REOSTAR ENERGY CORP - Form 10-K
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[x] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the fiscal year ended March 31, 2010
Commission file number 000-26139
REOSTAR ENERGY CORPORATION
(Name of small business issuer in its charter)
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Nevada
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20-8428738
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(State or other
jurisdiction of
incorporation or organization)
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(IRS Employer Identification
Number)
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3880 Hulen St., Ste
500, Fort Worth, TX
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76107
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(Address
of principal executive offices)
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(Zip Code)
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Issuer's telephone number:
817-989-7367
Securities registered under Section 12(b) of the Exchange Act:
None
Securities registered under Section 12(g) of the Exchange Act:
Common Stock, $.001 par value
(Title of class)
Check whether the issuer is not
required to file reports pursuant to Section 13 or 15(d) of the Exchange Act.
o
Check whether the issuer (1) filed all reports required to be filed by Section
13 or 15(d) of the Exchange Act during the past 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 x
No o
Check if there is no disclosure of delinquent filers in response to Item 405 of
Regulation S-B contained in this form, and no disclosure will 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 o
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act). Yes o
No x
Revenue for the fiscal year ended March 31, 2010 is $3,533,722 and the aggregate
market value of the voting stock held by non-affiliates of the registrant based
on the closing bid price of such stock as of March 31, 2010 amounted to $2,307,592.
The number of shares outstanding of the registrant's common stock as of March
31, 2010 was 80,743,912 shares.
Table of Contents
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the registrant's 2010 annual meeting of shareholders
to be filed with the SEC within 120 days after the end of the fiscal year ended
March 31, 2010 are incorporated by reference in Part III of this Form 10-K.
Transitional Small Business Disclosure Format (check one):
Yes o
No x
REOSTAR ENERGY CORPORATION
FORM 10-K ANNUAL REPORT
FISCAL YEAR ENDED MARCH 31, 2010
TABLE OF CONTENTS
Table of Contents
Disclosures Regarding
Forward-Looking Statements
Certain information included in this report, other materials filed or to be filed
with the Securities and Exchange Commission (the "SEC"), as well as information
included in oral statements or other written statements made or to be made by
us contain or incorporate by reference certain statements (other than statements
of historical fact) that constitute forward-looking statements within the meaning
of Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. When used herein, the words "budget," "budgeted," "assumes,"
"should," "goal," "anticipates," "expects," "believes," "seeks," "plans," "estimates,"
"intends," "projects" or "targets" and similar expressions that convey the uncertainty
of future events or outcomes are intended to identify forward-looking statements.
Where any forward-looking statement includes a statement of the assumptions or
bases underlying such forward-looking statement, we caution that while we believe
these assumptions or bases to be reasonable and to be made in good faith, assumed
facts or bases almost always vary from actual results and the difference between
assumed facts or bases and the actual results could be material, depending on
the circumstances. It is important to note that our actual results could differ
materially from those projected by such forward-looking statements. Although we
believe that the expectations reflected in such forward-looking statements are
reasonable and such forward-looking statements are based upon the best data available
at the date this report is filed with the SEC, we cannot assure you that such
expectations will prove correct. Factors that could cause our results to differ
materially from the results discussed in such forward-looking statements include,
but are not limited to, the following: the factors described in Item 1A of this
report under the heading "Risk Factors," production variance from expectations,
volatility of oil and gas prices, hedging results, the need to develop and replace
reserves, the substantial capital expenditures required to fund operations, exploration
risks, environmental risks, uncertainties about estimates of reserves, competition,
litigation, government regulation, political risks, our ability to implement our
business strategy, costs and results of drilling new projects, mechanical and
other inherent risks associated with oil and gas production, weather, availability
of drilling equipment and changes in interest rates. All such forward-looking
statements in this document are expressly qualified in their entirety by the cautionary
statements in this paragraph, we do not undertake, and specifically disclaim any
obligation, to update or revise such statements to reflect new circumstances or
unanticipated events as they occur, and we urge readers to review and consider
disclosures we make in this and other reports that discuss factors germane to
our business, including our reports on Forms 10-K, 10-Q, and 8-K subsequently
filed from time to time with the SEC.
PART I
ITEM 1. BUSINESS
General
We are engaged in the exploration, development and
acquisition of oil and gas properties, primarily located in the state of Texas.
We seek to increase oil and gas reserves and production through internally generated
drilling projects on currently owned assets, coupled with complementary acquisitions.
At year-end 2010, we owned approximately 9,000 acres of leasehold, which includes
5,000 acres of exploratory and developmental prospects as well as 4,000 acres
of enhanced oil recovery prospects. We have built a multi-year inventory of drilling
projects and drilling locations and currently have enough acreage to sustain several
years of drilling.
ReoStar was incorporated in Nevada on November 29, 2004 under the name Goldrange
Resources, Inc. In February of 2007 we changed our name to ReoStar Energy Corporation.
Our corporate offices are located at 3880 Hulen Street, Suite 500, Fort Worth,
Texas 76107. Our telephone number is (817) 989-7367.
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Table of Contents
Business Strategy
Our objective is to build shareholder value by establishing and consistently
growing our production and reserves with a strong emphasis on cost control and
risk mitigation. Our strategy is (1) to control operations of all our leases through
our affiliated operating companies, (2) to acquire and develop leasehold in key
regional resource development plays while utilizing existing infrastructure and
engaging in long-term drilling and development programs, and (3) to acquire leasehold
in mature fields and implement enhanced oil recovery programs.
Significant Accomplishments in Fiscal Year 2010
• Leasehold
Acquisition and Development:
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• |
Barnett Shale. Our
main area of interest in the Barnett Shale play is located in the "oil window"
of the Barnett in southwest Cooke County, Texas.
We completed, and began production in the two wells that were in process
as of March 31, 2009. |
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Corsicana Enhanced Oil
Recovery ("EOR") Project. We entered into negotiations to test a new
chemical foam technology that appears to have similar sweep efficiencies
as surfactant polymer but at a reduced operational cost. We expect to deploy
the technology in the wells originally drilled for our Phase II of the surfactant
polymer project. |
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• |
Corsicana deeper zone
exploration. We successfully drilled and completed two deeper exploratory
wells in the Pecan Gap zone in the Corsicana acreage and expect to continue
drilling Pecan Gap on our acreage in Corsicana. |
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Corsicana
technology survey. The Company is currently testing a new technology
in the Corsicana field involving the detection and recording of helium atoms
through sub-surface sensors that are being placed throughout our leasehold.
This technology could assist the Company in its mapping of the Pecan Gap
reservoir could substantially affect the results of subsequent drilling
into that zone. |
• Concentrate
in Core Operating Areas. We currently focus in one region: the Southern Mid-continent
region of the United States (which includes the Barnett Shale of North Central
Texas and our Corsicana EOR prospect in East Central Texas). Concentrating our
drilling and producing activities in these core areas allows us to develop the
regional expertise needed to interpret specific geological and operating trends
and develop economies of scale. Operating developmental projects (such as our
Barnett Shale prospects) and Enhanced Oil Recovery prospects in the same core
area allow us to achieve reserve growth, balance our portfolio between oil and
natural gas, and minimize some of the operational risks inherent in our industry,
while leveraging the benefits of the existing infrastructure.
During the fiscal year, our wholly owned subsidiary, ReoStar Operating, Inc.,
assumed operations in our Corsicana field.
• Manage
Our Risk Exposure.
We continue to sell a portion of the working interests in the development wells
we drill, which allows us to spread the risk by drilling more wells for the same
capital expenditure budget.
Plans for fiscal year 2011
Barnett Shale
In December 2008, we suspended our Barnett Shale development due to depressed
natural gas prices. We do not expect to renew the development program during this
fiscal year. However, we expect to resume the development program during the next
fiscal year.
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Table of Contents
Corsicana
We have completed our analysis of the results of Phase I of our surfactant polymer
flood. We have concluded that the results of the program warrant execution of
Phase II. However, during the course of our evaluation, potential new technology
with similar sweep efficiencies was evaluated. Based upon the data, we believe
the new technology could be employed at a substantial cost savings when compared
with a surfactant polymer flood. We have entered into negotiations with the company
that owns the technology and expect to begin implementation of a pilot program
to test the technology in the second quarter of the fiscal year.
We are also testing a new technology in the Corsicana field involving the detection
and recording of helium atoms through the drilling of one-meter holes in 300 plotted
locations throughout our leasehold. The technology is owned by one of our largest
shareholders and has been successful in its application in foreign oil fields.
This technology is able to detect and map helium atoms in the soil, which are
always present in hydrocarbon molecules. This technology could assist the Company
in its mapping of the Pecan Gap reservoir in leasehold and could substantially
affect the results of subsequent drilling in that zone. This Company is not being
charged for the direct costs associated with the implementation of the helium
technology.
Production, Revenues and Price History
The following table sets forth information regarding oil and gas production, and
revenues for ReoStar Energy.
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Years Ending |
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March 31,
2010
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March 31,
2009
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March 31,
2008
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| Production |
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| Oil
(Bbl) |
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23,949
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45,105
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33,602
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| Gas
(Mcf) |
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404,131
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479,180
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351,538
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| Revenues |
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| Crude
Oil |
$ |
1,613,235
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$ |
4,034,376
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$ |
2,704,468
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| Gas
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1,406,275
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2,523,693
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2,197,604
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| Total
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3,019,510
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6,558,069
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4,902,072
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| Average Sale Price per
Bbl |
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67.36
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89.44
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$ |
$80.49
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| Average Sale Price per MCF |
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3.48
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5.27
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$ |
6.25
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| Lease Operating Costs (per BOE)
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20.13
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20.79
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$ |
23.05
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| Severance Taxes (per BOE)
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1.71
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3.00
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$ |
3.13
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| Average Sale Price (per
BOE) |
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33.07
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52.48
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$ |
53.17
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| Average Sale Price (per MCFE)
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5.51
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8.75
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$ |
8.86
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(a) Natural Gas was converted to BOE at the rate of 1 barrel
equals 6 MCF.
Competition
We encounter substantial competition in developing and acquiring oil and gas properties,
securing and retaining personnel, conducting drilling and field operations and
marketing production. Competitors in exploration, development, acquisitions and
production include the major oil companies as well as numerous independent oil
companies, individual proprietors and others. Although our sizable acreage position
and core-area concentration provide some competitive advantages, many competitors
have financial and other resources substantially exceeding ours. Therefore, competitors
may be able to pay more for desirable leases and to evaluate, bid for and purchase
a greater number of properties or prospects than our financial or personnel resources
allow. Our ability to replace and expand our reserve base depends on our ability
to attract and retain quality personnel and our ability to identify and acquire
suitable producing properties and prospects for future drilling.
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Table of Contents
Employees
As of April 1, 2010, ReoStar Energy Corporation and our subsidiaries had 13 full-time
and 4 part-time employees.
All of ReoStar's full-time employees are eligible to receive equity awards approved
by the Compensation Committee of the Board of Directors. No employees are covered
by a labor union or other collective bargaining arrangement. We believe that the
relationship with our employees is excellent. We regularly utilize independent
consultants and contractors to perform various professional services, particularly
in the areas of drilling, completion, field and on-site production operation services,
mainly through our affiliated operator, Rife Energy Operating, Inc.
Available Information
We maintain an internet website under the name "www.reostarenergy.com." Information
contained on or connected to our website is not incorporated by reference into
this Form 10-K and should not be considered part of this report or any other filing
that we make with the SEC. Our Code of Ethics is available on our website and
available to any stockholder who provides a written request to Investor Relations
at 3880 Hulen Street, Suite 500, Fort Worth, Texas 76107.
We file annual reports on Form 10-K, quarterly reports on Form 10-Q and current
reports on Form 8-K, proxy statements and other documents with the SEC under the
Securities Exchange Act of 1934. The public may read and copy any materials that
we file with the SEC at the SEC's Public Reference Room at 100 F Street, N.E.,
Washington DC 20549. The public may obtain information on the operation of the
Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains
an internet website that contains reports, proxy and information statements, and
other information regarding issuers, including REOSTAR, that file electronically
with the SEC. The public can obtain any document we file with the SEC at "www.sec.gov."
Marketing and Customers
We market nearly all of our oil and
gas production from the properties we operate for both our interest and that of
the other working interest owners and royalty owners. All of our gas produced
from the Barnett Shale is sold pursuant to a gas contract with Copano Field Services/North
Texas LLC. The contract expires May 31, 2017 and provides for two stages of gathering
fees. For all wells in production through December 31, 2010, a gathering fee of
$0.55 per MMBTU is assessed against our revenue. Thereafter, for all wells in
production as of December 31, 2010, no gathering fee will be assessed. Currently,
none of our gas is sold under long-term fixed price contracts. Our Barnett oil
is currently sold to Parnon Gathering, Inc. under a month to month contract until
such time as either party cancels by providing thirty (30) days advance written
notice to the other party of intent to cancel. The contract pays Platts plus minus
$1.00 based on Plains - North Texas Sweet posted price.
Oil and gas purchasers are selected on the basis of price, credit quality and
service. For a summary of purchasers of our oil and gas production that accounted
for 10% or more of consolidated revenue, see Note 13 to our financial statements.
Because alternative purchasers of oil and gas are usually readily available, we
believe that the loss of any of these purchasers would not have a material adverse
effect on us.
During the fiscal year, we implemented a comprehensive commodity price hedging
program. The Company entered into a swap contract for 2,000 barrels of oil per
month from August through December 2009. The contract locked in the price of oil
at $70.40 per barrel. The Company entered into a swap contract for 20,000 MMBTU
of natural gas per month from August through December 2009. The contract locked
in the price of natural gas at $4.205 per MMBTU. The Company entered into a swap
contract for 20,000 MMBTU of natural gas per month from January 2010 through June
2010. The contract locks in the price of natural gas at $5.54 per MMBTU.
During the fiscal year ended March 31, 2010, the Company entered into put and
call contracts, which collar 2,000 barrels of oil per month during calendar 2010.
The floor is $65 per barrel and the ceiling is $85 per barrel. The Company also
entered into put and call contracts which collar 20,000 MMBTU of natural gas per
month from July 2010 through December 2010. The floor is $5.50 per MMBTU and the
ceiling is $6.50 per MMBTU.
Proximity to local markets, availability of competitive fuels and overall supply
and demand are factors affecting the prices for which our production can be sold.
Market volatility due to international political developments, overall energy
supply and demand, fluctuating weather conditions, economic growth rates and other
factors in the United States and worldwide has had, and will continue to have,
a significant effect on energy prices.
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Table of Contents
For additional information, see "Risk Factors".
Governmental Regulation
Federal, state and local laws and regulations substantially affect our operations.
In particular, oil and gas production and related operations are, or have been,
subject to price controls, taxes and numerous other laws and regulations. All
of the jurisdictions in which we own or operate producing crude oil and natural
gas properties have statutory provisions regulating the exploration for and production
of crude oil and natural gas, including provisions related to permits for the
drilling of wells, bonding requirements in order to drill or operate wells, the
location of wells, the method of drilling and casing wells, the surface use and
restoration of properties upon which wells are drilled, and the abandonment of
wells. Our operations are also subject to various conservation laws and regulations.
These include the regulation of the size of drilling and spacing units or proration
units, the number of wells which may be drilled in an area, and the unitization
or pooling of crude oil and natural gas wells, generally prohibit the venting
or flaring of natural gas, and impose certain requirements regarding the ratability
or fair apportionment of production from fields and individuals wells.
In August 2005, Congress enacted the Energy Policy Act of 2005 ("EPAct 2005").
Among other matters, the EPAct 2005 amends the Natural Gas Act ("NGA"), to make
it unlawful for "any entity", including otherwise non-jurisdictional producers
such as ReoStar, to use any deceptive or manipulative device or contrivance in
connection with the purchase or sale of natural gas or the purchase or sale of
transportation services subject to regulation by the Federal Energy Regulatory
Commission ("FERC"), in contravention of rules prescribed by the FERC. On January
20, 2006, the FERC issued rules implementing this provision. The rules make it
unlawful in connection with the purchase or sale of natural gas subject to the
jurisdiction of FERC, or the purchase or sale of transportation services subject
to the jurisdiction of FERC, for any entity, directly or indirectly, to use or
employ any device, scheme or artifice to defraud; to make any untrue statement
of material fact or omit to make any such statement necessary to make the statements
made not misleading; or to engage in any act or practice that operates as a fraud
or deceit upon any person. EPAct 2005 also gives the FERC authority to impose
civil penalties for violations of the NGA up to $1,000,000 per day per violation.
The new anti-manipulation rule does not apply to activities that relate only to
intrastate or other non-jurisdictional sale or gathering, but does apply to activities
or otherwise non-jurisdictional entities to the extent the activities are conducted
"in connection with" gas sales, purchases or transportation subject to FERC jurisdiction.
It therefore reflects a significant expansion of FERC's enforcement authority.
ReoStar does not anticipate it will be affected any differently than other producers
of natural gas.
Failure to comply with applicable laws and regulations can result in substantial
penalties. The regulatory burden on the industry increases the cost of doing business
and affects profitability. Although we believe we are in substantial compliance
with all applicable laws and regulations, such laws and regulations are frequently
amended or reinterpreted. Therefore, we are unable to predict the future costs
or impact of compliance. Congress, the states, the FERC, and the courts regularly
consider additional proposals and proceedings that affect the oil and gas industry.
We cannot predict when or whether any such proposals may become effective.
Environmental Matters
Our operations are subject to stringent federal, state and local laws governing
the discharge of materials into the environment or otherwise relating to environmental
protection. Numerous governmental departments such as the Environmental Protection
Agency ("EPA") issue regulations to implement and enforce such laws, which are
often difficult and costly to comply with and which carry substantial civil and
criminal penalties for failure to comply. These laws and regulations may require
the acquisition of a permit before drilling commences, restrict the types, quantities
and concentrations of various substances that can be released into the environment
in connection with drilling, production and transporting through pipelines, limit
or prohibit drilling activities on certain lands lying within wilderness, wetlands,
frontier and other protected areas, require some form of remedial action to prevent
pollution from former operations such as plugging abandoned wells, and impose
substantial liabilities for pollution resulting from operations. In addition,
these laws, rules and regulations may restrict the rate of production. The regulatory
burden on the oil and gas industry increases the cost of doing business, affecting
growth and profitability. Changes in environmental laws and regulations occur
frequently, and changes that result in more stringent and costly waste handling,
disposal or clean-up requirements could adversely affect our operations and financial
position, as well as the industry in general. We believe we are in substantial
compliance with current applicable environmental laws and regulations. Although
we have not experienced any material adverse effect from compliance with environmental
requirements, there is no assurance that this will continue. We did not have any
material capital or other non-recurring expenditures in connection with complying
with environmental laws or environmental remediation matters during fiscal year
ended 2010, nor do we anticipate that such expenditures will be material in fiscal
year ended 2011.
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Table of Contents
The Comprehensive Environmental Response,
Compensation and Liability Act ("CERCLA"), known as the "Superfund" law, imposes
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons who are considered to be responsible for the release
of a "hazardous substance" into the environment. These persons include owners
or operators of the disposal site or sites where the release occurred and companies
that disposed of or arranged for the disposal of the hazardous substances at the
site where the release occurred. Under CERCLA, such persons may be subject to
joint and several liabilities for the costs of cleaning up the hazardous substances
that have been released into the environment, for damages to natural resources
and for the costs of certain health studies. Furthermore, although petroleum,
including crude oil and natural gas, is not a "hazardous substance" under CERCLA,
at least two courts have ruled that certain wastes associated with the production
of crude oil may be classified as "hazardous substances" under CERCLA and that
such wastes may therefore give rise to liability under CERCLA. Beyond CERCLA,
state laws regulate the disposal of oil and gas wastes, and periodically new state
legislative initiatives are proposed that could have a significant impact on us.
In addition, it is not uncommon for neighboring landowners and other third parties
to file claims for personal injury and property damages allegedly caused by the
release of hazardous substances or other pollutants into the environment pursuant
to environmental statutes, common law or both.
The Federal Water Pollution Control Act ("FWPCA") imposes restrictions and strict
controls regarding the discharge of produced waters and other oil and gas wastes
into waters of the United States. Permits must be obtained to discharge pollutants
into state and federal waters. The FWPCA and analogous state laws provide for
civil, criminal and administrative penalties for any unauthorized discharges of
oil and other hazardous substances in reportable quantities and may impose substantial
potential liability for the costs of removal, remediation and damages. State water
discharge regulations and Federal National Pollutant Discharge Elimination System
permits applicable to the oil and gas industry generally prohibit the discharge
of produced water, sand and some other substances into coastal waters. The cost
to comply with zero discharges mandated under federal and state law has not had
a material adverse impact on our financial condition and results of operations.
Some oil and gas exploration and production facilities are required to obtain
permits for their storm water discharges. Costs may be incurred in connection
with treatment of wastewater or developing and implementing storm water pollution
prevention plans. The Resource Conservation and Recovery Act ("RCRA") as amended,
generally does not regulate most wastes generated by the exploration and production
of oil and gas. RCRA specifically excludes from the definition of hazardous waste
"drilling fluids, produced waters, and other wastes associated with the exploration,
development, or production of crude oil, natural gas or geothermal energy." However,
these wastes may be regulated by the EPA or state agencies as non-hazardous solid
waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents,
laboratory wastes and waste compressor oils, can be regulated as hazardous wastes.
Although the costs of managing wastes classified as hazardous waste may be significant,
we do not expect to experience more burdensome costs than similarly situated companies.
The Oil Pollution Act ("OPA") requires owners and operators of facilities that
could be the source of an oil spill into "waters of the United States" (a term
defined to include rivers, creeks, wetlands and coastal waters) to adopt and implement
plans and procedures to prevent any spill of oil into any waters of the United
States. OPA also requires affected facility owners and operators to demonstrate
that they have sufficient financial resources to pay for the costs of cleaning
up an oil spill and compensating any parties damaged by an oil spill. Substantial
civil and criminal fines and penalties can be imposed for violations of OPA and
other environmental statutes.
Stricter standards in environmental legislation may be imposed
on the oil and gas industry in the future. For instance, legislation has been
proposed in Congress from time-to-time that would alter the RCRA exemption by
reclassifying certain oil and gas exploration and production wastes as "hazardous
wastes" and make the waste subject to more stringent handling, disposal and clean-up
restrictions. If such legislation were enacted, it could have a significant impact
on our operating costs, as well as the industry in general. Compliance with environmental
requirements generally could have a material adverse effect on our capital expenditures,
earnings or competitive position. Although we have not experienced any material
adverse effect from compliance with environmental requirements, no assurance may
be given that this will continue.
6
Table of Contents
ITEM 1A. RISK FACTORS
An investment in our common stock is speculative and involves a high degree of
risk and uncertainty. You should carefully consider the risks described below,
together with the other information contained in our reports filed with the SEC,
including the consolidated financial statements and notes thereto of our company,
before deciding to invest in our common stock. The risks described below are not
the only ones facing our company. Additional risks not presently known to us or
that we presently consider immaterial may also adversely affect our company. If
any of the following risks occur, our business, financial condition and results
of operations and the value of our common stock could be materially and adversely
affected.
The Company received a qualified going concern opinion in the report from its
auditors.
In their report dated June 29, 2010, the Company's auditors indicated there was
substantial doubt about the Company's ability to continue as a going concern without
additional fund-raising. Accordingly, unless we raise additional working capital,
project financing and/or revenues grow to support our business plan we may be
unable to remain in business
Volatility of oil and natural gas prices significantly affects our cash
flow and capital resources and could hamper our ability to produce oil and gas
economically.
Oil and natural gas prices are volatile, and a decline in prices would adversely
affect our profitability and financial condition. The oil and natural gas industry
is typically cyclical, and prices for oil and natural gas have been highly volatile.
Historically, the industry has experienced severe downturns characterized by oversupply
and/or weak demand. In recent years, higher oil and natural gas prices have contributed
to increased earnings industry wide. However, long-term supply and demand for
oil and natural gas is uncertain and subject to a myriad of factors such as:
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• |
the domestic and foreign supply
of oil and gas; |
| |
• |
the price and availability of
alternative fuels; |
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• |
weather conditions; |
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• |
the level of consumer demand;
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• |
the price of foreign imports;
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• |
world-wide economic conditions;
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• |
political conditions in oil and
gas producing regions; and |
| |
• |
domestic and foreign governmental
regulations. |
Decreases in oil and natural gas prices from current levels could adversely affect
our revenues, net income, cash flow and economically recoverable proved reserves.
Significant price decreases could have a material adverse effect on our operations
and limit our ability to fund capital expenditures. Without the ability to fund
capital expenditures, we would be unable to replace reserves and production.
High operating costs are inherent in enhanced oil recovery projects and
could impair our ability to produce oil and gas economically.
The Company has initiated a surfactant polymer
flood, which is classified as an enhanced oil recovery project. The cost of the
surfactants and polymers, the cost of preparing the mixture for injection, the
cost of injection, the cost of monitoring the quality of the injected solution,
and the cost of monitoring the results all contribute to operating expenses which
are significantly higher than operating expenses incurred using primary and secondary
recovery techniques. Additionally, the response time, response rate, and overall
recovery rate of a surfactant polymer flood are uncertain, which could materially
impact the operating cost per unit produced.
Due to the higher operating costs (which for the fiscal year ended March 31, 2008
averaged more than $30.00 per BOE), a significant decline in commodity prices
could magnify the negative impact on net income, cash flow and proved reserves.
7
Table of Contents
Hedging transactions may limit our potential gains and involve other risks.
To manage our exposure to price risk, we may, from time to time, enter into hedging
arrangements, utilizing commodity derivatives with respect to a significant portion
of our future production. The goal of hedging is to lock in prices so as to limit
volatility and increase the predictability of cash flow. These transactions may
limit potential gains if oil and natural gas prices rise above the price established
by the hedge. In addition, hedging transactions may cause risk of financial loss
in certain circumstances.
Information concerning our reserves and future net reserve estimates is
uncertain.
There are numerous uncertainties inherent in estimating quantities of proved oil
and natural gas reserves and their values, including many factors beyond our control.
Estimates of proved reserves are by their nature uncertain. Although we believe
these estimates are reasonable, actual production, revenues and costs to develop
will likely vary from estimates, and these variances could be material.
The accuracy of any reserve estimate is a function of the quality of available
data; engineering and geological interpretation and judgment; assumptions used
regarding quantities of oil and natural gas in place; recovery rates; and future
commodity pricing.
Actual prices, production, development expenditures, operating expenses and quantities
of recoverable oil and natural gas reserves will vary from those assumed in our
estimates, and such variances may be material. Any variance in the assumptions
could materially affect the estimated quantity and value of the reserves.
If oil and natural gas prices decrease or exploration efforts are unsuccessful,
we may be required to take write-downs of our oil and natural gas properties.
This could occur when oil and natural gas prices are low, if we have downward
adjustments to our estimated proved reserves, increases in our estimates of operating
or development costs, deterioration in our exploration results, unsatisfactory
results in our enhanced oil recovery projects, or mechanical problems with wells
where the cost to re-drill or repair does not justify the expenditures required.
Accounting rules require that the carrying value of oil and natural gas properties
be periodically reviewed for possible impairment. "Impairment" is recognized when
the book value of a proven property is greater than the expected undiscounted
future net cash flows from that property and on acreage when conditions indicate
the carrying value is not recoverable. We may be required to write down the carrying
value of a property based on oil and natural gas prices at the time of the impairment
review, as well as a continuing evaluation of drilling results, production data,
economics and other factors. While an impairment charge reflects our long-term
ability to recover an investment, it does not impact cash or cash flow from operating
activities, but it does reduce our reported earnings and negatively impacts our
leverage ratios.
Our business is subject to operating hazards and environmental regulations
that could result in substantial losses or liabilities.
Oil and natural gas operations are subject to many risks, including well blowouts,
mechanical failures, explosions, uncontrollable flows of oil, natural gas or well
fluids, fires, formations with abnormal pressures, pipeline ruptures or spills,
pollution, releases of toxic natural gas and other environmental hazards and risks.
If any of these hazards occur, we could sustain substantial losses as a result
of:
| |
• |
injury or loss of life; |
| |
• |
severe damage to or destruction
of property, natural resources, and equipment; |
| |
• |
pollution or other environmental
damage; |
| |
• |
clean-up responsibilities; |
| |
• |
regulatory investigations and
penalties; or |
| |
• |
suspension of operations. |
8
Table of Contents
As we drill to deeper horizons and in more
geologically complex areas, we could experience a greater increase in operating
and financial risks due to inherent higher reservoir pressures and unknown down-hole
risk exposures. As we continue to drill deeper, the number of rigs capable of
drilling to such depths will be fewer and we may experience greater competition
from other operators.
Our operations are subject to numerous and increasingly strict federal, state
and local laws, regulations and enforcement policies relating to the environment.
We may incur significant costs and liabilities in complying with existing or future
environmental laws, regulations and enforcement policies and may incur costs arising
out of property damage or injuries to employees and other persons. These costs
may result from our current and former operations and even may be caused by previous
owners of property we own or lease. Any past, present or future failure by us
to completely comply with environmental laws, regulations and enforcement policies
could cause us to incur substantial fines, sanctions or liabilities from cleanup
costs or other damages. Incurrence of those costs or damages could reduce or eliminate
funds available for exploration, development or acquisitions or cause us to incur
losses.
In accordance with our operating agreements, the operator maintains insurance
against some, but not all, of these potential risks and losses. We may elect not
to obtain insurance if we believe that the cost of available insurance is excessive
relative to the risks presented. We do not maintain business interruption insurance.
In addition, pollution and environmental risks generally are not fully insurable.
If a significant accident or other event occurs that is not fully covered by insurance,
it could have a material adverse affect on our financial condition and results
of operations.
We are subject to financing and interest rate exposure risks.
Our business and operating results can be harmed by factors such as the availability,
terms of and cost of capital, increases in interest rates or a reduction in credit
rating. These changes could cause our cost of doing business to increase, which
limit our ability to pursue acquisition opportunities and place us at a competitive
disadvantage.
Many of our current and potential competitors have greater resources than
ours, and we may not be able to successfully compete in acquiring, exploring and
developing new properties.
We face competition in every aspect of our business, including, but not limited
to, acquiring reserves and leases, obtaining goods, services and employees needed
to operate and manage our business and marketing oil and natural gas. Competitors
include multinational oil companies, independent production companies and individual
producers and operators. Many of our competitors have greater financial and other
resources than we do.
The demand for field services and their ability to meet that demand may
limit our ability to drill and produce our oil and natural gas properties.
Due to current industry demands, well service providers and related equipment
and personnel are in short supply. This will result in escalating prices, the
possibility of poor services coupled with potential damage to down-hole reservoirs
and personnel injuries. Such pressures will likely increase the actual cost of
services, extend the time to secure such services and add costs for damages due
to accidents sustained from the over use of equipment and inexperienced personnel.
The oil and natural gas industry is subject to extensive regulation.
The oil and natural gas industry is subject to various types of regulations in
the United States by local, state and federal agencies. Legislation affecting
the industry is under constant review for amendment or expansion, frequently increasing
our regulatory burden. Numerous departments and agencies, both state and federal,
are authorized by statute to issue rules and regulations binding on participants
in the oil and natural gas industry. Compliance with such rules and regulations
often increases our cost of doing business and, in turn, decreases our profitability.
9
Table of Contents
Acquisitions are subject to the risks
and uncertainties of evaluating reserves and potential liabilities and may be
disruptive and difficult to integrate into our business.
We could be subject to significant liabilities related to acquisitions. It generally
is not feasible to review in detail every individual property included in an acquisition.
Ordinarily, a review is focused on higher valued properties. However, even a detailed
review of all properties and records may not reveal existing or potential problems
in all of the properties, nor will it permit us to become sufficiently familiar
with the properties to assess fully their deficiencies and capabilities. We do
not always inspect every well we acquire, and environmental problems, such as
groundwater contamination, are not necessarily observable even when an inspection
is performed.
In addition, there is intense competition for acquisition opportunities in our
industry. Competition for acquisitions may increase the cost of, or cause us to
refrain from, completing acquisitions. Our acquisition strategy is dependent upon,
among other things, our ability to obtain debt and equity financing and, in some
cases, regulatory approvals. Our ability to pursue our acquisition strategy may
be hindered if we are not able to obtain financing on terms acceptable to regulatory
approvals or us.
Acquisitions often pose integration risks and difficulties. In connection with
future acquisitions, the process of integrating acquired operations into our existing
operations may result in unforeseen operating difficulties and may require significant
management attention and financial resources that would otherwise be available
for the ongoing development or expansion of existing operations. Future acquisitions
could result in our incurring additional debt, contingent liabilities, expenses
and diversion of resources, all of which could have a material adverse effect
on our financial condition and operating results.
Our success depends on key members of our management and our ability to
attract and retain experienced technical and other professional personnel.
Our success is highly dependent on our management personnel. The loss of one or
more of these individuals could have a material adverse effect on our business.
Furthermore, competition for experienced technical and other professional personnel
is intense. If we cannot retain our current personnel or attract additional experienced
personnel, our ability to compete could be adversely affected.
Our future success depends on our ability to replace reserves that we produce.
Because the rate of production from oil and natural gas properties generally declines
as reserves are depleted, our future success depends upon our ability to economically
find or acquire and produce additional oil and natural gas reserves. Except to
the extent that we acquire additional properties containing proved reserves, conduct
successful exploration and development activities or, through engineering studies,
identify additional behind-pipe zones or secondary recovery reserves, our proved
reserves will decline as reserves are produced. Future oil and natural gas production,
therefore, is highly dependent upon our level of success in acquiring or finding
additional reserves that are economically recoverable. We cannot assure you that
we will be able to find or acquire and develop additional reserves at an acceptable
cost.
New technologies may cause our current exploration and drilling methods
to become obsolete.
The oil and natural gas industry is subject to rapid and significant advancements
in technology, including the introduction of new products and services using new
technologies. As competitors use or develop new technologies, we may be placed
at a competitive disadvantage, and competitive pressures may force us to implement
new technologies at a substantial cost. In addition, competitors may have greater
financial, technical and personnel resources that allow them to enjoy technological
advantages and may in the future allow them to implement new technologies before
we can. One or more of the technologies that we currently use or that we may implement
in the future may become obsolete. We cannot be certain that we will be able to
implement technologies on a timely basis or at a cost that is acceptable to us.
If we are not able to maintain technological advancements consistent with industry
standards, our operations and financial condition may be adversely affected.
10
Table of Contents
Our business depends on oil and natural
gas transportation facilities, most of which are owned by others.
The marketability of our oil and natural gas production depends in part on the
availability, proximity and capacity of pipeline systems owned by third parties.
The unavailability of or lack of available capacity on these systems and facilities
could result in the shut-in of producing wells or the delay or discontinuance
of development plans for properties. Although we have some contractual control
over the transportation of our product, material changes in these business relationships
could materially affect our operations. We generally do not purchase firm transportation
on third party facilities and therefore, our production transportation can be
interrupted by those having firm arrangements.
Federal and state regulation of oil and natural gas production and transportation,
tax and energy policies, changes in supply and demand, pipeline pressures, damage
to or destruction of pipelines and general economic conditions could adversely
affect our ability to produce, gather and transport oil and natural gas.
The disruption of third-party facilities due to maintenance and/or weather could
negatively impact our ability to market and deliver our products. We have no control
over when or if such facilities are restored or what prices will be charged. A
total shut-in of production could materially affect us due to a lack of cash flow,
and if a substantial portion of the production is hedged at lower than market
prices, those financial hedges would have to be paid from borrowings absent sufficient
cash flow.
Indebtedness could limit our ability to successfully operate our business.
If we decide to pursue additional acquisitions, our capital expenditures will
increase both to complete such acquisitions and to explore and develop any newly
acquired properties. Our existing operations will also require ongoing capital
expenditures. We may choose to increase debt in order to finance any of these
potential capital expenditure requirements. The degree to which we are leveraged
could have other important consequences, including the following:
| |
• |
we may be required
to dedicate a substantial portion of our cash flows from operations to the
payment of our indebtedness, reducing the funds available for our operations;
|
| |
• |
a portion of our
borrowings are at variable rates of interest, making us vulnerable to increases
in interest rates; |
| |
• |
we may be more highly
leveraged than some of our competitors, which could place us at a competitive
disadvantage; |
| |
• |
our degree of leverage
may make us more vulnerable to a downturn in our business or the general
economy; |
| |
• |
the terms of our
credit arrangements could contain numerous financial and other restrictive
covenants; |
| |
• |
our debt level could
limit our flexibility in planning for, or reacting to, changes in our business
and the industry in which we operate; and |
| |
• |
we may have difficulties
borrowing money in the future. |
Any failure to meet our debt
obligations could harm our business, financial condition and results of operations.
If our cash flow and capital resources are insufficient to fund our current or
future debt obligations, we may be forced to sell assets, seek additional equity
or restructure our debt. In addition, any failure to make scheduled payments of
interest and principal on our outstanding indebtedness would likely result in
a reduction of our credit rating, which could harm our ability to incur additional
indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient
for payment of interest on and principal of our debt in the future and any such
alternative measures may be unsuccessful or may not permit us to meet scheduled
debt service obligations, which could cause us to default on our obligations and
impair our liquidity.
11
Table of Contents
The current global financial crisis
may adversely affect our business, operating results and financial condition.
The global financial markets are in turmoil, and the economies of the United States
and many other countries have recently been in recession, which may be severe
and prolonged and have been characterized by high unemployment, limited availability
of credit and capital, increased rates of default and bankruptcy and decreased
consumer and business spending. These developments could negatively affect our
business, operating results and financial condition in a number of ways. For example,
this recession has had an unprecedented negative impact on the global credit and
capital markets, resulting in financing terms that are less attractive to borrowers,
and in many cases, the unavailability of certain types of debt or capital financing.
If this crisis continues or worsens, and if we are required to obtain financing
in the near term to meet our working capital or other business needs, we may not
be able obtain that financing. Further, even if we are able to obtain the financing
we need, it may be on terms that are not favorable to us, with increased financing
costs and restrictive covenants.
We exist in a litigious environment.
Any constituent could bring suit or allege a violation of an existing contract.
This action could delay when operations can actually commence or could cause a
halt to production until the courts resolve such alleged violations. Not only
could we incur significant legal and support expenses in defending our rights,
planned operations could be delayed which would impact our future operations and
financial condition. Such legal disputes could also distract management and other
personnel from their primary responsibilities.
Common stockholders will be diluted if additional shares are issued.
We may incur debt that provides for a conversion to equity. Additionally, we may
issue stock as consideration for additional property acquisitions. If we issue
additional shares of our common stock in the future, it may have a dilutive effect
on our current outstanding stockholders.
Dividend limitations.
Our ability to pay dividends may be limited by covenants imposed under future
debt arrangements.
Our financial statements are complex.
Due to accounting rules, our financial statements continue to be complex, particularly
with reference to hedging, asset retirement obligations, equity awards, and deferred
taxes. We expect such complexity to continue and possibly increase.
Our stock price may be volatile and you may not be able to resell shares
of our common stock at or above the price you paid.
The price of our common stock fluctuates significantly, which may result in losses
for investors. To date our stock has been lightly traded, with the average daily
volume being quite low. The low trading volume may prevent you from liquidating
your position in our stock quickly. Additionally, the low trading volume may contribute
significantly to price volatility. We expect our stock to be subject to fluctuations
as a result of a variety of factors, including factors beyond our control. These
include:
| |
• |
changes in oil and natural
gas prices; |
| |
• |
variations in quarterly
drilling, re-completions, acquisitions and operating results; |
| |
• |
changes in financial estimates
by securities analysts; |
| |
• |
changes in market valuations
of comparable companies; |
| |
• |
additions or departures
of key personnel; or |
| |
• |
future sales of our stock. |
12
Table of Contents
We may fail to meet expectations of our
stockholders or of securities analysts at some time in the future, and our stock
price could decline as a result. Furthermore, the ability to access capital has
been somewhat impaired due to the financial downturn, which could impact the Company's
ability to do the same.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable
ITEM 2. PROPERTIES
The information below summarizes certain data for our core operating areas for
the year ended March 31, 2010. Segment reporting is not applicable to us as we
have a single company-wide management team that administers all properties as
a whole rather than by discrete operating segments. We track only basic operational
data by area. We do not maintain complete separate financial statement information
by area. We measure financial performance as a single enterprise and not on an
area-by-area basis.
We conduct drilling, production and field operations in the Barnett Shale of North
Central Texas, and the Corsicana field of East Central Texas.
Barnett Shale
The Barnett Shale is a non-conventional natural gas resource play located in North
Texas. It underlies approximately 5,000 square miles and at least 17 counties.
Our leases lie in the north western portion of the Barnett Shale, an area known
as the "oil window," due to its production of both oil and gas.
We have drilled and own interests in 71 completed wells, all of which are operated
by Rife Energy Operating, Inc., a non-publicly traded affiliated company owned
by a shareholder who controls more than 25% of our outstanding stock. Our average
working interest is 47%, and our average net revenue interest is 36%. We have
approximately 5,215 acres under lease, the majority of which is not classified
as proven. During the fiscal year ended March 31, 2010, our Barnett Shale production
consisted of 404,131 MCF of natural gas and 23,949 barrels of oil, or approximately
91,300 BOE (547,825 MCFE).
Proved developed producing reserves consisted of 1,920 MMCF of natural gas and
58 M barrels of oil, or, 378 MBOE (2,267 MMCFE). Proved developed non-producing
reserves consisted of 33 MMCF of natural gas and 8 M barrels of oil, or, 13 MBOE
(81 MMCFE). Total proved developed reserves at March 31, 2010 were 392 MBOE (2,348
MMCFE). Total proven, undeveloped reserves consisted of 16,820 MMCF natural gas
and 643 M barrels of oil, or, 3,446 MBOE (20,680 MMCFE).
At March 31, 2010, we had a Barnett Shale drilling inventory of 50 proven drilling
locations and more than 100 probable drilling locations.
Corsicana Field
We own interests in 77 producing well bores and 199 inactive wells. During the
fiscal year, we transitioned operation of all of our properties in Corsicana from
a non-publicly traded affiliate to a ReoStar Operating, Inc. Our average working
interest is 95%, and our average net revenue interest is 76%. During the fiscal
year ended March 31, 2010, our oil production in the Corsicana field totaled 10,300
barrels of oil.
The Nacatoch reservoir is fairly shallow with depths of less than 1,000 feet.
While this field has been producing for more than one hundred years, several engineering
studies have estimated that more than 80% of the original reserves still remain
in place or approximately 100 MMBO.
We are evaluating optional EOR techniques including the use of chemicals (micellar
flood), steam, and fire floods.
There are many alternative reservoirs between 1000 and 7000 feet, which are being
evaluated for optimal exploitation. The company feels that there are tremendous
opportunities in the multiple zones within this range and it plans on attempting
to produce from each one.
13
Table of Contents
During the fiscal year ended March 31, 2010,
the Company drilled three Pecan Gap test wells. Two of the wells were successfully
completed. The Company has identified 7 additional proven undeveloped drilling
locations in the Pecan Gap formation and plans to beginning drilling these wells
in the fourth quarter of the fiscal year. If these wells are successful, the Company
expects to begin an extensive drilling program, and may drill up to 200 more Pecan
Gap wells. The Pecan Gap formation lies at about 1,800 feet, and the wells cost
approximately $130,000 to drill and complete. The Company has secured co-financing
for these wells from an industry partners who have purchased working interests
in the first three wells and expects to sell up to 50% of any additional Pecan
Gap wells we drill.
We are also testing a new technology in the Corsicana field involving the detection
and recording of helium atoms through the drilling of one-meter holes in 300 plotted
locations throughout our leasehold. The technology is owned by one of our largest
shareholders and has been successful in its application in foreign oil fields.
This technology is able to detect and map helium atoms in the soil, which are
always present in hydrocarbon molecules. This technology could assist the Company
in its mapping of the Pecan Gap reservoir in leasehold and could substantially
affect the results of subsequent drilling in that zone. This Company is not being
charged for the direct costs associated with the implementation of the helium
technology.
As of March 31, 2010, total proved developed reserves were 32 MBOE and proved
undeveloped reserves totaled 40 MBOE.
East Texas Properties
During the fiscal year ended March 31, 2010, the Company divested of its East
Texas assets.
Proven Reserves
Proven oil and gas reserves are defined as the estimated quantities of crude oil,
condensate, natural gas liquids and natural gas that geological and engineering
data demonstrate with reasonable certainty are recoverable from known reservoirs
under existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalations based
upon future conditions.
See financial statement footnote number 17, "Supplemental Info on Oil and Gas
Exploration, Development, and Production Activities" for the disclosures required
by FASB ASC 932 and more detailed information regarding our proven reserves.
At year-end 2010, the independent petroleum-consulting firm of Forrest Garb and
Associates, Inc. reviewed our reserves. These engineers were selected for their
geographic expertise and their history in engineering enhanced oil recovery prospects
similar to our Corsicana properties. At March 31, 2010, these consultants reviewed
100% of our proved reserves.
All estimates of oil and gas reserves are subject to uncertainty. The following
table sets forth the estimated proven reserves in barrel of oil equivalents and
the benchmark prices used in projecting them (in thousands except prices):
| Estimated
Proved Reserves |
|
Barnett
Shale
|
|
Corsicana
Field
|
|
Total
|
|
| Proved Developed
(MBOE) |
|
392
|
|
32
|
|
424
|
|
| Proved Undeveloped (MBOE)
|
|
3,446
|
|
40
|
|
3,486
|
|
| Total
Proven Reserves at March 31, 2010 |
|
3,838
|
|
72
|
|
3,910
|
|
| |
|
|
|
|
|
|
|
| Benchmark
Pricing |
|
|
|
|
|
|
|
| Natural
Gas per mmbtu |
|
$3.99
|
|
|
|
|
|
| Crude
Oil per barrel |
|
$70.03
|
|
|
|
|
|
There are numerous uncertainties inherent in estimating reserves and related information
and different reservoir engineers often arrive at different estimates for the
same properties. No estimates of our reserves have been filed with or included
in reports to another federal authority or agency.
14
Table of Contents
Wells are classified as crude oil or natural
gas according to their predominant production stream.
The day-to-day operations of oil and gas properties are the responsibility of
the operator designated under pooling or operating agreements. The operator supervises
production, maintains production records, employs or contracts for field personnel
and performs other functions. An operator receives reimbursement for direct expenses
incurred in the performance of its duties as well as monthly per-well producing
and drilling overhead reimbursement at rates customarily charged by unaffiliated
third parties. The charges customarily vary with the depth and location of the
well being operated. The operator of our Barnett Shale properties is affiliated
with ReoStar and is owned by shareholders who own more than 25% of our issued
and outstanding common stock.
Undeveloped Acreage Expirations
A significant amount of our Barnett Shale acreage is not yet held by production.
However, due to our planned drilling schedules and lease renewal provisions, we
do not anticipate significant leasehold expirations during the next two years.
Our Corsicana properties are held by production.
Title to Properties
We believe that we have satisfactory title to all of our producing properties
in accordance with generally accepted industry standards. As is customary in the
industry, in the case of undeveloped properties, often minimal investigation of
record title is made at the time of lease acquisition. Investigations are made
prior to the consummation of an acquisition of producing properties and before
commencement of drilling operations on undeveloped properties. Individual properties
may be subject to burdens that we believe do not materially interfere with the
use or affect the value of the properties. Burdens on properties may include:
| |
• |
customary royalty interests; |
| |
• |
liens incident to operating agreements
and for current taxes; |
| |
• |
obligations or duties under applicable
laws; |
| |
• |
development obligations under
oil and gas leases; or |
| |
• |
burdens such as net profit interests.
|
Our headquarters are located at 3880 Hulen St, Suite 500, Fort Worth, Texas. We
lease approximately 12,000 square feet of office space under a lease and sublease
approximately one- half of the space to our affiliated operating entity, which
contributes to the costs of leasing and maintenance of the leasehold, pro-rata
to their respective usage. The lease expires on January 31, 2011. We pay rent
at a rate of $1.26 per square foot, per month. Our administrative and office facilities
are suitable for their respective uses.
ITEM 3. LEGAL PROCEEDINGS
On September 15, 2008, a royalty owner in the Corsicana polymer pilot, representing
approximately one-third of the mineral ownership, filed an amendment to a suit
originally filed in 2007. The amendment was filed to include the Company as a
defendant. The suit, filed in the 13th Judicial District Court in Navarro County,
Texas, alleges the lease has expired because no oil was produced from January
2005 through September 2005. The plaintiff has asked the court to declare the
lease to be void; demands payment for any oil produced and sold subsequent to
the time the lease expired; demands that all equipment and salvage located on
the lease be given by court order to the plaintiff; and asks that any plugging
liability be adjudged to be the responsibility of the Company.
The other royalty owners representing the remaining two-thirds mineral ownership
have ratified the lease.
15
Table of Contents
In October 2008, the court issued an order
requiring the Company and plaintiff to attend mediation to settle the matter.
The Company and plaintiff attended mediation in Corsicana, Texas, but were unable
to resolve the matter during mediation. In March, the plaintiff filed a motion
for summary judgment, which the court has denied. The Company is evaluating which
actions are the most appropriate for the Company to take in respect of this matter,
and we intend to continue to defend this matter vigorously or otherwise resolve
this matter in a manner that we believe will not have a material adverse effect
on our business, financial condition and results of operations.
If the plaintiff should prevail in the lawsuit, the amount of the loss contingency
cannot be reasonable estimated; therefore no expense for this contingency has
been recorded on the accompanying financial statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of our security holders during the fourth
quarter of 2010.
PART II
ITEM 5. MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES
OF EQUITY SECURITIES
Market Information
Our common stock is currently quoted for trading on Over-the-Counter Bulletin
Board (OTCBB) maintained by the Financial Industry Regulatory Authority (FINRA)
under the symbol "REOS". There was no active market or any trading volume with
respect to the shares of our common stock in the periods prior to the quarter
ended December 31, 2006.
The following table sets forth the high and low closing sale price of our common
stock, as reported by the National Association of Securities Dealers Composite
for each quarter during the past two fiscal years.
| Fiscal 2009 |
High |
|
Low |
| 30-Jun-09
|
$0.51 |
|
$0.06 |
| 30-Sep-09
|
$0.50 |
|
$0.10 |
| 31-Dec-09
|
$0.49 |
|
$0.11 |
| 31-Mar-10
|
$0.39 |
|
$0.08 |
| |
|
|
|
| Fiscal 2009 |
High |
|
Low |
| 30-Jun-08
|
$0.95 |
|
$0.20 |
| 30-Sep-08
|
$0.74 |
|
$0.20 |
| 31-Dec-08
|
$0.50 |
|
$0.10 |
| 31-Mar-09
|
$0.30 |
|
$0.05 |
Holders of Record
On March 31, 2010, there were approximately 90 holders of record of our common
stock.
Dividends
We have not paid any cash dividends on our Common Stock, and do not anticipate
paying cash dividends on our Common Stock in the next year. We anticipate that
any income generated in the foreseeable future will be retained for the development
and expansion of our business. Future dividend policy is subject to the discretion
of the Board of Directors and will depend upon a number of factors, including
future earnings, debt service, debt covenants, capital requirements, business
conditions, the financial condition of the Company and other factors that the
Board of Directors may deem relevant.
16
Table of Contents
ITEM 6. SELECTED FINANCIAL DATA
Not applicable.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion is intended to assist you in understanding our business
and results of operations together with our present financial condition. This
section should be read in conjunction with the financial statements and the accompanying
notes included elsewhere in this annual report on Form 10-K.
Statements in our discussion may be forward-looking. These forward-looking statements
involve risks and uncertainties. We caution that a number of factors could cause
future production, revenues and expenses to differ materially from our expectations.
See "Disclosures Regarding Forward-Looking statements" at the beginning of this
Annual Report and "Risk Factors" in Item 1A for additional discussion of some
of these factors and risks.
Overview of Our Business
We are an independent natural gas and oil company engaged in the acquisition,
development, and exploration of oil and gas properties, primarily in Texas. Our
objective is to build a balanced portfolio consisting of oil and gas producing
properties and reserves in both resource (developmental) and enhanced oil recovery
(redevelopment) plays. We will expand reserves through internally generated drilling
projects coupled with complementary acquisitions.
Our revenues, profitability and future growth depend substantially on prevailing
prices for oil and gas and on our ability to find, develop and acquire oil and
gas reserves that are economically recoverable. Our profitability depends upon
our ability to control operations of our oil and gas assets.
We have a single company-wide management team that administers all properties
as a whole rather than by independent operating segments. We track only basic
operational data by area and we do not maintain complete separate financial statement
information by area. We measure financial performance as a single enterprise and
not on an area-by-area basis.
Successful Efforts Method of Accounting
We account for our exploration and development activities utilizing the successful
efforts method of accounting. Under this method, costs of productive exploratory
wells, development dry holes and productive wells and undeveloped leases are capitalized.
Oil and natural gas lease acquisition costs are also capitalized. Exploration
costs, including personnel costs, certain geological and geophysical expenses
and delay rentals for oil and natural gas leases, are charged to expense as incurred.
Exploratory drilling costs are initially capitalized, but charged to expense if
and when the well is determined not to have found reserves in commercial quantities.
The sale of a partial interest in a proved property is accounted for as a cost
recovery and no gain or loss is recognized as long as this treatment does not
significantly affect the unit-of-production amortization rate. A gain or loss
is recognized for all other sales of producing properties.
The application of the successful efforts method of accounting requires managerial
judgment to determine the proper classification of wells designated as developmental
or exploratory which will ultimately determine the proper accounting treatment
of the costs incurred. The results from a drilling operation can take considerable
time to analyze and the determination that commercial reserves have been discovered
requires both judgment and industry experience. Wells may be completed that are
assumed to be productive and actually deliver oil and natural gas in quantities
insufficient to be economic, which may result in the abandonment of the wells
at a later date. The evaluation of oil and natural gas leasehold acquisition costs
requires managerial judgment to estimate the fair value of these costs with reference
to drilling activity in a given area.
17
Table of Contents
The successful efforts method of accounting
can have a significant impact on the operational results reported when we enter
a new exploratory area in hopes of finding an oil and natural gas field that will
be the focus of future developmental drilling activity. The initial exploratory
wells may be unsuccessful and will be expensed. Seismic costs can be substantial
which will result in additional exploration expenses when incurred.
Industry Environment
We operate entirely within the United States, a mature region for the exploration
and production of oil and gas. As a mature region, the size and frequency of new
discoveries is declining, while finding and development costs are increasing.
We believe that there remain certain areas in the southern Mid-continent region
which are under-explored or have not been fully explored and developed with the
benefit of newly available exploration, production and reserve enhancement technology.
Examples of such technology include advanced 3-D seismic processing, hydraulic
reservoir fracture stimulation, advances in well logging and analysis, and enhanced
oil recovery practices.
Another characteristic of a mature region is the historical exit of larger independent
producers and major oil companies from such regions. These companies, searching
for larger new discoveries, have ventured increasingly overseas and offshore,
de-emphasizing their onshore United States assets. This movement out of mature
basins by larger companies has provided acquisition opportunities for companies
that are capable of quickly analyzing opportunities, well positioned financially
to quickly close an acquisition, and have the technical expertise to generate
additional value from these assets.
In other situations, larger independent producers and major integrated oil companies
have allowed smaller companies the opportunity to explore and develop reserves
on their undeveloped acreage through joint ventures and farm-in arrangements.
We believe the acquisition market for natural gas properties has become extremely
competitive as producers vie for additional production and expanded drilling opportunities.
During the last fiscal year, leasehold acquisition values reached historic highs.
While these prices have moderated with the decline in natural gas commodity prices,
we expect these values to increase in the near future. As natural gas demand rebounds,
we expect drilling and service costs pressures to increase, resulting in higher
finding and development costs. In addition, we expect lease-operating expenses
to continue to rise as producers are forced to make operational enhancements to
maintain production in aging fields.
Crude oil and natural gas are commodities that are traded on regulated markets.
The price that we receive for the crude oil and natural gas we produce is largely
a function of market supply and demand. Demand for natural gas in the United States
has increased dramatically over the last ten years. Demand is impacted by general
economic conditions, estimates of gas in storage, weather and other seasonal conditions,
including hurricanes and tropical storms. Demand for crude oil has also increased
over the last ten years while the increase in supply has not increased proportionately
resulting in a tight market. Market conditions involving over or under supply
of crude oil and natural gas can result in substantial price volatility. Historically,
commodity prices have been volatile and we saw extreme volatility during the last
fiscal year. We expect the volatility to continue in the future. A substantial
or extended decline in oil and gas prices or poor drilling results could have
a material adverse effect on our financial position, results of operations, cash
flows, quantities of oil and gas reserves that may be economically produced and
our ability to access capital markets.
We derive our revenues from the sale of crude oil and natural gas that is produced
from our properties. Revenues are a function of the volume produced and the prevailing
market price at the time of sale. The price of oil and natural gas is the primary
factor affecting our revenues.
Principal Components of Our Cost Structure
• Direct
Operating Expenses. These are day-to-day costs incurred to bring hydrocarbons
out of the ground and to the market together with the daily costs incurred to
maintain our producing properties. Such costs also include work-over repairs to
our oil and gas properties not covered by insurance. To minimize and help control
our costs, we acquired a work-over drilling rig and a swab rig in June of 2007.
During fiscal year ended March 31, 2009 we completed refurbishment of a shallow
well oil drilling rig which will be used to drill our Corsicana Nacatoch and Pecan
Gap wells.
18
Table of Contents
• Production
and Ad Valorem Taxes. These costs are primarily paid based on a percentage
of market prices or at fixed rates established by federal, state or local taxing
authorities.
• Exploration
Expense. The costs include geological and geophysical costs, seismic costs,
delay rentals and the costs of unsuccessful wells or dry holes. While our current
asset mix requires a minimum of geological and geophysical costs and seismic costs,
it is possible this component of our cost structure could sharply increase depending
upon future property acquisitions.
• Plugging
Costs. The Corsicana field is over one hundred years old and has hundreds
of abandoned well bores scattered throughout the properties. In order to properly
execute our enhanced oil recovery projects, we need to plug these abandoned, worn
out well bores. Since the wells are fairly shallow, we are able to cement in the
entire well bore at a cost of less than $1,500 per well.
• General
and Administrative Expenses. Overhead, including payroll and benefits for
our corporate staff, costs of maintaining our headquarters, costs of finding our
working interest partners, costs of managing our production and development operations,
audit and other professional fees and legal compliance are included in general
and administrative expense. General and administrative expense includes stock-based
compensation expense (non-cash) associated with the adoption of FASB ASC 718,
amortization of restricted stock grants as part of employee compensation.
• Interest.
We increased our levels of debt during fiscal year 2010, and in the future, we
may finance a larger portion of our working capital requirements and acquisitions
with borrowings under a credit facility or with longer-term public traded debt
securities. As a result, interest expense could become a much more prevalent component
of our cost structure.
• Depreciation,
Depletion and Amortization. As a successful efforts company, we capitalize
all costs associated with our acquisition and all successful development and exploration
efforts, and apportion these costs to each unit of production through depreciation,
depletion and amortization expense. This also includes the systematic, monthly
depreciation of our oilfield equipment assets.
• Changes
in Estimates. Changes in estimates of proved reserves significantly impact
the depletion expense we record each year. When proved reserves increase, our
depletion rate decreases, resulting in a lower depletion expense and higher net
income. Conversely, as proved reserves decrease, our depletion rate increases,
resulting in a higher depletion expense and lower net income. Changes in estimates
of proved reserves are frequently the result of changes in commodity prices, changes
in operating costs, and reservoir performance history. While depletion is a non-cash
expense, volatility in commodity prices and the resulting volatility in depletion
can have a material impact on our profitability and on certain leverage ratios.
• Income
Taxes. We are subject to federal income taxes but are currently not in a tax
paying position for regular federal income taxes, primarily due to the current
deductibility of intangible drilling costs ("IDC"). Currently, we are not subject
to state income taxes. Virtually all of our Federal taxes are deferred; however,
at some point, we will utilize all of our net operating loss carry-forwards and
we will recognize current income tax expense and continue to recognize current
tax expense as long as we are generating taxable income.
Results and Analysis of Financial Condition, Cash Flows and Liquidity
Barnett Shale Project: During the fiscal year ended March 31, 2010, we completed
the two wells that were awaiting completion at the beginning of the fiscal year.
ReoStar retained a 60% working interest in these wells at a total net investment
of $955,000.
Corsicana Project: We completed injection of surfactant polymer in phase
I of the polymer project and conducted an evaluation as to the effectiveness of
the flood. We concluded that the flood was a scientific success and that further
flooding was warranted. However, during the course of the evaluation, we were
introduced to a different chemical flood technology that we believe will provide
similar sweep efficiencies at a lower operating cost. We have begun negotiations
to implement the technology in the wells that were originally drilled for Phase
II of the polymer flood. We expect to initiate a pilot flood in the second quarter
of the 2011 fiscal year.
19
Table of Contents
We drilled one unsuccessful Pecan Gap exploratory
well in Corsicana. We sold 75% working interests in the well to industry partners
under a turn-key contract. Our dry hole costs associated with these wells was
minimal based on the terms of the associated drilling contracts. We drilled two
successful Pecan Gap wells in the Corsicana area at a total net investment of
$72,612. We retained a 25% working interest in these wells.
The average sales price per barrel of oil during the fiscal year was $67.36 compared
with $89.44 for the fiscal year ended March 31, 2009. The average price realized
per thousand cubic feet (MCF) of gas produced during the fiscal year was $3.48
compared with $5.27 compared with for the fiscal year ended March 31, 2009
Oil and gas production for the year decreased 27% to a total of 91,304 BOE compared
with 124,968 BOE for the fiscal year ended March 31, 2009. Oil and gas revenue
for the year decreased 54% to a total of $3.0 million compared to $6.5 million
for the fiscal year ended March 31, 2009. We had a net loss of $3.1 million compared
to a net loss of $2.0 million for the prior fiscal year.
During fiscal year ended March 31, 2010, our cash used in operations was $455,000
and we used $700,000 in investing activities. Financing activities provided net
cash of $1.0 million.
On March 31, 2010, we had $277,000 in cash and total assets of $21.3 million.
Debt consisted of payables to non-related parties of $10.8 million, which were
all classified as current due to the technical defaults under the senior secured
credit facility. See Note 5 in the footnotes for more information. We also had
accounts and notes payables to related parties of $3.6 million.
Cash is required to fund capital expenditures necessary to offset inherent declines
in production and reserves.. Future success in growing reserves and production
will be highly dependent on capital resources available and the success of finding
or acquiring additional reserves.
In their report dated June 29, 2010, the Company's auditors indicated there was
substantial doubt about the Company's ability to continue as a going concern without
adequate fund-raising. Accordingly, unless we raise additional working capital,
project financing and/or revenues grow to support our business plan, we may be
unable to remain in business.
We are in the process of securing additional capital financing. The additional
financing may be in the form of additional equity, which would be dilutive to
current shareholders. The financing may be in the form of a convertible debt instrument
and the conversion feature would be dilutive to current shareholders. The additional
financing could be a hybrid of the two. The proceeds of the financing will be
used to close the acquisition of the South Texas leasehold, stage 1 of the South
Texas drilling program, funding the fiscal year 2010 capital expenditure program
in the Barnett Shale properties, refinancing the related party debt, and working
capital.
Cautionary Statement: There can be no assurance that we will be successful
in raising capital, whether in the form of equity, convertible debt, or a combination
of the two. Even if we are successful in raising capital through the sources specified,
there can be no assurances that any such financing would be available in a timely
manner or on terms acceptable to our management and current shareholders. Additional
equity financing will be dilutive to our then existing shareholders, and any debt
financing could involve restrictive covenants with respect to future capital raising
activities and other financial and operational matters.
Long-term cash flows are subject to a number of variables including the level
of production and prices as well as various economic conditions that have historically
affected the oil and gas business. A material drop in oil and gas prices or a
reduction in production and reserves would reduce our ability to fund capital
expenditures, meet financial obligations and/or remain profitable. We operate
in an environment with numerous financial and operating risks, including, but
not limited to, the inherent risks of the search for, development and production
of oil and gas, the ability to buy properties and sell production at prices which
provide an attractive return and the highly competitive nature of the industry.
Our ability to expand our reserve base is, in part, dependent on obtaining sufficient
capital through internal cash flow, bank borrowings or the issuance of debt or
equity securities. There can be no assurance that internal cash flow and other
capital sources will provide sufficient funds to maintain capital expenditures
that we believe are necessary to efficiently develop our properties and offset
inherent declines in production and proved reserves.
20
Table of Contents
Cash Flow
Our principal sources of cash are net cash generated by oil and gas operations,
the sale of a portion of the working interest in our drilling projects, and the
issuance of equity or debt securities. Our operating cash flow is highly dependent
on oil and gas prices.
Based on current projections and oil and gas futures prices, the 2011 capital
program is expected to be funded with the proceeds of the senior secured credit
facility, internal cash flow, and debt or equity financing from investors.
Capital Requirements
Our primary needs for cash are for exploration and development of our Barnett
Shale properties, establishing the enhanced oil recovery project the Pecan Gap
drilling program in our Corsicana properties, and the acquisition of additional
oil and gas properties, both in unconventional gas plays and re-development of
mature fields. During the three months ended March 31, 2007, $4.5 million of capital
was expended on Barnett Shale drilling projects, during the fiscal year ended
March 31, 2008, $18.2 million of capital was expended on Barnett Shale drilling
projects, and during the fiscal year ended March 31, 2009, $12 million of capital
was expended on Barnett Shale drilling. For fiscal year 2008, $12.2 million of
the capital program was funded via the sale of working interests on a turn-key
basis and the balance of the capital program was funded by cash flow from operations
and the proceeds of the private placement. For fiscal year 2009, $6.6 million
of the capital program was funded via the sale of working interests on a turn-key
basis and the balance of the capital program was funded by cash flow from operations
and the proceeds of the senior secured credit facility. For fiscal year 2010,
the $2.0 million capital expended was funded by proceeds from the senior secured
credit facility and working capital.
Our capital expenditure budget for fiscal year 2011 is $1.5 million. Of this,
$1 million is budgeted for Barnett Shale and $0.5 million is budgeted for the
Corsicana micellar flood pilot. Our capital expenditure budget will be partially
funded from cash flow from the properties. The majority of the capital expenditure
budget will be funded from a planned equity financing.
Future Commitments
In addition to our capital expenditure program, we are committed to making cash
payments in the future on two types of contracts: note agreements and operating
leases. As of March 31, 2010, we do not have any capital leases nor have we entered
into any material long-term contracts for equipment, nor do we have any off-balance
sheet debt or other such unrecorded obligations.
The table below provides estimates of the timing of future payments that we are
obligated to make based on agreements in place at March 31, 2010. In addition
to the contractual obligations listed on the table below, our balance sheet at
March 31, 2010 reflects accrued interest payable on our debt of $88,500 which
is payable throughout the rest of 2010.
| |
|
Fiscal year ended March
31
|
|
|
|
|
| In thousands |
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
Thereafter
|
|
| Office
Lease |
$ |
149,270
|
|
$ |
-
|
|
$ |
-
|
|
$ |
-
|
|
| Senior
Credit Facility |
|
10,800,000
|
|
|
-
|
|
|
-
|
|
|
-
|
|
| Related Party Notes |
|
-
|
|
|
-
|
|
|
3,518,924
|
|
|
-
|
|
Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements to enhance liquidity
and capital resource position, or for any other purpose.
21
Table of Contents
Inflation and Changes in Prices
Our revenues, the value of our assets and our ability to obtain bank loans or
additional capital on attractive terms have been and will continue to be affected
by changes in oil and gas prices and the costs to produce our reserves. Oil and
gas prices are subject to significant fluctuations that are beyond our ability
to control or predict. Although certain of our costs and expenses are affected
by general inflation, inflation does not normally have a significant effect on
our business. In a trend that began in 2004 and accelerated during 2008 and 2009,
commodity prices for oil and gas increased significantly. The higher prices led
to increased activity in the industry and, consequently, sharply rising costs.
These costs trends have put pressure not only on our operating costs but also
on our capital costs.
Management's Discussion of Critical Accounting Estimates
Our discussion and analysis of our financial condition and results of operations
are based upon consolidated financial statements, which have been prepared in
accordance with accounting principles generally accepted in the United States.
The preparation of our financial statements requires us to make estimates and
assumptions that affect the reported amounts of assets and liabilities, the disclosure
of contingent assets and liabilities at year-end and the reported amounts of revenues
and expenses during the year. We base our estimates on historical experience and
various other assumptions that we believe are reasonable; however, actual results
may differ.
Certain accounting estimates are considered to be critical if (a) the nature of
the estimates and assumptions is material due to the level of subjectivity and
judgment necessary to account for highly uncertain matters or the susceptibility
of such matters to changes; and (b) the impact of the estimates and assumptions
on financial condition or operating performance is material.
Oil and Gas Properties
To ensure the reliability of our reserve estimates, we engage independent petroleum
consultants to prepare an estimate of proved reserves. Proved the SEC defines
reserves as those volumes of crude oil, condensate, natural gas liquids and natural
gas that geological and engineering data demonstrate with reasonable certainty
are recoverable from known reservoirs under existing economic and operating conditions.
Proved developed reserves are volumes expected to be recovered through existing
wells with existing equipment and operating methods. Although our engineers are
knowledgeable of and follow the guidelines for reserves established by the SEC,
the estimation of reserves requires engineers to make a significant number of
assumptions based on professional judgment. Reserve estimates are updated at least
annually and consider recent production levels and other technical information.
Estimated reserves are often subject to future revisions, which could be substantial,
based on the availability of additional information, including: reservoir performance,
new geological and geophysical data, additional drilling, technological advancements,
price and cost changes and other economic factors. Changes in oil and gas prices
can lead to a decision to start-up or shut-in production, which can lead to revisions
to reserve quantities. Reserve revisions in turn cause adjustments in the depletion
rates utilized by us. We cannot predict what reserve revisions may be required
in future periods.
We monitor our long-lived assets recorded in property, plant
and equipment in our consolidated balance sheet to ensure they are fairly presented.
We must evaluate our properties for potential impairment when circumstances indicate
that the carrying value of an asset could exceed its fair value. A significant
amount of judgment is involved in performing these evaluations since the results
are based on estimated future events. Such events include a projection of future
oil and natural gas sales prices, an estimate of the ultimate amount of recoverable
oil and gas reserves that will be produced from a field, the timing of future
production, future production costs, future abandonment costs, and future inflation.
The need to test a property for impairment can be based on several factors, including
a significant reduction in sales prices for oil and/or gas, unfavorable adjustment
to reserves, physical damage to production equipment and facilities, a change
in costs, or other changes to contracts, environmental regulations or tax laws.
All of these factors must be considered when testing a property's carrying value
for impairment. We cannot predict whether impairment charges may be required in
the future. We are required to develop estimates of fair value to allocate purchase
prices paid to acquire businesses to the assets acquired and liabilities assumed
under the purchase method of accounting. The purchase price paid to acquire a
business is allocated to its assets and liabilities based on the estimated fair
values of the assets acquired and liabilities assumed as of the date of acquisition.
We use all available information to make these fair value determinations.
22
Table of Contents
Deferred Taxes
We are subject to income and other taxes in all areas in which we operate. When
recording income tax expense, certain estimates are required because income tax
returns are generally filed many months after the close of a calendar year, tax
returns are subject to audit, which can take, years to complete and future events
often impact the timing of when income tax expenses and benefits are recognized.
We have deferred tax assets relating to tax operating loss carry forwards and
other deductible differences. We routinely evaluate deferred tax assets to determine
the likelihood of realization. A valuation allowance is recognized on deferred
tax assets when we believe that certain of these assets are not likely to be realized.
In determining deferred tax liabilities, accounting rules require OCI to be considered,
even though such income or loss has not yet been earned.
At year-end 2010, deferred tax liabilities exceeded deferred tax assets by $639,000.
We may be challenged by taxing authorities over the amount and/or timing of recognition
of revenues and deductions in our various income tax returns. Although we believe
that we have adequately provided for all taxes, gains or losses could occur in
the future due to changes in estimates or resolution of outstanding tax matters.
Contingent Liabilities
A provision for legal, environmental and other contingent matters is charged to
expense when the loss is probable and the cost or range of costs can be reasonably
estimated. Judgment is often required to determine when expenses should be recorded
for legal, environmental and contingent matters. In addition, we must often estimate
the amount of such losses. In many cases, our judgment is based on the input of
our legal advisors and on the interpretation of laws and regulations, which can
be interpreted differently by regulators and/or the courts. We monitor known and
potential legal, environmental and other contingencies and make our best estimate
of when to record losses for these matters based on available information. Although
we continue to monitor all contingencies closely, particularly our outstanding
litigation, we currently have no material accruals for contingent liabilities.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not applicable.
23
Table of Contents
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
F-1
Table of Contents
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
ReoStar Energy Corporation
Fort Worth, Texas 76107
We have audited the accompanying consolidated balance sheets of ReoStar Energy
Corporation as of March 31, 2010 and 2009, and the related consolidated statements
of operations, stockholders' equity, and cash flows for the years then ended.
ReoStar Energy Corporation's management is responsible for these consolidated
financial statements. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. The company is not required to have,
nor were we engaged to perform, an audit of its internal control over financial
reporting. Our audits included consideration of internal control over financial
reporting as a basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion on the effectiveness
of the company's internal control over financial reporting. Accordingly, we express
no such opinion. An audit also includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits provide
a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of ReoStar Energy Corporation
as of March 31, 2010 and 2009, and the results of its operations and its cash
flows for the years then ended in conformity with accounting principles generally
accepted in the United States of America.
The accompanying financial statements have been prepared assuming that the Company
will continue as a going concern. As discussed in Note 2 to the financial statements,
the Company has a working capital deficit of $9,195,946 due to default on loan
covenants and borrowing base requirements of their lender. These conditions raise
substantial doubt about the Company's ability to continue as a going concern.
Management's plans regarding this matter are described in Note 2. The financial
statements do not include any adjustments that might result from the outcome of
this uncertainty.
/s/ Killman, Murrell & Company, P.C.
Killman, Murrell & Company,
P.C.
Odessa, Texas
June 29, 2010
F-2
Table of Contents
ReoStar
Energy Corporation
Consolidated Balance Sheets
| |
March
31, 2010
|
|
March 31, 2009
|
|
|
ASSETS |
|
|
|
|
|
|
|
| Current
Assets: |
|
|
|
|
|
|
|
| Cash |
$ |
277,307
|
|
|
$ |
426,430
|
|
| Accounts
Receivable: |
|
|
|
|
|
|
|
| Oil
and Gas - Related Party |
|
639,738
|
|
|
|
337,879
|
|
| Related
Party |
|
561,169
|
|
|
|
1,107,854
|
|
| Other
|
|
-
|
|
|
|
15,760
|
|
| Inventory
|
|
130,886
|
|
|
|
7,514
|
|
| Other
Current Assets |
|
248,759
|
|
|
|
6,317
|
|
| Total
Current Assets |
|
1,857,859
|
|
|
|
1,901,754
|
|
|
|
|
|
|
|
|
|
| Notes Receivable
|
|
213,619
|
|
|
|
553,536
|
|
|
|
|
|
|
|
|
|
| Oil and
Gas Properties - successful efforts method |
|
26,847,329
|
|
|
|
25,254,777
|
|
| Less
Accumulated Depletion and Depreciation |
|
(9,034,348
|
) |
|
|
(6,206,558
|
) |
| Oil
and Gas Properties (net) |
|
17,812,981
|
|
|
|
19,048,219
|
|
|
|
|
|
|
|
|
|
| Other Depreciable
Assets: |
|
2,028,487
|
|
|
|
2,171,654
|
|
| Less
Accumulated Depreciation |
|
(427,013
|
) |
|
|
(315,093
|
) |
| Other
Depreciable Assets (net) |
|
1,601,474
|
|
|
|
1,856,561
|
|
|
|
|
|
|
|
|
|
| Leasehold
Held for Sale |
|
-
|
|
|
|
150,000
|
|
| Total
Assets |
$ |
21,485,933
|
|
|
$ |
23,510,070
|
|
|
|
|
|
|
|
|
|
| LIABILITIES
|
|
|
|
|
|
|
|
| Current
Liabilities: |
|
|
|
|
|
|
|
| Accounts
Payable |
$ |
278,233
|
|
|
$ |
22,033
|
|
| Revenue
Payable |
|
20,912
|
|
|
|
-
|
|
| Payable
to Related Parties |
|
148,550
|
|
|
|
148,550
|
|
| Other
Current Liabilities |
|
93,923
|
|
|
|
-
|
|
| Accrued
Expenses |
|
140,390
|
|
|
|
106,141
|
|
| Accrued
Expenses - Related Parties |
|
88,458
|
|
|
|
130,870
|
|
| Current
Portion of Long-Term Debt |
|
10,283,339
|
|
|
|
-
|
|
| Total
Current Liabilities |
|
11,053,805
|
|
|
|
407,594
|
|
|
|
|
|
|
|
|
|
| Notes
Payable |
|
-
|
|
|
|
8,955,202
|
|
| Notes
Payable - Related Parties |
|
3,518,924
|
|
|
|
3,518,924
|
|
| Total
Long-Term Debt |
|
3,518,924
|
|
|
|
12,474,126
|
|
|
|
|
|
|
|
|
|
| Asset
Retirment Obligation |
|
324,773
|
|
|
|
344,079
|
|
| Deferred
Tax Liability |
|
639,034
|
|
|
|
1,702,782
|
|
| Total
Liabilities |
|
15,536,536
|
|
|
|
14,928,581
|
|
|
|
|
|
|
|
|
|
| Commitments
& Contingencies: |
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
| Stockholders'
Equity |
|
|
|
|
|
|
|
Common
Stock, $.001 par,200,000,000 shares authorized and
80,743,912
and 80,353,912 shares outstanding on
March
31, 2010 and 2009, respectively |
|
80,743
|
|
|
|
80,353
|
|
| |
|
|
|
|
|
|
|
| Additional
Paid-In-Capital |
|
11,460,893
|
|
|
|
10,959,965
|
|
| Treasury
Stock, at cost |
|
(12,240
|
) |
|
|
-
|
|
| Retained
Deficit |
|
(5,579,999
|
) |
|
|
(2,458,829
|
) |
| Total
Stockholders' Equity |
|
5,949,397
|
|
|
|
8,581,489
|
|
| Total
Liabilities & Stockholders' Equity |
$ |
21,485,933
|
|
|
$ |
23,510,070
|
|
| |
|
|
|
|
|
|
|
See Accompanying
Notes to Consolidated Financial Statements
F-3
Table of Contents
ReoStar
Energy Corporation
Consolidated Statements of Operations
| |
Years
Ended
|
|
| |
Mar.
31, 2010
|
|
Mar.
31, 2009
|
|
|
Revenues |
|
|
|
|
|
|
|
| Oil
and Gas Sales |
$ |
3,019,510
|
|
|
$ |
6,558,069
|
|
| Sale
of Leases |
|
170,174
|
|
|
|
18,005
|
|
| Other
Income |
|
344,038
|
|
|
|
458,365
|
|
|
|
|
3,533,722
|
|
|
|
7,034,439
|
|
|
|
|
|
|
|
|
|
| Costs
and Expenses |
|
|
|
|
|
|
|
| Oil
and Gas Lease Operating Expenses |
|
1,840,151
|
|
|
|
2,598,208
|
|
| Workover
Expenses |
|
90,736
|
|
|
|
114,683
|
|
| Severance
and Ad Valorem Taxes |
|
233,367
|
|
|
|
427,307
|
|
| Delay
Rentals |
|
5,000
|
|
|
|
2,975
|
|
| Plugging
Costs and Expired Leases |
|
43,594
|
|
|
|
433,976
|
|
| Depletion
and Depreciation |
|
3,589,316
|
|
|
|
3,487,440
|
|
| ARO
Accretion |
|
40,567
|
|
|
|
-
|
|
| General
and Administrative: |
|
|
|
|
|
|
|
| Salaries
and Benefits |
|
840,782
|
|
|
|
874,418
|
|
| Legal
and Professional |
|
732,047
|
|
|
|
720,771
|
|
| Other
General and Administrative |
|
495,967
|
|
|
|
701,687
|
|
Interest,
net of capitalized interest of $555,575 and
$537,024 for the years
ended March 31, 2010 and
March 31, 2009, respectively
|
|
-
|
|
|
|
3,780
|
|
|
|
|
7,911,527
|
|
|
|
9,365,245
|
|
|
|
|
|
|
|
|
|
| Other Income
(Expense) |
|
|
|
|
|
|
|
| Interest
Income |
|
18,445
|
|
|
|
79,876
|
|
| Hedging
Gains (Losses) |
|
174,442
|
|
|
|
(6,745
|
) |
| Loss
on Equity Method Investments |
|
-
|
|
|
|
(206,561
|
) |
|
|
|
|
|
|
|
|
| Loss
from operations before income taxes |
|
(4,184,918
|
) |
|
|
(2,464,236
|
) |
|
|
|
|
|
|
|
|
| Income
Tax Benefit |
|
1,063,748
|
|
|
|
460,402
|
|
|
|
|
|
|
|
|
|
| Net
Loss |
$ |
(3,121,170
|
) |
|
$ |
(2,003,834
|
) |
|
|
|
|
|
|
|
|
| Basic
and Diluted Loss per Common Share: |
|
|
|
|
|
|
|
| Net
Loss per Common Share |
$ |
(0.04
|
) |
|
$ |
(0.02
|
) |
|
|
|
|
|
|
|
|
| Weighted
Average Common Shares Outstanding |
|
80,593,912
|
|
|
|
80,300,804
|
|
| |
|
|
|
|
|
|
|
See Accompanying
Notes to Consolidated Financial Statements
F-4
Table of Contents
ReoStar
Energy Corporation
Consolidated Statements of Stockholders' Equity
Years Ended March 31, 2009 and 2010
| |
Common
Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Number
of
Shares
|
|
|
|
Amount
|
|
|
|
Paid-In
Capital
|
|
|
|
Treasury
Stock
|
|
|
|
Retained
Deficit
|
|
|
|
Total
|
|
| Balance,
March 31, 2008 |
80,181,310
|
|
|
$ |
80,181
|
|
|
$ |
9,553,346
|
|
|
$ |
-
|
|
|
$ |
(454,995
|
) |
|
$ |
9,178,532
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Issued for
Penalty Shares |
172,602
|
|
|
|
172
|
|
|
|
172,430
|
|
|
|
-
|
|
|
|
-
|
|
|
|
172,602
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants
Issued for short-term
note payable |
-
|
|
|
|
-
|
|
|
|
36,967
|
|
|
|
-
|
|
|
|
-
|
|
|
|
36,967
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants
Issued in connection
with consulting contract |
-
|
|
|
|
-
|
|
|
|
300,000
|
|
|
|
-
|
|
|
|
-
|
|
|
|
300,000
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants
Issued for success
fee related to senior secured
credit facility |
-
|
|
|
|
-
|
|
|
|
375,000
|
|
|
|
|
|
|
|
-
|
|
|
|
375,000
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee
and director
stock options granted |
-
|
|
|
|
-
|
|
|
|
522,222
|
|
|
|
-
|
|
|
|
-
|
|
|
|
522,222
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net
Loss 2009 |
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2,003,834
|
) |
|
|
(2,003,834
|
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance,
March 31, 2009 |
80,353,912
|
|
|
|
80,353
|
|
|
|
10,959,965
|
|
|
|
-
|
|
|
|
(2,458,829
|
) |
|
|
8,581,489
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Issued with
consulting contracts |
390,000
|
|
|
|
390
|
|
|
|
175,110
|
|
|
|
-
|
|
|
|
-
|
|
|
|
175,500
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Treasury
Stock |
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(12,240
|
) |
|
|
-
|
|
|
|
(12,240
|
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee
and director stock
options granted |
-
|
|
|
|
- |
|
|
|
325,818
|
|
|
|
-
|
|
|
|
- |
|
|
|
325,818
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net
Loss 2009 |
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(3,121,170
|
) |
|
|
(3,121,170
|
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance,
March 31, 2009 |
80,743,912
|
|
|
$ |
80,743
|
|
|
$ |
11,460,893
|
|
|
$ |
(12,240
|
) |
|
$ |
(5,579,999
|
) |
|
$ |
5,949,397
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Accompanying
Notes to Consolidated Financial Statements
F-5
Table of Contents
ReoStar
Energy Corporation
Consolidated Statements of Cash Flows
| |
Fiscal
Year Ended
|
|
| Operating
Activities: |
Mar.
31, 2010
|
|
Mar.
31, 2009
|
|
|
Net Loss |
$ |
(3,121,170
|
) |
|
$ |
(2,003,834
|
) |
|
Adjustments to reconcile net loss to net cash from operating activities:
|
|
|
|
|
|
|
|
| Deferred
Income Tax Benefit |
|
(1,063,748
|
) |
|
|
(460,402
|
) |
| Depletion,
Depreciation, & Amortization |
|
3,589,316
|
|
|
|
3,487,440
|
|
| Expired
Leases |
|
43,594
|
|
|
|
433,976
|
|
| Non-employee
stock based compensation |
|
175,500
|
|
|
|
300,000
|
|
| Stock
based compensation |
|
325,818
|
|
|
|
307,240
|
|
| Penalty
shares |
|
-
|
|
|
|
172,602
|
|
| Loss
on Equity Method Investment |
|
-
|
|
|
|
206,561
|
|
| ARO
Accretion |
|
40,567
|
|
|
|
-
|
|
| ARO
on Sold Properties |
|
(87,516
|
) |
|
|
-
|
|
| Treasury
Stock Received for Asset Sale Proceeds |
|
(12,240
|
) |
|
|
-
|
|
| Changes
in Operating Assets and Liabilities |
|
|
|
|
|
|
|
| Changes
in Accrued Liabilities |
|
(8,163
|
) |
|
|
(685,671
|
) |
| Change
in Inventory |
|
(123,372
|
) |
|
|
(2,766
|
) |
| Change
in Related Party Receivables/Payables |
|
(56,143
|
) |
|
|
(1,369,752
|
) |
| Changes
in Other Receivables |
|
15,760
|
|
|
|
(15,760
|
) |
| Changes
in Other Current Assets |
|
-
|
|
|
|
6,745
|
|
| Changes
in Hedging Activity |
|
(148,519
|
) |
|
|
-
|
|
| Change
in Revenue Receivables |
|
(301,859
|
) |
|
|
530,527
|
|
| Change
in Revenue Payable |
|
20,912
|
|
|
|
-
|
|
| Changes
in Accounts Payable |
|
256,200
|
|
|
|
(81,446
|
) |
| Net
Cash provided (used) from operating activities |
|
(455,063
|
) |
|
|
825,460
|
|
|
|
|
|
|
|
|
|
| Investing
Activities: |
|
|
|
|
|
|
|
| Oil
& Gas Drilling, Completing and Leasehold Acquisition Costs |
|
(2,024,820
|
) |
|
|
(8,706,952
|
) |
| Change
in Related Party Payable related to drilling |
|
602,828
|
|
|
|
(1,547,136
|
) |
| Net
Investment in Leasehold Sold |
|
350,690
|
|
|
|
-
|
|
| Investment
in Other Depreciable Assets |
|
(184,633
|
) |
|
|
(534,287
|
) |
| Net
Investment in Other Depreciable Assets Sold |
|
221,957
|
|
|
|
-
|
|
| Investment
in Equity Method Investment |
|
-
|
|
|
|
(64,166
|
) |
| Note
Receivable (Advances) |
|
(213,619
|
) |
|
|
-
|
|
| Note
Receivable Collections |
|
553,537
|
|
|
|
801,692
|
|
| Net
Cash used in continuing activities |
|
(694,060
|
) |
|
|
(10,050,849
|
) |
|
|
|
|
|
|
|
|
| Financing
Activities: |
|
|
|
|
|
|
|
| Notes
Payable Advances Net of Loan Fees |
|
1,000,000
|
|
|
|
10,401,254
|
|
| Notes
Payable Principal Payments |
|
-
|
|
|
|
(1,342,100
|
) |
| Related
Party Note (Payments) |
|
(200,000
|
) |
|
|
-
|
|
| Related
Party Note Advances |
|
200,000
|
|
|
|
-
|
|
| Net
Cash provided by continuing activities |
|
1,000,000
|
|
|
|
9,059,154
|
|
| Net Decrease
in cash |
|
(149,123
|
) |
|
|
(166,235
|
) |
| Cash
- Beginning of the year |
|
426,430
|
|
|
|
592,665
|
|
| Cash -
End of the year |
$ |
277,307
|
|
|
$ |
426,430
|
|
| |
|
|
|
|
|
|
|
See Accompanying
Notes to Consolidated Financial Statements
F-6
Table of Contents
ReoStar
Energy Corporation
Consolidated Statements of Cash Flows
(Continued)
| |
Year
Ended
|
|
| |
Mar.
31, 2010
|
|
|
Mar.
31, 2009
|
|
| Supplemental
Disclosure of Cash Flow Information |
|
|
|
|
|
|
|
| Cash
paid during period for: |
|
|
|
|
|
|
|
| Interest
|
$ |
621,107
|
|
|
$ |
466,792
|
|
| |
|
|
|
|
|
|
|
|
Income Taxes |
$ |
-
|
|
|
$ |
-
|
|
| |
|
|
|
|
|
|
|
| Non
Cash Investing and Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Treasury
Stock Received for Asset Sale |
$ |
(12,240
|
) |
|
$ |
-
|
|
| |
|
|
|
|
|
|
|
| Stock
Based Loan Costs |
$ |
-
|
|
|
$ |
375,000
|
|
|
|
|
|
|
|
|
|
| Stock
Issued for Interest |
$ |
-
|
|
|
$ |
36,967
|
|
|
|
|
|
|
|
|
|
| Stock
Based Compensation |
$ |
325,818
|
|
|
$ |
522,222
|
|
| |
|
|
|
|
|
|
|
| Stock
Based Consulting Fees |
$ |
175,500
|
|
|
$ |
300,000
|
|
| |
|
|
|
|
|
|
|
See Accompanying
Notes to Consolidated Financial Statements
F-7
Table of Contents
REOSTAR ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2010 AND 2009
(1) SUMMARY OF ORGANIZATION AND NATURE OF BUSINESS
REOSTAR ENERGY CORPORATION ("REOSTAR ," "we," "us," or "our") is engaged in the
exploration, development and acquisition of oil and gas properties primarily in
Texas. We seek to increase our reserves and production primarily through drilling,
complementary acquisitions, and the development of enhanced oil recovery prospects.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation
The financial statements and notes are representations of the Company's management
who are responsible for their integrity and objectivity. The Company's accounting
policies conform to accounting principles generally accepted in the United States
of America and have been consistently applied in the preparation of these consolidated
financial statements.
The consolidated financial statements include the accounts of the Company and
its wholly owned subsidiaries, ReoStar Operating, Inc., ReoStar Leasing, Inc.
and ReoStar Gathering, Inc. Intercompany accounts and transactions have been eliminated
in consolidation.
Going Concern
The accompanying financial statements have been prepared in accordance with accounting
principles generally accepted in the United States of America with the assumption
that the Company will be able to realize its assets and discharge its liabilities
in the normal course of business. The Company has a working capital deficit of
$9,195,946. This working capital deficit was precipitated because the Company
could not meet its covenant or borrowing base requirements of their lender due
in part to a reduction in their borrowing base. Therefore the note payable to
Union Bank of California was classified as current. A complete discussion regarding
the transactions leading to the default is more fully discussed in Note 5. The
Company's ability to continue as a going concern is further contemplated upon
its ability to complete certain capital generating activities in the future. Management's
plan in this regard is to secure additional funds through equity financing activities.
These conditions raise substantial doubt about the Company's ability to continue
as a going concern. The financial statements do not include any adjustments to
the amounts and classifications of assets and liabilities that might be necessary
should the Company be unable to continue as a going concern.
Use of Estimates
The preparation of financial statements in accordance with generally accepted
accounting principles ("GAAP") in the United States requires us to make estimates
and assumptions that affect the reported amounts of assets and liabilities, the
disclosure of contingent assets and liabilities at year-end and the reported amounts
of revenues and expenses during the year. Actual results could differ from the
estimates and assumptions used.
Income per Common Share
Basic net income per share is calculated based on the weighted average number
of common shares outstanding. Diluted net income per share assumes issuance of
stock compensation awards and exercise of stock warrants, provided the effect
is not anti-dilutive.
Revenue Recognition
Oil, gas, and natural gas liquids revenues are recognized when the products are
sold and delivery to the purchaser has occurred. Although receivables are concentrated
in the oil and gas industry, we do not view this as unusual credit risk.
F-8
Table of Contents
Cash and Equivalents
Cash and cash equivalents include cash on hand and on deposit and investments
in highly liquid debt instruments with maturities of three months or less.
Allowance for Doubtful Accounts
We regularly review our accounts receivable for quality of accounts receivable.
Other than related party receivables, we accrue a provision for doubtful accounts
equal to 20% of any accounts receivable balance that has aged more than one hundred
twenty (120) days. As of March 31, 2010, we had no accounts receivable balances
over the 120 day threshold, therefore, no allowance for doubtful accounts has
been accrued.
Inventory
Inventory consists of tubing, rods, casing, and storage tanks and is stated at
the lower of cost (first-in, first-out) or market value.
Oil and Gas Properties
Oil and gas investments are accounted for by the successful efforts method of
accounting. Accordingly, the costs incurred to acquire property (proved and unproved),
all development costs, and successful exploratory costs are capitalized, whereas
the costs of unsuccessful exploratory wells are expensed.
Oil and gas properties consisted of the following at March 31, 2010 and 2009:
| |
|
2010
|
|
|
|
2009
|
|
|
| Producing
Leasehold |
$ |
23,999,312
|
|
|
$ |
22,159,295
|
|
|
| Non-Producing
Leasehold |
|
1,063,346
|
|
|
|
1,081,482
|
|
|
| Well
in Process |
|
229,476
|
|
|
|
1,014,380
|
|
|
| Capitalized
Interest |
|
1,555,195
|
|
|
|
999,620
|
|
|
| |
|
26,847,329
|
|
|
|
25,254,777
|
|
|
| |
|
|
|
|
|
|
|
|
| Less
accumulated depletion and amortization |
|
(9,034,348
|
) |
|
|
(6,206,558
|
) |
|
| |
|
|
|
|
|
|
|
|
| |
$ |
17,812,981
|
|
|
$ |
19,048,219
|
|
|
| |
|
|
|
|
|
|
|
|
Depletion of capitalized oil and gas well
costs is provided using the units of production method based on estimated proved
developed oil and gas reserves of the respective oil and gas properties. Cost,
net of estimated salvage value, is recovered on each property via depletion.
The carrying value of capitalized oil and gas property costs is compared annually
to the future net revenues attributed to the related proved developed oil and
gas reserves. If such costs exceed the future net revenues of the related proved
oil and gas reserves, an impairment provision is recorded.
Our policy is to minimize risks associated with drilling exploratory wells by
selling most of the working interest associated with each particular well on a
turn-key basis (up to 80% of the working interest may be sold). The proceeds are
credited to the net book value of the property. In the event the proceeds from
selling the working interest exceed the total cost of acquiring the leasehold
and drilling the well, we record the net proceeds in excess of cost as gain on
the sale of oil and gas properties.
Gain or loss is recognized from the sale of any interest of proven developed properties.
F-9
Table of Contents
Depletion
Our proven oil and gas properties are depleted using a field level cost center.
A field is defined as an area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural feature
and/or stratigraphic condition. There may be two or more reservoirs in a field
which are separated vertically by intervening impervious strata, or laterally
by local geologic barriers, or by both. Reservoirs that are associated by being
in overlapping or adjacent fields may be treated as a single or common operational
field. The geological terms "structural feature" and "stratigraphic condition"
are intended to identify localized geological features as opposed to the broader
terms of basins, trends, provinces, plays, areas of interest, etc. A reservoir
is defined as a porous and permeable underground formation containing a natural
accumulation of producible oil or gas that is confined by impermeable rock or
water barriers and is individual and separate from other reservoirs.
If all the oil and gas properties in a field-wide cost center are proven properties,
then all of the leasehold costs will be aggregated and depleted on a units-of-production
basis over the total proved reserves of the field. If the cost center contains
some properties that are proved and some properties that are unproved, only the
proved property leasehold costs are aggregated and depleted. The total capitalized
costs for wells and equipment is also aggregated and depleted on a units-of-production
basis over the total proved developed reserves of the field.
Other Depreciable Assets
Other depreciable assets consisted of the following at March 31, 2010 and 2009:
| |
|
2010
|
|
|
|
2009
|
|
|
| Buildings |
$ |
409,764
|
|
|
$ |
409,764
|
|
|
| Office
Equipment |
|
130,256
|
|
|
|
130,256
|
|
|
| Property
and Equipment |
|
1,488,467
|
|
|
|
1,631,634
|
|
|
| |
|
2,028,487
|
|
|
|
2,171,654
|
|
|
| |
|
|
|
|
|
|
|
|
| Less
accumulated depreciation |
|
(427,013
|
) |
|
|
(315,093
|
) |
|
| |
|
|
|
|
|
|
|
|
| |
$ |
1,601,474
|
|
|
$ |
1,856,561
|
|
|
| |
|
|
|
|
|
|
|
|
Depreciation
The workover, service, and swab rigs are depreciated using the straight-line method
over the estimated useful life of 10 years. Computer equipment is depreciated
using the straight-line method over the estimated useful life of 3 years. All
other equipment is depreciated using the straight-line method over 5 years.
Interest Expense
ReoStar capitalizes interest expense related to the financing obtained to acquire
and develop oil and gas properties. Capitalized interest associated with oil and
gas properties is recovered via depletion, using the overall depletion rate on
producing properties.
Deferred Taxes
Deferred tax assets and liabilities are recognized for the estimated future tax
consequences attributable to the differences between the financial statement carrying
amounts of assets and liabilities and their tax bases as reported in our filings
with the respective taxing authorities. The realization of deferred tax assets
is assessed periodically based on several interrelated factors. These factors
include our expectation to generate sufficient taxable income including tax credits
and operating loss carryforwards.
Stock-based Compensation
The Company accounts for its stock options and warrants in accordance FASB ASC
718, "Compensation - Stock Compensation". In accordance with FASB ASC 718, the
Company recognizes stock-based compensation expense based on the fair value of
the stock options (or warrants) on the date of grant. The fair value of the stock
options (or warrants) at the date of grant is amortized over the vesting period,
with the offsetting credit to additional paid in capital. If the stock options
are exercised, the proceeds are credited to share capital. Likewise, if the stock
warrants are exercised, the proceeds are credited to share capital.
F-10
Table of Contents
Comprehensive Income
FASB ASC 220, "Comprehensive Income," establishes standards for reporting and
financial statement presentation of comprehensive income, its components and accumulated
balances. Comprehensive income is defined to include all changes in equity except
those resulting from investments by owners and distributions to owners. Among
other disclosures, FASB ASC 220 requires that all items that are required to be
recognized under current accounting standards as components of comprehensive income
be reported in a financial statement that is displayed with the same prominence
as other financial statements. The Company does not have comprehensive income
items requiring disclosure of comprehensive income.
Impairment of Long-Lived Assets
In accordance with FASB ASC 360, "Property, Plant and Equipment", long lived assets,
such as oil and gas properties and equipment are reviewed for impairment whenever
events or changes in circumstances indicate that the carrying amount of an asset
may not be recoverable. Recoverability of assets to be held and used is measured
by a comparison of the carrying amount of an asset to estimated undiscounted future
cash flows expected to be generated by the asset. If the carrying amount of an
asset exceeds its estimated future cash flows, an impairment charge is recognized
by the amount by which the carrying amount of the asset exceeds the fair value
of the asset. Assets to be disposed of would be separately presented in the balance
sheet and reported at the lower of the carrying amount of the fair value less
costs to sell and are no longer depreciated. The assets and liabilities of a disposed
group classified as held for sale would be presented separately in the appropriate
asset and liability sections of the balance sheet.
Contingencies
Certain conditions may exist as of the date the financial statements are issued,
which may result in a loss to the Company, but which will only be resolved when
one or more future events occur or fail to occur. The Company's management and
legal counsel assess such contingent liabilities, and such assessment inherently
involves an exercise of judgment. In assessing loss contingencies related to legal
proceedings that are pending against the Company, or unasserted claims that may
result in such proceedings, the Company's legal counsel evaluates the perceived
merits of any legal proceedings or unasserted claims as well as the perceived
merits of the amount of relief sought or expected to be sought therein.
If the assessment of a contingency indicates that it is probable that a material
loss has been incurred and the amount of the liability can be estimated, the estimated
liability is accrued in the Company's financial statements. If the assessment
indicates that a potentially material loss contingency is not probable but is
reasonably possible, or is probable but cannot be estimated, then the nature of
the contingent liability, together with an estimate of the range of possible loss
if determinable and material, is disclosed.
Loss contingencies considered remote are generally not disclosed unless they involve
guarantees, in which case the guarantees are disclosed.
Financial Instruments
The carrying amount of financial instruments including cash and cash equivalents,
accounts receivable, accounts payable and accrued liabilities approximate fair
value, unless otherwise stated, as of March 31, 2010. The carrying amount of long-term
debt approximates market value due to the use of market interest rates.
Fair value estimates of financial instruments are made at the period end based
on relevant information about financial markets and specific financial instruments.
As these estimates are subjective in nature, involving uncertainties and matters
of significant judgment, they cannot be determined with precision. Changes in
assumptions can significantly affect estimated fair value.
F-11
Table of Contents
Asset Retirement Obligation
Our financial statements reflect the fair value for asset retirement obligation,
which consist of estimated future plugging and abandonment expenditures related
to our oil and gas properties, to the extent they can be reasonably estimated.
The asset retirement obligation is recorded as a liability at its estimated present
value at the asset's inception, with an offsetting increase to producing properties
on the consolidated balance sheet. Periodic accretion of the discount of the estimated
liability is recorded as an expense in the consolidated statements of operations.
Recent Accounting Pronouncements
The FASB established the FASB Accounting Standards Codification ("Codification")
as the source of authoritative U.S. generally accepted accounting principles ("GAAP")
recognized by the FASB to be applied by nongovernmental entities in the preparation
of financial statements issued for interim and annual periods ending after September
15, 2009. The codification has changed the manner in which U.S. GAAP guidance
is referenced, but did not have an impact on our consolidated financial position,
results of operations or cash flows.
In January 2010, the Financial Accounting Standards Board ("FASB") issued Accounting
Standards Update ("ASU") 2010-06, "Fair Value Measurements and Disclosures (Topic
820) - Improving Disclosures about Fair Value Measurements." This ASU requires
some new disclosures and clarifies some existing disclosure requirements about
fair value measurement as set forth in Accounting Standards Codification ("ASC")
820. ASU 2010-06 amends ASC 820 to now require: (1) a reporting entity should
disclose separately the amounts of significant transfers in and out of Level 1
and Level 2 fair value measurements and describe the reasons for the transfers;
and (2) in the reconciliation for fair value measurements using significant unobservable
inputs, a reporting entity should present separately information about purchases,
sales, issuances, and settlements. In addition, ASU 2010-06 clarifies the requirements
of existing disclosures. ASU 2010-06 is effective for interim and annual reporting
periods beginning after December 15, 2009, except for the disclosures about purchases,
sales, issuances, and settlements in the roll forward of activity in Level 3 fair
value measurements. Those disclosures are effective for fiscal years beginning
after December 15, 2010, and for interim periods within those fiscal years. Early
application is permitted. The Company will comply with the additional disclosures
required by this guidance upon its adoption in January 2010.
Also in January 2010, the FASB issued Accounting Standards Update No. 2010-03,
"Extractive Activities-Oil and Gas-Oil and Gas Reserve Estimation and Disclosures."
This ASU amends the "Extractive Industries-Oil and Gas" Topic of the Codification
to align the oil and gas reserve estimation and disclosure requirements in this
Topic with the SEC's Release No. 33-8995, "Modernization of Oil and Gas Reporting
Requirements (Final Rule)," discussed below. The amendments are effective for
annual reporting periods ending on or after December 31, 2009, and the adoption
of these provisions on December 31, 2009 did not have a material impact on our
consolidated financial statements.
On December 31, 2008, the Securities and Exchange Commission (SEC) issued Release
No. 33-8995, "Modernization of Oil and Gas Reporting Requirements (Final Rule),"
which adopted major revisions to its rules governing oil and gas company reporting
requirements. These include provisions that permit the use of new technologies
to determine proved reserves, and allow companies to disclose their probable and
possible reserves to investors. Previously, the rules limited disclosure to only
proved reserves. The new disclosure requirements also require companies to report
the independence and qualifications of the person primarily responsible for the
preparation or audit of reserve estimates, and to file reports when a third party
is relied upon to prepare or audit reserves estimates. The new rules also require
that oil and gas reserves be reported and the full-cost ceiling value calculated
using an average price based upon the prior 12-month period. The new oil and gas
reporting requirements are effective for annual reports on Form 10-K for fiscal
years ending on or after December 31, 2009, with early adoption not permitted.
In August 2009, the FASB issued ASU No. 2009-05, "Fair Value Measurements and
Disclosures (Topic 820) - Measuring Liabilities at Fair Value," related to fair
value measurement of liabilities. This update provides clarification that in circumstances
in which a quoted price in an active market for an identical liability is not
available, a reporting entity is required to measure fair value using one or more
valuation techniques. This guidance is effective for the first reporting period
beginning after issuance.
F-12
Table of Contents
In June 2009, the FASB issued guidance under ASC
105, "Generally Accepted Accounting Principles." This guidance established a new
hierarchy of GAAP sources for non-governmental entities under the FASB Accounting
Standards Codification. The Codification is the sole source for authoritative
U.S. GAAP and supersedes all accounting standards in U.S. GAAP, except for those
issued by the SEC. The guidance was effective for financial statements issued
for reporting periods ending after September 15, 2009. The adoption had no impact
on the Company's financial position, cash flows or results of operations.
In May 2009, the FASB issued guidance under ASC 855 "Subsequent Events," which
sets forth: (1) the period after the balance sheet date during which management
of reporting entity should evaluate events or transactions that may occur for
potential recognition or disclosure in the financial statements, (2) the circumstances
under which an entity should recognize events or transactions occurring after
the balance sheet date in its financial statements and (3) the disclosures that
an entity should make about events or transactions that occurred after the balance
sheet date. The guidance was effective on a prospective basis for interim or annual
financial periods ending after June 15, 2009.
In April 2009, the FASB updated its guidance under ASC 820, "Fair Value Measurements
and Disclosures," related to estimating fair value when the volume and level of
activity for an asset or liability have significantly decreased and identifying
circumstances that indicate a transaction is not orderly. The guidance was effective
for interim and annual reporting periods ending after June 15, 2009 with early
adoption permitted for periods ending after March 15, 2009. The adoption of this
guidance did not have any impact on the Company's results of operations.
Also in April 2009, the FASB updated its guidance under ASC 825, "Financial Instruments,"
which requires disclosures about fair value of financial instruments for interim
reporting periods of publicly traded companies as well as in annual financial
statements. This guidance also requires those disclosures in summarized financial
information at interim reporting periods. The guidance was effective for interim
reporting periods ending after June 15, 2009 with early adoption permitted for
periods ending after March 15, 2009.
The FASB updated its guidance under ASC 805, "Business Combinations," in April
2009, which addresses application issues on initial recognition and measurement,
subsequent measurement and accounting, and disclosure of assets and liabilities
arising from contingencies in a business combination. This guidance was effective
for business combinations occurring on or after the beginning of the first annual
period on or after December 15, 2008.
In June 2008, the FASB updated its guidance under ASC 260, "Earnings Per Share."
This guidance clarified that all unvested share-based payment awards with a right
to receive nonforfeitable dividends are participating securities and provides
guidance on how to allocate earnings to participating securities and compute basic
earnings per share using the two-class method. This guidance was effective for
fiscal years beginning after December 15, 2008. The Company adopted this guidance
on January 1, 2009. The adoption did not have a material impact on the Company's
earnings per share calculations.
In March 2008, the FASB issued guidance under ASC 815, "Derivatives and Hedging,"
which changes the disclosure requirements for derivative instruments and hedging
activities. Entities will be required to provide enhanced disclosures about how
and why an entity uses derivative instruments, how derivative instruments and
related hedged items are accounted for, and how derivative instruments and related
items affect an entity's financial position, operations and cash flows. This guidance
was effective as of the beginning of an entity's fiscal year that begins after
November 15, 2008. The Company adopted this guidance on January 1, 2009.
(3) DEFERRED TAX LIABILITY
Our income tax benefit from operations was $1,063,748 and $460,402 for the years
ended March 31, 2010 and 2009, respectively. A reconciliation between the statutory
federal income tax rate and our effective income tax rate is as follows:
F-13
Table of Contents
| |
|
March 31,
2010
|
|
|
March 31,
2009
|
|
| Federal Statutory Tax
Rate |
|
35%
|
|
|
35%
|
|
| State |
|
0%
|
|
|
0%
|
|
| Consolidated
Effective Tax Rate |
|
35%
|
|
|
35%
|
|
| |
|
|
|
|
|
|
Deferred income taxes reflect the net tax effects
of temporary differences between the carrying amounts of assets and liabilities
for financial reporting purposes and the amounts used for income tax provisions.
Our income tax expense (benefit) is as follows:
| |
|
Years Ended March 31,
|
|
|
| |
|
2010
|
|
|
|
2009
|
|
|
| Current income tax expense
|
|
|
|
|
|
|
|
|
| Federal
|
$ |
-
|
|
|
$ |
-
|
|
|
| State |
|
-
|
|
|
|
-
|
|
|
| Total
current tax expense |
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
| Deferred
income tax (benefit) from continuing operations |
|
|
|
|
|
|
|
|
| Federal
|
|
(1,063,748
|
) |
|
|
(460,402
|
) |
|
| State |
|
-
|
|
|
|
-
|
|
|
| Total income tax benefit |
$ |
(1,063,748
|
) |
|
$ |
(460,402
|
) |
|
| |
|
|
|
|
|
|
|
|
The income tax provision differs from the
amount computed at the statutory rate of 35% as follows:
| |
|
Years Ended March 31,
|
|
|
| |
|
2010
|
|
|
|
2009
|
|
|
| Rate |
|
35%
|
|
|
|
35%
|
|
|
| Tax on Income from Continuing
Operations at Statutory Rate |
$ |
(1,464,721
|
) |
|
$ |
(862,483
|
) |
|
|
|
|
|
|
|
|
|
|
| Increase (decrease) resulting
from: |
|
|
|
|
|
|
|
|
| Permanent differences
|
|
400,973
|
|
|
|
402,081
|
|
|
| Income Tax Provision |
$ |
(1,063,748
|
) |
|
$ |
(460,402
|
) |
|
| |
|
|
|
|
|
|
|
|
F-14
Table of Contents
Significant components of deferred tax assets
and liabilities are as follows:
| |
|
March 31,
2010
|
|
|
|
March 31,
2009
|
|
|
| Deferred Tax
Assets: |
|
|
|
|
|
|
|
|
| Net
Operating Loss Carryforward |
$ |
1,950,405
|
|
|
$ |
751,045
|
|
|
| Other
Deferred Tax Assets |
|
146,544
|
|
|
|
-
|
|
|
| Total
Deferred Tax Assets |
|
2,096,949
|
|
|
|
751,045
|
|
|
|
|
|
|
|
|
|
|
|
| Deferred Tax Liabilities |
|
|
|
|
|
|
|
|
| Oil
and Gas Properties Basis |
|
2,475,875
|
|
|
|
2,086,984
|
|
|
| Other
Deferred Tax Liabilities |
|
260,108
|
|
|
|
366,843
|
|
|
| Total
Deferred Liabilites |
|
2,735,983
|
|
|
|
2,453,827
|
|
|
| Net Deferred Tax Liability |
$ |
639,034
|
|
|
$ |
1,702,782
|
|
|
| |
|
|
|
|
|
|
|
|
At March 31, 2010 and 2009, we had net operating
loss carryforwards for tax purposes of approximately $5.6 million and $2.2 million,
of which, approximately $3.4 million and $2.2 million expire on March 31, 2030
and 2029, respectively.
(4) EARNINGS PER COMMON SHARE
The average stock price for both years was less than the strike price of the outstanding
stock warrants and stock options. Therefore, there were no dilutive common stock
equivalents as of March 31, 2010 and 2009. The following table sets forth the
computation of basic earnings per common share.
| |
|
March 31,
2010
|
|
|
|
March 31,
2009
|
|
|
| Numerator
|
|
|
|
|
|
|
|
|
| Net
Income (Loss) |
$ |
(3,121,170
|
) |
|
$ |
(2,003,834
|
) |
|
| Denominator
|
|
|
|
|
|
|
|
|
| Weighted
Average Shares Outstanding - Basic |
|
80,593,912
|
|
|
|
80,300,804
|
|
|
|
|
|
|
|
|
|
|
|
| Basic - Net Income |
$ |
(0.04
|
) |
|
$ |
(0.02
|
) |
|
(5) INDEBTEDNESS
The following debt was outstanding as of March 31, 2010 and March 31, 2009, respectively:
Lease Notes Payable. The Company had three lease bank obligations related
to the acquisition of certain leasehold in the Fayetteville Shale play. All three
obligations were non-recourse in nature and required repayment of the principal
as the acquired leasehold was drilled or when the underlying leasehold was sold.
The Company fully impaired the underlying acreage during the year ended March
31, 2009 (see Note 9 for more information). Since the obligations are non-recourse
in nature, the Company has written off the related lease bank obligations as of
March 31, 2009.
Senior Secured Credit Facility. As of March 31, 2010 and 2009, respectively,
the Company had outstanding principal of $10,800,000 and $9,800,000 on the note.
The Company incurred costs associated with the note (including legal fees and
investment banking fees) of approximately $1 million. The loan fees are amortized
over the life of the note, and amortization for the years ended March 31, 2010
and 2009 was approximately $325 thousand and $190 thousand, respectively. The
carrying value of the note is reduced by the loan costs net of amortization, leaving
a carrying balance of approximately $10,283,000 and $8,955,000, respectively.
At March 31, 2010 the interest rate was 5.75%.
F-15
Table of Contents
On October 30, 2008, we entered into a $25 million
senior secured credit facility with lenders led by Union Bank, N.A. ("UB"), as
administrative agent and as issuing lender. Pursuant to the terms of the senior
credit facility, the initial borrowing base was set at $14 million and is subject
to re-determination every six months with one optional re-determination allowed
between scheduled re-determinations. During the fiscal year ended March 31, 2010,
the borrowing base was adjusted downward to $7.6 million leaving an over-advance
of $3.2 million. The Company lacks the liquidity to repay the over-advance.
The credit facility is secured by all of the Company's assets and is senior to
all other long-term debt. The outstanding principal is due October 30, 2011. However,
if, pursuant to the terms of the senior credit facility, specific evens of default
occur, the due date of all outstanding principal and accrued interest may be accelerated.
Specific events of default include, but are not limited to: payment defaults;
breaches of representations and warranties, and covenants; insolvency; a "change
of control" in our ownership as described in the senior credit agreement; and
a "material adverse change" as described in the senior credit agreement.
The senior credit facility requires us to comply with certain credit metrics,
such as the maintenance of minimum working capital, certain ratios of debt to
EBITDA (as defined in the senior credit facility), maintenance of a minimum EBITDA
to interest, and places a cap on Capital Expenditures each year. Each metric is
further defined below.
Working capital, defined as consolidated current assets less consolidated current
liabilities is required to be at least $1.5 million as of the last day of each
fiscal quarter. Current assets includes the unused amount available under the
senior credit facility. We were not in compliance with the working capital requirement
as of March 31, 2010.
The leverage ratio is as follows: (a) for each fiscal quarter, the ratio of (i)
Funded Debt (as defined in the senior credit facility) to (ii) consolidated EBITDA
for the four fiscal quarter periods then ended must not be greater than 3.50 to
1.00. For the purposes of calculating the leverage ratio, the definition of "Funded
Debt" does not include Notes Payable to Shareholders that has been subordinated
to the senior credit facility. EBITDA is defined as Consolidated Net Income adjusted
plus, to the extent deducted in determining net income, interest expense, income
taxes, depletion, depreciation, amortization, and other non-cash charges for the
period. We were not in compliance with the leverage ratio as of March 31, 2010.
The interest coverage ratio is the ratio of our consolidated EBITDA for the four
fiscal quarter periods then ended to our consolidated Interest Expense for the
four fiscal quarters then ended must be at least 3.00 to 1.00. We were not in
compliance with the interest coverage ratio as of March 31, 2010.
In February, Union Bank formally notified the Company of non-compliance under
the above covenants and the over-advance resulting from the revision of the borrowing
base. See the Form 8-K filed on February 17, 2010.
The senior credit agreement imposes certain restrictions on us and our subsidiaries,
subject to specific exceptions, including, but not limited to, the following:
(i) incurring additional liens; (ii) incurring additional debt; (iii) merging
or consolidating or selling, transferring, assigning, farming-out, conveying or
otherwise disposing of any property; (iv) making certain payments, including cash
dividends to our stockholders; (v) making any loans, advances or capital contributions
to, or making any investment in, or purchasing or committing to purchase any stock
or other securities or interests in any person or any oil and natural gas properties
or activities related to oil and natural gas properties unless with regard to
new oil and natural gas properties, such properties are mortgaged to UB, as administrative
agent, or with regard to new subsidiaries, such subsidiaries execute a guaranty,
pledge agreement, security agreement and mortgage in favor of UB, as administrative
agent; and (vi) entering into affiliate transactions on terms that are not at
least as favorable to us as comparable arm's length transactions.
F-16
Table of Contents
Notes Payable to Related Parties.
ReoStar has a note payable to ReoStar's President and CEO. The note was renewed
in October 2008 and matures on April 1, 2012. The note bears interest of 8%. The
principal balance of the note on March 31, 2010 and 2009 was $324,330 and $324,330,
respectively. The note is subordinated to the Senior Secured Credit Facility.
ReoStar has a note payable to a limited partnership owned by the Chairman of the
Board. The note was renewed in October 2008 and matures on April 1, 2012. The
note provides for an interest rate of 5.95%. The principal balance at March 31,
2010 and 2009 was $3,194,594 and $3,194,594, respectively. The note is subordinated
to the Senior Secured Credit Facility.
The following table summarizes our note payable repayment obligations.
| |
Fiscal Years Ending March
31,
|
|
|
|
|
|
|
| |
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
Thereafter
|
|
|
Total
|
| Note Payable - Shareholder
|
|
-
|
|
|
-
|
|
|
324,330
|
|
|
-
|
|
|
-
|
|
|
324,330
|
| Note Payable - Shareholder |
|
-
|
|
|
-
|
|
|
3,194,594
|
|
|
-
|
|
|
-
|
|
|
3,194,594
|
| Senior Secured
Credit Facility |
|
10,800,000
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
10,800,000
|
| |
$ |
10,800,000
|
|
$ |
-
|
|
$ |
3,518,924
|
|
$ |
-
|
|
$ |
-
|
|
$ |
14,318,924
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payables to Related Party. ReoStar contracts
with the operators of its oil and gas properties to drill and complete all new
wells. The operators are affiliated entities owned by a ReoStar shareholder who
owns more than 20% of ReoStar stock. The outstanding payable to the operators
as of March 31, 2010 and 2009 was $0 and $148,550, respectively.
Accrued Expenses. Accrued expenses consist of accrued interest expense
totaling $0 and $23,030, royalty payable totaling $101,395 and $68,406, and severance
and sales taxes payable totaling $38,995 and $14,705 at March 31, 2010 and 2009,
respectively.
Accrued interest payable to related parties aggregated of $88,458 and $130,870
on March 31, 2010 and 2009, respectively.
(6) CAPITAL STOCK
We have authorized capital stock of 200 million shares of common stock. The following
is a schedule of changes in the number of outstanding common shares since March
31, 2008.
| |
Shares Outstanding
|
|
| Shares Outstanding
March 31, 2008 |
80,181,310
|
|
|
| Shares issued as penalty
for late registration of private placement shares |
172,602
|
|
|
| Balance
at March 31, 2009 |
80,353,912
|
|
|
| Shares issued as compensation
to consultants |
390,000
|
|
|
| Balance
at March 31, 2010 |
80,743,912
|
|
|
| |
|
|
|
During the fiscal years ended March 31, 2007 and
2008, the Company issued shares via a private placement offering. The private
placement subscription agreement provided for additional penalty shares to be
issued in the event the stock was not registered with the Securities Exchange
Commission within 90 days of subscription. During the fiscal year ended March
31, 2009, the company issued 172,602 penalty shares because the registration was
not completed within the specified time period for some, but not all, of the private
placement subscriptions. The penalty stock was valued at $1.00 per share based
upon the bid price on the relevant date and an expense of $172,602 was recorded
for the year ended March 31, 2009.
F-17
Table of Contents
The private placement subscription agreement also provided
for the issuance of 1 warrant for each share of stock issued. The warrants had
a strike price of $1.50 per share and expired in two years. In total, the Company
issued 11,462,000 warrants in conjunction with the private placement offering
in 2007. Of these, 6,605,000 warrants were scheduled to expire by March 31, 2009.
The remaining 4,757,000 warrants were scheduled to expire in the quarter ending
June 30, 2009. In April 2009, the Company extended the expiration date for all
of the warrants to June 16, 2009. All of the warrants have since expired.
There were stock option grants issued to members of ReoStar's Board of Directors
of 100,000 shares during the year ended March 31, 2008. The stock options were
valued at $69,856 using the Black-Scholes model with a volatility of 183.59% and
a strike price of $1.11. Of the stock options, one-third vested on March 31, 2008
at an expense of $39,376, one-third vested on March 31, 2009 at an expense of
$21,251, and the balance vested on March 31, 2010 at an expense of $9,229.
At March 31, 2008, there were 350,000 shares of unvested restricted stock granted
to two of the Company's officers outstanding. In July 2008, the Board approved
an employee stock option plan that provides for stock options up to 8,000,000
shares. The Board canceled the restricted stock grants and replaced them with
stock options. Stock options were issued to three of the Company's officers totaling
2,500,000 shares. The options were granted on July 25, 2008 and were valued at
$873,348 using the Black-Scholes model with a volatility of 194.44% and a strike
price of $0.35 per share. Of the stock options, one-third vested on March 31,
2009, one-third vested on March 31, 2010, and the balance will vest on March 31,
2011. During the fiscal year ended March 31, 2010, one of the officers resigned.
In lieu of severance, the officer and the company agreed that the balance of the
unvested options would vest immediately. Amounts expensed were $316,589 and $480,338
for the years ended March 31, 2010 and 2009, respectively.
Salaries and Benefits expense included stock based compensation expense of $325,818
and $307,240 for the years ended March 31, 2010 and 2009, respectively.
During the fiscal year ended March 31, 2009, the Company issued 1,250,000 warrants
to purchase 1 share of stock to our investment banking firm as part of the success
fee in closing the Union Bank of California senior secured credit facility. The
warrants were issued October 31, 2008 when the Company's stock price was $0.30
per share. The warrants have a strike price of $0.50 per share and are scheduled
to expire October 31, 2012. Using the Black-Scholes model, the warrants were valued
at $375,000.
The Company issued 100,000 warrants to purchase 1 share of stock to a private
lender in lieu of interest during the fiscal year ended March 31, 2009. The warrants
were issued on June 11, 2008 and expire on June 30, 2012. The stock was trading
at $0.50 at the time of issue and the strike price is also $0.50 per share. Using
the Black-Scholes model, the warrants were valued at $36,967.
The Company issued 1,000,000 warrants to a consultant during the fiscal year ended
March 31, 2009. The warrants were issued effective January 1, 2009 and are scheduled
to expire December 31, 2019. The strike price of $0.30 per share is equal to the
market price on the date of issue. Using the Black-Scholes model, the warrants
were valued at $300,000.
The Company issued 390,000 shares of stock to various consultants during the fiscal
year ended March 31, 2010. The stock was valued $175,500 - the average price on
the date the stock was issued. An expense of $175,500 was included in Legal and
Professional expenses during the year.
(7) TREASURY STOCK
In February 2010, the Company acquired 102,000 shares of its common stock in conjunction
with the sale of two oil and gas leases at a cost of $12,240. The Company accounts
for treasury stock using the cost method and includes treasury stock as a component
of stockholder's equity.
F-18
Table of Contents
(8) FAIR VALUE ESTIMATES
In September 2006, the FASB issued FASB ASC 820, "Fair Value Measurements and
Disclosures". The objective of FASB ASC 820 is to increase consistency and comparability
in fair value measurements and to expand disclosures about fair value measurements.
FASB ASC 820 defines fair value, establishes a framework for measuring fair value
in generally accepted accounting principles, and expands disclosures about fair
value measurements. FASB ASC 820 applies under other accounting pronouncements
that require or permit fair value measurements and does not require any new fair
value measurements.
The Company measures its derivative instruments in accordance with FASB Codification
Topic 820-10. Topic 820-10 specifies a valuation hierarchy based on whether the
inputs to those valuation techniques are observable or unobservable. Observable
inputs reflect market data obtained from independent sources, while unobservable
inputs reflect the Company's own assumptions. These two types of inputs have created
the following fair value hierarchy:
| |
• |
Level 1 -
Quoted prices for identical instruments in active markets; |
| |
• |
Level 2 -
Quoted prices for similar instruments in active markets, quoted prices for
identical or similar instruments in markets that are not active, and model-derived
valuations in which all significant inputs and significant value drivers
are observable in active markets; and |
| |
• |
Level
3 - Valuations derived from valuation techniques in which one or more significant
inputs or significant value drivers are unobservable. |
|
Type of Contract
|
|
Balance Sheet Location
|
|
|
Estimated
Fair Value
|
|
|
| Natural
Gas Swaps |
|
Other
Current Assets |
|
$ |
98,856
|
|
|
| Natural Gas Collars |
|
Other Current Assets |
|
|
143,587
|
|
|
| Total
Current Derivative Assets |
|
|
242,443
|
|
|
| |
|
|
|
|
|
|
|
| Crude
Oil Swaps |
|
Other
Current Liabilities |
|
|
-
|
|
|
| Crude Oil Collars |
|
Other Current Liabilities
|
|
|
(93,923
|
) |
|
| Total
Current Derivative Liabilities |
|
|
(93,923
|
) |
|
| |
|
|
|
|
|
|
|
| Crude
Oil Collars |
|
Other
Non-Current Liabilities |
|
|
-
|
|
|
| Natural Gas Collars |
|
Other Non-Current Liabilities
|
|
|
-
|
|
|
| Total
Non-Current Derivative Liabilities |
|
|
-
|
|
|
| Total
Net Derivative Assets |
|
$ |
148,520
|
|
|
| |
|
|
|
|
|
|
|
This hierarchy requires the Company to minimize the
use of unobservable inputs and to use observable market data, if available, when
estimating fair value. The fair value of the options and warrants and derivative
assets and liabilities at March 31, 2010 was as follows:
Fair Value Measurements at Reporting Date
Using
| |
|
Quoted
Prices in
Active
Markets for
Identical
Assets
|
|
|
|
Significant
Other
Observable
Inputs
|
|
|
|
Significant
Unobservable
Inputs
|
|
|
|
|
|
| |
|
(Level 1)
|
|
|
|
(Level 2)
|
|
|
|
(Level 3)
|
|
|
|
Total
|
|
| Options |
$ |
-
|
|
|
$ |
325,818
|
|
|
$ |
-
|
|
|
$ |
325,818
|
|
| Derivative Assets and Liabilities,
net |
$ |
148,520
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
148,520
|
|
F-19
Table of Contents
The fair value of the options and warrants and long-lived
assets held for sale at March 31, 2009 was as follows:
Fair Value Measurements at Reporting Date Using
| |
|
Quoted
Prices in
Active
Markets for
Identical
Assets
|
|
|
|
Significant
Other
Observable
Inputs
|
|
|
|
Significant
Unobservable
Inputs
|
|
|
|
|
|
| |
|
(Level 1)
|
|
|
|
(Level 2)
|
|
|
|
(Level 3)
|
|
|
|
Total
|
|
| Options and
Warrants |
$ |
-
|
|
|
$ |
1,234,189
|
|
|
$ |
-
|
|
|
$ |
1,234,189
|
|
| Long-lived Assets Held For Sale
|
$ |
-
|
|
|
$ |
150,000
|
|
|
$ |
-
|
|
|
$ |
150,000
|
|
Options and warrants were valued using the
Black-Scholes model.
Certain east Texas leases were valued using an agreed upon sales price in connection
with the pending sale of the leases.
(9) ASSET RETIRMENT OBLIGATION
The asset retirement obligation ("ARO") represents the estimated present value
of the amount we will incur to plug and abandon our producing properties at the
end of their productive lives, in accordance with applicable state laws.
We recorded the initial ARO during the fiscal year ended March 31, 2009. We calculated
the present value of the ARO by applying an annual inflation factor of 3% to the
current cost to plug and abandon our producing properties in order to estimate
the future cost to plug and abandon the properties. We discounted the future costs
to present values using a discount rate of 12.5% (the credit adjusted risk free
rate). The carrying cost of the property was increased by the present value of
the ARO and a liability was recorded. At March 31, 2010 and 2009, our liability
for ARO was approximately $325,000 and $344,000, respectively, all of which was
classified as non-current. Our asset retirement obligations are recorded as current
or non-current liabilities based on the estimated timing of the related cash flows.
(10) ABANDONED LEASEHOLD
In 2005, The Company's predecessors acquired certain non-producing leasehold in
the Fayetteville Shale. The leases had 5 year terms and will begin to expire during
the fiscal year ending March 31, 2011. During the year ended March 31, 2008, the
Company's management concluded that the acreage no longer fit with the rest of
the Company's portfolio of oil and gas properties and decided to offer the acreage
for sale. The Company received some initial indications of interest in the property,
however, mid-way through the fiscal year, natural gas prices declined substantially.
As of March 31, 2009, we had not received any offers on the property, and based
upon the continuing low natural gas price and relatively short remaining term
of the leases, management concluded that an impairment should be recorded and
that the appropriate fair value of the leases was zero. Therefore, the Fayetteville
acreage was fully impaired.
F-20
Table of Contents
The acreage was acquired with non-recourse financing.
The financing agreements provide for repayment of the money loaned to acquire
the property only as the property was drilled or out of the proceeds of a sale.
Since we no longer plan to drill the property and there appears to be no market
for the leasehold, the full amount of the liabilities related to the acquisition
of the Fayetteville acreage and all accrued interest was offset against the cost.
For the year ended March 31, 2009, a net abandonment loss of $424,000 was recorded
related to the impairment of the Fayetteville Shale leasehold.
(11) COMMITMENTS AND CONTINGENCIES
Office Lease
We signed a six-month extension to the long-term sublease in January 2010. The
lease provides for base rent of $14,927 monthly. The lease is scheduled to expire
in July 2010. The minimum base rent until the lease expires on July 31, 2010 is
$59,708.
Plugging
Some of the Corsicana oil and gas leases have been producing for more than one
hundred years and there are approximately one hundred abandoned wells scattered
throughout the leases. In order for tertiary recovery efforts to be successful,
we will need to cement in the old wells. Since the wells are relatively shallow,
we are able to completely plug each well for less than $1,500. We consider these
plugging costs to be costs of developing the field. Successful efforts accounting
requires that such development costs be capitalized, consequently, the plugging
costs are capitalized as part of the project. Because these costs are related
to the planned tertiary recovery project, rather than a retirement of an asset,
management has not included the cost of plugging these old well bores in the asset
retirement obligation. No contingency has been recorded as management believes
the plugging costs to be immaterial
(12) NOTE RECEIVABLE
ReoStar had a note receivable from our drilling contractor. The note is secured
by the rig that was dedicated to our Barnett Shale acreage. During the year, the
outstanding note principal was paid in full. The outstanding principal balance
on March 31, 2010 and 2009 was $0 and $553,536, respectively.
During fiscal year 2010, the Company sold two oil and gas leases in east Texas.
The purchase and sales agreement provides for monthly production payments equal
to 10% of the gross revenue attributable to the working interests sold commencing
with May 2010 production. The production payments will continue until a total
of $165,000 has been collected by the Company. The Company estimates the present
value of the production payments to be $112,991 using a discount rate of 10%.
A note receivable in that amount was recorded.
During fiscal year 2010, the Company sold the balance of the east Texas assets.
The purchase and sales agreement provides for consideration consisting of $10,000
cash, 102,000 shares of the Company's stock, and a promissory note. The promissory
note provides for monthly production payments equal to 50% of the net proceeds
attributable to production from two oil and gas leases and $50 per hour of billable
rig work completed in each 30 day period. The first payment is due in May 2010
and production payments will continue until a total of $112,500 is collected.
The Company estimated the present value of the payments to be $100,628 using a
discount rate of 10%. A note receivable in that amount was recorded.
(13) MAJOR CUSTOMERS
We market our production on a competitive basis. Gas produced in the Barnett is
sold under a long-term contract scheduled to expire on May 31, 2017. Oil purchasers
may be changed on 30 days notice. The price for oil is generally equal to a posted
price set by major purchasers in the area or is based on NYMEX pricing, adjusted
for quality and transportation. We sell to oil and gas purchasers on the basis
of price, credit quality and service. For the years ended March 31, 2010 and 2009,
three customers, Parnon Gathering, Inc; Copano Field Services, North Texas LLC;
and Plains Marketing L.P. accounted for nearly 100% of total oil and gas sales.
Since our products are commodities and since there are numerous purchasers that
service our markets, we believe that the loss of any one customer would not have
a material adverse effect on our results.
F-21
Table of Contents
(14) CREDIT RISK
We frequently maintain a balance in our bank accounts in excess of the federally
insured limits.
(15) DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT
The Company does not engage in speculative derivative activities or derivative
trading activities, nor does it use derivatives with leverage features. The Company
uses derivative instruments from time to time to manage market risks resulting
from the fluctuations in the prices of crude oil and natural gas. The gains and
losses resulting from changes in the fair value of derivatives are recorded in
operations. See Note 8 for the fair values of the derivatives as of March 31,
2010.
The Company may periodically enter into derivative contracts, including price
swaps and costless collars utilizing put and call options, which require payments
to (or receipts from) counterparties based upon the differential between a fixed
price and a variable price for a fixed quantity of crude oil or natural gas without
delivering the physical product. The notional amount of the financial instruments
is based upon production forecasts from existing wells.
During the fiscal year ended March 31, 2010, the Company entered into a swap contract
for 2,000 barrels of oil per month from August through December 2009. The contract
locked in the price of oil at $70.40 per barrel. The Company entered into a swap
contract for 20,000 MMBTU of natural gas per month from August through December
2009. The contract locked in the price of natural gas at $4.205 per MMBTU. The
Company entered into a swap contract for 20,000 MMBTU of natural gas per month
from January 2010 through June 2010. The contract locks in the price of natural
gas at $5.54 per MMBTU.
During the fiscal year ended March 31, 2010, the Company entered into put and
call contracts which collar 2,000 barrels of oil per month during calendar 2010.
The floor is $65 per barrel and the ceiling is $85 per barrel. The Company also
entered into put and call contracts which collar 20,000 MMBTU of natural gas per
month from July 2010 through December 2010. The floor is $5.50 per MMBTU and the
ceiling is $6.50 per MMBTU.
There were no net premiums paid or received when the Company entered into these
contracts.
The following table reflects open commodity derivative hedging contracts as of
March 31, 2010, the associated volumes, and the corresponding reference price.
| Settlement
Period |
Monthly
Volumes
|
|
|
Fixed Price
|
|
|
Price
Floor
|
|
|
Price
Ceiling
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Natural
Gas Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
| 1/01/10
- 6/30/10 |
20,000
|
|
MMBTU
|
$ |
5.54
|
|
|
N/A
|
|
|
N/A
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Crude
Oil Collars |
|
|
|
|
|
|
|
|
|
|
|
|
| 1/01/10
- 12/31/10 |
2,000
|
|
BBLS
|
|
N/A
|
|
$ |
65.00
|
|
$ |
85.00
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Natural
Gas Collars |
|
|
|
|
|
|
|
|
|
|
|
|
| 7/1/10
- 12/31/10 |
20,000
|
|
MMBTU |
|
N/A
|
|
$ |
5.50
|
|
$ |
6.50
|
|
F-22
Table of Contents
(16) SUBSEQUENT EVENTS
In May 2009, the FASB issued FASB ASC 855, "Subsequent Events". ASC 855 establishes
general standards of accounting for and disclosure of events after the balance
sheet date but before financial statements are issued or are available to be issued.
The adoption in the fourth quarter of 2009 did not have any material impact on
the Company's financial statements. Accordingly, the Company evaluated subsequent
events through June 29, 2010, the date the financial statements were issued.
(17) SUPPLEMENTAL INFO ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION
ACTIVITIES (UNAUDITED).
The following information concerning our natural gas and oil operations has been
provided pursuant to FASB ASC 932, "Extractive Industries - Oil and Gas". All
of our natural gas and oil producing activities are located in Texas.
Capitalized Costs Relating to Oil and Gas Producing Activities
| |
|
Fiscal Year Ended March
31,
|
|
|
| |
|
2010
|
|
|
|
2009
|
|
|
| Unproved
oil and gas properties |
$ |
564,804
|
|
|
$ |
484,198
|
|
|
| Proved oil and gas properties
|
|
24,727,330
|
|
|
|
23,770,959
|
|
|
| Support
Equipment and facilities |
|
-
|
|
|
|
-
|
|
|
| Capitalized Interest |
|
1,555,195
|
|
|
|
999,620
|
|
|
| Total
Capitalized Cost of Oil and Gas Properties |
|
26,847,329
|
|
|
|
25,254,777
|
|
|
| Less accumulated depletion,
depreciation, and amortization |
|
(9,034,348
|
) |
|
|
(6,206,558
|
) |
|
| Net Capitalized
Costs |
$ |
17,812,981
|
|
|
$ |
19,048,219
|
|
|
| |
|
|
|
|
|
|
|
|
Costs incurred in Oil and Gas Producing Activities
| |
|
Fiscal Year Ended March
31,
|
|
|
| |
|
2010
|
|
|
|
2009
|
|
|
| Property Acquisition
Costs |
|
|
|
|
|
|
|
|
| Proved
|
$ |
422,963
|
|
|
$ |
427,676
|
|
|
| Unproved
|
|
91,810
|
|
|
|
15,472
|
|
|
| Exploration Costs |
|
235,003
|
|
|
|
267,212
|
|
|
| Development
Costs |
|
719,470
|
|
|
|
7,393,929
|
|
|
| Asset retirement costs recognized
|
|
27,643
|
|
|
|
344,079
|
|
|
| Total Costs
Incurred |
$ |
1,496,889
|
|
|
$ |
8,448,368
|
|
|
| |
|
|
|
|
|
|
|
|
F-23
Table of Contents
Results of Operations for Producing Activities:
The following reflects results of operations for the fiscal years ended March
31, 2010 and 2009:
| |
|
Fiscal Year Ended March
31,
|
|
|
| |
|
2010
|
|
|
|
2009
|
|
|
| Oil & Gas
Revenue |
$ |
3,019,510
|
|
|
$ |
6,558,069
|
|
|
| Gain on Sale of Oil & Gas Leases
|
|
170,174
|
|
|
|
18,005
|
|
|
| Production
Costs |
|
2,164,254
|
|
|
|
3,140,198
|
|
|
| Exploration Costs |
|
5,000
|
|
|
|
2,975
|
|
|
| Expired Leases
and Plugging Costs |
|
43,594
|
|
|
|
433,969
|
|
|
| Depreciation, Depletion, & Amortization
|
|
2,765,126
|
|
|
|
2,968,429
|
|
|
| |
|
(1,788,290
|
) |
|
|
30,503
|
|
|
| Income Taxes at 35% |
|
625,902
|
|
|
|
(10,676
|
) |
|
Results of
operations for oil and gas producing
activities (excluding corporate overhead and
financing costs) |
$ |
(1,162,389
|
) |
|
$ |
19,827
|
|
|
| |
|
|
|
|
|
|
|
|
Estimated Quantities of Proved Oil and Gas Reserves
(Unaudited)
We engaged Forrest A. Garb & Associates, Inc. to conduct a reserve study and to
estimate our reserves of crude oil, condensate, natural gas liquids and natural
gas. Reserves are adjusted to reflect contractual arrangements and royalty rates
in effect at the end of each year. Many assumptions and judgmental decisions are
required to estimate reserves. Reported quantities are subject to future revisions,
some of which may be substantial, as additional information becomes available
from reservoir performance, new geological and geophysical data, additional drilling,
technological advancements, price changes and other economic factors.
The SEC defines proved reserves as those volumes of crude oil, condensate, natural
gas liquids and natural gas that geological and engineering data demonstrate with
reasonable certainty are recoverable from known reservoirs under existing economic
and operating conditions. Proved developed reserves are those proved reserves
which can be expected to be recovered from existing wells with existing equipment
and operating methods. Proved undeveloped reserves are volumes expected to be
recovered as a result of additional investments for drilling new wells to offset
productive units, recompleting existing wells, and/or installing facilities to
collect and transport production.
Changes in estimates of proved reserves significantly impact the depletion expense
we record each year. When proved reserves increase, our depletion rate decreases,
resulting in a lower depletion expense and higher net income. Conversely, when
proved reserves decrease, our depletion rate increases, resulting in a higher
depletion expense and lower net income. Changes in estimates of proved reserves
are frequently the result of changes in commodity prices, changes in operating
costs, and reservoir performance history.
Production quantities shown are net volumes sold. These may differ from volumes
withdrawn from reservoirs due to inventory changes, and, especially in the case
of natural gas, volumes consumed for fuel and/or shrinkage from extraction of
natural gas liquids.
The reported value of proved reserves is not necessarily indicative of either
fair market value or present value of future net cash flows because prices, costs
and governmental policies do not remain static, appropriate discount rates may
vary, and extensive judgment is required to estimate the timing of production.
Other logical assumptions would likely have resulted in significantly different
amounts.
The March 31, 2010 report utilizes the preceding 12-month average on the first
trading day of the month spot price posted for West Texas Intermediate crude oil
and Henry Hub natural gas in accordance with updated SEC guidelines. The March
31, 2010 oil price was $70.03 per barrel ("Bbl") and has been adjusted by lease
for gravity, transportation fees, and regional price differentials. The March
31, 2010 natural gas price per thousand cubic feet (MCF) was based on a benchmark
price of $3.99 per
F-24
Table of Contents
million British
thermal units ("MMBtu") and has been adjusted by lease for Btu content, transportation
fees and regional price differentials. The March 31, 2009 report utilizes the
base crude oil and natural gas prices in effect at March 31, 2009 in accordance
with the SEC guidelines then in effect. For the reserves at March 31, 2009, the
base crude oil and natural gas prices were $49.65 per Bb and $3.58 per MMbtu,
respectively. The base prices for both crude oil and natural gas are adjusted
by the normal price differential between the prices we historically have received
for our products and the spot price quoted on the relevant market exchange.
Our proved reserves (000's omitted) are summarized in the table below.
| |
|
Oil
(MBBL)
|
|
|
|
Gas
(MMCF)
|
|
|
| |
|
|
|
|
|
|
|
|
| Reserves at
March 31, 2008 |
|
1,411
|
|
|
|
18,809
|
|
|
| Revisions of previous estimates
|
|
(739
|
) |
|
|
(11,269
|
) |
|
| Improved recovery
|
|
-
|
|
|
|
-
|
|
|
| Purchases of minerals in place
|
|
1
|
|
|
|
25
|
|
|
| Extensions
and discoveries |
|
397
|
|
|
|
4,725
|
|
|
| Production |
|
(45
|
) |
|
|
(479
|
) |
|
| Sales of minerals
in place |
|
-
|
|
|
|
-
|
|
|
| Reserves at March 31, 2009 |
|
1,025
|
|
|
|
11,811
|
|
|
| Revisions of
previous estimates |
|
(650
|
) |
|
|
(3,735
|
) |
|
| Improved recovery |
|
-
|
|
|
|
-
|
|
|
| Purchases of
minerals in place |
|
-
|
|
|
|
-
|
|
|
| Extensions and discoveries |
|
442
|
|
|
|
11,101
|
|
|
| Production
|
|
(24
|
) |
|
|
(404
|
) |
|
| Sales of minerals in place |
|
(12
|
) |
|
|
-
|
|
|
| Reserves at
March 31, 2010 |
|
781
|
|
|
|
18,773
|
|
|
| |
|
|
|
|
|
|
|
|
Revisions of previous estimates: The
table above identifies downward revisions in both oil and gas reserves for the
year ended March 31, 2009. The downward revision is primarily a function of price.
The base oil price at March 31, 2009 was more than 51% lower than the base price
included in the previous reserve report. The table above identifies downward revisions
in both oil and gas reserves for the year ended March 31, 2010. The downward revision
is primarily related to corrections to the projected decline curves of our Barnett
Shale properties.
Purchases of minerals in place: The Company has continued its working interest
repurchase program in its Barnett Shale properties. Throughout both years, the
company repurchased small working interests in several wells.
Extensions and discoveries: The Company successfully drilled 8 of the Barnett
shale locations that were classified as proven undeveloped properties for the
years ending March 31, 2009. The successful drilling of the wells resulted in
additional proven undeveloped reserves in offset locations. During the year ended
March 31, 2010, multiple successful wells were drilled in leasehold acreage offsetting
our Barnett Shale acreage. Based upon these successful wells and our drilling
history, an additional 33 proven undeveloped drilling locations were identified.
All wells classified as proven undeveloped are expected to be drilled within 5
years of our fiscal year end.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves (Unaudited)
The following summarizes the policies we used in the preparation of the accompanying
natural gas and oil reserve disclosures, standardized measures of discounted future
net cash flows from proved natural gas and oil reserves and the reconciliations
of standardized measures from year to year. The information disclosed, as prescribed
by FASB ASC 932, is an attempt to present the information in a manner comparable
with industry peers.
F-25
Table of Contents
The information is based on estimates of proved reserves
attributable to our interest in natural gas and oil properties as of April 1,
2010. These estimates were prepared by an independent petroleum engineering firm,
Forest Garb and Associates, Inc. Proved reserves are estimated quantities of natural
gas and crude oil which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
The standardized measure of discounted future net cash flows from production of
proved reserves was developed as follows:
| |
• |
Estimates are made
of quantities of proved reserves and future amounts expected to be produced
based on current year-end economic conditions. |
| |
• |
Estimated future
cash inflows are calculated by applying the benchmark prices of natural
gas and oil relating to our proved reserves to the quantities of those reserves
produced in each future year. For the March 31, 2010 reserve report, SEC
guidelines required the benchmark price for both oil and gas to be based
upon the preceding 12-month average of the first trading-day of the month
spot price on the most relevant exchange. For the March 31, 2009, SEC guidelines
required the benchmark price for both oil and gas to be the closing price
on the last trading-day of the fiscal year. |
| |
• |
Future cash flows
are reduced by estimated production costs, costs to develop and produce
the proved reserves and abandonment costs, all based on current year-end
economic conditions. |
| |
• |
The resulting future
net cash flows are discounted to present value by applying a discount rate
of 10%. |
The standardized measure of discounted future net
cash flows does not purport, nor should it be interpreted, to present the fair
value of our natural gas and oil reserves. An estimate of fair value would also
take into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs and a discount
factor more representative of the time value of money and the risks inherent in
the industry.
The standardized measure of discounted future net cash flows relating to proved
natural gas and oil reserves as of March 31, 2010 and 2009 is as follows:
| |
|
As of March 31,
|
|
|
| In Thousands |
|
2010
|
|
|
|
2009
|
|
|
| Future Cash
Inflows |
$ |
127,486
|
|
|
$ |
90,391
|
|
|
| Future Production and Development
Costs |
|
(89,762
|
) |
|
|
(55,865
|
) |
|
| Income Taxes |
|
(13,204
|
) |
|
|
(12,084
|
) |
|
| Future Net Cash Flows |
|
24,520
|
|
|
|
22,442
|
|
|
| 10% Annual
Discount |
|
(17,359
|
) |
|
|
(12,120
|
) |
|
| Standardized Measure of Discounted
Future Net Cash Flow |
$ |
7,161
|
|
|
$ |
10,322
|
|
|
| |
|
|
|
|
|
|
|
|
F-26
Table of Contents
The following reconciles the change in the
standardized measure of discounted future net cash flow during the fiscal years
ended March 31, 2010 and 2009:
| |
|
Year Ended March 31,
|
|
|
| In Thousands |
|
2010
|
|
|
|
2009
|
|
|
| Balance
at beginning of yea |
$ |
10,322
|
|
|
$ |
68,301
|
|
|
| Net change in prices and
production costs |
|
11,145
|
|
|
|
(194,933
|
) |
|
| Net changes
in future development costs |
|
(20,306
|
) |
|
|
6,807
|
|
|
| Sales of oil & gas produced
net of production costs |
|
(452
|
) |
|
|
(3,533
|
) |
|
| Extensions
and discoveries |
|
20,698
|
|
|
|
23,664
|
|
|
| Previously estimated development
costs incurred |
|
532
|
|
|
|
8,243
|
|
|
| Revisions
of previous quantity estimates |
|
(8,419
|
) |
|
|
(10,020
|
) |
|
| Purchases of reserves |
|
-
|
|
|
|
427
|
|
|
| Net change
in income taxes |
|
(1,120
|
) |
|
|
59,271
|
|
|
| Accretion of discount |
|
(5,239
|
) |
|
|
52,095
|
|
|
| End of
Year |
$ |
7,161
|
|
|
$ |
10,322
|
|
|
| |
|
|
|
|
|
|
|
|
F-27
Table of Contents
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A(T). CONTROLS AND PROCEDURES
As of the end of the period covered by this report, we carried out an evaluation,
under the supervision and with the participation of management, including our
Chief Executive Officer and Chief Financial Officer, of the effectiveness of our
disclosure controls and procedures (as defined in 13a-15(e) of the Securities
Exchange Act of 1934, or the Exchange Act). Based on that evaluation, our Chief
Executive Officer and our Chief Financial Officer concluded that our disclosure
controls and procedures are effective.
Our management is responsible for establishing and maintaining adequate internal
control over financial reporting, as such term is defined in Exchange Act Rule
13a-15(f). Under the supervision and with the participation of our management,
including our Chief Executive Officer and Chief Financial Officer, we conducted
an evaluation of the effectiveness of our internal control over financial reporting
based on the framework in Internal Control - Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on our
evaluation, our management concluded that our internal control over financial
reporting was effective as of March 31, 2010.
This annual report does not include an attestation report of the company's registered
public accounting firm regarding internal control over financial reporting. Management's
report was not subject to attestation by the company's registered public accounting
firm pursuant to temporary rules of the Securities and Exchange Commission that
permit the company to provide only management's report in this annual report.
There have been no changes in our internal control over financial reporting identified
in connection with the evaluation required by paragraph (d) of Rule 13a-15 or
15d-15 under the Exchange Act that occurred during the quarter ended March 31,
2010 that has materially affected, or is reasonably likely to materially affect,
our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
Not Applicable.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
The information required by this Item is incorporated by reference from the information
under the captions entitled "Election of Directors-Nominees," "Executive Officers"
and "Section 16(a) Beneficial Ownership Reporting Compliance" in our definitive
proxy statement to be filed with the SEC within 120 days after the end of the
fiscal year ended March 31, 2010.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference from the information
under the caption entitled "Executive Officer Compensation and Other Information"
in our definitive proxy statement to be filed with the SEC within 120 days after
the end of the fiscal year ended March 31, 2010.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information required by this Item is incorporated by reference from the information
under the caption entitled "Security Ownership of Certain Beneficial Owners and
Management" in our definitive proxy statement to be filed with the SEC within
120 days after the end of the fiscal year ended March 31, 2010.
24
Table of Contents
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The information required by this Item is incorporated by reference from the information
under the caption entitled "Certain Transactions" in our definitive proxy statement
to be filed with the SEC within 120 days after the end of the fiscal year ended
March 31, 2010.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this Item is incorporated by reference from our
definitive proxy statement to be filed with the SEC within 120 days after the
end of the fiscal year ended March 31, 2010.
ITEM 15. EXHIBITS INDEX
(a) Financial statements
Reference is made to the Index and Financial Statements under Item 8 in Part II
hereof where these documents are listed.
25
Table of Contents
(b) Financial statement schedules
Financial statement schedules are either not required or the required information
is included in the consolidated financial statements or notes thereto filed under
Item 8 in Part II hereof.
(c) Exhibits
The exhibits to this Annual Report on Form 10-K are set forth below.
| Number
|
|
Exhibit
Description |
| 3(i).1 |
|
Articles of Incorporation
filed with the Nevada Secretary of State on November 29, 2004. (Incorporated
by reference from the registrant's registration statement on Form SB-2 filed
on September 8, 2005.) |
| |
|
|
| 3(i).2 |
|
Certificate of Change
filed with the Nevada Secretary of State on November 21, 2006. (Incorporated
by reference from the registrant's registration statement on Form 8-K filed
on November 30, 2006.) |
| |
|
|
| 3(i).3 |
|
Certificate of Amendment
filed with the Nevada Secretary of State on February 7, 2007. (Incorporated
by reference from the registrant's registration statement on Form SB-2 filed
on August 1, 2007.) |
| |
|
|
| 3(ii).1 |
|
Bylaws. (Incorporated
by reference from the registrant's registration statement on Form SB-2 filed
on August 1, 2007.) |
| |
|
|
| 10.2 |
|
Contribution Agreement
by and among the registrant, JMT Resources, Ltd., REO Energy, Ltd., and
Benco Operating, Inc. dated February 1, 2007. (Incorporated by reference
from the registrant's current report on Form 8-K filed on February 6, 2007.)
|
| |
|
|
| 10.5 |
|
Joint Operating
Agreement dated February 1, 2007 by Rife Energy Operating, Inc. and the
registrant. (Incorporated by reference from the registrant's registration
statement on Form SB-2 filed on August 1, 2007.) |
| |
|
|
| 10.6 |
|
Joint Operating
Agreement by and between the registrant and Texas MOR, Inc. dated February
1, 2007. (Incorporated by reference from the registrant's registration statement
on Form SB-2 filed on August 1, 2007.) |
| |
|
|
| 10.7 |
|
Employee Confidentiality
and Property Agreement by and between the registrant and Scott Allen. (Incorporated
by reference from the registrant's registration statement on Form SB-2 filed
on August 1, 2007.) |
26
Table of Contents
27
Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant
has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
| |
|
REOSTAR ENERGY CORPORATION
|
| |
|
|
| |
|
|
| Date: June 29, 2010 |
By: |
/s/
Mark S. Zouvas |
| |
|
Mark S. Zouvas |
| |
|
President, Chief Executive Officer
and Director |
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below
constitutes and appoints Mark S. Zouvas and Scott Allen, jointly and severally,
his attorney-in-fact, with the power of substitution, for him in any and all capacities,
to sign any amendments to this annual report on Form 10-K and to file the same,
with exhibits thereto and other documents in connection therewith, with the Securities
and Exchange Commission, hereby ratifying and confirming all that each of said
attorneys-in-fact, or his substitute or substitutes, may do or cause to be done
by virtue hereof.
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
dates indicated.
|
SIGNATURE
|
|
TITLE
|
|
DATE
|
| |
|
|
|
|
| /s/
Mark S. Zouvas
|
|
President, Chief Executive Officer
and Director |
|
June 29, 2010
|
| Mark
S. Zouvas |
|
(Principal Executive Officer)
|
|
|
| |
|
|
|
|
| /s/
Scott
Allen |
|
Chief Financial Officer and Director
July 14, 2008 |
|
June 29, 2010
|
| Scott
Allen |
|
(Principal Financial Officer)
|
|
|
| |
|
|
|
|
| /s/
M.
O. Rife III |
|
Chairman of the Board of Directors
|
|
June 29, 2010
|
| M. O.
Rife III |
|
|
|
|
| |
|
|
|
|
| /s/
Jean-Baptiste
Heinzer |
|
Director |
|
June 29, 2010
|
| Jean-Baptiste
Heinzer |
|
|
|
|
| |
|
|
|
|
| /s/
Alan Rae |
|
Director |
|
June 29, 2010
|
| Alan
Rae |
|
|
|
|
| |
|
|
|
|
28