandated economic assumptions; and
|
·
|
the
judgments of the persons preparing the
estimates.
|
Our
proved reserve information included in this Annual Report were based on internal
reports and audited by Williamson Petroleum Consultants, Inc., independent
petroleum engineers. Because these estimates depend on many
assumptions, all of which may differ substantially from actual results, reserve
estimates may be different from the quantities of oil and natural gas that are
ultimately recovered. We continually make revisions to reserve estimates
throughout the year as additional properties are acquired. We make changes to
depletion rates and impairment calculations in the same period that changes to
the reserve estimates are made.
All
capitalized costs of oil and gas properties, including estimated future costs to
develop proved reserves and estimated future costs of site restoration, are
amortized on the unit-of-production method using estimates of proved reserves as
determined by independent engineers. Investments in unproved
properties and major development projects are not amortized until proved
reserves associated with the projects can be determined.
34
Impairment of Oil and Natural Gas
Properties. We review the value of our oil and
natural gas properties whenever management judges that events and circumstances
indicate that the recorded carrying value of properties may not be recoverable.
We provide for impairments on undeveloped property when we determine that the
property will not be developed or a permanent impairment in value has occurred.
Impairments of proved producing properties are calculated by comparing future
net undiscounted cash flows using escalated prices to the net recorded book cost
at the end of each period (“Ceiling test”). If the net capitalized cost exceeds
net future cash flows, the cost of the property is written down to “fair value,”
which is determined using net discounted future cash flows from the producing
property. Current market conditions, in the form of low commodity prices, have
had a dramatic effect on this calculation. The net discounted future
cash flow from producing properties is directly impacted by commodity
prices. Different pricing assumptions or discount rates could result
in a different calculated impairment. We have never recorded property
impairments as a result of the ceiling test.
Our
reserve estimates as of December 31, 2009 are based on an average price of
$57.628 for oil and $4.904 for gas. We have run an impairment test
analysis to determine at approximately what price level impairment would
result. Because our reserves are predominantly oil, at approximately
85% of total reserves, this analysis was based solely on the oil price while
leaving gas prices at the levels used for preparing the reserve estimates as of
December 31, 2009. Based on this analysis, our contracted oil price
would have to drop below $37 per barrel for the ceiling test to result in
impairment to our producing properties.
Income
Taxes. Deferred income taxes are provided for the
difference between the tax basis of assets and liabilities and the carrying
amount in our financial statements. This difference will result in taxable
income or deductions in future years when the reported amount of the asset or
liability is settled. Since our tax returns are filed after the financial
statements are prepared, estimates are required in valuing tax assets and
liabilities. We record adjustments to actual in the period we file our tax
returns.
Derivative
Instruments. The estimated fair values of our
commodity derivative instruments are recorded in the consolidated balance sheet.
At inception, all of our commodity derivative instruments represent hedges of
the price of future oil and gas production. The changes in fair value of those
derivative instruments that qualify for hedge accounting treatment are recorded
in other comprehensive income until the hedged oil or natural gas quantities are
produced. If a hedge becomes ineffective because the hedged production does not
occur, or the hedge otherwise does not qualify for hedge accounting treatment,
the changes in the fair value of the derivative are recorded in the income
statement as derivative income or expense.
Our
hedges are specifically referenced to NYMEX prices. We evaluate the
effectiveness of our hedges at the time we enter the contracts, and periodically
over the life of the contracts, by analyzing the correlation between NYMEX
prices and the posted prices we receive from our designated production. Through
this analysis, we are able to determine if a high correlation exists between the
prices received for the designated production and the NYMEX prices at which the
hedges will be settled.
Effects
of Inflation and Pricing
We experienced increases and decreases
in costs during 2009 due to fluctuating demand for oil field products and
services as a result of fluctuating oil and gas prices. The oil and
natural gas industry is very cyclical and the demand for goods and services of
oil field companies, suppliers and others associated with the industry puts
extreme pressure on the economic stability and pricing structure within the
industry. Typically, as prices for oil and natural gas increase, so do all
associated costs. Material changes in prices impact the current
revenue stream, estimates of future reserves, borrowing base calculations of
bank loans and value of properties in purchase and sale transactions. Material
changes in prices can impact the value of oil and natural gas companies and
their ability to raise capital, borrow money and retain personnel. We anticipate
business costs will vary in accordance with commodity prices for oil and natural
gas, and the associated increase or decrease in demand for services related to
production and exploration.
35
Item
7A Quantitative and Qualitative
Disclosure About Market Risk
Commodity
Price Risk
Our major
market risk exposure is in the pricing applicable to our oil and natural gas
production. Market risk refers to the risk of loss from adverse changes in oil
and natural gas prices. Realized pricing is primarily driven by the prevailing
domestic price for crude oil and spot prices applicable to the region in which
we produce natural gas. Historically, prices received for oil and natural gas
production have been volatile and unpredictable. We expect pricing volatility to
continue. Oil prices we received during 2009 ranged from a low of $30.87 per
barrel to a high of $74.81 per barrel. Natural gas prices we received during
2009 ranged from a low of $0.72 per Mcf to a high of $11.92 per Mcf. A
significant decline in the prices of oil or natural gas could have a material
adverse effect on our financial condition and results of
operations.
As of December 31, 2009 the Company’s
only derivative contracts are costless collars. A collar is a
contract which combines both a put option or “floor” and a call option or
“ceiling.” The Company receives the excess, if any, of the floor
price over the reference price, based on NYMEX quoted prices, and pays the
excess, if any, of the reference price over the ceiling price. The
following is information relating to the Company’s collar position as of
December 31, 2009.
Commodity
|
Remaining
Period
|
Volume
(Bbls)
|
Floor
|
Ceiling
|
|||||||||
WTI
Crude Oil
|
January
2010 - December 2010
|
730,000 | $ | 65.00 | $ | 93.00 | |||||||
WTI
Crude Oil
|
January
2010 - December 2010
|
365,000 | $ | 70.00 | $ | 92.85 | |||||||
Commodity
|
Remaining
Period
|
Volume
(MMBTU)
|
Floor
|
Ceiling
|
|||||||||
El
Paso Permian Gas
|
January
2010 - December 2010
|
1,825,000 | $ | 4.00 | $ | 7.87 |
There
were no hedges in effect as of December 31, 2009,
therefore the Company did not record an asset or a liability. The
after tax impact of the change in the fair value of the hedge of $10,212,601 is
reflected in other comprehensive income as unrealized gain on oil derivative for
the period ended December 31, 2009. Changes in the fair value of
derivative instruments designated as cash flow hedges, to the extent they are
effective in offsetting cash flows attributable to the hedged risk, are recorded
in other comprehensive income until the hedged item is recognized in
earnings. Any change in fair value from ineffectiveness is recognized
currently in unrealized derivative gain or loss in the consolidated statements
of operations.
Cash settlements of cash flow hedges
are recorded as a gain or loss on derivatives in the operating section of the
Company’s statement of operations. Our statement of operations
includes a gain on derivative instruments of $14,884,846 for 2009 and a loss on
derivative instrument of $4,275,330 for 2008 and $932,361 for 2007.
Interest
Rate Risk
Our
current credit facility has a floating interest rate. Therefore, if
we draw funds on this credit facility, interest rate changes will impact future
results of operations and cash flows.
Item
8: Financial Statements and
Supplementary Data
The
financial statements and supplementary data required by this item are included
at page 53.
Item
9: Changes in and Disagreements
with Accountants And Accounting and Financial
Disclosure
None.
36
Item
9A: Controls and
Procedures
Evaluation of Disclosure
Controls and Procedures.
We maintain controls and procedures
designed to ensure that information required to be disclosed in the reports that
we file or submit under the Securities Exchange Act of 1934 is recorded,
processed, summarized and reported within the time periods specified in the
rules and forms of the Securities and Exchange Commission. As of the end of the
fiscal year ended December 31, 2009, our chief executive officer and chief
financial officer evaluated the effectiveness of our disclosure controls and
procedures. Based upon their evaluation of those controls and procedures, the
chief executive officer and the chief financial officer of the Company concluded
that as of the end of such period our disclosure controls and procedures are
effective in alerting them to material information in a timely manner that is
required to be included in the reports we file or submit under the Securities
Exchange Act of 1934.
Management’s Annual Report
on Internal Control Over Financial Reporting.
Our management is responsible for
establishing and maintaining adequate internal controls over financial
reporting. Our internal control system was designed to provide
reasonable assurance to our management and Board of Directors regarding the
preparation and fair presentation of published financial
statements.
All internal control systems, no matter
how well designed, have inherent limitations. Therefore, even those
systems determined to be effective can provide only reasonable assurance with
respect to financial statement preparation and presentation.
In making our assessment of internal
control over financial reporting, our management used the criteria issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated
Framework. Based on our assessment, we believe that, as of
December 31, 2009, our internal control over financial reporting is effective
based on those criteria.
Hansen, Barnett & Maxwell, P.C.,
our independent registered public accounting firm, has issued an attestation
report on management’s assessment of Arena’s internal control over financial
reporting.
Date: March
1, 2010
/s/ Phillip W. Terry | |
Chief Executive Officer | |
/s/ William R. Broaddrick | |
Chief Financial Officer |
37
HANSEN, BARNETT & MAXWELL,
P.C.
A Professional
Corporation
CERTIFIED PUBLIC ACCOUNTANTS
5 Triad Center, Suite 750
Salt
Lake City, UT 84180-1128
Phone: (801) 532-2200
Fax: (801) 532-7944
www.hbmcpas.com
|
Registered
with the Public Company
Accounting Oversight
Board
|
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Stockholders
of Arena Resources, Inc.
We have
audited Arena Resources, Inc.’s internal control over financial reporting as of
December 31, 2009, based on criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Arena Resources, Inc.’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 audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit of internal control over financial reporting included
obtaining an understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, and testing and evaluating
the design and operating effectiveness of internal control based on the assessed
risk. Our audit also included performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial
statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
In our
opinion, Arena Resources, Inc. maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2009, based on
criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO).
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the balance sheets and the related statements
of operations and comprehensive income, stockholders’ equity, and cash flows of
Arena Resources, Inc. and our report dated March 1, 2010 expressed an
unqualified opinion thereon.
/s/ HANSEN, BARNETT & MAXWELL, P.C. |
Salt Lake
City, Utah
March 1, 2010
38
Changes in Internal Control
Over Financial Reporting
We made
no change in our internal control over financial reporting during our fourth
quarter of 2009 that has materially affected, or is reasonably likely to
materially affect our internal control over financial reporting.
Item
9B: Other Information
None
39
PART
III
Item
10: Directors, Executive
Officers and Corporate Governance
Executive
Officers and Directors
The following table sets forth
information regarding our executive officers, certain other officers and
directors as of December 31, 2009:
Name
|
Age
|
Position
|
||
Lloyd
T. Rochford
|
63
|
Chairman
of the Board of Directors
|
||
Phillip
W. Terry
|
62
|
President
and Chief Executive Officer
|
||
William
R. Broaddrick
|
32
|
Vice
President and Chief Financial Officer
|
||
David
D. Ricks
|
49
|
Vice
President of Operations
|
||
Stanley
M. McCabe
|
77
|
Director
|
||
Clayton
E. Woodrum
|
69
|
Director
|
||
Anthony
B. Petrelli
|
57
|
Director
|
||
Carl
H. Fiddner
|
64
|
Director
|
Each of
the directors identified above were elected for a term of one year (or until
their successors are elected and qualified) at our annual meeting of
shareholders in December 2009.
Messrs.
Rochford and McCabe have served as directors since our inception in August
2000. Mr. Woodrum has served as a member of our Board since
2003. Mr. Petrelli was elected to the Board by the remaining members
of the Board of Directors in January 2007 to fill the vacancy left by the death
of Mr. Chris V. Kemendo, Jr. Mr. Fiddner was elected to the Board by
the remaining members of the Board of Directors on May 1, 2007, to fill the
vacancy left by the resignation of Charles Crawford.
The
following biographies describe the business experience of our executive officers
and directors:
Lloyd
T. Rochford – Chairman of the Board of Directors.
Mr. Rochford, 63, has been active as
an individual consultant and entrepreneur in the oil and gas industry since
1973. In this capacity, he has primarily been engaged in the organization and
funding of private oil and gas drilling and completion projects and ventures
within the mid-continent region of the United States. In 1990 Mr. Rochford was
co-founder, director and CEO of a public company known as Magnum Petroleum, Inc.
(Magnum) which was listed on the New York Stock Exchange. Subsequently, Magnum
acquired Hunter Resources, Inc. in August, 1995. Mr. Rochford served as Chairman
of the Board of the combined companies from August, 1995 to June, 1997. From
July, 1997 until he committed to participate in Arena Resources, Mr. Rochford
had primarily devoted his time and efforts to individual oil and gas acquisition
and development. In 1982, Mr. Rochford was co-founder of Dana Niguel
Bank, a publicly held California bank operation and served as a director until
1994. Mr. Rochford attended various college level courses in business from 1967
to 1970 in California.
Phillip
W. Terry – President and Chief Executive Officer.
Mr. Terry, 62, has served as
President and Chief Operating Officer since February 1, 2007 and as Chief
Executive Officer since May 20, 2008. Mr. Terry joined the Company in
April 2003, and since that time he has been in charge of all engineering and
field operations. Immediately prior to joining the Company, Mr. Terry owned and
operated an independent petroleum engineering consulting firm. The Company was
one of his clients. In 2001 and 2002, Mr. Terry was Vice President of Drilling
and Production for Bird Creek Resources, Inc. Mr. Terry received his Bachelor of
Science degree in Mechanical Engineering from Oklahoma State University in 1970,
and is a registered Professional Petroleum Engineer with over 35 years
experience in engineering, production, drilling, completions, reservoir
engineering, property evaluations and corporate management in the oil and gas
industry.
40
William
R. Broaddrick – Vice President and Chief Financial Officer.
Mr. Broaddrick, 32, was employed from
1997 to 2000 with Amoco Production Company, performing lease revenue accounting
and state production tax regulatory reporting functions. During 2000,
Mr. Broaddrick was employed by Duke Energy Field Services, LLC performing state
production tax functions. In September 2001, Mr. Broaddrick joined us
as chief accountant, and effective February 1, 2002, assumed responsibilities as
Vice President and Chief Financial Officer.
Mr. Broaddrick received a Bachelor’s
Degree in Accounting from Langston University, through Oklahoma State University
– Tulsa, in 1999. Mr. Broaddrick is a Certified Public
Accountant.
David
D. Ricks – Vice President of Operations.
Mr. Ricks, 49, joined the Company in
November 2007 as Vice President of Operations, he has over 28 years of petroleum
industry experience. Mr. Ricks began his career in 1982 as a production engineer
in Southeast New Mexico for Gulf Oil Co. Since then he has served in various
engineering capacities for Chevron USA, Amerada Hess Corp., Citation Oil and Gas
Corp., Newfield Exploration Mid-Continent, Inc., Apache Corp., and Latigo
Petroleum, Inc. His duties ranged from maintaining production, designing
workovers and recompletions and facility installation, to field supervision of
both primary and secondary production, including waterfloods and CO2 floods,
primarily in Oklahoma, North and West Texas and Southeast New
Mexico.
Stanley
M. McCabe –Director.
Mr. McCabe, 77, served from 1979 to
1989, as Chairman and CEO of Stanton Energy, Inc., a Tulsa, Oklahoma natural
resource company specializing in contract drilling and operation of oil and gas
wells. In 1990, Mr. McCabe also became a co-founder and subsequently an officer
and director of Magnum Petroleum, Inc., along with Mr. Rochford as previously
discussed. Subsequently, Mr. McCabe served as a director of Magnum Hunter
Resources, Inc., through December, 1996. From January, 1997, until he committed
to participate in Arena Resources, Mr. McCabe had primarily devoted his time and
efforts to individual oil and gas acquisition and development. Mr. McCabe
attended college courses at the University of Maryland, primarily in business,
in 1961 and 1962.
Clayton
E. Woodrum – Director.
Mr. Woodrum, 69, is a Certified Public
Accountant and has, from 1984 to present, been a principal shareholder in the
accounting firm of Woodrum, Kemendo, Tate & Westemeir, P.L.L.C., and has
been an owner of Computer Data Litigation Services, LLC and First Capital
Management, LLC. Mr. Woodrum is currently the Chairman of our audit
committee and compensation committee. From 1965 to 1975, Mr. Woodrum
was employed by Peat, Marwick, Mitchell & Co., serving as partner in charge
of the tax department during the final two years. From 1975 to 1980
he served as CFO for BancOklahoma Corp. and Bank of Oklahoma. From
1980 to 1984 Mr. Woodrum served as a partner in charge of the tax department at
Peat, Marwick, Mitchell & Co.
41
Anthony
B. Petrelli – Director.
Mr.
Petrelli, 57, was elected to the Board by the remaining members of the Board of
Directors in January 2007 to fill the vacancy left by the death of Mr. Chris V.
Kemendo, Jr. Since 1987 Mr. Petrelli has been with the firm of
Neidiger Tucker Bruner, Inc., which firm served as one of the lead underwriters
in our secondary registration of common stock in August of 2004. Mr.
Petrelli is currently a Director and Senior Vice President of such
firm. From August 2007 until June 2009, Mr. Petrelli also served on
the Board of Directors of XLR8 Inc., which had a class of securities registered
with the Securities and Exchange Commission. Also, between January
2006 and March 2007 Mr. Petrelli also served on the Board of Directors of
Whitney Information Network, Inc., which has a class of securities registered
with the Securities and Exchange Commission.
Carl
H. Fiddner – Director.
Mr.
Fiddner, 64, joined to the Board in May 2007, to fill the vacancy left
by the resignation of Charles Crawford. Mr. Fiddner is a certified
public accountant who managed his own public accounting firm for 25 years, prior
to joining Regier, Carr & Monroe, in Tulsa, Oklahoma, in December 2005. Mr.
Fiddner worked at Regier, Carr & Monroe through September 30, 2007 at which
time he became an independent financial consultant.
Our
executive officers are elected by, and serve at the pleasure of, our Board of
Directors. Our directors serve terms of one year each, with the current
directors serving until the 2010 annual meeting of stockholders, and in each
case until their respective successors are duly elected and
qualified.
Board
Committees
Our Board
of Directors has established an Audit Committee, a Compensation Committee and a
Nominating and Corporate Governance Committee, the composition and
responsibilities of which are briefly described below. The charters
for each of these committees can be found on our website
(www.arenaresourcesinc.com). We shall also provide any person without
charge, upon request, a copy of the charters for each of these
committees. Requests may be directed to Arena Resources, Inc., 6555
S. Lewis Ave., Tulsa, Oklahoma 74136, attention William R. Broaddrick, or by
calling (918) 747-6060.
The Audit
Committee’s principal functions are to assist the Board in monitoring the
integrity of our financial statements, the independent auditor’s qualifications
and independence, the performance of our independent auditors and our compliance
with legal and regulatory requirements. The Audit Committee has the sole
authority to retain and terminate our independent auditors and to approve the
compensation paid to our independent auditors. The Audit Committee is also
responsible for overseeing our internal audit function. During 2009, the Audit
Committee was comprised of our three independent directors, Messrs. Woodrum,
Petrelli and Fiddner, with Mr. Woodrum acting as the chairman. Our
Board of Directors determined that both Messrs. Woodrum and Fiddner qualified as
“audit committee financial experts” under the rules of the SEC adopted pursuant
to requirements of the Sarbanes-Oxley Act of 2002 (see the biographical
information for Messrs. Woodrum and Fiddner, infra, in this discussion of
“Directors and Executive Officers”). Each of Messrs. Woodrum, Petrelli and
Fiddner further qualified as “independent” in accordance with the applicable
regulations adopted by the SEC and Section 303A.02 of the New York Stock
Exchange Corporate Governance Standards. (see the biographical
information for Messrs. Woodrum, Petrelli and Fiddner, infra, in this discussion
of “Directors and Executive Officers”).
The
Compensation Committee’s principal function is to make recommendations regarding
the compensation of the Company’s officers. In accordance with the
rules of the New York Stock Exchange, the compensation of our chief executive
officer is recommended to the Board (in a proceeding in which the chief
executive officer does not participate) by the Compensation
Committee. Compensation for all other officers is also recommended to
the Board for determination, by the Compensation Committee. During
2009, the Compensation Committee was comprised of our three independent
directors, Messrs. Woodrum, Petrelli and Fiddner, with Mr. Woodrum acting as the
chairman.
42
The
Nominating and Corporate Governance Committee’s principal functions are to (a)
identify and recommend qualified candidates to the Board of Directors for
nomination as members of the Board and its committees, and (b) develop and
recommend to the Board corporate governance principles applicable to the
Company. During 2009, the Compensation Committee was comprised of our
three independent directors, Messrs. Woodrum, Petrelli and Fiddner, with Mr.
Woodrum acting as the chairman.
There
have been no material changes to the procedures by which security holders may
recommend nominees to our Board of Directors.
Our Board
may establish other committees from time to time to facilitate our
management.
Code
of Ethics
We have adopted a code of ethics (our
Code of Business Conduct) that applies to our principal executive officer,
principal financial officer and principal accounting officer or persons
performing similar functions (as well as our other employees and
directors). The Code of Business Conduct can be found on our website
(www.arenaresourcesinc.com). We
shall also provide any person without charge, upon request, a copy of such Code
of Business Conduct. Requests may be directed to Arena Resources,
Inc., 6555 S. Lewis Ave., Tulsa, Oklahoma 74136, attention William R.
Broaddrick, or by calling (918) 747-6060.
Section
16(a) Beneficial Ownership Reporting Compliance
Based solely upon a review of Forms 4
furnished to us during our most recent fiscal year, we know of no director,
officer or beneficial owner of more than ten percent of our common stock who
failed to file on a timely basis reports of beneficial ownership of the our
common stock as required by Section 16(a) of the Securities Exchange Act of
1934, as amended, other than the following:
William R. Broaddrick (Chief
Financial Officer) filed two Form 4’s late (one day each).
Lloyd T. Rochford (Chairman of the
Board) filed two Form 4’s late (one day and two days).
David D. Ricks (Vice President of
Operations) filed a Form 4 late (regarding the grant of 470 shares pursuant to a
restricted stock grant – 13 days).
Item
11: Executive
Compensation
Compensation
Discussion & Analysis
This
section contains a discussion of the material elements of compensation awarded
to, earned by or paid to our principal executive and principal financial
officers, and our other three most highly compensated executive officers and
employees. These individuals are referred to as the (“Named
Officers”) in this Annual Report on Form 10-K.
Our
current executive compensation programs are determined and approved by our
Compensation Committee, after consideration of recommendations by our Chairman
of the Board and our Chief Executive Officer, as to the other Named Officers.
None of the Named Officers are members of the Compensation
Committee. The Compensation Committee has the direct responsibility
and authority to review and approve the Company’s goals and objectives relative
to the compensation of the Named Officers, and to determine and approve (either
as a committee or with the other members of the Company’s Board of Directors who
qualify as “independent” directors under applicable guidelines adopted by the
New York Stock Exchange) the compensation levels of the Named
Officers.
43
Our
current executive compensation programs are intended to achieve two
objectives. The primary objective is to enhance the profitability of
the Company, and thus shareholder value. The second objective is to attract,
motivate, reward and retain employees, including executive personnel, who
contribute to the long-term success of the Company. As described in
more detail below, the material elements of our current executive compensation
program for Named Officers include a base salary, discretionary annual bonuses
and discretionary stock options grants.
The
Company believes that each element of the executive compensation program helps
to achieve one or both of the compensation objectives outlined
above. The table below lists each material element of our executive
compensation program and the compensation objective or objectives that it is
designed to achieve.
Compensation
Element
|
Compensation
Objectives Attempted to be Achieved
|
|
Base
Salary
|
Attract
and retain qualified executive’s
Motivate
and reward executives performance
|
|
Bonus
Compensation
|
Motivate
and reward executive’s performance
Enhance
profitability of Company and shareholder value
|
|
Equity-Based
Compensation – stock options and restricted stock grants
|
Enhance
profitability of Company and shareholder value by aligning long-term
incentives with shareholders’ long-term interests
|
As
illustrated by the table above, base salary is primarily intended to attract and
retain qualified executives. This is the element of the Company’s
current executive compensation program where the value of the benefit in any
given year is not wholly dependent on performance. Base salaries are intended to
attract and retain qualified executives as well as being linked to performance
by rewarding and/or motivating executives. Base salaries are reviewed
annually and take into account: experience and retention considerations; past
performance; improvement in historical performance; anticipated future potential
performance; and other issues specific to the individual executive.
There are
specific elements of the current executive compensation program that are
designed to reward performance and enhance profitability and shareholder value,
and therefore the value of these benefits is based on
performance. The Company’s discretionary annual bonus plan is
primarily intended to motivate and reward Named Officers’ performance to achieve
specific strategies and operating objectives, as well as improved financial
performance.
The
Compensation Committee, with input from both Messrs. McCabe and Rochford,
considers the salaries of comparable executives of peer companies for which such
information is publicly available. The Compensation Committee
believes that bonuses and equity compensation should fluctuate with the
Company’s success in achieving financial, operating and strategic
goals. The Committee’s philosophy is that the Company should continue
to use long-term compensation such as stock options to align shareholder and
executives’ interests and should allocate a portion of long-term compensation to
the entire executive compensation package.
The
Company has never retained an outside consultant in establishing its
compensation program or in establishing any specific compensation for an
executive officer.
44
Current
Executive Compensation Program Elements
Base
Salaries
Similar
to most companies within the industry, our policy is to pay Named Officers’ base
salaries in cash. Effective August 1, 2009, the Compensation
Committee increased salaries for Named Officers by an aggregate of
$60,000. The raises were to Messrs. David R. Ricks, Thomas W. Wahl
and William C. Gaines, raising Mr. Ricks individual base salary to $200,000 and
raising Messrs. Wahl and Gaines individual base salaries to $150,000
each. In approving these salary increases, the Committee took into
account factors including, peer group comparisons available to the Committee,
each executive’s individual experience and increased responsibilities and
improved performance for the Company.
Annual
Bonuses
In the
past, the Company has not had a formal policy regarding bonuses, and payment of
bonuses has been purely discretionary and is largely based on the
recommendations of the Chairman of the Board and the Chief Executive Officer
(except as to themselves). In the recent past, annual bonuses have
been established as a percentage of each employee’s base salary. The
Compensation Committee may reduce or increase the size of the payout for each
individual Named Officer at their discretion. Cash bonuses were
declared and paid out in July and December of 2009 for all five of the Named
Officers. Cash bonuses are not a significant portion of the executive
compensation package. The annual discretionary bonus is reported in
the “Bonus” column of the “Summary Compensation Table” for each Named
Officer.
Perquisites
The
Company currently provides a vehicle allowance for some of its employees,
including two of the Named Officers. Perquisites are reported in the
“All Other Compensation” column of the “Summary Compensation Table’ for each
Named Officer, if applicable.
Equity-Based
Compensation – Restricted Stock Grants
The
Company does not have a formal policy regarding granting of restricted stock,
and granting of stock is discretionary and is largely based on the
recommendations of the Chairman of the Board and the Chief Executive Officer
(except as to themselves). In 2009, restricted stock was granted in
conjunction with the cash bonus declared and paid in December, to three of the
Named Officers. Restricted stock grants are not a significant portion
of the executive compensation package. The grant date fair value, as
determined under generally accepted accounting principles, of the annual
discretionary bonus is reported in the “Stock Grant” column of the “Summary
Compensation Table” for each Named Officer.
Equity-Based
Compensation - Options
It is our
policy that the Named Officers’ long-term compensation should be directly linked
to enhancing profitability and value provided to shareholders of the Company’s
common stock. Accordingly, the Compensation Committee, (upon the
recommendation of Messrs. McCabe and Rochford, with respect to grants of options
other than to themselves) grants equity awards under the Company’s stock option
plan designed to link an increase in shareholder value to
compensation. All of the Named Officer’s equity-based compensation
opportunity was awarded in the form of the Company’s non-qualified stock
options. Stock option grants are valued using the Black-Scholes Model
and are calculated as a part of the executive compensation package for the year
based on the amount of requisite service period served. Non-qualified
stock options for Named Officers and other key employees generally vest ratably
over five years. The Compensation Committee believes that these
awards encourage Named Officers to continue to use their best professional
skills and to retain Named Officers for longer terms.
45
Grants
are determined for Named Officers based on his or her performance in the prior
year, his or her expected future contribution to the performance of the Company,
and other competitive data on grant values of peer companies. Awards
may be granted to new key employees or Named Officers on hire date. Other grant
date determinations are made by the Compensation Committee, which is based upon
the date the Committee met and proper communication was made to the Named
Officer or key employee as defined in the definition of grant date by generally
accepted accounting principles. Exercise prices are equal to
the value of the Company’s stock on the close of business on the determined
grant date. The Company has no program or practice to coordinate
timing of grants with release of material, nonpublic information.
The grant
date fair value as determined under generally accepted accounting principles is
shown in the “Summary Compensation Table” below.
Compensation
Committee’s Report on Executive Compensation (1)
Among the
duties imposed on our Compensation Committee under its charter, is the direct
responsibility and authority to review and approve the Company’s goals and
objectives relevant to the compensation of the Company’s Chief Executive Officer
and other executive officers, to evaluate the performance of such officers in
accordance with the policies and principles established by the Compensation
committee and to determine and approve, either as a Committee, or (as directed
by the Board) with the other “independent” Board members (as defined by the New
York Stock Exchange listing standards), the compensation level of the Chief
Executive Officer and the other executive officers. During 2009 the
Compensation Committee was composed of the three non-employee Directors named at
the end of this report each of whom is “independent” as defined by the New York
Stock Exchange listing standards.
The
Compensation Committee has reviewed and discussed with management the
disclosures contained in the Compensation Discussion and Analysis section of
this Item 11. Based upon this review and our discussions, the Arena
Resources, Inc. Compensation Committee recommended to its Board of Directors
that the Compensation Discussion and Analysis section be included in this annual
report on Form 10-K.
Compensation
Committee of the Board of Directors
Clayton
E. Woodrum (Chair)
Anthony
B. Petrelli
Carl H.
Fiddner
_____________________
(1) SEC
filings sometimes “incorporate information by reference.” This means the Company
is referring you to information that has previously been filed with the SEC, and
that this information should be considered as part of the filing you are
reading. Unless the Company specifically states otherwise, this
Compensation Committee Report shall not be deemed to be incorporated by
reference and shall not constitute soliciting material or otherwise be
considered filed under the Securities Act of 1933 as amended, or the Securities
Exchange act of 1934, as amended.
Compensation
Committee’s Interlocks and Insider Participation
The
Compensation Committee members whose names appear above were committee members
during 2009. No member of the Compensation Committee is or has been a
former or current Named Officer of the Company or had any relationships
requiring disclosure by the Company under the SEC’s rules requiring disclosure
of certain relationships and related-party transactions. None of our Named
Officers identified herein served as a director or a member of a compensation
committee (or other committee serving an equivalent function) of any other
entity.
46
Compensation
of Named Officers
The
“Summary Compensation Table” set forth below should be read in connection with
the tables and narrative descriptions that follow. The “Outstanding
Equity Awards at Fiscal Year End Table” and “Option Exercises and Stock Vested
Table” provide further information on the Named Officers’ potential realizable
value and actual value realized with respect to their equity
awards.
The
Company does not have any pension plans, non-qualified deferred compensation
plans or severance, retirement, termination,
constructive termination or change in control arrangements for any of its Named
Officers for the year ended December 31, 2009.
Summary
Compensation Table
|
||||||||||||||||||||||||||
Name
and Principal Position
|
Year
|
Salary
($)
|
Bonus
($)
|
Stock
Grants (1) ($)
|
Option
Awards (2) ($)
|
All
Other Compensation ($)
|
Total
($)
|
|||||||||||||||||||
Phillip
W. Terry, President and
|
2007
|
$ | 164,167 | $ | 16,000 | $ | - | 3,863,309 | $ | 12,408 | (3 | ) | 4,055,884 | |||||||||||||
Chief Executive Officer |
2008
|
250,000 | 25,000 | - | - | 20,750 | (3 | ) | 295,750 | |||||||||||||||||
2009
|
250,000 | 25,000 | - | - | 32,200 | (3 | ) | 307,200 | ||||||||||||||||||
William
R. Broaddrick,
|
2007
|
89,583 | 9,000 | - | 1,557,976 | 1,400 | (5 | ) | 1,657,959 | |||||||||||||||||
Vice President and |
2008
|
100,008 | 10,000 | - | - | 4,500 | (5 | ) | 114,508 | |||||||||||||||||
Chief Financial Officer |
2009
|
100,008 | 10,000 | - | - | 6,000 | (5 | ) | 116,008 | |||||||||||||||||
David
R. Ricks, Vice President
|
2007
|
28,500 | 1,425 | - | 714,645 | 4,230 | (4 | ) | 748,800 | |||||||||||||||||
of Operations |
2008
|
190,072 | 19,000 | - | 915,270 | 27,523 | (4 | ) | 1,151,865 | |||||||||||||||||
2009
|
195,995 | 29,750 | 20,257 | - | 33,897 | (4 | ) | 279,899 | ||||||||||||||||||
Thomas
W. Wahl,
|
2007
|
50,000 | 2,633 | - | 1,125,176 | 1,800 | (5 | ) | 1,179,609 | |||||||||||||||||
Vice President of Land |
2008
|
125,000 | 12,500 | - | - | 5,625 | (5 | ) | 143,125 | |||||||||||||||||
2009
|
142,869 | 15,625 | 15,645 | - | 8,572 | (5 | ) | 182,711 | ||||||||||||||||||
William
C. Gaines,
|
2007
|
92,639 | 9,741 | - | 981,129 | 575 | (5 | ) | 1,084,084 | |||||||||||||||||
Manager Reservoir |
2008
|
125,000 | 12,500 | - | - | 6,000 | (5 | ) | 143,500 | |||||||||||||||||
Engineering/Acquisitions |
2009
|
135,417 | 21,875 | 15,645 | - | 9,438 | (5 | ) | 182,375 |
(1) See discussion of assumptions made in valuing these awards in the notes to our financial statements.
(2) See
discussion of assumptions made in valuing these awards in the notes to our
financial statements.
(3) All
Other Compensation to Mr. Terry included cash paid as vehicle allowances of
$12,000 for each year presented and $408, $8,750 and $20,200 for the years 2007,
2008 and 2009, respectively, as company matching for contributions to a 401k
program.
(4) All
Other Compensation to Mr. Ricks included cash paid as vehicle allowances of
$2,520, $18,400 and $19,200 for the years 2007, 2008 and 2009 and $1,710, $9,123
and $14,697 for the years 2007, 2008 and 2009, respectively, as company matching
for contributions to a 401k program.
(5) All
Other Compensation to Messrs. Broaddrick, Wahl and Gaines consisted of company
matching for contributions to a 401k program.
The
Company awards stock options to key employees and the Named Officers either on
the initial date of employment or due to performance incentives throughout the
year. During 2009, there were no option grants to any Named
Officer.
As part
of annual discretionary bonus restricted stock awards were granted to three of
the Named officers during 2009.
47
Named
Officers are not separately entitled to receive dividend equivalent rights with
respect to each stock option. Each nonqualified stock option award
described in the “Grants of Plan-Based Awards Table” above expires six-months
following the fifth anniversary of its associated grant date and vests in equal
installments over the course of five years.
The
following table provides certain information regarding unexercised stock options
outstanding for each Named Officer as of December 31, 2009.
Outstanding
Equity Awards
|
|||||||||||||
Name
and Principal Position
|
Number
of Securities Underlying Unexercised Options (#)
Exercisable
|
Number
of Securities Underlying Unexercised Options (#)
Unexercisable
|
Options
Exercise
Price
($)
|
Option
Expiration
Date
|
|||||||||
Phillip
W. Terry
|
40,000 | 120,000 | 19.23 |
07/22/12
|
|||||||||
60,000 | 90,000 | 37.59 |
06/01/13
|
||||||||||
William
R. Broaddrick
|
40,000 | 60,000 | 19.23 |
07/22/12
|
|||||||||
20,000 | 30,000 | 37.59 |
06/01/13
|
||||||||||
David
R. Ricks
|
20,000 | 30,000 | 35.54 |
05/07/13
|
|||||||||
10,000 | 40,000 | 45.68 |
11/01/13
|
||||||||||
Thomas
W. Wahl
|
- | 60,000 | 26.96 |
01/24/13
|
|||||||||
William
C. Gaines
|
- | 60,000 | 23.42 |
12/01/12
|
|||||||||
The
following table presents information regarding the exercise of stock options by
Named Officers during 2009.
Option
Exercises and Stock Vesting
|
||
Option
Awards
|
||
Name
|
Number
of Shares
Acquired
on Exercise (#)
|
Value
Realized on
Exercise
($)
|
Thomas
W. Wahl
|
20,000
|
63,200
|
William
C. Gaines
|
27,000
|
277,020
|
Director Compensation
During
all of 2009, all directors were compensated with a stipend of $1,500 per month
plus $1,000 for each meeting of the directors attended. No director
receives a salary as a director.
Director
Compensation Table
|
||||||
Name
|
Fees
Earned or
Paid
in Cash ($)
|
Option
Awards
($) (1)
|
All
Other
Compensation
($)
|
Total
($)
|
||
Lloyd
T. Rochford
|
22,000
|
-
|
-
|
22,000
|
||
Stanley
M. McCabe
|
22,000
|
-
|
-
|
22,000
|
||
Clayton
E. Woodrum
|
22,000
|
-
|
-
|
22,000
|
||
Anthony
B. Petrelli
|
22,000
|
-
|
-
|
22,000
|
||
Carl
H. Fiddner
|
22,000
|
-
|
-
|
22,000
|
(1) No options or awards of restricted stock were granted to any of the directors during the year ended December 31, 2009.
48
The
following table sets forth information concerning our executive stock
compensation plans as of December 31, 2009.
Number
of securities to be issued upon exercise of outstanding
options
|
Weighted-average
exercise price of outstanding options
|
Number
of securities remaining available for future issuance under compensation
plans (excluding securities in column (a))
|
||||||||||
(a)
|
(b)
|
(c)
|
||||||||||
Equity
compensation plans
approved
by security holders
|
1,895,000 | $ | 23.87 | 1,294,774 | ||||||||
Equity
compensation plans not
approved
by security holders
|
- | - | - | |||||||||
Total
|
1,895,000 | $ | 23.87 | 1,294,774 | ||||||||
Item
12: Security Ownership of
Certain Beneficial Owners and Management and Related Stockholder
Matters
The
following table sets forth, as March 1, 2010, information regarding the
beneficial ownership of our common stock: (i) by each of our directors and
executive officers; and (ii) by all directors and executive officers as a group.
The mailing address for each of the persons indicated is our corporate
headquarters.
Beneficial ownership is determined
under the rules of the Securities and Exchange Commission. In general, these
rules attribute beneficial ownership of securities to persons who possess sole
or shared voting power and/or investment power with respect to those securities
and includes, among other things, securities that an individual has the right to
acquire within 60 days. Unless otherwise indicated, the stockholders identified
in the following table have sole voting and investment power with respect to all
shares shown as beneficially owned by them.
Shares
of Common Stock Beneficially Owned
|
||||
Name
|
Number
|
Percent
|
||
Lloyd
T. Rochford
|
365,200
(1)
|
1%
|
||
Phillip
W. Terry
|
230,000
(2)
|
1%
|
||
William
R. Broaddrick
|
191,200
(3)
|
1%
|
||
David
D. Ricks
|
30,470
(4)
|
*
|
||
Stanley
M. McCabe
|
350,000
(5)
|
1%
|
||
Clayton
E. Woodrum
|
20,000
(6)
|
*
|
||
Anthony
B. Petrelli
|
97,000
(7)
|
*
|
||
Carl
H. Fiddner
|
38,736
(8)
|
*
|
||
All
directors and executive officers
|
1,322,606
(9)
|
3%
|
||
(1)
|
Includes
70,000 shares issuable upon the exercise of stock options that are
currently exercisable and 80,000 shares issuable upon the exercise of
stock options that are exercisable within 60
days.
|
(2)
|
Includes
100,000 shares issuable upon the exercise of stock options that are
currently exercisable and 40,000 shares issuable upon the exercise of
stock options that are exercisable within 60
days.
|
49
(3)
|
Includes
60,000 shares issuable upon the exercise of stock options that are
currently exercisable and 20,000 shares issuable upon the exercise of
stock options that are exercisable within 60
days.
|
(4)
|
Includes
30,000 shares issuable upon the exercise of stock options that are
currently exercisable.
|
(5)
|
Includes
270,000 shares issuable upon the exercise of stock options that are
currently exercisable and 80,000 shares issuable upon the exercise of
stock options that are exercisable within 60
days.
|
(6)
|
Includes
10,000 shares issuable upon the exercise of stock options that are
currently exercisable and 5,000 shares issuable upon the exercise of stock
options that are exercisable within 60
days.
|
(7)
|
Includes
50,000 shares issuable upon the exercise of stock options that are
currently exercisable and 20,000 shares issuable upon the exercise of
stock options that are exercisable within 60
days.
|
(8)
|
Includes
30,000 shares issuable upon the exercise of stock options that are
currently exercisable.
|
(9)
|
Includes
620,000 shares issuable upon the exercise of stock options that are
currently exercisable and 245,000 shares issuable upon the exercise of
stock options that are exercisable within 60 days by all executive
officers and directors.
|
*
|
Represents
beneficial ownership of less than
1%
|
The
following table sets forth, as March 1, 2010, information regarding the
beneficial ownership of our common stock: by all persons known to us to own 5%
or more of our outstanding shares of common stock.
Shares of Stock Beneficially Owned | ||||
Name
and Address
|
Number
|
Percentage
|
||
Neuberger
Berman Group, LLC
605
Third Avenue
New
York, New York 10158
|
4,285,209
(1)
|
11.05%
|
||
FMR
LLC
82
Devonshire Street
Boston,
Massachusetts 02109
|
3,233,498
(2)
|
8.30%
|
||
BlackRock,
Inc.
40
East 52nd
Street
New
York, New York 10022
|
2,915,226
(3)
|
7.51%
|
||
T.
Rowe Price Associates, Inc.
100
E. Pratt Street
Baltimore,
Maryland 21202
|
2,147,920
(4)
|
5.54%
|
______________________________________
(1)
|
This
share ownership information was provided by a Schedule 13G filed February
17, 2010, which discloses that each of Neuberger Berman Group, LLC and
Neuberger Berman, LLC possesses shared power to dispose or direct the
disposition of 4,285,209 shares, and shared power to vote 3,562,743
shares. The Schedule 13G further discloses that Neuberger Berman
Management LLC possesses shared power to vote and dispose or direct the
disposition of 1,909,522 shares, and Neuberger Berman, Equity Funds
possesses shared power to vote and dispose or direct the disposition of
3,403,528 shares.
|
(2)
|
This share ownership information was
provided by a Schedule 13G filed February 16, 2010, which discloses that
FMR LLC, possesses beneficial ownership of the reported
shares.
|
(3)
|
This
share ownership information was provided by a Schedule 13G filed January
29, 2010, following the acquisition by BlackRock, Inc. of Barclays Global
Investors, NA; the Schedule discloses BlackRock possesses sole power to
dispose or direct the disposition and sole power to vote or to direct the
vote of such shares.
|
(4)
|
This
share ownership information was provided by a Schedule 13G filed February
11, 2010, which discloses that T. Rowe Price Associates, Inc. possesses
sole dispositive power of the reported
shares.
|
Percentage
ownership calculations for any stockholder listed above are based on 38,793,963
shares of our common stock outstanding as of March 1, 2010.
50
Item
13: Certain Relationships and
Related Transactions, and Director Independence
In July 2002, we borrowed $200,000 from
each of Messrs. Rochford and McCabe, which debts are evidenced by notes payable
which matured and were paid in January 2007. The notes bore interest
at a rate of 10% per annum, and were secured by our assets (although such notes
were subordinate to our credit facility with our primary commercial
lender).
As
discussed under Item 10 of this Form 10-K, the Board of Directors has determined
that Messrs. Woodrum, Petrelli and Fiddner, are each “independent” directors
within the meaning of Section 303A.00 of the New York Stock Exchange Listed
Company Manual. None of our independent directors falls within any of
the categories of persons who would not be independent as described in Section
303A.00(b) of the New York Stock Exchange rules. Because the Board of
Directors believes it is not possible to anticipate or provide for all
circumstances that might give rise to conflicts of interest or that might bear
on the materiality of a relationship between a director and the Company, the
Board has not established specific objective criteria, apart from the criteria
set forth in the New York Stock Exchange rules, to determine
“independence”. In addition to such criteria, in making the
determination of “independence”, the Board of Directors considers such other
matters including (i) the business and non-business relationships that each
independent director has or may have had with the Company and its other
Directors and executive officers, (ii) the stock ownership in the Company held
by each such Director, (iii) the existence of any familial relationships with
any executive officer or Director of the Company, and (iv) any other relevant
factors which could cause any such Director to not exercise his independent
judgment.
Item
14: Principal Accountant Fees
and Services
The firm
of Hansen, Barnett & Maxwell, P.C., (“HBM”) has served as the Company’s
independent auditors since 2000. The Audit Committee selected HBM as
the independent auditors of the Company for the fiscal year ending December 31,
2009. The Audit Committee has adopted a policy that requires advance
approval of all audit, audit-related, tax services and other services performed
by the independent auditor.
Fees
and Independence
Audit Fees. HBM
billed the Company an aggregate of $124,646 and $124,062 for professional
services rendered for the audit of the Company’s financial statements for the
years ended December 31, 2009 and 2008, respectively, and its reviews of the
Company’s financial statements included in its Form 10-Q’s for the first three
quarters of 2009 and 2008.
Audit Related
Fees. HBM billed the Company $0 and $37,024 for the years
ended December 31, 2009 and 2008, respectively, for its services in connection
with the review of the Company’s registration statements on Form S-3 and for the
audit of the Phoenix Petrocorp acquisition.
Tax Fees. HBM
billed the Company $5,000 for professional services rendered for tax compliance,
tax advice and tax planning for each of the years ended December 31, 2009 and
2008.
All Other Fees. No
other fees were billed by HBM to the Company during 2009 and 2008.
The Audit
Committee of the Board of Directors has determined that the provision of
services by HBM described above is compatible with maintaining HBM’s
independence as the Company’s principal accountant.
51
Item
15: Exhibits
(a) | Financial Statements |
See Index to Financial Statements on page 54 | |
(b) | Exhibits |
3.1 | Articles of Incorporation of Arena Resources, Inc. (i) |
3.2 | By-Laws of Arena Resources, Inc. (i) |
10.1 | Second Amended and Restated Credit Agreement dated as of June 30, 2009, effective as of July 2, 2009, among the Company, MidFirst Bank, Compass Bank and Capital One, N.A. (ii) |
23.1 | Consent of Williamson Petroleum Consultants, Inc., Independent Petroleum Engineers |
23.2 | Consent of Hansen, Barnett & Maxwell, P.C., Independent |
31.1 | Certification of CEO |
31.2 | Certification of CFO |
32.1 | Section 1350 Certification - CEO |
32.2 | Section 1350 Certification – CFO |
99 | Reserves Audit Report of Williamson Petroleum Consultants, Inc. |
(i) Incorporated
herein by reference to the exhibits to Arena Resources, Inc.’s Form SB-1 filed
January 2, 2001 (SEC File No. 333-46164).
(ii)
Incorporated herein by reference to the exhibit to Arena Resources, Inc.’s Form
8-K filed July 29, 2009.
52
SIGNATURES
In accordance with Section 13 or 15(d)
of the Exchange Act, the registrant caused this report to be signed on behalf by
the undersigned, thereunto duly authorized.
Arena
Resources, Inc.
|
|
By:______________________
|
|
Mr.
Phillip W. Terry
|
|
President
and Chief Executive Officer
|
|
Date: March
1, 2010
|
|
By:______________________
|
|
Mr.
William R. Broaddrick
|
|
Chief
Financial Officer
|
|
Date: March
1, 2010
|
|
In accordance with the Exchange Act,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the date indicated.
______________________
|
|
Mr.
Lloyd T. Rochford
|
|
Director
|
|
Date: March
1, 2010
|
|
______________________
|
|
Mr.
Stanley McCabe
|
|
Director
|
|
Date: March
1, 2010
|
|
______________________
|
|
Mr.
Clayton E. Woodrum
|
|
Director
|
|
Date: March
1, 2010
|
|
______________________
|
|
Mr.
Anthony B. Petrelli
|
|
Director
|
|
Date: March
1, 2010
|
|
______________________
|
|
Mr.
Carl H. Fiddner
|
|
Director
|
|
Date: March
1, 2010
|
|
53
ARENA
RESOURCES, INC.
INDEX
TO FINANCIAL STATEMENTS
Page
|
|
Report
of Independent Registered Public Accounting Firm
|
55
|
Consolidated
Balance Sheets
|
56
|
Consolidated
Statements of Operations
|
57
|
Consolidated
Statements of Stockholders’ Equity
|
58
|
Consolidated
Statements of Cash Flows
|
59
|
Notes
to Consolidated Financial Statements
|
60
|
Supplemental
Information on Oil and Gas Producing Activities
|
76
|
54
HANSEN, BARNETT & MAXWELL,
P.C.
A Professional
Corporation
CERTIFIED PUBLIC ACCOUNTANTS
5 Triad Center, Suite 750
Salt
Lake City, UT 84180-1128
Phone: (801) 532-2200
Fax: (801) 532-7944
www.hbmcpas.com
|
Registered
with the Public Company
Accounting Oversight
Board
|
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Stockholders
of Arena
Resources, Inc.
We have
audited the accompanying consolidated balance sheets of Arena Resources, Inc.
and subsidiaries as of December 31, 2009 and 2008, and the related consolidated
statements of operations and comprehensive income, stockholders' equity, and
cash flows for each of the three years in the period ended December 31, 2009.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe our audits provide a reasonable basis for our
opinion.
In our
opinion, the financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Arena Resources, Inc.
and subsidiaries as of December 31, 2009 and 2008, and the consolidated results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2009, in conformity with accounting principles
generally accepted in the United States of America.
We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of Arena Resources, Inc.’s
internal control over financial reporting as of December 31, 2009, based on
criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated March 1, 2010 expressed an
unqualified opinion thereon.
/s/ HANSEN, BARNETT & MAXWELL, P.C. |
Salt Lake
City, Utah
March 1,
2010
55
ARENA
RESOURCES, INC.
CONSOLIDATED
BALANCE SHEETS
December
31,
|
2009
|
2008
|
||||||
ASSETS
|
||||||||
Current
Assets
|
||||||||
Cash
|
$ | 63,635,078 | $ | 58,489,574 | ||||
Accounts
receivable
|
13,103,483 | 8,637,308 | ||||||
Joint
interest billing receivable
|
2,392,814 | 2,836,948 | ||||||
Receivable
from oil derivative
|
- | 2,508,396 | ||||||
Fair
value of oil derivative
|
- | 16,210,478 | ||||||
Prepaid
expenses
|
1,040,513 | 847,433 | ||||||
Total
Current Assets
|
80,171,888 | 89,530,137 | ||||||
Property
and Equipment
|
||||||||
Oil
and gas properties subject to amortization
|
661,453,134 | 548,714,235 | ||||||
Oil
and gas gathering systems
|
2,134,876 | - | ||||||
Inventory
for property development
|
1,052,538 | 1,670,067 | ||||||
Drilling
rigs
|
6,694,841 | 6,899,433 | ||||||
Land,
buildings, equipment and leasehold improvements
|
5,991,983 | 5,799,045 | ||||||
Total
Property and Equipment
|
677,327,372 | 563,082,780 | ||||||
Less: Accumulated
depreciation , depletion and amortization
|
(100,428,326 | ) | (60,928,142 | ) | ||||
Net
Property and Equipment
|
576,899,046 | 502,154,638 | ||||||
Total
Assets
|
$ | 657,070,934 | $ | 591,684,775 | ||||
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
||||||||
Current
Liabilities
|
||||||||
Accounts
payable
|
$ | 17,155,260 | $ | 12,877,084 | ||||
Current
taxes payable
|
314,700 | - | ||||||
Deferred
income taxes
|
- | 6,046,508 | ||||||
Accrued
liabilities
|
1,101,633 | 865,955 | ||||||
Total
Current Liabilities
|
18,571,593 | 19,789,547 | ||||||
Long-Term
Liabilities
|
||||||||
Asset
retirement liability
|
7,209,812 | 5,066,348 | ||||||
Deferred
income taxes
|
108,622,799 | 84,533,419 | ||||||
Total
Long-Term Liabilities
|
115,832,611 | 89,599,767 | ||||||
Stockholders'
Equity
|
||||||||
Preferred
stock - $0.001 par value; 10,000,000 shares authorized;
|
||||||||
no
shares issued or outstanding
|
- | - | ||||||
Common
stock - $0.001 par value; 100,000,000 shares authorized;
|
||||||||
38,693,963
shares and 38,210,187 shares outstanding, respectively
|
38,694 | 38,210 | ||||||
Additional
paid-in capital
|
326,990,590 | 318,701,383 | ||||||
Retained
earnings
|
195,637,446 | 153,343,267 | ||||||
Accumulated
other comprehensive income
|
- | 10,212,601 | ||||||
Total
Stockholders' Equity
|
522,666,730 | 482,295,461 | ||||||
Total
Liabilities and Stockholders' Equity
|
$ | 657,070,934 | $ | 591,684,775 | ||||
The
accompanying notes are an integral part of these consolidated financial
statements.
56
ARENA
RESOURCES, INC.
CONSOLIDATED
STATEMENTS OF OPERATIONS
For
the years ended December 31,
|
2009
|
2008
|
2007
|
|||||||||
Oil
and Gas Revenues
|
$ | 126,240,777 | $ | 208,858,645 | $ | 100,089,698 | ||||||
Costs
and Operating Expenses
|
||||||||||||
Oil
and gas production costs
|
15,543,461 | 17,833,144 | 11,500,461 | |||||||||
Oil
and gas production taxes
|
6,455,585 | 10,518,370 | 5,655,877 | |||||||||
Realized
loss (gain) on oil derivative
|
(14,884,846 | ) | 4,275,330 | 932,361 | ||||||||
Depreciation,
depletion and amortization
|
38,957,641 | 29,789,794 | 17,968,062 | |||||||||
Accretion
expense
|
410,926 | 309,402 | 190,904 | |||||||||
General
and administrative (which includes $4,649,928, $6,586,279
and
$4,140,747, respectively, in stock based
compensation)
|
13,453,384 | 13,557,202 | 7,815,721 | |||||||||
Total
Costs and Operating Expenses
|
59,936,151 | 76,283,242 | 44,063,386 | |||||||||
Income
from Operations
|
66,304,626 | 132,575,403 | 56,026,312 | |||||||||
Other
Income (Expense)
|
||||||||||||
Interest
income
|
828,992 | 1,299,939 | 884,990 | |||||||||
Interest
expense
|
- | (1,145,456 | ) | (1,411,520 | ) | |||||||
Net
Other Income (Expense)
|
828,992 | 154,483 | (526,530 | ) | ||||||||
Income
Before Provision for Income Taxes
|
67,133,618 | 132,729,886 | 55,499,782 | |||||||||
Provision
for Income Taxes
|
(24,839,439 | ) | (49,112,685 | ) | (21,057,843 | ) | ||||||
Net
Income
|
$ | 42,294,179 | $ | 83,617,201 | $ | 34,441,939 | ||||||
Basic
Net Income Per Common Share
|
$ | 1.10 | $ | 2.28 | $ | 1.07 | ||||||
Diluted
Net Income Per Common Share
|
1.09 | 2.20 | 1.02 | |||||||||
Other
Comprehensive Income (Loss)
|
||||||||||||
Net
income
|
$ | 42,294,179 | $ | 83,617,201 | $ | 34,441,939 | ||||||
Realized
loss (gain) on hedge derivative contract settlements reclassified from
other comprehensive loss (income), net of
tax
|
(10,222,546 | ) | 12,381,887 | - | ||||||||
Change
in unrealized deferred hedging gains (losses), net of tax
|
9,945 | 632,212 | (2,801,498 | ) | ||||||||
Total
Comprehensive Income
|
$ | 32,081,578 | $ | 96,631,300 | $ | 31,640,441 | ||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
57
ARENA
RESOURCES, INC.
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS’ EQUITY
FOR
THE YEARS ENDED DECEMBER 31, 2007, 2008 AND 2009
Accumulated
|
||||||||||||||||||||||||||||
Additional
|
Other
|
Total
|
||||||||||||||||||||||||||
Common
Stock
|
Paid-in
|
Deferred
|
Retained
|
Comprehensive
|
Stockholders'
|
|||||||||||||||||||||||
Shares
|
Amount
|
Capital
|
Compensation
|
Earnings
|
Income
(Loss)
|
Equity
|
||||||||||||||||||||||
Balance
December 31, 2006
|
29,337,574 | $ | 29,338 | $ | 84,730,586 | $ | - | $ | 35,284,127 | $ | - | $ | 120,044,052 | |||||||||||||||
Options
exercised for cash
|
570,000 | 570 | 1,851,930 | - | - | - | 1,852,500 | |||||||||||||||||||||
Warrants
exercised for cash
|
127,126 | 127 | 540,169 | - | - | - | 540,295 | |||||||||||||||||||||
Warrants
exercised using cashless exercise provision
|
139,079 | 139 | (139 | ) | - | - | - | - | ||||||||||||||||||||
Shares
issued in property acquisition
|
5,000 | 5 | 204,745 | - | - | - | 204,750 | |||||||||||||||||||||
Tax
impact of option exercises
|
- | - | 4,298,722 | - | - | - | 4,298,722 | |||||||||||||||||||||
Issuance
of common stock for cash, net
|
4,100,000 | 4,100 | 95,085,358 | - | - | - | 95,089,458 | |||||||||||||||||||||
Expense
related to vesting stock based compensation
|
- | - | 4,140,747 | - | - | - | 4,140,747 | |||||||||||||||||||||
Loss
on change in fair value of oil derivative, net of tax
|
- | - | - | - | - | (2,801,498 | ) | (2,801,498 | ) | |||||||||||||||||||
Net
income
|
- | - | - | - | 34,441,939 | - | 34,441,939 | |||||||||||||||||||||
Balance
December 31, 2007
|
34,278,779 | $ | 34,279 | $ | 190,852,118 | $ | - | $ | 69,726,066 | $ | (2,801,498 | ) | $ | 257,810,965 | ||||||||||||||
Options
exercised for cash
|
1,333,000 | 1,333 | 4,689,927 | - | - | - | 4,691,260 | |||||||||||||||||||||
Warrants
exercised for cash
|
97,158 | 97 | 446,099 | - | - | - | 446,196 | |||||||||||||||||||||
Issuance
of common stock for cash, net
|
2,501,250 | 2,501 | 116,126,960 | - | - | - | 116,129,461 | |||||||||||||||||||||
Expense
related to vesting stock based compensation
|
- | - | 6,586,279 | - | - | - | 6,586,279 | |||||||||||||||||||||
Gain
on change in fair value of oil derivative, net of tax
|
- | - | - | - | - | 13,014,099 | 13,014,099 | |||||||||||||||||||||
Net
income
|
- | - | - | - | 83,617,201 | - | 83,617,201 | |||||||||||||||||||||
Balance
December 31, 2008
|
38,210,187 | $ | 38,210 | $ | 318,701,383 | $ | - | $ | 153,343,267 | $ | 10,212,601 | $ | 482,295,461 | |||||||||||||||
Options
exercised for cash
|
317,000 | 317 | 2,922,123 | - | - | - | 2,922,440 | |||||||||||||||||||||
Warrants
exercised for cash
|
161,550 | 162 | 717,161 | - | - | - | 717,323 | |||||||||||||||||||||
Expense
related to vesting stock based compensation
|
- | - | 4,633,873 | - | - | - | 4,633,873 | |||||||||||||||||||||
Restricted
stock grant and vesting
|
5,226 | 5 | 16,050 | - | - | - | 16,055 | |||||||||||||||||||||
Loss
on change in fair value of oil derivative, net of tax
|
- | - | - | - | - | (10,212,601 | ) | (10,212,601 | ) | |||||||||||||||||||
Net
income
|
- | - | - | - | 42,294,179 | - | 42,294,179 | |||||||||||||||||||||
Balance
December 31, 2009
|
38,693,963 | $ | 38,694 | $ | 326,990,590 | $ | - | $ | 195,637,446 | $ | - | $ | 522,666,730 |
The
accompanying notes are an integral part of these consolidated financial
statements.
58
ARENA
RESOURCES, INC.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
For
the years ended December 31,
|
2009
|
2008
|
2007
|
|||||||||
Cash
Flows From Operating Activities
|
||||||||||||
Net
income
|
$ | 42,294,179 | $ | 83,617,201 | $ | 34,441,939 | ||||||
Adjustments
to reconcile net income to net cash
|
||||||||||||
provided by operating activities:
|
||||||||||||
Depreciation,
depletion and amortization
|
38,957,641 | 29,789,794 | 17,968,062 | |||||||||
Provision
for income taxes
|
24,839,439 | 49,112,685 | 21,057,843 | |||||||||
Gain
on sale of equipment
|
- | - | (881 | ) | ||||||||
Stock
based compensation
|
4,649,928 | 6,586,279 | 4,140,747 | |||||||||
Accretion
of asset retirement obligation
|
410,926 | 309,402 | 190,904 | |||||||||
Changes
in assets and liabilities:
|
||||||||||||
Accounts,
joint interest and oil derivative receivable
|
(1,513,645 | ) | 9,835,045 | (14,165,921 | ) | |||||||
Current
and deferred income taxes
|
- | (612,480 | ) | - | ||||||||
Prepaid
expenses
|
(472,478 | ) | (714,040 | ) | (30,808 | ) | ||||||
Excess
tax benefits from share-based payment arrangements
|
- | - | (4,298,722 | ) | ||||||||
Accounts
payable and accrued liabilities
|
4,513,854 | (587,238 | ) | (814,999 | ) | |||||||
Net
Cash Provided by Operating Activities
|
113,679,844 | 177,336,648 | 58,488,164 | |||||||||
Cash
Flows from Investing Activities
|
||||||||||||
Proceeds
from sale of property and equipment
|
- | - | 7,000 | |||||||||
Proceeds
from sale of oil and gas properties
|
- | 296,800 | 1,915,640 | |||||||||
Purchase
and development of oil and gas properties
|
(103,778,202 | ) | (207,022,666 | ) | (168,582,803 | ) | ||||||
Purchase
of inventory for property development
|
(6,068,087 | ) | (1,670,067 | ) | - | |||||||
Construction
of oil and gas gathering systems
|
(2,134,876 | ) | - | - | ||||||||
Purchase
of buildings, machinery and office equipment
|
(192,938 | ) | (1,931,517 | ) | (8,615,501 | ) | ||||||
Net
Cash Used in Investing Activities
|
(112,174,103 | ) | (210,327,450 | ) | (175,275,664 | ) | ||||||
Cash
Flows From Financing Activities
|
||||||||||||
Proceeds
from issuance of common stock and warrants, net of offering
costs
|
- | 116,129,461 | 95,089,458 | |||||||||
Proceeds
from exercise of warrants, net of offering costs
|
717,323 | 446,196 | 540,295 | |||||||||
Proceeds
from exercise of options
|
2,922,440 | 4,691,260 | 1,852,500 | |||||||||
Excess
tax benefits from share-based payment arrangements
|
- | - | 4,298,722 | |||||||||
Issuance
of notes payable
|
- | 11,000,000 | 65,700,000 | |||||||||
Payment
of notes payable
|
- | (46,000,000 | ) | (50,400,000 | ) | |||||||
Net
Cash Provided by Financing Activities
|
3,639,763 | 86,266,917 | 117,080,975 | |||||||||
Net
Increase in Cash
|
5,145,504 | 53,276,115 | 293,475 | |||||||||
Cash
at Beginning of Period
|
58,489,574 | 5,213,459 | 4,919,984 | |||||||||
Cash
at End of Period
|
$ | 63,635,078 | $ | 58,489,574 | $ | 5,213,459 | ||||||
For
the years ended December 31,
|
2009
|
2008
|
2007
|
|||||||||
Supplemental
Cash Flow Information
|
||||||||||||
Cash
paid for income taxes
|
$ | - | $ | 612,480 | $ | - | ||||||
Cash
paid for interest
|
- | 1,280,122 | 1,463,328 | |||||||||
Non-Cash
Investing and Financing Activities
|
||||||||||||
Common
stock issued for properties
|
$ | - | $ | - | $ | 204,750 | ||||||
Asset
retirement obligation incurred in property acquisition and
development
|
1,732,538 | 1,459,534 | 1,001,613 | |||||||||
Depreciation
on drilling rigs capitalized as oil and gas properties
|
542,543 | 640,977 | 306,133 | |||||||||
Use
of inventory in property development
|
6,685,616 | - | - |
The
accompanying notes are an integral part of these consolidated financial
statements.
59
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
1 – ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and
Nature of Operations – Arena Resources, Inc. (the “Company”) is a Nevada
corporation that owns interests in oil and gas properties located in Oklahoma,
Texas, Kansas and New Mexico. The Company is engaged primarily in the
acquisition, exploration and development of oil and gas properties and the
production and sale of oil and gas. In 2006, the Company formed two
wholly owned subsidiaries, Arena Drilling Co. and ARD Production
Company. The accompanying statements of operations and
cash flows include the operations of the above subsidiaries from the date of
acquisition/formation.
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, disclosure of contingent assets and
liabilities and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those
estimates. Changes in the future estimated oil and natural gas
reserves or the estimated future cash flows attributable to the reserves that
are utilized for impairment analysis could have a significant impact on the
future results of operations.
Consolidation
– The accompanying consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries. All significant
intercompany balances and transactions have been eliminated in
consolidation.
Concentration of
Credit Risk and Accounts Receivable – Financial instruments that
potentially subject the Company to a concentration of credit risk consist
principally of cash and accounts receivable. The Company has cash in
excess of federally insured limits at December 31, 2009. The Company
places its cash with a high credit quality financial institution.
Substantially
all of the Company’s accounts receivable is from purchasers of oil and
gas. Oil and gas sales are generally unsecured. The
Company has not had any significant credit losses in the past and believes its
accounts receivable are fully collectable. Accordingly, no allowance
for doubtful accounts has been provided. The Company also has a joint
interest billing receivable. Joint interest billing receivables are
collateralized by the pro rata revenue attributable to the joint interest
holders and further by the interest itself.
Cash – The
Company considers all highly liquid investments purchased with an original
maturity of three months or less to be cash equivalents.
Oil and Gas
Properties – The Company uses the full cost method of accounting for oil
and gas properties. Under this method, all costs associated with
acquisition, exploration, and development of oil and gas properties are
capitalized. Costs capitalized include acquisition costs, geological and
geophysical expenditures, lease rentals on undeveloped properties and costs of
drilling and equipping productive and non-productive wells. Drilling costs
include directly related overhead costs. Capitalized costs are categorized
either as being subject to amortization or not subject to
amortization.
The
Company records a liability in the period in which an asset retirement
obligation (“ARO”) is incurred, in an amount equal to the discounted estimated
fair value of the obligation that is capitalized. Thereafter this
liability is accreted up to the final retirement cost. An ARO is a
future expenditure related to the disposal or other retirement of certain
assets. The Company’s ARO’s relate to future plugging and abandonment
expenses of its oil and gas properties and related facilities
disposal.
60
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
All
capitalized costs of oil and gas properties, including the estimated future
costs to develop proved reserves and estimated future costs to plug and abandon
wells and costs of site restoration, less the estimated salvage value of
equipment associated with the oil and gas properties, are amortized on the
unit-of-production method using estimates of proved reserves as determined by
independent engineers. If the results of an assessment indicate that
the properties are impaired, the amount of the impairment is added to the
capitalized costs to be amortized. Following is a table showing total
depletion and depletion per barrel-of-oil-equivalent rate, by year for the years
ended December 31, 2009, 2008, and 2007.
For
the Years Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Depletion
|
$ | 38,659,746 | $ | 29,554,184 | $ | 17,885,561 | ||||||
Depletion
rate, per barrel-of-oil-equivalent (BOE)
|
$ | 16.34 | $ | 12.65 | $ | 11.42 |
In
addition, capitalized costs less accumulated amortization and related deferred
income taxes shall not exceed an amount (the full cost ceiling) equal to the sum
of:
1)
the present value of estimated future net revenues discounted ten percent
computed in compliance with SEC guidelines;
2)
plus the cost of properties not being amortized;
3)
plus the lower of cost or estimated fair value of unproven properties included
in the costs being amortized;
4)
less income tax effects related to differences between the book and tax basis of
the properties.
Drilling Rigs –
Drilling rigs are valued at historical cost, adjusted for impairment loss
less accumulated depreciation. Historical costs include all direct
costs associated with the acquisition of drilling rigs and placing them in
service. Drilling rigs are depreciated over 10 years but are only
depreciated during periods during which they are in use and the depreciation is
capitalized as part of oil and gas properties subject to
amortization. For the year ended December 31, 2009, 2008 and 2007 the
Company had depreciation of $542,543, $640,977 and $306,133, respectively, on
the company owned drilling rigs.
Land, Buildings,
Equipment and Leasehold Improvements – Land, buildings, equipment and
leasehold improvements are valued at historical cost, adjusted for impairment
loss less accumulated depreciation. Historical costs include all
direct costs associated with the acquisition of land, buildings, equipment and
leasehold improvements and placing them in service.
Depreciation
of buildings and equipment is calculated using the straight-line method based
upon the following estimated useful lives:
Buildings
and improvements
|
30
years
|
Office
equipment and software
|
5-7
years
|
Machinery
and equipment
|
5-7
years
|
Depreciation
expense was $297,895, $235,609 and $62,921 for the years ended December 31,
2009, 2008 and 2007, respectively. An aggregate value of $530,000 has
been attributed to the land on which the buildings sit and is not subject to
depreciation.
Inventory for
Property Development – Inventories consist primarily of tubular goods
used in development and are stated at the lower of specific cost of each
inventory item or market value.
61
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Revenue
recognition – The Company predominantly derives its revenue from the sale
of produced crude oil and natural gas. Revenue is recorded in the month the
product is delivered to the purchaser. At the end of each month, the
Company estimates the amount of production delivered to purchasers and the price
we received. Variances between the Company’s estimated revenue and actual
payment are recorded in the month the payment is received; however, differences
have been insignificant.
Income
Taxes – Provisions for income taxes are based on taxes payable or
refundable for the current year and deferred taxes. Deferred taxes
are provided on differences between the tax bases of assets and liabilities and
their reported amounts in the financial statements, and tax carry
forwards. Deferred tax assets and liabilities are included in the
financial statements at currently enacted income tax rates applicable to the
period in which the deferred tax assets and liabilities are expected to be
realized or settled. As changes in tax laws or rates are enacted,
deferred tax assets and liabilities are adjusted through the provision for
income taxes.
Earnings Per
Share – Basic earnings per share is computed by dividing net income by
the weighted-average number of common shares outstanding during the
year. Diluted earnings per share are calculated to give effect to
potentially issuable dilutive common shares.
Major
Customers – During the year ended December 31, 2009, sales to three
customers represented 75% 13% and 8% of total sales, respectively. At
December 31, 2009, these customers made up 74%, 14% and 7% of accounts
receivable, respectively. During the year ended December 31, 2008,
sales to three customers represented 83% 8% and 5% of total sales,
respectively. At December 31, 2008, these customers made up 84%, 9%
and 5% of accounts receivable, respectively. During the year ended
December 31, 2007, sales to two customers represented 83% and 11% of total
sales, respectively. At December 31, 2007, these customers made up
85% and 7% of accounts receivable, respectively. The loss of any of
the foregoing customers would not have a material adverse affect on the Company
as there is an available market for its crude oil and natural gas production
from other purchasers.
Stock-Based
Employee Compensation – The Company has outstanding stock options and
restricted stock grants to directors and employees, which are described more
fully in Note 7. The Company accounts for its stock options and
restricted stock grants in accordance with generally accepted accounting
principles. The generally accepted accounting principles require the
recognition of the cost of employee services received in exchange for an award
of equity instruments in the financial statements and is measured based on the
grant date fair value of the award. The generally accepted accounting principles
also requires the stock option compensation expense to be recognized over the
period during which an employee is required to provide service in exchange for
the award (the vesting period).
Stock-based
employee compensation incurred for the years ended December 31, 2009, 2008, and
2007 was $4,649,928, $6,586,279 and $4,140,747, respectively.
Stock-Based
Compensation to Non-Employees – The Company accounts for its stock-based
compensation issued to non-employees using the fair value method in accordance
with generally accepted accounting principles. Under generally accepted
accounting principles, stock-based compensation is determined as either the fair
value of the consideration received or the fair value of the equity instruments
issued, whichever is more reliably measurable. The measurement date for
these issuances is the earlier of the date at which a commitment for performance
by the recipient to earn the equity instruments is reached or the date at which
the recipient’s performance is complete.
62
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Derivative Instruments and Hedging
Activities – Generally accepted accounting principles have established
accounting and reporting standards requiring that derivative instruments
(including certain derivative instruments embedded in other contracts) be
recorded at fair value and included in the consolidated balance sheet as assets
or liabilities. The accounting for changes in the fair value of a derivative
instrument depends on the intended use of the derivative and the resulting
designation, which is established at the inception of a derivative. For
derivative instruments designated as cash flow hedges, changes in fair value, to
the extent the hedge is effective, are recognized in other comprehensive income
until the hedged item is recognized in earnings. Any change in the fair value
resulting from ineffectiveness, as defined by generally accepted accounting
principles, is recognized immediately in oil and natural gas sales. For
derivative instruments designated as fair value hedges, changes in fair value,
as well as the offsetting changes in the estimated fair value of the hedged item
attributable to the hedged risk, are recognized currently in earnings.
Differences between the changes in the fair values of the hedged item and the
derivative instrument, if any, represent gains or losses on ineffectiveness and
are reflected currently in interest expense. Hedge effectiveness is measured at
least quarterly based on the relative changes in fair value between the
derivative contract and the hedged item over time. Changes in fair value of
contracts that do not qualify as hedges or are not designated as hedges are also
recognized currently in earnings. See Note 11—Derivative Instruments and Hedging
Activities.
New Accounting
Policies – Recent SEC
Rule-Making Activity. In December 2008, the SEC announced that it
had approved revisions to modernize the oil and gas reserve reporting
disclosures. The new disclosure requirements include provisions
that:
·
|
Introduce
a new definition of oil and gas producing activities. This new definition
allows companies to include in their reserve base volumes from
unconventional resources. Such unconventional resources include bitumen
extracted from oil sands and oil and gas extracted from coal beds and
shale formations.
|
·
|
Report
oil and gas reserves using an unweighted average price using the prior
12-month period, based on the closing prices on the first day of each
month, rather than year-end prices.
|
·
|
Permit
companies to disclose their probable and possible reserves on a voluntary
basis. In the past, proved reserves were the only reserves allowed in the
disclosures. We have chosen not to make disclosure under these
categories.
|
·
|
Requires
companies to provide additional disclosure regarding the aging of proved
undeveloped reserves.
|
·
|
Permit
the use of reliable technologies to determine proved reserves if those
technologies have been demonstrated empirically to lead to reliable
conclusions about reserves volumes.
|
·
|
Replace
the existing “certainty” test for areas beyond one offsetting drilling
unit from a productive well with a “reasonable certainty”
test.
|
·
|
Require
additional disclosures regarding the qualifications of the chief technical
person who oversees the company’s overall reserve estimation process.
Additionally, disclosures regarding internal controls over reserve
estimation, as well as a report addressing the independence and
qualifications of its reserves preparer or auditor will be
mandatory.
|
We
adopted the rules effective December 31, 2009.
63
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
In August 2009, the FASB issued Accounting Standards Update
2009-5, “Measuring Liabilities at Fair Value” in order to provide further
guidance on how to measure the fair value of a liability. The Update clarifies
that, in circumstances in which a quoted price in an active market for the
identical liability is not available, a reporting entity is required to measure
fair value using one or more prescribed techniques. We adopted the new guidance
as of October 1, 2009. Adoption of the new guidance had no impact on our
financial position or results of operations.
Fair Value Option
Under US GAAP for fair value measurements, companies have an option to report
selected financial assets and liabilities at fair value. We adopted the new
guidance for optional fair value measurements as of January 1, 2008.
Adoption of the new guidance had no effect on our financial position or results
of operations as we made no elections to report selected financial assets or
liabilities at fair value.
Derivative Instruments and Hedging
Activities In March 2008, the FASB issued new standards
which amended and expanded previous disclosure requirements related to
derivative instruments and hedging activities. The new standards require
qualitative disclosures about objectives and strategies for using derivative
instruments, quantitative disclosures about fair value amounts of derivative
instruments and related gains and losses, and disclosures about credit
risk-related contingent features in derivative agreements. We adopted the new
standards as of January 1, 2009. They provide only for enhanced disclosures, and
adoption of the new standards had no impact on our financial position or results
of operations. See Note 11. Derivative Instruments and Hedging
Activities.
Subsequent Events
In May 2009, the FASB issued new standards which establish the accounting for
and disclosure of events that occur after the balance sheet date but before
financial statements are issued. In particular, the new standards set
forth:
·
|
the
period after the balance sheet date during which management of a reporting
entity should evaluate events or transactions that may occur for potential
recognition or disclosure in the financial statements (through the date
that the financial statements are issued or are available to be
issued);
|
·
|
the
circumstances under which an entity should recognize events or
transactions occurring after the balance sheet date in its financial
statements; and
|
·
|
the
disclosures that an entity should make about events or transactions that
occurred after the balance sheet
date.
|
We
adopted the new standards as of June 30, 2009. We have evaluated subsequent
events after the balance sheet date of December 31, 2009 through the time of
filing with the SEC on March 1, 2010, which is the date the financial statements
were issued.
Accounting Standards
Codification In June 2009, the FASB established the FASB
Accounting Standards Codification (Codification), which officially commenced
July 1, 2009, to become the source of authoritative US GAAP recognized by the
FASB to be applied by nongovernmental entities. Rules and
interpretive releases of the SEC under authority of federal securities laws are
also sources of authoritative US GAAP for SEC registrants. Generally,
the Codification is not expected to change US GAAP. All other
accounting literature excluded from the Codification will be considered
nonauthoritative. The Codification is effective for financial
statements issued for interim and annual periods ending after September 15,
2009. We adopted the new standards for our quarter ending September
30, 2009. All references to authoritative accounting literature are
now referenced in accordance with the Codification.
64
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
2 – EARNINGS PER SHARE INFORMATION
For
the years ended December 31,
|
2009
|
2008
|
2007
|
|||||||||
Net
Income
|
$ | 42,294,179 | $ | 83,617,201 | $ | 34,441,939 | ||||||
Basic
Weighted-Average Common Shares Outstanding
|
38,380,284 | 36,732,000 | 32,071,279 | |||||||||
Effect
of dilutive securities
|
||||||||||||
Warrants
|
75,924 | 205,846 | 325,034 | |||||||||
Stock
options
|
501,737 | 986,251 | 1,271,616 | |||||||||
Diluted
Weighted-Average Common Shares Outstanding
|
38,957,945 | 37,924,097 | 33,667,929 | |||||||||
Basic
Income Per Common Share
|
||||||||||||
Net
income
|
1.10 | 2.28 | 1.07 | |||||||||
Diluted
Income Per Common Share
|
||||||||||||
Net
Income
|
1.09 | 2.20 | 1.02 |
NOTE
3 – OIL AND GAS PRODUCING ACTIVITIES
Set forth
below is certain information regarding the aggregate capitalized costs of oil
and gas properties and costs incurred by the Company for its oil and gas
property acquisitions, development and exploration activities:
Capitalized
Costs Relating to Oil and Gas Producing Activities
|
||||||||||||
December
31,
|
2009
|
2008
|
2007
|
|||||||||
Unproved
oil and gas properties
|
$ | 5,642,624 | $ | 5,642,624 | $ | 5,642,624 | ||||||
Proved
oil and gas properties
|
655,810,510 | 543,071,611 | 334,245,235 | |||||||||
Oil
and gas gathering systems
|
2,134,876 | - | - | |||||||||
Inventory
for property development
|
1,052,538 | 1,670,067 | - | |||||||||
Drilling
rigs
|
6,694,841 | 6,899,433 | 6,254,737 | |||||||||
Land,
buildings, equipment and leasehold improvements
|
5,991,983 | 5,799,045 | 4,512,224 | |||||||||
Total
capitalized costs
|
677,327,372 | 563,082,780 | 350,654,820 | |||||||||
Less
accumulated depletion, depreciation and amortization
|
(100,428,326 | ) | (60,928,142 | ) | (30,497,371 | ) | ||||||
Net
Capitalized Costs
|
$ | 576,899,046 | $ | 502,154,638 | $ | 320,157,449 | ||||||
Net
Costs Incurred in Oil and Gas Producing Activities
|
||||||||||||
For
the Years Ended December 31,
|
2009 | 2008 | 2007 | |||||||||
Acquisition
of proved properties (net of proceeds from property sale)
|
3,942,103 | 16,782,225 | 53,554,064 | |||||||||
Acquisition
of unproved properties (net of proceeds from property
sale)
|
- | - | 542,650 | |||||||||
Exploration
costs
|
- | - | - | |||||||||
Development
costs
|
107,064,257 | 190,584,617 | 113,084,344 | |||||||||
Total
Net Costs Incurred
|
$ | 111,006,360 | $ | 207,366,842 | $ | 167,181,058 |
NOTE
4 – NOTES PAYABLE
Notes Payable –
In June 2009, the Company entered into a new agreement that provides for
a credit facility of $150 million with a borrowing base of $75 million with the
structure in place to increase that borrowing base an additional $75
million. The new facility has an interest rate grid with a range of
LIBOR plus 2.25% to 3.25%, depending upon the Company’s level of utilization of
the credit facility with the total interest rate to be charged being no less
than 4.00%. The Company is required under the terms of the credit
facility to maintain a 5-to-1 ratio of income before interest, taxes,
depreciation, depletion and amortization to interest expense, maintain a current
asset to current liability ratio of 1-to-1 and a rolling four quarter maximum
leverage ratio of no more than 2.5-to-1. As of December 31, 2009, the
Company were in compliance with all covenants and did not have any amount
outstanding under this credit facility.
65
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
5 – ASSET RETIREMENT OBLIGATION
A
reconciliation of the asset retirement obligation for the years ended December
31, 2007, 2008 and 2009 is as follows:
Balance,
January 1, 2007
|
$ | 2,250,332 | ||
Liabilities
incurred
|
1,027,945 | |||
Accretion
expense
|
190,904 | |||
Deletion
related to property divestitures
|
(26,332 | ) | ||
Liabilities
settled
|
(45,019 | ) | ||
Balance,
December 31, 2007
|
$ | 3,397,830 | ||
Liabilities
incurred
|
1,459,534 | |||
Accretion
expense
|
309,402 | |||
Liabilities
settled
|
(100,418 | ) | ||
Balance,
December 31, 2008
|
$ | 5,066,348 | ||
Liabilities
incurred
|
1,732,538 | |||
Accretion
expense
|
410,926 | |||
Balance,
December 31, 2009
|
$ | 7,209,812 | ||
NOTE
6 – STOCKHOLDERS’ EQUITY
The
Company is authorized to issue 100,000,000 common shares, with a par value of
$0.001 per share, and 10,000,000 Class “A” convertible preferred shares, with a
par value of $0.001 per share.
Preferred
Stock – There is no preferred stock outstanding.
Common Stock
Issued in Stock Split – In September 2007, the Company’s Board of
Directors authorized a 2 for 1 stock split. The split was effective
to shareholders of record at the close of business on October 15,
2007. The split was in the form of a stock dividend, with one
additional share distributed for every share held. The additional
shares were distributed on October 26, 2007 and the Company’s stock began
trading at its post-split price on October 29, 2007. Accordingly, all
amounts of common stock, warrants and options have been retroactively restated
throughout these financial statements to give effect to the 2 for 1 stock
split.
Common Stock
Issued in Offerings – In June 2007, the Company issued 4,100,000 shares
of common stock, valued at $100,450,000, or $24.50 per share, in a private
placement. Proceeds from the offering totaled $95,089,458, net of
offering costs and expenses paid of $5,360,542.
In June
2008, the Company issued 2,501,250 shares of common stock, valued at
$119,434,688, or $47.75 per share, in a public offering pursuant to a shelf
registration statement. Proceeds to the Company, net of offering
costs of $3,305,227, totaled $116,129,461.
Common Stock
Issued from Warrant Exercises – During the year ended December 31, 2007,
the Company issued 127,126 shares of common stock from the exercise of warrants
for proceeds of $540,295. Of these warrants, 20,000 had an exercise
price of $4.50 per share, 34,952 had an exercise price of $5.15 per share and
72,174 had an exercise price of $3.7425. Additionally, during the
year ended December 31, 2007, the Company issued 134,120 shares of common stock
in a cashless exercise of 145,000 warrants with an exercise price of $3.7425 per
share and 4,959 shares of common stock in a cashless exercise of 5,824 warrants
with an exercise price of $5.15 per share.
66
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
During
the year ended December 31, 2008, the Company issued 97,158 shares of common
stock from the exercise of warrants. Of these warrants, 33,246 had an
exercise price of $4.50 per share, 23,132 had an exercise price of $3.7425 per
share and 40,780 had an exercise price of $5.15 per share, for total proceeds of
$446,159.
During
the year ended December 31, 2009, the Company issued 161,550 shares of common
stock from the exercise of warrants. Of these warrants, 42,772 had an
exercise price of $3.7425, 83,830 had an exercise price of $4.50 and 34,948 had
an exercise price of $5.15, for total proceeds of $717,323.
Common Stock
Issued from Option Exercises – During the year ended December 31, 2007,
the Company issued 570,000 shares of common stock upon the exercise of options
for proceeds of $1,852,500, or an average of $3.25 per share. As a
result of these exercises, the Company recognized an additional tax benefit in
the amount of $4,298,722, which was recorded against additional paid-in
capital.
During
the year ended December 31, 2008, the Company issued 1,333,000 shares of common
stock from the exercise of options for proceeds of $4,691,260. Of
these options, 1,140,000 had an exercise price of $1.85 per share, 60,000 had an
exercise price of $2.40 per share, 20,000 had an exercise price of $4.15 per
share, 20,000 had an exercise price of $13.70 per share, 40,000 had an exercise
price of $19.23 per share, 33,000 had an exercise price of $23.42 per share and
20,000 had an exercise price of $26.96 per share.
During
the year ended December 31, 2009, the Company issued 317,000 shares of common
stock from the exercise of options for proceeds of $2,922,440. Of
these options, 220,000 had an exercise price of $4.15, 20,000 had an exercise
price of $10.43, 20,000 had an exercise price of $13.70, 27,000 had an exercise
price of $23.42, 20,000 had an exercise price of $26.96 and 10,000 had an
exercise price of $35.53.
Common Stock
Issued pursuant to Restricted Stock Award Plan – On December 17, 2009,
the Company issued 5,226 shares of common stock to key personnel. The
shares issued are subject to a six month vesting period which ends in June
2010. The shares were valued at $43.10, based on the closing price on
the date the shares were awarded. The expense associated with this
issuance will be allocated ratably over the six month vesting
period.
Warrants
Issued – Prior to 2007 the Company issued stock purchase warrants in
relation to various offerings. No purchase warrants have been issued
in 2007, 2008 or 2009. However, through 2009 some of the previously
issued warrants remained outstanding. During the year ended December
31, 2009, the balance of the remaining outstanding warrants was
exercised.
Stock
purchase warrants issued and exercised during the years ended December 31, 2009,
2008 and 2007 are summarized as follows:
2009
|
2008
|
2007
|
||||||||||||||||||||||
Warrants
|
Weighted-Average
Exercise Price
|
Warrants
|
Weighted-Average
Exercise Price
|
Warrants
|
Weighted-Average
Exercise Price
|
|||||||||||||||||||
Outstanding
at beginning of the year
|
161,550 | $ | 4.44 | 258,708 | $ | 4.50 | 536,658 | $ | 4.25 | |||||||||||||||
Issued
|
- | - | - | - | - | - | ||||||||||||||||||
Expired
|
- | - | - | - | - | - | ||||||||||||||||||
Exercised
|
(161,550 | ) | 4.44 | (97,158 | ) | 4.59 | (277,950 | ) | 3.08 | |||||||||||||||
Outstanding
at end of year
|
- | $ | - | 161,550 | $ | 4.44 | 258,708 | $ | 4.50 |
67
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
7 – EMPLOYEE STOCK OPTIONS AND RESTRICTED STOCK AWARD PLAN
In 2003,
the Company’s Board of Directors and shareholders approved and adopted a
non-qualified executive stock option plan, which was subsequently amended by the
shareholders. The amendments effectively increased the number of
shares available under the plan to 6,000,000. Additionally, in 2009
the shareholders approved the adoption of a restricted stock award
plan. Shares granted under the restricted stock award plan come from
the same pool of available shares as the option plan. There are
1,294,774 shares eligible for grant, either as options or as restricted stock,
at December 31, 2009.
Employee Stock Options –
Following is a table reflecting the issuances during 2007 and 2008 and their
related exercise prices:
Grant
date
|
#
of options
|
Exercise
price
|
||||||
January
11, 2007
|
100,000 | $ | 18.675 | |||||
January
22, 2007
|
600,000 | 19.23 | ||||||
May
1, 2007
|
200,000 | 23.42 | ||||||
July
24, 2007
|
100,000 | 26.96 | ||||||
November
1, 2007
|
50,000 | 35.53 | ||||||
November
7, 2007
|
50,000 | 35.54 | ||||||
December
1, 2007
|
300,000 | 37.59 | ||||||
December
17, 2007
|
125,000 | 37.85 | ||||||
1,525,000 | ||||||||
Grant
date
|
#
of options
|
Exercise
price
|
||||||
May
7, 2008
|
50,000 | $ | 45.68 | |||||
May
15, 2008
|
50,000 | 49.74 | ||||||
July
24, 2008
|
50,000 | 41.09 | ||||||
August
18, 2008
|
50,000 | 39.02 | ||||||
September
2, 2008
|
25,000 | 40.75 | ||||||
225,000 |
No
options were granted during 2009.
All
granted options vest at the rate of 20% each year over five years beginning one
year from the date granted and expire six months after the date of complete
vesting. A summary of the status of the stock options as of December
31, 2009 and changes during the years ended December 31, 2009, 2008 and 2007 is
as follows:
68
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
2009
|
2008
|
2007
|
||||||||||||||||||||||
Options
|
Weighted-Average
Exercise Price
|
Options
|
Weighted-Average
Exercise Price
|
Options
|
Weighted-Average
Exercise Price
|
|||||||||||||||||||
Outstanding
at beginning of the year
|
2,252,000 | $ | 22.12 | 3,450,000 | $ | 13.55 | 2,610,000 | $ | 3.31 | |||||||||||||||
Issued
|
- | 225,000 | 43.53 | 1,525,000 | 26.45 | |||||||||||||||||||
Forfeited
|
(40,000 | ) | 41.09 | (90,000 | ) | 22.73 | (115,000 | ) | 3.35 | |||||||||||||||
Exercised
|
(317,000 | ) | 9.22 | (1,333,000 | ) | 3.52 | (570,000 | ) | 3.25 | |||||||||||||||
Outstanding
at end of year
|
1,895,000 | $ | 23.87 | 2,252,000 | $ | 22.12 | 3,450,000 | $ | 13.55 | |||||||||||||||
Exercisable
at end of year
|
705,000 | $ | 20.96 | 537,000 | $ | 13.27 | 1,050,000 | $ | 2.33 | |||||||||||||||
Weighted
average fair value of
|
||||||||||||||||||||||||
options
granted during the year
|
$ | - | $ | 17.52 | $ | 10.84 |
The
Company uses the Black-Scholes option pricing model to calculate the fair-value
of each option grant. The expected volatility is based on the historical price
volatility of the Company’s common stock. We elected to use the
simplified
method for estimating the expected term
as allowed by generally accepted accounting principles for options granted
through December 31, 2008 and 2007. Under the
simplified
method, the expected term is equal to
the midpoint between the vesting period and the contractual term of the stock
option. The risk-free interest rate represents the U.S. Treasury bill rate for
the expected life of the related stock options. The dividend yield represents
the Company’s anticipated cash dividend over the expected life of the stock
options. The following are the Black-Scholes weighted-average
assumptions used for options granted during the years ended December 31, 2008
and 2007 (no options were granted during 2009):
2008
|
2007
|
||
Risk
free interest rate
|
3.14%
|
4.30%
|
|
Expected
life
|
4.25
years
|
4.25
years
|
|
Dividend
yield
|
-
|
-
|
|
Volatility
|
45%
|
47%
|
|
As of
December 31, 2009, there was approximately $4,827,499 of unrecognized
compensation cost related to stock options that will be recognized over a
weighted average period of 2.07 years. The aggregate intrinsic value
of options vested and expected to vest at December 31, 2009 was
$32,337,120. The aggregate intrinsic value of options exercisable at
December 31, 2009 was $15,714,850. The year end intrinsic values are
based on a December 31, 2009 closing price of $43.12.
The
317,000, 1,333,000 and 570,000 options exercised during 2009, 2008 and 2007,
respectively, had an aggregate intrinsic value on the date of exercise of
7,963,220, $44,715,770 and $12,122,600, respectively.
69
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The
following table summarizes information related to the Company’s stock options
outstanding at December 31, 2009:
Options
Outstanding
|
||||||||||||||
Exercise
price
|
Number
Outstanding
|
Weighted-Average
Remaining Contractual Life (in years)
|
Number
Exercisable
|
|||||||||||
4.15 | 305,000 | 0.50 | 200,000 | |||||||||||
10.425 | 40,000 | 1.30 | 20,000 | |||||||||||
13.70 | 40,000 | 1.95 | - | |||||||||||
18.675 | 100,000 | 2.53 | 40,000 | |||||||||||
19.23 | 560,000 | 2.56 | 200,000 | |||||||||||
23.42 | 140,000 | 2.84 | 20,000 | |||||||||||
26.96 | 60,000 | 3.07 | - | |||||||||||
35.53 | 40,000 | 3.33 | 10,000 | |||||||||||
35.54 | 50,000 | 3.35 | 20,000 | |||||||||||
37.59 | 250,000 | 3.42 | 100,000 | |||||||||||
37.85 | 125,000 | 3.46 | 50,000 | |||||||||||
39.02 | 50,000 | 3.85 | 10,000 | |||||||||||
40.75 | 25,000 | 3.87 | 5,000 | |||||||||||
41.09 | 10,000 | 4.07 | 10,000 | |||||||||||
45.68 | 50,000 | 4.13 | 10,000 | |||||||||||
49.74 | 50,000 | 4.17 | 10,000 | |||||||||||
1,895,000 | 2.06 | 705,000 |
Any
excess tax benefits from the exercise of stock options will not be recognized in
paid-in capital until the Company is in a current tax paying position.
Presently, all of the Company’s income taxes are deferred and is only subject to
alternative minimum tax. The Company has substantial net operating
losses available to carryover to future periods. Accordingly, no excess tax
benefits have been recognized for the years ended December 31, 2009 or
2008.
Restricted stock grants – On
December 17, 2009, the Company granted a total of 5,226 shares of stock under
the Restricted Stock Award Plan. The shares were valued based on the
market price of the shares on the grant date of $43.10 for an aggregate total of
$225,241. These shares vest over a six month period and the Company
will record the expense over that period. As of December 31, 2009,
the Company showed an expense of $16,055. Unamortized deferred
compensation of $209,186 will be amortized over the next six
months.
The
Restricted Stock Award Plan was approved by the shareholders during 2009,
therefore no shares were issued under the plan prior to
2009. Additionally, no shares vested during any of the years 2009,
2008 or 2007.
NOTE
8 – RELATED PARTY TRANSACTIONS
In July
2002, the Company borrowed $400,000 from two of its officers under the terms of
secured, 10% promissory notes. These notes and all accrued interest
were paid during 2007.
70
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
9 – COMMITMENTS
Standby Letters
of Credit – A commercial bank has issued standby letters of credit on
behalf of the Company to the states of Texas, Oklahoma and New Mexico totaling
$686,969 to allow the Company to do business in those states. The
Company intends to renew the standby letters of credit for as long as the
Company does business in those states. No amounts have been drawn under the
standby letters of credit.
Operating leases
– Effective August 20, 2008, the Company entered into a lease agreement
for office space in Midland, Texas. The lease is for approximately
1,869 square feet and is for five years commencing November 2008. The
Company incurred lease expense of $19,780 and $3,271 for the years ended
December 31, 2009 and 2008, respectively. The following table
reflects the future minimum lease payments under the operating lease as of
December 31, 2009.
Year
|
Lease
Obligation
|
|||
2010
|
20,715 | |||
2011
|
21,649 | |||
2012
|
22,584 | |||
2013
|
19,469 | |||
$ | 84,417 |
NOTE 10 – INCOME TAXES
At
December 31, 2009, the Company calculated alternative minimum income tax of
$798,690 of which $314,700 is currently payable, due to a previous
overpayment. At December 31, 2008, the Company had no alternative
minimum income tax due and had no current tax liability. The
provision for income taxes consisted of the following:
Provision for income
taxes
|
2009
|
2008
|
2007
|
|||||||||
Current
|
$ | 4,661,395 | $ | - | $ | - | ||||||
Minimum
tax
|
798,690 | 539,793 | ||||||||||
Benefit
of net operating loss
|
(4,661,395 | ) | ||||||||||
Deferred
|
24,040,749 | 49,112,685 | 20,518,050 | |||||||||
$ | 24,839,439 | $ | 49,112,685 | $ | 21,057,843 |
The
following is a reconciliation of income taxes computed using the U.S. federal
statutory rate to the provision for income taxes:
Rate
Reconciliation
|
2009
|
2008
|
2007
|
|||||||||
Tax
at federal statutory rate (34%)
|
$ | 22,825,430 | $ | 45,128,161 | $ | 18,869,926 | ||||||
Non-deductible
expenses
|
- | 29,406 | 13,939 | |||||||||
State
tax, net of federal benefit
|
2,014,009 | 4,380,086 | 1,831,493 | |||||||||
Other
|
- | (424,968 | ) | 342,485 | ||||||||
$ | 24,839,439 | $ | 49,112,685 | $ | 21,057,843 |
71
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
As of
December 31, 2009, the Company had net operating loss carry forwards for federal
income tax reporting purposes of approximately $75 million which, if unused,
will expire in 2026, 2027 and 2028. The Company has minimum tax
credits of $1,765,774 which do not expire.
The net
deferred tax liability consisted of the following:
Deferred
taxes:
|
2009
|
2008
|
2007
|
|||||||||
Deferred
tax liabilities
|
||||||||||||
Current
unrealized gain on oil derivative
|
$ | - | $ | 6,046,508 | $ | - | ||||||
Property
and equipment
|
124,200,047 | 107,316,108 | 63,011,335 | |||||||||
Total
deferred tax liabilities
|
124,200,047 | 113,362,616 | 63,011,335 | |||||||||
Deferred
tax assets
|
||||||||||||
Stock-based
compensation
|
5,243,557 | 3,953,790 | 1,808,770 | |||||||||
Minimum
tax credit
|
1,765,774 | 967,084 | 862,000 | |||||||||
Unrealized
loss on oil derivative
|
- | - | 1,658,665 | |||||||||
Operating
loss and IDC carryforwards
|
8,567,917 | 17,861,815 | 24,785,172 | |||||||||
Total
deferred tax assets
|
15,577,248 | 22,782,689 | 29,114,607 | |||||||||
Net
deferred income tax liability
|
$ | 108,622,799 | $ | 90,579,927 | $ | 33,896,728 |
Accounting for Uncertainty in Income
Taxes In accordance with generally accepted accounting
principles, the Company has analyzed its filing positions in all jurisdictions
where it is required to file income tax returns for the open tax years in such
jurisdictions. The Company has identified its federal income tax return and its
state income tax returns in Texas, New Mexico, Oklahoma and Kansas in which it
operates as “major” tax jurisdictions. The Company’s federal income tax returns
for the years ended December 31, 2006 through 2008 remain subject to
examination. The Company’s income tax returns in major state income tax
jurisdictions remain subject to examination for years ended December 31,
2006 through 2008, with the exception of Texas, which would also include the
year ended December 31, 2005. The Company currently believes that all
significant filing positions are highly certain and that all of its significant
income tax filing positions and deductions would be sustained upon audit.
Therefore, the Company has no significant reserves for uncertain tax positions
and no adjustments to such reserves were required by generally accepted
accounting principles. No interest or penalties have been levied against the
Company and none are anticipated, therefore interest or penalty has been
included in our provision for income taxes in the consolidated statements of
operations.
NOTE
11 – DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Under
generally accepted accounting principles, the nature of a derivative instrument
must be evaluated to determine if it qualifies for hedge accounting treatment.
Instruments qualifying for hedge accounting treatment are recorded as an asset
or liability measured at fair value and subsequent changes in fair value are
recognized in equity through other comprehensive income, net of related taxes,
to the extent the hedge is effective. The Company’s derivative instrument
qualified for hedge accounting for all periods presented. The change
in fair value of the derivative instrument was recorded to other comprehensive
income for the years ended December 31, 2007, 2008 and 2009. The cash
settlements of cash flow hedges are recorded in the operating section of the
Company’s statement of operations. Instruments not qualifying for hedge
accounting treatment are recorded in the balance sheet at fair value and changes
in fair value are recognized on the statement of operations.
72
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The Company’s hedges are specifically
referenced to NYMEX prices. The effectiveness of hedges is evaluated at the time
the contracts are entered into, as well as periodically over the life of the
contracts, by analyzing the correlation between NYMEX prices and the posted
prices received from the designated production. Through this analysis, the
Company is able to determine if a high correlation exists between the prices
received for its designated production and the NYMEX prices at which the hedges
will be settled. At December 31, 2007, 2008 and 2009, the Company’s hedging
contracts were considered effective cash flow hedges.
The
statement of operations includes a realized gain on derivative instruments of
$14,884,846 for 2009 and a realized loss on derivative instruments of $4,275,330
and $932,361 for 2008 and 2007, respectively.
As of
December 31, 2009, the Company had entered into the following costless collar
contracts accounted for as a cash flow hedge:
Commodity
|
Remaining
Period
|
Volume
(Bbls)
|
Floor
|
Ceiling
|
|||||||||
WTI
Crude Oil
|
January
2010 - December 2010
|
730,000 | $ | 65.00 | $ | 93.00 | |||||||
WTI
Crude Oil
|
January
2010 - December 2010
|
365,000 | $ | 70.00 | $ | 92.85 | |||||||
Commodity
|
Remaining
Period
|
Volume
(MMBTU)
|
Floor
|
Ceiling
|
|||||||||
El
Paso Permian Gas
|
January
2010 - December 2010
|
1,825,000 | $ | 4.00 | $ | 7.87 |
There
were no hedges in effect as of December 31, 2009, therefore the Company did not
record an asset or a liability. The fair value of the 2010 hedges is
zero as of December 31, 2009, as the relative price curve for the index prices
used is between the floor and the ceiling.
NOTE
12 – FAIR VALUE MEASUREMENTS
Generally
accepted accounting principles establish a fair value hierarchy that prioritizes
the inputs used to measure fair value. The hierarchy gives the highest priority
to quoted prices in active markets for identical assets or liabilities (Level 1
measurement) and the lowest priority to unobservable inputs (Level 3
measurement). The Company’s fair value balances are based on the observability
of those inputs. The three levels of the fair value hierarchy are as
follows:
•
|
Level
1 — Quoted prices in active markets for identical assets or liabilities
that the Company has the ability to access. Active markets are those in
which transactions for the asset or liability occur in sufficient
frequency and volume to provide pricing information on an ongoing
basis. The Company does not have any fair value balances
classified as Level 1.
|
||
•
|
Level
2 — Inputs other than quoted prices in active markets included in Level 1,
that are either directly or indirectly observable. These inputs are either
directly observable in the marketplace or indirectly observable through
corroboration with market data for substantially the full contractual term
of the asset or liability being measured. The Company’s Level 2 items
consist of a costless collar.
|
||
•
|
Level
3 — Includes inputs that are not observable for which there is little, if
any, market activity for the asset or liability being measured. These
inputs reflect management’s best estimate of the assumptions market
participants would use in determining fair value. Level 3 would include
instruments valued using industry standard pricing models and other
valuation methods that utilize unobservable pricing inputs that are
significant to the overall fair value. The Company does not have any fair
value balances classified as Level
3.
|
73
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
In
valuing certain contracts, the inputs used to measure fair value may fall into
different levels of the fair value hierarchy. For disclosure purposes, assets
and liabilities are classified in their entirety in the fair value hierarchy
level based on the lowest level of input that is significant to the overall fair
value measurement. Our assessment of the significance of a particular input to
the fair value measurement requires judgment and may affect the placement within
the fair value hierarchy levels.
The fair
value of all hedge instruments was zero as of December 31, 2009, therefore the
Company does not have either an asset or a liability recorded in connection with
those instruments.
NOTE
13 –EMPLOYEES’ BENEFIT PLANS
The
Company’s employees are eligible to participate in a 401(k) plan after attaining
the age of 21. Participants may defer up to 100% of eligible compensation. The
Company matches participant contributions dollar for dollar up to 6% of
participant compensation not exceeding $16,500 per employee ($22,000 for those
over 50, choosing to catch-up). For the year ended December 31, 2009, 2008 and
2007, the Company made contributions to the plan totaling 290,695, $311,825 and
$68,743, respectively.
NOTE
14 – QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly
financial information is presented in the following summary:
2007
|
||||||||||||||||
Three
Months Ended
|
||||||||||||||||
March
31
|
June
30
|
September
30
|
December
31
|
|||||||||||||
Revenues
|
$ | 16,651,301 | $ | 21,620,299 | $ | 26,731,699 | $ | 35,086,399 | ||||||||
Operating
Income
|
9,395,863 | 13,283,378 | 17,661,615 | 15,685,456 | ||||||||||||
Net
Income
|
5,707,890 | 7,899,378 | 11,403,777 | 9,430,894 | ||||||||||||
Basic
Net Income Per Share
|
$ | 0.19 | $ | 0.26 | $ | 0.33 | $ | 0.28 | ||||||||
Diluted
Net Income Per Share
|
0.18 | 0.24 | 0.32 | 0.26 |
2008
|
||||||||||||||||
Three
Months Ended
|
||||||||||||||||
March
31
|
June
30
|
September
30
|
December
31
|
|||||||||||||
Revenues
|
$ | 45,312,392 | $ | 62,159,281 | $ | 68,412,686 | $ | 32,974,286 | ||||||||
Operating
Income
|
29,650,936 | 39,637,781 | 42,188,778 | 21,097,908 | ||||||||||||
Net
Income
|
18,318,395 | 24,794,349 | 26,922,966 | 13,581,491 | ||||||||||||
Basic
Net Income Per Share
|
$ | 0.52 | $ | 0.69 | $ | 0.71 | $ | 0.36 | ||||||||
Diluted
Net Income Per Share
|
0.51 | 0.67 | 0.69 | 0.35 |
2009
|
||||||||||||||||
Three
Months Ended
|
||||||||||||||||
March
31
|
June
30
|
September
30
|
December
31
|
|||||||||||||
Revenues
|
$ | 20,193,160 | $ | 27,636,695 | $ | 36,060,878 | $ | 42,350,044 | ||||||||
Operating
Income
|
9,998,248 | 22,702,454 | 18,954,179 | 14,649,746 | ||||||||||||
Net
Income
|
6,465,449 | 14,436,065 | 12,113,026 | 9,279,639 | ||||||||||||
Basic
Net Income Per Share
|
$ | 0.17 | $ | 0.38 | $ | 0.32 | $ | 0.24 | ||||||||
Diluted
Net Income Per Share
|
0.17 | 0.37 | 0.31 | 0.24 |
The net
income per share information above will not match the income statement due to
rounding.
74
ARENA
RESOURCES, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
15 – SIGNIFICANT FOURTH QUARTER ADJUSTMENTS
There
were no material fourth quarter adjustments or accounting changes.
NOTE
16 – SUBSEQUENT EVENTS
Subsequent
to December 31, 2009, the Company issued a total of 75,000 shares of stock
pursuant to the restricted stock award plan. These shares were valued
based on the market price of the shares of $45.05 on the date of grant of
January 6, 2010. These shares will vest 50% per year for two years
and the fair value of these shares will be expensed over that
period.
We have
evaluated subsequent events after the balance sheet date of December 31, 2009
through the time of filing with the SEC on March 1, 2010, which is the date the
financial statements were issued.
75
ARENA
RESOURCES, INC.
SUPPLEMENTAL
INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(Unaudited)
Results of Operations from Oil and
Gas Producing Activities – The Company’s results of operations from oil
and gas producing activities exclude interest expense, gain from change in fair
value of put options, and other financing expense. Income taxes are
based on statutory tax rates, reflecting allowable deductions.
For
the Years Ended December 31,
|
2009
|
2008
|
2007
|
|||||||||
Oil
and gas revenues
|
$ | 126,240,777 | $ | 208,858,645 | $ | 100,089,698 | ||||||
Production
costs
|
(15,543,461 | ) | (17,833,144 | ) | (11,500,461 | ) | ||||||
Production
taxes
|
(6,455,585 | ) | (10,518,370 | ) | (5,655,877 | ) | ||||||
Realized
loss on oil derivative
|
14,884,846 | (4,275,330 | ) | (932,361 | ) | |||||||
Depreciation,
depletion, amortization and accretion
|
(39,368,567 | ) | (30,099,196 | ) | (18,158,966 | ) | ||||||
General
and administrative (exclusive of corporate overhead)
|
(3,804,383 | ) | (3,034,525 | ) | (3,011,753 | ) | ||||||
Results
of operations before income taxes
|
75,953,627 | 143,098,080 | 60,830,280 | |||||||||
Provision
for income taxes
|
(28,102,842 | ) | (52,946,290 | ) | (22,507,204 | ) | ||||||
Results
of Oil and Gas Producing Operations
|
$ | 47,850,785 | $ | 90,151,790 | $ | 38,323,076 |
Recent SEC and FASB Rule-Making
Activity -- In December 2008, the SEC announced that it had approved
revisions designed to modernize the oil and gas company reserves reporting
requirements. See Note 1 Organization and Summary of Significant Accounting
Policies – New Accounting Policies. We adopted the rules effective December 31,
2009 and the rule changes, including those related to pricing and technology,
are included in our reserves estimates. The new rule does not allow
for prior-year reserve information to be restated, so all information related to
periods prior to 2009 is presented consistent with prior SEC rules for the
estimation of proved reserves.
In
addition, in January 2010 the FASB issued Accounting Standards Update 2010-03,
"Oil and Gas Reserve Estimation and Disclosures", to provide consistency with
the SEC rules. See Note 1 Organization and Summary of Significant Accounting
Policies – New Accounting Policies.
Reserve Quantities Information
– The following estimates of proved and proved developed reserve quantities and
related standardized measure of discounted net cash flow are estimates only, and
do not purport to reflect realizable values or fair market values of the
Company’s reserves. The Company emphasizes that reserve estimates are
inherently imprecise and that estimates of new discoveries are more imprecise
than those of producing oil and gas properties. Accordingly, these
estimates are expected to change as future information becomes
available. All of the Company’s reserves are located in the United
States of America.
Proved
reserves are estimated reserves of crude oil (including condensate and natural
gas liquids) and natural gas that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved
developed reserves are those expected to be recovered through existing wells,
equipment and methods.
The
standardized measure of discounted future net cash flows is computed by applying
the price according to the SEC guidelines for oil and gas to the estimated
future production of proved oil and gas reserves, less estimated future
expenditures (based on year-end costs) to be incurred in developing and
producing the proved reserves, less estimated future income tax expenses (based
on year-end statutory tax rates) to be incurred on pretax net cash flows less
tax basis of the properties and available credits, and assuming continuation of
existing economic conditions. The estimated future net cash flows are
then discounted using a rate of 10 percent per year to reflect the estimated
timing of the future cash flows.
76
ARENA
RESOURCES, INC.
SUPPLEMENTAL
INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(Unaudited)
For the Years
Ended December
31,
|
2009
|
2008
|
2007
|
|||||||||||||||||||||
Oil (1)
|
Gas (1)
|
Oil (1)
|
Gas (1)
|
Oil (1)
|
Gas (1)
|
|||||||||||||||||||
Proved
Developed and Undeveloped Reserves
|
||||||||||||||||||||||||
Beginning
of year
|
55,845,257 | 58,804,662 | 47,413,322 | 48,074,962 | 36,064,273 | 42,424,199 | ||||||||||||||||||
Purchases
of minerals in place
|
1,589,141 | 2,791,611 | 3,638,095 | 2,364,908 | 7,021,972 | 4,330,246 | ||||||||||||||||||
Improved
recovery and extensions
|
14,360,492 | 13,605,184 | 9,547,981 | 11,391,853 | 6,016,660 | 6,852,346 | ||||||||||||||||||
Production
|
(2,004,498 | ) | (2,172,790 | ) | (2,018,335 | ) | (1,911,713 | ) | (1,316,023 | ) | (1,503,611 | ) | ||||||||||||
Revision
of previous estimate
|
(10,074,880 | ) | (15,813,979 | ) | (2,735,806 | ) | (1,115,348 | ) | (373,560 | ) | (4,028,218 | ) | ||||||||||||
End
of year
|
59,715,512 | 57,214,688 | 55,845,257 | 58,804,662 | 47,413,322 | 48,074,962 | ||||||||||||||||||
Proved
Developed at end of year
|
21,144,906 | 28,302,469 | 20,231,477 | 28,659,033 | 14,951,794 | 30,783,255 |
1
Oil reserves
are stated in barrels; gas reserves are stated in thousand cubic
feet.
Standardized
Measure of Discounted Cash Flows
|
||||||||||||
December
31,
|
2009
|
2008
|
2007
|
|||||||||
Future
cash flows
|
$ | 3,721,873,750 | $ | 2,391,888,946 | $ | 4,634,645,500 | ||||||
Future
production costs
|
(902,963,847 | ) | (716,121,604 | ) | (790,284,047 | ) | ||||||
Future
development costs
|
(543,022,875 | ) | (330,672,457 | ) | (321,485,125 | ) | ||||||
Future
income taxes
|
(746,548,080 | ) | (394,800,287 | ) | (1,254,982,170 | ) | ||||||
Future
net cash flows
|
1,529,338,948 | 950,294,598 | 2,267,894,158 | |||||||||
10%
annual discount for estimated timing of cash flows
|
(775,105,191 | ) | (489,607,688 | ) | (991,727,804 | ) | ||||||
Standardized
Measure of Discounted Cash Flows
|
$ | 754,233,757 | $ | 460,686,910 | $ | 1,276,166,354 |
Changes
in Standardized Measure of Discounted Future Net Cash
Flows
|
||||||||||||
|
2009
|
2008
|
2007
|
|||||||||
Beginning
of the year
|
$ | 460,686,910 | $ | 1,276,166,354 | $ | 545,439,675 | ||||||
Purchase
of minerals in place
|
28,329,307 | 41,597,736 | 325,058,027 | |||||||||
Extensions,
discoveries and improved recovery, less related costs
|
253,485,559 | 129,110,323 | 297,610,301 | |||||||||
Development
costs incurred during the year
|
107,237,470 | 190,631,820 | 113,109,335 | |||||||||
Sales
of oil and gas produced, net of production costs
|
(110,697,316 | ) | (190,374,853 | ) | (82,949,751 | ) | ||||||
Accretion
of discount
|
48,058,341 | 131,684,244 | 69,291,660 | |||||||||
Net
changes in price and production costs
|
619,543,318 | (1,526,963,575 | ) | 592,749,069 | ||||||||
Net
change in estimated future development costs
|
6,550,757 | (22,637,628 | ) | (111,175,136 | ) | |||||||
Revision
of previous quantity estimates
|
(447,110,784 | ) | 293,723,576 | (7,424,163 | ) | |||||||
Revision
of estimated timing of cash flows
|
(35,543,586 | ) | (409,158,356 | ) | (62,546,312 | ) | ||||||
Net
change in income taxes
|
(176,306,219 | ) | 546,907,269 | (402,996,351 | ) | |||||||
End
of the Year
|
$ | 754,233,757 | $ | 460,686,910 | $ | 1,276,166,354 |
77