Attached files
As filed with the Securities and Exchange Commission on October 18, 2011.
Commission File No. 333-172576
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM S-1
Amendment No. 2
Registration Statement Under
THE SECURITIES ACT OF 1933
SYNERGY RESOURCES CORPORATION
(Exact name of registrant as specified in charter)
Colorado 1311 20-2835920
---------------------------- ----------------------- -----------------------
(State or other jurisdiction (Primary Standard Classi- (IRS Employer
of incorporation) fication Code Number) I.D. Number)
20203 Highway 60
Platteville, CO 80651
(970) 737-1073
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(Address and telephone number of principal executive offices)
20203 Highway 60
Platteville, CO 80651
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(Address of principal place of business or intended principal place of business)
William E. Scaff, Jr.
20203 Highway 60
Platteville, CO 80651
(970) 737-1073
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(Name, address and telephone number of agent for service)
Copies of all communications, including all communications sent
to the agent for service, should be sent to:
William T. Hart, Esq.
Hart & Trinen, LLP
1624 Washington Street
Denver, Colorado 80203
303-839-0061
As soon as practicable after the effective date of this Registration Statement
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APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC:
If any of the securities being registered on this Form are to be offered on a
delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933 check the following box: [x]
If this Form is filed to register additional securities for an offering pursuant
to Rule 462(b) under the Securities Act, please check the following box and list
the Securities Act registration statement number of the earlier effective
registration statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under
the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under
the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
the definitions of "large accelerated filer," "accelerated filer" and "smaller
reporting company" in Rule 12b2 of the Exchange Act.
Large accelerated filer [ ] Accelerated filer [ ]
Non-accelerated filer [ ] Smaller reporting company [X]
(Do not check if a smaller reporting company)
CALCULATION OF REGISTRATION FEE
Title of each Proposed Proposed
Class of Maximum Maximum
Securities Securities Offering Aggregate Amount of
to be to be Price Per Offering Registration
Registered Registered Share (1) Price Fee
---------- ---------- ----------- ------------- --------------
Common Stock (2) 9,000,000 $3.15 $28,350,000 $3,288.60
(1) Offering price computed in accordance with Rule 457(c).
(2) Shares of common stock offered by selling shareholders.
The registrant hereby amends this Registration Statement on such date or
dates as may be necessary to delay its effective date until the registrant shall
file a further amendment which specifically states that this Registration
Statement shall thereafter become effective in accordance with Section 8(a) of
the Securities Act of l933 or until the Registration Statement shall become
effective on such date as the Commission, acting pursuant to said Section 8(a),
may determine.
PROSPECTUS
SYNERGY RESOURCES CORPORATION
Common Stock
By means of this prospectus a number of our shareholders are offering to
sell up to 9,000,000 shares of our common stock. The shares owned by selling
shareholders may be sold through the NYSE Amex, any other trading facility on
which the shares are traded, or otherwise, at prices related to the then current
market price, or in negotiated transactions.
We will not receive any proceeds from the sale of the common stock by the
selling stockholders. We will pay for the expenses of this offering which are
estimated to be $50,000.
Our common stock is traded on the NSYE Amex under the symbol "SYRG". On
September 21, 2011 the closing price for our common stock was $2.86.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or passed upon the
accuracy or adequacy of this prospectus. Any representation to the contrary is a
criminal offense.
THESE SECURITIES ARE SPECULATIVE AND INVOLVE A HIGH DEGREE OF RISK. FOR A
DESCRIPTION OF CERTAIN IMPORTANT FACTORS THAT SHOULD BE CONSIDERED BY
PROSPECTIVE INVESTORS, SEE "RISK FACTORS" BEGINNING ON PAGE 8 OF THIS
PROSPECTUS.
The date of this prospectus is September ___, 2011.
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PROSPECTUS SUMMARY
Synergy Resources Corporation ("we" or the "Company" or "Synergy") is the
entity that resulted from a business combination between Brishlin Resources,
Inc., a public company, ("predecessor Brishlin") and Synergy Resources
Corporation, a private company, ("predecessor Synergy"). We were incorporated in
Colorado in May 2005 and are involved in oil and gas exploration and
development.
Our website is: www.synergyresourcescorporation.com.
Our offices are located at 20203 Highway 60, Platteville, CO 80651. Our
office telephone number is (970) 737-1073 and our fax number is (970) 737-1045.
See the "Glossary" section of this prospectus for the definition of terms
pertaining to the oil and gas industry which are used in this prospectus.
The Offering
During December 2010 and January 2011, we sold 9,000,000 shares of our
common stock to a group of private investors at a price of $2.00 per share.
By means of this prospectus a number of our shareholders are offering to
sell up to 9,000,000 shares of our common stock. See the section of this
prospectus entitled "Selling Shareholders" for more information.
As of September 15, 2011, we had 36,098,212 outstanding shares of common
stock. The number of our outstanding shares does not include shares issuable
upon the exercise of outstanding warrants or the exercise of options granted to
our officers, directors and employees. See the section of this prospectus
captioned "Comparative Share Data" for more information.
The purchase of the securities offered by this prospectus involves a high
degree of risk. Risk factors include our short operating history, losses since
we were incorporated, and the possible need for us to sell shares of our common
stock to raise capital. See "Risk Factors" section of this prospectus below for
additional Risk Factors.
Forward-Looking Statements
This prospectus contains or incorporates by reference "forward-looking
statements," as that term is used in federal securities laws, concerning our
financial condition, results of operations and business. These statements
include, among others:
o statements concerning the benefits that we expect will result from our
business activities and results of exploration that we contemplate or
have completed, such as increased revenues; and
o statements of our expectations, beliefs, future plans and strategies,
anticipated developments and other matters that are not historical
facts.
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You can find many of these statements by looking for words such as
"believes," "expects," "anticipates," "estimates" or similar expressions used in
this prospectus.
These forward-looking statements are subject to numerous assumptions, risks
and uncertainties that may cause our actual results to be materially different
from any future results expressed or implied in those statements. Because the
statements are subject to risks and uncertainties, actual results may differ
materially from those expressed or implied. We caution you not to put undue
reliance on these statements, which speak only as of the date of this
prospectus. Further, the information contained in this prospectus, or
incorporated herein by reference, is a statement of our present intention and is
based on present facts and assumptions, and may change at any time.
RISK FACTORS
Investors should be aware that this offering involves certain risks,
including those described below, which could adversely affect the value of our
common stock. We do not make, nor have we authorized any other person to make,
any representation about the future market value of our common stock. In
addition to the other information contained in this prospectus, the following
factors should be considered carefully in evaluating an investment in our
securities.
We may never be profitable. As of the date of this prospectus we had reported
significant net losses for each year since inception. Although we recently
reported an operating profit for the quarter ended May 31, 2011, we reported a
net loss of $13,189,974 for the nine months ended May 31, 2011, and we expect to
report a net loss for the year ended August 31, 2011. Unless and until we are
profitable for an entire year, we will need to raise enough capital to be able
to fund the costs of our operations and our planned oil and gas exploration and
development activities.
Our transactions with related parties may cause conflicts of interests that may
adversely affect us.
Between June 11, 2008 and June 30, 2010, and pursuant to the terms of an
Administrative Services Agreement with Petroleum Management, LLC, we were
provided with office space and equipment storage in Platteville, Colorado, as
well as secretarial, word processing, telephone, fax, email and related services
for a fee of $20,000 per month. Following the termination of the Administrative
Services Agreement, and since July 1, 2010, we have leased the office space and
equipment storage yard in Platteville from HS Land & Cattle, LLC at a rate of
$10,000 per month.
In addition to the above, and as mentioned in the section of this
Prospectus captioned "Acquisition of Assets from Petroleum Exploration &
Management," we acquired oil and gas properties from Petroleum Exploration &
Management, LLC ("PEM").
Petroleum Management, LLC, PEM and HS Land & Cattle, LLC are controlled by
Ed Holloway and William E. Scaff, Jr., both of whom are our officers, directors
and principal shareholders. In addition, in the past we have purchased oil and
gas assets from PEM.
We believe that the transactions and agreements that we have entered into
with these affiliates are on terms that are at least as favorable as could
reasonably have been obtained at such time from third parties. However, these
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relationships could create, or appear to create, potential conflicts of interest
when our board of directors is faced with decisions that could have different
implications for us and these affiliates. The appearance of conflicts, even if
such conflicts do not materialize, might adversely affect the public's
perception of us, as well as our relationship with other companies and our
ability to enter into new relationships in the future, which could have a
material adverse effect on our ability to do business.
Hydraulic fracturing, the process used for releasing oil and gas from shale
rock, has recently come under increased scrutiny and could be the subject of
further regulation that could impact the timing and cost of development.
The Environmental Protection Agency (the "EPA") recently amended the
Underground Injection Control, or UIC, provisions of the federal Safe Drinking
Water Act (the "SDWA") to exclude hydraulic fracturing from the definition of
"underground injection." However, the U.S. Senate and House of Representatives
are currently considering bills entitled the Fracturing Responsibility and
Awareness of Chemicals Act (the "FRAC Act"), to amend the SDWA to repeal this
exemption. If enacted, the FRAC Act would amend the definition of "underground
injection" in the SDWA to encompass hydraulic fracturing activities, which could
require hydraulic fracturing operations to meet additional permitting and
financial assurance requirements, adhere to certain construction specifications,
fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging
and abandonment requirements. The FRAC Act also proposes to require the
reporting and public disclosure of chemicals used in the fracturing process,
which could make it easier for third parties opposing the hydraulic fracturing
process to initiate legal proceedings based on allegations that specific
chemicals used in the fracturing process could adversely affect groundwater.
Depending on the legislation that may ultimately be enacted or the
regulations that may be adopted at the federal, state and/or provincial levels,
exploration and production activities that entail hydraulic fracturing could be
subject to additional regulation and permitting requirements. Individually or
collectively, such new legislation or regulation could lead to operational
delays or increased operating costs and could result in additional burdens that
could increase the costs and delay the development of unconventional oil and gas
resources from shale formations which are not commercial without the use of
hydraulic fracturing. This could have an adverse effect on our business.
Our failure to obtain capital may significantly restrict our proposed
operations. We need additional capital to provide working capital and to fund
our capital expenditure plans. We do not know what the terms of any future
capital raising may be but any future sale of our equity securities would dilute
the ownership of existing stockholders and could be at prices substantially
below the price investors paid for the shares of common stock sold in this
offering. Our failure to obtain the capital which we require will result in the
slower implementation of our business plan or our inability to implement our
business plan. There can be no assurance that we will be able to obtain the
capital which we will need.
We will need to generate positive cash flow or obtain additional financing
until we are able to consistently earn a profit. As a result of our short
operating history it is difficult for potential investors to evaluate our
business. There can be no assurance that we can implement our business plan,
that we will be profitable, or that the securities which may be sold in this
offering will have any value.
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Oil and gas exploration is not an exact science, and involves a high degree of
risk. The primary risk lies in the drilling of dry holes or drilling and
completing wells which, though productive, do not produce gas and/or oil in
sufficient amounts to return the amounts expended and produce a profit. Hazards,
such as unusual or unexpected formation pressures, downhole fires, blowouts,
loss of circulation of drilling fluids and other conditions are involved in
drilling and completing oil and gas wells and, if such hazards are encountered,
completion of any well may be substantially delayed or prevented. In addition,
adverse weather conditions can hinder or delay operations, as can shortages of
equipment and materials or unavailability of drilling, completion, and/or
work-over rigs. Even though a well is completed and is found to be productive,
water and/or other substances may be encountered in the well, which may impair
or prevent production or marketing of oil or gas from the well.
Exploratory drilling involves substantially greater economic risks than
development drilling because the percentage of wells completed as producing
wells is usually less than in development drilling. Exploratory drilling itself
can be of varying degrees of risk and can generally be divided into higher risk
attempts to discover a reservoir in a completely unproven area or relatively
lower risk efforts in areas not too distant from existing reservoirs. While
exploration adjacent to or near existing reservoirs may be more likely to result
in the discovery of oil and gas than in completely unproven areas, exploratory
efforts are nevertheless high risk activities.
Although the completion of oil and gas wells is, to a certain extent, less
risky than drilling for oil and gas, the process of completing an oil or gas
well is nevertheless associated with considerable risk. In addition, even if a
well is completed as a producer, the well for a variety of reasons may not
produce sufficient oil or gas in order to repay our investment in the well.
The acquisition, exploration and development of oil and gas properties, and the
production and sale of oil and gas are subject to many factors which are outside
our control. These factors include, among others, general economic conditions,
proximity to pipelines, oil import quotas, supply, demand, and price of other
fuels and the regulation of production, refining, transportation, pricing,
marketing and taxation by Federal, state, and local governmental authorities.
Buyers of our gas, if any, may refuse to purchase gas from us in the event of
oversupply. If wells which we drill are productive of natural gas, the
quantities of gas that we may be able to sell may be too small to pay for the
expenses of operating the wells. In such a case, the wells would be "shut-in"
until such time, if ever, that economic conditions permit the sale of gas in
quantities which would be profitable.
Interests that we may acquire in oil and gas properties may be subject to
royalty and overriding royalty interests, liens incident to operating
agreements, liens for current taxes and other burdens and encumbrances,
easements and other restrictions, any of which may subject us to future
undetermined expenses. We do not intend to purchase title insurance, title
memos, or title certificates for any leasehold interests we will acquire. It is
possible that at some point we will have to undertake title work involving
substantial costs. In addition, it is possible that we may suffer title failures
resulting in significant losses.
The drilling of oil and gas wells involves hazards such as blowouts, unusual or
unexpected formations, pressures or other conditions which could result in
substantial losses or liabilities to third parties. Although we intend to
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acquire adequate insurance, or to be named as an insured under coverage acquired
by others (e.g., the driller or operator), we may not be insured against all
such losses because insurance may not be available, premium costs may be deemed
unduly high, or for other reasons. Accordingly, uninsured liabilities to third
parties could result in the loss of our funds or property.
Our operations are dependent upon the continued services of our officers. The
loss of any of these officers, whether as a result of death, disability or
otherwise, may have a material adverse effect upon our business.
Our operations will be affected from time to time and in varying degrees by
political developments and Federal and state laws and regulations regarding the
development, production and sale of crude oil and natural gas. These regulations
require permits for drilling of wells and also cover the spacing of wells, the
prevention of waste, and other matters. Rates of production of oil and gas have
for many years been subject to Federal and state conservation laws and
regulations and the petroleum industry is subject to Federal tax laws. In
addition, the production of oil or gas may be interrupted or terminated by
governmental authorities due to ecological and other considerations. Compliance
with these regulations may require a significant capital commitment by and
expense to us and may delay or otherwise adversely affect our proposed
operations.
From time to time legislation has been proposed relating to various
conservation and other measures designed to decrease dependence on foreign oil.
No prediction can be made as to what additional legislation may be proposed or
enacted. Oil and gas producers may face increasingly stringent regulation in the
years ahead and a general hostility towards the oil and gas industry on the part
of a portion of the public and of some public officials. Future regulation will
probably be determined by a number of economic and political factors beyond our
control or the oil and gas industry.
Our activities will be subject to existing federal and state laws and
regulations governing environmental quality and pollution control. Compliance
with environmental requirements and reclamation laws imposed by Federal, state,
and local governmental authorities may necessitate significant capital outlays
and may materially affect our earnings. It is impossible to predict the impact
of environmental legislation and regulations (including regulations restricting
access and surface use) on our operations in the future although compliance may
necessitate significant capital outlays, materially affect our earning power or
cause material changes in our intended business. In addition, we may be exposed
to potential liability for pollution and other damages.
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MARKET FOR OUR COMMON STOCK.
On February 27, 2008, our common stock began trading on the OTC Bulletin
Board under the symbol "BRSH." There was no established trading market for our
common stock prior to that date.
On September 22, 2008, a 10-for-1 reverse stock split, approved by our
shareholders on September 8, 2008, became effective on the OTC Bulletin Board
and our trading symbol was changed to "SYRG.OB." On July 27, 2011 our common
stock began trading on the NYSE Amex under the symbol "SYRG".
Shown below is the range of high and low closing prices for our common
stock for the periods indicated as reported by the OTC Bulletin Board prior to
July 27, 2011 and by the NYSE Amex on and after July 27, 2011. The market
quotations reflect inter-dealer prices, without retail mark-up, mark-down or
commissions and may not necessarily represent actual transactions.
Quarter Ended High Low
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November 30, 2008 $4.75 $3.10
February 28, 2009 $3.45 $1.25
May 31, 2009 $1.80 $1.45
August 31, 2009 $1.80 $1.10
November 30, 2009 $1.47 $1.00
February 28, 2010 $3.86 $1.35
May 31, 2010 $3.85 $2.40
August 31, 2010 $3.00 $2.25
November 30, 2010 $2.40 $1.95
February 28, 2011 $4.74 $2.25
May 31, 2011 $4.90 $3.20
August 31, 2011 $3.69 $2.55
On September 21, 2011 the closing price of our common stock on the NYSE
Amex was $2.86.
As of September 15, 2011, we had 36,098,212 outstanding shares of common
stock and 293 shareholders of record. The number of beneficial owners of our
common stock is approximately 925.
Holders of our common stock are entitled to receive dividends as may be
declared by our board of directors. Our board of directors is not restricted
from paying any dividends but is not obligated to declare a dividend. No cash
dividends have ever been declared and it is not anticipated that cash dividends
will ever be paid.
Our articles of incorporation authorize our board of directors to issue up
to 10,000,000 shares of preferred stock. The provisions in the articles of
incorporation relating to the preferred stock allow our directors to issue
preferred stock with multiple votes per share and dividend rights which would
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have priority over any dividends paid with respect to the holders of our common
stock. The issuance of preferred stock with these rights may make the removal of
management difficult even if the removal would be considered beneficial to
shareholders generally, and will have the effect of limiting shareholder
participation in certain transactions such as mergers or tender offers if these
transactions are not favored by our management.
On December 1, 2008, we purchased 1,000,000 shares of our common stock from
the Synergy Energy Trust, one of our initial shareholders, for $1,000, which was
the same amount which we received when the shares were sold to the Trust. With
the exception of that transaction, we have not purchased any of our securities
and no person affiliated with us has purchased any of our securities for our
benefit.
COMPARATIVE SHARE DATA
The following table lists additional shares of our common stock, which may
be issued as of September 15, 2011 upon the exercise of outstanding options or
warrants or the issuance of shares for oil and gas leases.
Number of Note
Shares Reference
--------- ---------
Shares issuable upon the exercise of Series C warrants 9,000,000 A
Shares issuable upon the exercise of placement agents'
warrants 779,906 A
Shares issuable upon exercise of Series A warrants
that were granted to those persons owning shares of
our common stock prior to the acquisition of
Predecessor Synergy 1,038,000 B
Shares issuable upon exercise of Series A warrants
sold in prior private offering. 2,060,000 C
Shares issuable upon exercise of Series A and Series
B warrants 2,000,000 D
Shares issuable upon exercise of sales agent warrants 126,932 D
Shares issuable upon exercise of options held by our
officers and employees 4,470,000 E
A. Between December 2009 and March 2010, we sold 180 Units at a price of
$100,000 per Unit to private investors. Each Unit consisted of one $100,000 note
and 50,000 Series C warrants. The notes were converted into shares of our common
stock at a conversion price of $1.60 per share, at the option of the holder.
Each Series C warrant entitles the holder to purchase one share of our common
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stock at a price of $6.00 per share at any time prior to December 31, 2014. As
of the interim reporting period ended May 31, 2011, all notes had been converted
into 11,250,000 shares of our common stock.
We paid Bathgate Capital Partners (now named GVC Capital), the placement
agent for the Unit offering, a commission of 8% of the amount Bathgate Capital
raised in the Unit offering. We also sold to the placement agent, for a nominal
price, warrants to purchase 1,125,000 shares of our common stock at a price of
$1.60 per share. The placement agent's warrants expire on December 31, 2014. As
of the interim reporting period ended May 31, 2011, warrants to purchase 345,094
shares had been exercised by their holders.
B. Each shareholder of record on the close of business on September 9, 2008
received one Series A warrant for each share which they owned on that date (as
adjusted for a reverse split of our common stock which was effective on
September 22, 2008). Each Series A warrant entitles the holder to purchase one
share of our common stock at a price of $6.00 per share at any time prior to
December 31, 2012.
C. Prior to our acquisition of Predecessor Synergy, Predecessor Synergy sold
2,060,000 Units to a group of private investors at a price of $1.00 per Unit.
Each Unit consisted of one share of Predecessor Synergy's common stock and one
Series A warrant. In connection with the acquisition of Predecessor Synergy,
these Series A warrants were exchanged for 2,060,000 of our Series A warrants.
The Series A warrants are identical to the Series A warrants described in Note B
above.
D. Between December 1, 2008 and June 30, 2009, we sold 1,000,000 units at a
price of $3.00 per unit. Each unit consisted of two shares of our common stock,
one Series A warrant and one Series B warrant. The Series A warrants are
identical to the Series A warrants described in Note B above. Each Series B
warrant entitles the holder to purchase one share of our common stock at a price
of $10.00 per share at any time prior to December 31, 2012.
In connection with this unit offering, we paid the sales agent for the
offering a commission of 10% of the amount the sales agent sold in the offering.
We also issued warrants to the sales agent. The warrants allow the sales agent
to purchase 31,733 units (which units were identical to the units sold in the
offering) at a price of $3.60 per unit. The sales agent warrants will expire on
the earlier of December 31, 2012 or twenty days following written notification
from us that our common stock had a closing bid price at or above $7.00 per
share for any ten of twenty consecutive trading days.
E. See the section of this prospectus captioned "Management-Executive
Compensation" for information regarding shares issuable upon exercise of options
held by our officers and employees.
We may sell additional shares of our common stock, preferred stock,
warrants, convertible notes or other securities to raise additional capital. We
do not have any commitments or arrangements from any person to purchase any of
our securities and there can be no assurance that we will be successful in
selling any additional securities.
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MANAGEMENT'S DISCUSSION AND ANALYSIS
AND PLAN OF OPERATION
Introduction
The following discussion and analysis was prepared to supplement information
contained in the financial statements included as part of this prospectus and is
intended to explain certain items regarding our financial condition as of August
31, 2010 and May 31, 2011, and the results of operations for the years ended
August 31, 2010, and 2009 and the nine months ended May 31, 2010 and 2011. It
should be read in conjunction with the audited and unaudited financial
statements and related notes contained in this prospectus.
Background
We were incorporated in Colorado on May 11, 2005.
Prior to September 2008, our only material asset was one shut-in gas well.
On September 10, 2008 we acquired approximately 89% of the outstanding shares of
Predecessor Synergy in exchange for 8,882,500 shares of our common stock and
1,042,500 Series A warrants.
Predecessor Synergy was incorporated in Colorado in December 2007. As of
the date of our acquisition of Predecessor Synergy, Predecessor Synergy's only
material asset was approximately $2.2 million in cash that it raised from
private investors.
On December 19, 2008, we acquired the remaining shares of Predecessor
Synergy for 1,077,500 shares of our common stock and 1,017,500 Series A
warrants. See "Comparative Share Data" for information concerning the terms of
these warrants.
Subsequent to the Predecessor Synergy acquisition, we changed our fiscal
year end from December 31 to August 31.
Contingent upon the amount of capital available, we plan to continue to
explore for oil and gas. We expect that most of our wells will be drilled in the
Wattenberg Field which is located in the D-J Basin in northeast Colorado.
Overview
We are an independent oil and gas operator in Colorado and are focused on
the acquisition, development, exploitation, exploration and production of oil
and natural gas properties primarily located in the Wattenberg field in the
Denver-Julesburg ("D-J") Basin in northeast Colorado. We commenced active
operations in September 2008 and have grown significantly during the last two
years. As of August 31, 2009, we had two productive wells (net wells of 0.6). As
of August 31, 2010, we had twenty-four productive wells and fourteen wells in
the process of completion (net wells of 19). As of May 31, 2011, we had 124
gross wells, including 114 producing wells, 8 wells in progress, and 2 shut in
wells (net wells of 89).
As of May 31, 2011, we had estimated proved reserves of 1,721,647 Bbls of
oil and 13,586,923 Mcf of gas, including reserves acquired in the transaction
with PEM.
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Our growth plans for 2012 include additional drilling activities,
acquisition of existing wells, and recompletion of wells that provide good
prospects for improved hydraulic stimulation techniques. As cash flow from
operations is not sufficient to fund our growth plans, we are required to seek
additional financing. The completion of our recent financing for gross proceeds
of $18 million and the sales of mineral interests for approximately $8.6 million
will satisfy some of our capital needs. However, we expect that future financing
will be required, especially as we move forward into our 2012 drilling program.
Ultimately, implementation of our growth plans will be dependent upon the amount
of financing we are able to obtain.
Results of Operations
Material changes of certain items in our statements of operations included
in our financial statements for the periods presented are discussed below.
Year ended August 31, 2010
For the year ended August 31, 2010, we reported a net loss of $10,794,172,
or $0.88 per share, compared to a net loss of $12,351,873, or $1.14 per share
for the period ended August 31, 2009. The comparison between the two years was
primarily influenced by (a) increasing revenues and expenses associated with the
2010 drilling program, (b) costs associated with the $18 million financing
transaction, and (c) the costs of share based compensation.
Oil and Gas Production and Revenues - For the year ended August 31, 2010,
we recorded total oil and gas revenues of $2,158,444 compared to $94,121 for the
year ended August 31, 2009, as summarized in the following table:
Year Ended August, 31
2010 2009
------------- -------------
Production:
Oil (Bbls) 21,080 1,730
Gas (Mcf) 141,154 4,386
Total production in BOE 44,606 2,461
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Year Ended August, 31
---------------------------
2010 2009
------------- -------------
Revenues:
Oil $ 1,441,562 $ 78,872
Gas 716,882 15,249
------------- -------------
Total $ 2,158,444 $ 94,121
============= =============
Average sales price:
Oil (Bbls) $ 68.38 $ 45.59
Gas (Mcf) $ 5.08 $ 3.48
"Bbl" refers to one stock tank barrel, or 42 U.S. gallons liquid volume in
reference to crude oil or other liquid hydrocarbons. "Mcf" refers to one
thousand cubic feet. A BOE (i.e. barrel of oil equivalent) combines Bbls of oil
and Mcf of gas by converting each six Mcf of gas to one Bbl of oil.
Net oil and gas production for the year ended August 31, 2010 was 44,606
BOE, or 122 BOE per day. The significant increase in production from the prior
year reflects the additional 22 wells that began production during the year.
Production for the fourth quarter averaged 241 BOE per day. The change in
average sales price reflects changes in the commodity prices for oil and gas,
which fluctuate from day to day based upon numerous factors, including changes
in supply and demand.
Lease Operating Expenses - As summarized in the following table, our lease
expenses include the direct operating costs of producing oil and natural gas and
taxes on production and properties:
Year Ended August 31,
--------------------------
2010 2009
------------- -----------
Production costs $ 86,554 $ 2,094
Severance and ad valorem taxes 236,966
9,478
------------- -----------
Total production expenses $323,520 $11,572
============= ===========
Per BOE:
Production costs $ 1.94 $ 0.85
Severance and ad valorem taxes 5.31 3.85
------------- -----------
Total per BOE $ 7.25 $ 4.70
============= ===========
Production costs tend to increase or decrease primarily in relation to the
number of wells in production, and, to a lesser extent, on fluctuation in oil
field service costs and changes in the production mix of crude oil and natural
gas. Taxes tend to increase or decrease primarily based on the value of oil and
gas sold, and, as a percent of revenues, averaged 11% in 2010 and 12% in 2009.
Depreciation, Depletion, and Amortization ("DDA") - DDA expense is
summarized in the following table:
12
Year Ended August 31,
------------------------
2010 2009
------------ ----------
Depletion expense $692,274 $97,309
Depreciation and amortization
9,126 296
------------ ----------
Total DDA $701,400 $97,605
============ ==========
Depletion expense per BOE $ 15.52 $ 39.54
The determination of depreciation, depletion and amortization expense is
highly dependent on the estimates of the proved oil and natural gas reserves. As
of August 31, 2010, we had 1,423,524 BOE of estimated net proved reserves with a
Standardized Measure of $13,022,397 (based on average prices of $4.76 Mcf and
$69.20 Bbl using the new SEC requirements). As of August 31, 2009, we had 10,710
BOE of estimated net proved reserves with a Standardized Measure of $232,957 (at
year-end prices of $2.05 Mcf and $61.24 Bbl under the former SEC requirements).
This significant increase in reserves resulted in a reduction to the DDA rate.
Impairment of Oil and Gas Properties - We use the full cost accounting
method, which requires recognition of impairment when the total capitalized
costs of oil and gas properties exceed the "ceiling" amount, as defined in the
full cost accounting literature. During the year ended August 31, 2010, no
impairment was recorded because our capitalized costs subject to the ceiling
test were less than the estimated future net revenues from proved reserves
discounted at 10% plus the lower of cost or market value of unevaluated
properties. During the year ended August 31, 2009, we recorded $945,079 of
non-cash impairment expense as a result of our capitalized costs exceeding
estimated future net revenues from then proved reserves. The ceiling test is
performed each quarter and there is the possibility for impairments to be
recognized in future periods. Once impairment is recognized, it cannot be
reversed.
General and Administrative - The following table summarizes the components
of general and administration expenses:
Year Ended August 31,
----------------------------
2010 2009
------------- -------------
Share based compensation $ 581,233 $ 10,296,521
Other general and administrative 1,202,624 752,070
Capitalized general and
administrative (95,475) -
------------- -------------
Totals $1,688,382 $ 11,048,591
============= =============
13
The share-based compensation recorded in general and administrative
expenses related to the issuance of stock grants and stock options to officers,
directors, and employees. The expense recorded for stock grants is based on the
market value of the common stock on the date of grant. When stock options are
issued we estimate their fair value using the Black-Scholes-Merton
option-pricing model. The estimated fair value is recorded as an expense on a
pro-rata basis over the vesting period.
Other general and administrative expenses, which include salaries,
benefits, professional fees, and other corporate overhead, increased
approximately $450,000 as we undertook the 2010 drilling program.
Certain general and administrative expenses for the year ended August 31,
2010, were directly related to the acquisition and development of oil and gas
properties. Those costs are reclassified from general and administrative expense
into capitalized costs in the full cost pool.
Other Income (Expense) - The issuance of $18,000,000 convertible promissory
notes and Series C warrants during the year ended August 31, 2010 generated a
significant increase in other expenses. The notes bear interest at 8% per year,
payable quarterly, and mature on December 31, 2012, unless earlier converted by
the noteholders at $1.60 per share or repaid by the Company, and each Series C
warrant entitles the holder to purchase one share of common stock at a price of
$6.00 per share and expires on December 31, 2014. Interest expense of $551,603,
net of capitalized interest of $269,761, was recognized during the year ended
August 31, 2010. At March 12, 2010, the day that we completed the offering, fair
values of the warrant component and the conversion feature were deemed to be
$1,760,048 and $3,455,809, respectively, resulting in a total discount of
$5,215,857, which was recorded as a reduction to the liability on the balance
sheet and is being accreted to the statement of operations over the 36- month
life of the notes, using the effective interest method, resulting in a non-cash
expense of $1,333,590 during the year ended August 31, 2010. A total of
$2,041,455 was recorded for issuance costs, which is being recognized pro-rata
in expenses over the 36 month amortization period, producing an expense of
$453,656 for the year ended August 31, 2010.
A non-cash expense of $7,678,457 was reflected in the statement of
operations for the year ended August 31, 2010 to represent the change in the
fair value of the derivative conversion liability since issuance of the notes.
This conversion feature, considered an embedded derivative and recorded as a
liability at its estimated fair value, when marked-to-market, over time is
reflected as a non-cash item in the statement of operations. As such, the
periodic marking-to-market of the conversion feature may result in non-cash
income or expense in the statements of operations of future periods. Certain
factors which are beyond our control are used in the determination of the fair
value of our derivative conversion liability. The estimated fair value is
derived from the Monte Carlo Simulation ("MCS") model, which uses forward
pricing, volatilities and credit risk rates for similar liabilities in active
markets (namely, for commercial debt issued by the Company's peer group
companies, as such information is published for these peer companies, where it
is not for Synergy due to our relatively short history and lack of commercially
originated debt).
We estimated the fair value of the warrants and the conversion feature of
the notes at inception by using the Black-Scholes-Merton option pricing model.
The Black-Scholes-Merton option-pricing model also requires an assumption about
the fair value of our common stock. It was concluded, upon issuance of the
notes, that our stock traded in an illiquid market, and the reported sales
14
prices may not represent fair value. As a result, a model that estimated our
enterprise value based upon oil and gas reserve estimates was used to place a
value of $1.39 on our common stock. Subsequent to the valuation at inception,
the model used to value the derivative conversion liability was changed from the
Black-Scholes-Merton option pricing model to the MCS model and the market for
our common stock became more active and orderly. The year end valuation model
used a value of $2.25 for our common stock based upon the quoted closing price.
The notes contain a conversion feature, at an initial conversion price of
$1.60 and subject to adjustment under certain circumstances, which allow the
noteholders to convert the $18,000,000 principal balance into a maximum of
11,250,000 common shares, plus conversion of accrued and unpaid interest into
common shares, also at $1.60 per share. During the quarter ended August 31,
2010, holders of convertible promissory notes with a face amount of $2,092,000
plus accrued interest of $2,438 elected to convert the notes into 1,309,027
shares of common stock, leaving notes with a principal amount of $15,908,000
outstanding at August 31, 2010. At the time the notes were converted, the
estimated fair value of the derivative conversion liability apportioned to the
converted notes totaled $1,809,149, which was reclassified on the balance sheet
from derivative conversion liability to additional paid in capital.
Conversion of notes into common shares accelerates accretion of unamortized
debt discount. As notes are converted, the unamortized discount apportioned to
each note is removed from the balance sheet, approximately one-third of which is
reclassified to equity and two-thirds of which is recognized as a non-cash
expense in the statement of operations, consistent with the composition of the
original discount (approximately one-third was the derived fair value of the
warrants and two-thirds was the derived fair value of the conversion feature).
The unamortized discount apportioned to the notes converted to common shares in
the quarter ended August 31, 2010, totaled $488,816. The portion applicable to
the conversion option summed $323,604 and was charged to accretion of debt
discount in the statement of operations. The unamortized discount applicable to
the warrants ($165,212) was reclassified on the balance sheet from debt discount
to additional paid in capital on shares issued pursuant to the conversion.
Income Taxes - Our effective tax rate is currently zero. We have reported a
net loss every year since inception and for tax purposes have a net operating
loss carry forward ("NOL") of approximately $10 million. The NOL is available to
offset future taxable income, if any. At such time, if ever, that we are able to
demonstrate that it is more likely than not that we will be able to realize the
benefits of our tax assets, we will be able to recognize the benefits in our
financial statements.
Three months ended May 31, 2011
For the three months ended May 31, 2011, we reported a net loss of
$291,612, or $0.01 per share, compared to a net loss of $3,649,812, or $0.30 per
share, for the three months ended May 31, 2010. The comparison between the two
periods was primarily influenced by increasing revenues and expenses associated
with the 36 wells completed during the 2010 drilling program which provided
operating income of $547,272 in 2011 compared to an operating loss of $51,094 in
2010. During both periods, we incurred significant non-cash expenses for the
change in value of the derivative conversion liability and the amortization of
loan fee and debt discount.
15
Three Months Ended May 31,
----------------------------
2011 2010
-------------- ------------
Production:
Oil (Bbls) 23,371 4,679
Gas (Mcf) 117,647 54,024
Total production in
BOE 42,979 13,683
Revenues:
Oil $ 2,293,945 $ 342,594
Gas 627,965 264,659
-------------- ------------
Total $ 2,921,910 $ 607,253
============== ============
Average sales price:
Oil (Bbls) $ 98.15 $ 73.22
Gas (Mcf) $ 5.34 $ 4.90
"Bbl" refers to one stock tank barrel, or 42 U.S. gallons liquid volume in
reference to crude oil or other liquid hydrocarbons. "Mcf" refers to one
thousand cubic feet. A BOE (i.e. barrel of oil equivalent) combines Bbls of oil
and Mcf of gas by converting each six Mcf of gas to one Bbl of oil.
Net oil and gas production for the three months ended May 31, 2011, was
42,979 BOE, or 467 BOE per day. The significant increase in production from the
comparable period in the prior year reflects the additional wells that began
production over the past twelve months. The change in average sales price is a
function of worldwide commodity prices, which have increased the realized sales
price of oil by 34% and increased the realized sales price of natural gas by 9%.
We do not currently engage in any commodity hedging activities, although we
may do so in the future.
Service Revenue- For the three months ended May 31, 2011, we recorded
revenue generated from the management of wells owned by third parties of
$184,426.
Lease Operating Expenses - As summarized in the following table, our lease
expenses include the direct operating costs of producing oil and natural gas and
taxes on production and properties:
Three Months Ended May 31,
----------------------------
2011 2010
------------- ------------
Production costs $ 86,521 $ 30,480
Severance and ad valorem taxes 290,663 76,023
Workover costs 291,499 -
------------- ------------
Total lease operating $ 668,683 $ 106,503
expenses ============= ============
16
Three Months Ended May 31,
----------------------------
2011 2010
------------- ------------
Per BOE:
Production costs $ 2.01 $ 2.23
Severance and ad valorem taxes 6.76 5.56
Workover costs 6.78 -
------------- ------------
Total per BOE $ 15.55 $ 7.79
============= ============
Production costs tend to increase or decrease primarily in relation to the
number of wells in production, and, to a lesser extent, on fluctuation in oil
field service costs and changes in the production mix of crude oil and natural
gas. Production costs may vary substantially among wells depending on the
methods of recovery employed and other factors, such as workover operations,
maintenance and repair, labor and utilities. Taxes tend to increase or decrease
primarily based on the value of oil and gas sold. As a percent of oil and gas
revenues, lease operating costs were 23% in the three months ended May 31, 2011,
and 18% in the respective period in 2010.
Depreciation, Depletion, and Amortization ("DDA") - DDA expense is
summarized in the following table:
Three Months Ended May 31,
--------------------------------------------
2011 2010
--------------------- ---------------------
Depletion $ 803,756 $ 198,474
Depreciation and
amortization 17,700 882
Accretion of asset
retirement obligations 9,183 1,534
--------------------- ---------------------
Total DDA $ 830,639 $ 200,890
===================== =====================
Depletion per BOE $ 18.70 $ 14.51
The determination of depreciation, depletion and amortization expense is
highly dependent on the estimates of the proved oil and natural gas reserves.
The capitalized costs of evaluated oil and gas properties are depleted using the
units-of-production method based on estimated reserves. Production volumes for
the quarter are compared to beginning of quarter estimated total reserves to
calculate a depletion rate. For the three months ended May 31, 2011, production
volumes of 42,979 BOE and estimated net proved reserves of 1,366,340 BOE were
the basis of the depletion rate calculation. For the three months ended May 31,
2010, production volumes of 13,683 BOE and estimated net proved reserves of
261,342 BOE were the basis of the depletion rate calculation.
17
General and Administrative - The following table summarizes the components
of general and administration expenses:
Three Months Ended May 31,
------------------------------------
2011 2010
----------------- ----------------
Stock based compensation $ 292,547 $ 6,962
Other general and
administrative 813,869 343,992
Capitalized general and
administrative (46,674) -
----------------- ----------------
Totals $ 1,059,742 $ 350,954
================= ================
The stock-based compensation recorded in general and administrative
expenses related to the issuance of stock grants and stock options to officers,
directors, consultants, and employees. The expense recorded for stock grants is
based on the market value of the common stock on the date of grant. When stock
options are issued we estimate their fair value using the Black-Scholes-Merton
option-pricing model. The estimated fair value is recorded as a non-cash expense
on a pro-rata basis over the vesting period.
Other general and administrative expenses, which include salaries,
benefits, professional fees, and other corporate overhead, increased
approximately $460,000 during the current three-month period over the comparable
quarter in the prior year due to the growth in our business. The following items
contributed to the increase: salaries and benefits increased by $380,000 as we
increased the number of employees from seven to ten and we incurred additional
professional fees of approximately $150,000 related to the acquisition of assets
from PEM. The increased expenses in these areas were somewhat offset by a
$30,000 decrease in administrative services purchased from a related party.
Certain general and administrative expenses are directly related to the
acquisition and development of oil and gas properties. Those costs were
reclassified from general and administrative expense into capitalized costs in
the full cost pool.
Other Income (Expense) - During the three months ended May 31, 2011, we
recognized $838,884 in other expense compared to $3,598,718 during the
comparable period in 2010. The significant change between the periods was driven
by the change in fair value of a derivative conversion liability related to $18
million of convertible promissory notes.
The notes contained a conversion feature which was considered an embedded
derivative and recorded as a liability at its estimated fair value, when
marked-to-market, over time is reflected as a non-cash item in the statement of
operations. By May 31, 2011, all of the notes had been converted, thereby
eliminating the derivative conversion liability.
In addition, the line item of interest expense, net, contains several
components related to the 8% convertible promissory notes. In addition to the 8%
coupon rate, we recorded amortization of debt issue costs of $422,528 and
accretion of debt discount of $762,136 during the three months ended May 31,
2011. During the comparable period ended May 31, 2010, amortization of debt
issue costs was $183,398 and accretion of debt discount was $376,871.
18
Income Taxes - Our effective tax rate is currently zero. We have reported a
net loss every year since inception and, for tax purposes, have a net operating
loss carry forward ("NOL") of approximately $10 million. The NOL is available to
offset future taxable income, if any. At such time, if ever, that we are able to
demonstrate that it is more likely than not that we will be able to realize the
benefits of our tax assets, we will recognize the benefits in our financial
statements. If operational results for the remainder of the fiscal year continue
to improve, we may recognize the benefits of certain tax assets during the
latter periods of the year.
Nine months ended May 31, 2011
For the nine months ended May 31, 2011, we reported a net loss of
$13,189,974, or $0.58 per share, compared to a net loss of $4,455,142, or $0.37
per share, for the nine months ended May 31, 2010. The comparison between the
two periods was primarily influenced by increasing revenues and expenses
associated with the 36 wells completed during the 2010 drilling program which
provided operating income of $1,244,525 in 2011 compared to an operating loss of
$445,974 in 2010. During both periods, we incurred significant non-cash expenses
for the change in value of the derivative conversion liability and the
amortization of loan fee and debt discount.
Nine Months Ended May 31,
----------------------------
2011 2010
-------------- ------------
Production:
Oil (Bbls) 59,749 8,327
Gas (Mcf) 297,668 75,340
Total production in
BOE 109,360 20,884
Revenues:
Oil $ 5,079,629 $ 587,190
Gas 1,319,564 408,574
-------------- ------------
Total $ 6,399,193 $ 995,764
============== ============
Average sales price:
Oil (Bbls) $ 85.02 $ 70.52
Gas (Mcf) $ 4.43 $ 5.42
"Bbl" refers to one stock tank barrel, or 42 placecountry-regionU.S.
gallons liquid volume in reference to crude oil or other liquid hydrocarbons.
"Mcf" refers to one thousand cubic feet. A BOE (i.e. barrel of oil equivalent)
combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl
of oil.
Net oil and gas production for the nine months ended May 31, 2011, was
109,360 BOE, or 401 BOE per day. The significant increase in production from the
comparable period in the prior year reflects the additional wells that began
production over the past twelve months. The change in average sales price is a
function of worldwide commodity prices, which have increased the realized sales
price of oil by 21% and decreased the realized sales price of natural gas by
18%.
19
We do not currently engage in any commodity hedging activities, although we
may do so in the future.
Service Revenue- For the nine months ended May 31, 2011, we recorded
revenue generated from the management of wells owned by third parties of
$211,715.
Lease Operating Expenses - As summarized in the following table, our lease
expenses include the direct operating costs of producing oil and natural gas and
taxes on production and properties:
Nine Months ended May 31,
----------------------------
2011 2010
------------- ------------
Production costs $ 203,868 $ 46,399
Severance and ad valorem taxes 636,470 115,146
Workover costs 291,499 -
------------- ------------
Total lease operating $ 1,131,837 $ 161,545
expenses
============= ============
Per BOE:
Production costs $ 1.86 $ 2.22
Severance and ad valorem taxes 5.82 5.51
Workover costs 2.67 -
------------- ------------
Total per BOE $ 10.35 $ 7.73
============= ============
Production costs tend to increase or decrease primarily in relation to the
number of wells in production, and, to a lesser extent, on fluctuation in oil
field service costs and changes in the production mix of crude oil and natural
gas. Production costs may vary substantially among wells depending on the
methods of recovery employed and other factors, such as workover operations,
maintenance and repair, labor and utilities. Taxes tend to increase or decrease
primarily based on the value of oil and gas sold. As a percent of revenues,
lease operating costs were 18% in the nine months ended May 31, 2011, and 16% in
the respective period in 2010.
Depreciation, Depletion, and Amortization ("DDA") - DDA expense is
summarized in the following table:
Nine Months ended May 31,
-----------------------------------
2011 2010
---------------- -----------------
Depletion $ 1,999,311 $ 291,191
Depreciation and
amortization 39,438 1,104
Accretion of asset
retirement obligations 24,076 1,534
---------------- -----------------
Total DDA $ 2,062,825 $ 293,829
================ =================
Depletion per BOE $ 18.28 $ 13.94
20
The determination of depreciation, depletion and amortization expense is
highly dependent on the estimates of the proved oil and natural gas reserves.
The capitalized costs of evaluated oil and gas properties are depleted using the
units-of-production method based on estimated reserves. Production volumes for
the quarter are compared to beginning of quarter estimated total reserves to
calculate a depletion rate. For the nine months ended May 31, 2011, production
volumes of 109,360 BOE and estimated net proved reserves of 1,430,896 BOE were
the basis of the depletion rate calculation. For the nine months ended May 31,
2010, production volumes of 20,884 BOE and estimated net proved reserves of
268,544 BOE were the basis of the depletion rate calculation.
General and Administrative - The following table summarizes the components
of general and administration expenses:
Nine Months ended May 31,
------------------------------------
2011 2010
----------------- ----------------
Stock based compensation $ 553,518 $ 17,790
Other general and
administrative 1,772,824 968,574
Capitalized general and
administrative (154,621) -
----------------- ----------------
Totals $ 2,171,721 $ 986,364
================= ================
The stock-based compensation recorded in general and administrative
expenses related to the issuance of stock grants and stock options to officers,
directors, consultants, and employees. The expense recorded for stock grants is
based on the market value of the common stock on the date of grant. When stock
options are issued we estimate their fair value using the Black-Scholes-Merton
option-pricing model. The estimated fair value is recorded as a non-cash expense
on a pro-rata basis over the vesting period.
Other general and administrative expenses, which include salaries,
benefits, professional fees, and other corporate overhead, increased
approximately $794,000 during the current nine-month period over the comparable
period in the prior year due to the growth in our business. The following items
contributed to the increase: salaries and benefits increased by $630,000 as we
increased the number of employees from three to ten, reservoir engineering fees
increased by approximately $30,000, and we incurred additional professional fees
of approximately $150,000 related to the acquisition of assets from PEM. The
increased expenses in these areas were somewhat offset by a $90,000 decrease in
administrative services purchased from a related party.
Certain general and administrative expenses are directly related to the
acquisition and development of oil and gas properties. Those costs were
reclassified from general and administrative expense into capitalized costs in
the full cost pool.
Other Income (Expense) - During the nine months ended May 31, 2011, we
recognized $14,434,499 in other expenses compared to $4,009,168 during the
comparable period in 2010. The amounts included in other income (expense) are
primarily related to components of the 8% convertible promissory notes.. The
notes, contained a conversion feature which was considered an embedded
derivative and recorded as a liability at its estimated fair value, when
marked-to-market, over time is reflected as a non-cash item in the statement of
operations. The change in fair value increased by $7,464,341, from $2,764,888
21
during the nine months ended May 31, 2010, to $10,229,229 during the nine months
ended May 31, 2011
In addition, the line item of interest expense, net, contains several
components related to the 8% convertible promissory notes. In addition to the 8%
coupon rate, we recorded amortization of debt issue costs of $1,587,799 and
accretion of debt discount of $2,664,138 during the nine months ended May 31,
2011. During the comparable period ended May 31, 2010, amortization of debt
issue costs was $283,535 and accretion of debt discount was $622,214.
Income Taxes - Our effective tax rate is currently zero. We have reported a
net loss every year since inception and for tax purposes have a net operating
loss carry forward ("NOL") of approximately $10,000,000. The NOL is available to
offset future taxable income, if any. At such time, if ever, that we are able to
demonstrate that it is more likely than not that we will be able to realize the
benefits of our tax assets, we will recognize the benefits in our financial
statements. If operational results for the remainder of the fiscal year continue
to improve, we may recognize the benefits of certain tax assets during the
latter periods of the year.
Liquidity and Capital Resources
Our sources and (uses) of funds for the periods indicated, are shown below:
Year Ended August 31, Nine Months Ended May 31,
------------------------------ ----------------------------
2010 2009 2011 2010
-------------- -------------- ------------- -------------
Cash provided by
(used in) operations $(2,443,059) $(1,626,139) $3,824,882 $(984,550)
Acquisition of oil
and gas properties
equipment (9,152,175) (1,658,035) (21,163,392) (5,717,527)
Deposit - (85,000) - -
Proceeds from sale
of convertible
notes, net of debt
issuance costs 16,651,023 - - -
(Repayment)/proceeds
from bank loan (1,161,811) 1,161,811 - -
Proceeds from sale
of common stock and
warrants, net of
offering costs - 2,766,694 16,690,721 16,651,023
Sale of oil and gas
leases - - 4,995,817 -
Principal payments
on convertible notes - - (1,161,811)
Other - 2,987 - -
-------------- -------------- ------------- -------------
Net increase in cash $ 3,893,978 $ 562,318 $4,348,028 $8,787,135
============== ============== ============= =============
22
Between December 2009 and March 2010, we received net proceeds of
approximately $16.7 million from the private sale of 180 Units. The Units were
sold at a price of $100,000 per Unit. Each Unit consisted of one promissory note
in the principal amount of $100,000 and 50,000 Series C warrants. The notes bore
interest at 8% per year, payable quarterly, and were payable on December 31,
2012. At any time after May 31, 2010, the notes could be converted into shares
of our common stock, at a conversion price of $1.60 per share. Each Series C
warrant entitles the holder to purchase one share of our common stock at a price
of $6.00 per share at any time on or before December 31, 2014.
The proceeds from the sale of the Units were used to drill and complete oil
and gas wells in the Wattenberg Field located in the D-J Basin.
During the twelve month period between May 31, 2010, and May 31, 2011, all
convertible promissory notes were converted into 11,250,000 shares of our common
stock.
On January 11, 2011, we completed the sale of 9 million shares of our
common stock in a private offering. The shares were sold at a price of $2.00 per
share. Net proceeds to us from the sale of the shares were $16,690,721 after
deductions for sales commissions and expenses.
On March 21, 2011, we sold oil and gas leases covering 3,502 gross acres
(2,383 net acres) for net cash proceeds of $4,995,817, after the deduction of
selling costs of $248,700.
On May 24, 2011, we acquired certain assets from PEM for a cash payment of
$10,000,000, issuance of 1,381,818 shares of restricted common stock valued at
$4,698,181, and a $5,200,000 promissory note that matures on January 2, 2012.
In a transaction which closed on July 21, 2011, we sold oil and gas leases
covering 2,400 gross acres (1,355 net acres) for cash proceeds of $3,386,350.
Cash payments for the acquisition of oil and gas properties, drilling
costs, and other development activities for the nine months ended May 31, 2011
and 2010, were $21,163,392 and $5,717,527, respectively. These amounts differ
from the amounts reported as the increase in capitalized costs during the
period, which differences reflect non cash items plus the timing of when the
capital expenditure obligations are incurred and when the actual cash payment is
made. A reconciliation of the differences is summarized in the following table:
23
Nine Months Ended May 31,
-----------------------------------------
2011 2010
--------------------- -----------------
Cash payments $ 21,163,392 $ 5,717,524
Accrued costs, beginning of
period (3,446,439) -
Accrued costs, end of period 2,242,117 1,526,113
Properties acquired in exchange
for common stock 7,603,698 -
Properties acquired in exchange
for note payable 5,200,000 -
Proceeds from sale of properties (4,995,817) -
Asset retirement obligation 242,357 184,305
Other (64,568) -
--------------------- ------------------
Increase in capitalized costs $ 27,944,740 $ 7,427,942
===================== ==================
Under full cost accounting requirements, the proceeds from the sale of
mineral interests are generally credited to the full cost pool and no gain or
loss in recognized, unless the transaction would have a significant impact on
proved reserves or the future rate of depreciation, depletion, and amortization
(DDA). The sale completed during the quarter ended May 31, 2011, was noteworthy,
but did not reach the level of significance required to recognize a gain. Our
accounting method reduced the amortization base used in the DDA calculation by
approximately 12% and it is estimated that future amortization expense will be
reduced by approximately $2.29 per BOE.
Capital expenditures for the nine months ended May 31, 2011, included the
acquisition of eight existing wells, 15 drill sites, and associated equipment
for a purchase price of $1,017,435, completion and rework activities on wells
previously drilled, and drilling additional 14 wells in Weld County, Colorado.
Our operating cash requirements are expected to approximate $250,000 per
month, which amount includes salaries and other corporate overhead of $150,000
and lease operating expenses of $100,000. During the current fiscal year, we
began to generate meaningful cash flow from operations, and we expect that the
revenue from wells recently placed into production will further improve our cash
flow.
Our primary need for cash during the fiscal year ending August 31, 2012
will be to fund our acquisition and drilling program. Although our recent sale
of securities for gross proceeds of $18 million plus our recent sales of mineral
interests for cash proceeds of $8.6 million plus our recent acquisition of
mineral interests in exchange for shares of common stock will provide some of
the capital resources required to fund our capital expenditure plans, we may
seek additional funding to expand our plans or to provide additional resources
for our 2012 drilling program. We have not completed our capital budget for
2012. On a tentative basis, we expect to budget between $35 million and $50
million on the acquisition of mineral interests and drilling new wells. Our
capital expenditure estimate is subject to significant adjustment for drilling
success, acquisition opportunities, operating cash flow, and available capital
resources.
24
We plan to generate profits by drilling or acquiring productive oil or gas
wells. However, we may need to raise some of the funds required to drill new
wells through the sale of our securities, from loans from third parties or from
third parties willing to pay our share of drilling and completing the wells. We
may not be successful in raising the capital needed to drill or acquire oil or
gas wells. Any wells which may be drilled by us may not produce oil or gas in
commercial quantities.
Contractual Obligations
The following table summarizes our contractual obligations as of August 31,
2010:
2011 2012 2013 Total
---- ---- ---- -----
Employment Agreements $ 600,000 $ 600,000 $ 600,000 $ 1,800,000
Principal - Convertible
Promissory Notes - - $15,908,000 $ 15,908,000(1)
Interest - Convertible
Promissory Notes $1,233,000 $1,233,000 $ 617,000 $ 3,083,000(1)
(1) As of September 15, 2011, all convertible promissory notes had been
converted into 11,250,000 shares of our common stock.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements that have or are
reasonable likely to have a current or future material effect on our financial
condition, changes in financial condition, results of operations, liquidity or
capital resources.
Outlook
The factors that will most significantly affect our results of operations
include (i) activities on properties that we do not operate, (ii) the
marketability of our production, (iii) our ability to satisfy our substantial
capital requirements, (iv) completion of acquisitions of additional properties
and reserves, (v) competition from larger companies and (vi) prices for oil and
gas. Our revenues will also be significantly impacted by our ability to maintain
or increase oil or gas production through exploration and development
activities.
It is expected that our principal source of cash flow will be from the
production and sale of oil and gas reserves which are depleting assets. Cash
flow from the sale of oil and gas production depends upon the quantity of
production and the price obtained for the production. An increase in prices will
permit us to finance our operations to a greater extent with internally
generated funds, may allow us to obtain equity financing more easily or on
better terms, and lessens the difficulty of obtaining financing. However, price
increases heighten the competition for oil and gas prospects, increase the costs
of exploration and development, and, because of potential price declines,
increase the risks associated with the purchase of producing properties during
times that prices are at higher levels.
25
A decline in oil and gas prices (i) will reduce our cash flow which in turn
will reduce the funds available for exploring for and replacing oil and gas
reserves, (ii) will increase the difficulty of obtaining equity and debt
financing and worsen the terms on which such financing may be obtained, (iii)
will reduce the number of oil and gas prospects which have reasonable economic
terms, (iv) may cause us to permit leases to expire based upon the value of
potential oil and gas reserves in relation to the costs of exploration, (v) may
result in marginally productive oil and gas wells being abandoned as
non-commercial, and (vi) may increase the difficulty of obtaining financing.
However, price declines reduce the competition for oil and gas properties and
correspondingly reduce the prices paid for leases and prospects.
Other than the foregoing, we do not know of any trends, events or
uncertainties that will have had or are reasonably expected to have a material
impact on our sales, revenues or expenses.
Critical Accounting Policies
The discussion and analysis of our financial condition and results of
operations are based upon our financial statements, which have been prepared in
accordance with accounting principles generally accepted in the United States.
The preparation of these financial statements requires us to make estimates and
assumptions that affect the reported amounts of assets, liabilities, including
oil and gas reserves, and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Management routinely makes judgments and
estimates about the effects of matters that are inherently uncertain. Management
bases its estimates and judgments on historical experience and on various other
factors that are believed to be reasonable under the circumstances, the results
of which form the basis for making judgments about the carrying values of assets
and liabilities that are not readily apparent from other sources. Estimates and
assumptions are revised periodically and the effects of revisions are reflected
in the financial statements in the period it is determined to be necessary.
Actual results could differ from these estimates.
We provide expanded discussion of our more significant accounting policies,
estimates and judgments below. We believe these accounting policies reflect our
more significant estimates and assumptions used in preparation of our financial
statements. See Note 1 of the Notes to the financial statements for a discussion
of additional accounting policies and estimates made by management.
Oil and Gas Properties: We use the full cost method of accounting for costs
related to its oil and gas properties. Accordingly, all costs associated with
acquisition, exploration, and development of oil and gas reserves (including the
costs of unsuccessful efforts) are capitalized into a single full cost pool.
These costs include land acquisition costs, geological and geophysical expense,
carrying charges on non-producing properties, costs of drilling, and overhead
charges directly related to acquisition and exploration activities. Under the
full cost method, no gain or loss is recognized upon the sale or abandonment of
oil and gas properties unless non-recognition of such gain or loss would
significantly alter the relationship between capitalized costs and proved oil
and gas reserves.
Capitalized costs of oil and gas properties are amortized using the
unit-of-production method based upon estimates of proved reserves. For
amortization purposes, the volume of petroleum reserves and production is
26
converted into a common unit of measure at the energy equivalent conversion rate
of six thousand cubic feet of natural gas to one barrel of crude oil.
Investments in unevaluated properties and major development projects are not
amortized until proved reserves associated with the projects can be determined
or until impairment occurs. If the results of an assessment indicate that the
properties are impaired, the amount of the impairment is added to the
capitalized costs to be amortized.
Under the full cost method of accounting, a ceiling test is performed each
quarter. The full cost ceiling test is an impairment test prescribed by SEC
regulations. The ceiling test determines a limit on the book value of oil and
gas properties. The capitalized costs of proved and unproved oil and gas
properties, net of accumulated depreciation, depletion, and amortization, and
the related deferred income taxes, may not exceed the estimated future net cash
flows from proved oil and gas reserves, less future cash outflows associated
with asset retirement obligations that have been accrued, plus the cost of
unevaluated properties being amortized, plus the lower of cost or estimated fair
value of unevaluated properties not being amortized, less income tax effects.
Prices are held constant for the productive life of each well. Net cash flows
are discounted at 10%. If net capitalized costs exceed this limit, the excess is
charged to expense and reflected as additional accumulated depreciation,
depletion and amortization. The calculation of future net cash flows assumes
continuation of current economic conditions. Once impairment expense is
recognized, it cannot be reversed in future periods, even if increasing prices
raise the ceiling amount.
Oil and Gas Reserves: The determination of depreciation, depletion and
amortization expense, as well as the ceiling test related to the recorded value
of our oil and natural gas properties, will be highly dependent on the estimates
of the proved oil and natural gas reserves. Oil and natural gas reserves include
proved reserves that represent estimated quantities of crude oil and natural gas
which geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic and
operating conditions. There are numerous uncertainties inherent in estimating
oil and natural gas reserves and their values, including many factors beyond our
control. Accordingly, reserve estimates are often different from the quantities
of oil and natural gas ultimately recovered and the corresponding lifting costs
associated with the recovery of these reserves.
Fair Value Measurements: Effective September 1, 2008, we adopted FASB
Accounting Standards Codification ("ASC") "Fair Value Measurements and
Disclosures", which establishes a framework for assets and liabilities measured
at fair value on a recurring basis included in our balance sheets. Effective
September 1, 2009, similar accounting guidance was adopted for assets and
liabilities measured at fair value on a nonrecurring basis. As defined in the
guidance, fair value is the price that would be received to sell an asset or be
paid to transfer a liability in an orderly transaction between market
participants at the measurement date (exit price).
We use market data or assumptions that market participants would use in
pricing the asset or liability, including assumptions about risk. These inputs
can either be readily observable, market corroborated or generally unobservable.
Fair value balances are classified based on the observability of the various
inputs.
Asset Retirement Obligations: Our activities are subject to various laws
and regulations, including legal and contractual obligations to reclaim,
remediate, or otherwise restore properties at the time the asset is permanently
removed from service. The fair value of a liability for the asset retirement
27
obligation ("ARO") is initially recorded when it is incurred if a reasonable
estimate of fair value can be made. This is typically when a well is completed
or an asset is placed in service. When the ARO is initially recorded, we
capitalize the cost (asset retirement cost or "ARC") by increasing the carrying
value of the related asset. Over time, the liability increases for the change in
its present value (accretion of ARO), while the capitalized cost decreases over
the useful life of the asset. The capitalized ARCs are included in the full cost
pool and subject to depletion, depreciation and amortization. In addition, the
ARCs are included in the ceiling test calculation. Calculation of an ARO
requires estimates about several future events, including the life of the asset,
the costs to remove the asset from service, and inflation factors. The ARO is
initially estimated based upon discounted cash flows over the life of the asset
and is accreted to full value over time using our credit adjusted risk free
interest rate. Estimates are periodically reviewed and adjusted to reflect
changes.
Derivative Conversion Liability: We account for embedded conversion
features in our convertible promissory notes in accordance with the guidance for
derivative instruments, which require a periodic valuation of their fair value
and a corresponding recognition of liabilities associated with such derivatives.
The recognition of derivative conversion liabilities related to the issuance of
convertible debt is applied first to the proceeds of such issuance as a debt
discount at the date of the issuance. Any subsequent increase or decrease in the
fair value of the derivative conversion liabilities is recognized as a charge or
credit to other income (expense) in the statements of operations.
Revenue Recognition: Revenue is recognized for the sale of oil and natural
gas when production is sold to a purchaser and title has transferred. Revenues
from production on properties in which we share an economic interest with other
owners are recognized on the basis of our interest. Provided that reasonable
estimates can be made, revenue and receivables are accrued and adjusted upon
settlement of actual volumes and prices, as payment is received often sixty to
ninety days after production.
Stock Based Compensation: We record stock-based compensation expense in
accordance with the fair value recognition provisions of US GAAP. Stock based
compensation is measured at the grant date based upon the estimated fair value
of the award and the expense is recognized over the required employee service
period, which generally equals the vesting period of the grant. The fair value
of stock options is estimated using the Black-Scholes-Merton option-pricing
model. The fair value of restricted stock grants is estimated on the grant date
based upon the fair value of the common stock.
Recent Accounting Pronouncements: We evaluate the pronouncements of various
authoritative accounting organizations, primarily the Financial Accounting
Standards Board ("FASB"), the Securities and Exchange Commission ("SEC"), and
the Emerging Issues Task Force ("EITF"), to determine the impact of new
pronouncements on US GAAP and the impact on the Company.
We have recently adopted the following new accounting standards:
Effective September 1, 2010, we adopted ASU No. 2010-11 - Derivatives and
Hedging, which was issued in March 2010 and clarifies that the transfer of
credit risk that is only in the form of subordination of one financial
instrument to another is an embedded derivative feature that should not be
28
subject to potential bifurcation and separate accounting. Adoption of the ASU
had no material effect on our financial position, results of operations, or cash
flows.
There were various other updates recently issued, most of which represented
technical corrections to the accounting literature or were applicable to
specific industries, and are not expected to have a material impact on our
financial position, results of operations or cash flows.
BUSINESS
We are an oil and gas operator in Colorado and are focused on the
acquisition, development, exploitation, exploration and production of oil and
natural gas properties primarily located in the Wattenberg field in the D-J
Basin in northeast Colorado. As of September 15, 2011, we had 181,500 gross and
160,800 net acres under lease, most of which are located in the D-J Basin. Of
this acreage, 5,547 gross acres are held by production. Between September 1,
2008 and September 15, 2011, we drilled and completed 52 development wells on
our leases. We have not completed our reserve analysis for the period ended
August 31, 2011. In our most recent complete reserve report available, effective
for the period ended August 31, 2010, our estimated net proved oil and gas
reserves, as prepared by our independent reserve engineering firm, Ryder Scott
Company, L.P., were 4.5 Bcf of natural gas and 676.7 MBbls of oil and
condensate.
Business Strategy
Our primary objective is to enhance shareholder value by increasing our net
asset value, net reserves and cash flow through acquisitions, development,
exploitation, exploration and divestiture of oil and gas properties. We intend
to follow a balanced risk strategy by allocating capital expenditures in a
combination of lower risk development and exploitation activities and higher
potential exploration prospects. Key elements of our business strategy include
the following:
o Concentrate on our existing core area in the D-J Basin, where we have
significant operating experience. All of our current wells and
undeveloped acreage are located within the D-J Basin. Focusing our
operations in this area leverages our management, technical and
operational experience in the basin.
o Develop and exploit existing oil and natural gas properties. Since our
inception our principal growth strategy has been to develop and
exploit our acquired and discovered properties to add proved reserves.
As of September 15, 2011, we have identified over four hundred
development and extension drilling locations and over twenty
recompletion/workover projects on our existing properties and wells.
o Complete selective acquisitions. We seek to acquire undeveloped and
producing oil and gas properties, primarily in the D-J Basin. We will
seek acquisitions of undeveloped and producing properties that will
provide us with opportunities for reserve additions and increased cash
flow through production enhancement and additional development and
exploratory prospect generation opportunities.
o Retain control over the operation of a substantial portion of our
production. As operator on a majority of our wells and undeveloped
acreage, we control the timing and selection of new wells to be
drilled or existing wells to be recompleted. This allows us to modify
our capital spending as our financial resources allow and market
conditions support.
29
o Maintain financial flexibility while focusing on controlling the costs
of our operations. We intend to finance our operations through a
mixture of debt and equity capital as market conditions allow. Our
management has historically been a low cost operator in the D-J Basin
and we continue to focus on operating efficiencies and cost
reductions.
Our growth plans for the fiscal year ending August 31, 2012 include
additional drilling activities, acquisition of existing wells, and recompletion
of wells that provide good prospects for improved stimulation techniques.
Implementation of our growth plans will be dependent upon the amount of
financing we are able to obtain.
Competitive Strengths
We believe that we are positioned to successfully execute our business
strategy because of the following competitive strengths:
o Management experience. Our key management team possesses an average of
thirty years of experience in the oil and gas industry, primarily
within the D-J Basin. Members of our management team have drilled,
participated in drilling, and/or operated over 350 wells in the D-J
Basin.
o Balanced oil and natural gas reserves and production. Approximately
48% of our estimated proved reserves were oil and condensate and 52%
were natural gas. We believe this balanced commodity mix will provide
diversification of sources of cash flow and will lessen the risk of
significant and sudden decreases in revenue from short-term commodity
price movements.
o Ability to recomplete D-J Basin wells numerous times throughout the
life of a well. We have experience with and knowledge of D-J Basin
wells that have been recompleted up to four times since initial
drilling. This provides us with numerous high return recompletion
investment opportunities on our current and future wells and the
ability to manage the production through the life of a well.
o Insider ownership. At September 15, 2011 our directors and executive
officers beneficially owned approximately 33% of our outstanding
shares of common stock, providing a strong alignment of interest
between management, the board of directors and our outside
shareholders.
30
Recent Developments
On October 7, 2010, we completed the acquisition of oil and gas properties
in the Wattenberg Field within the D-J Basin from Petroleum Management, LLC and
Petroleum Exploration & Management, LLC for approximately $1.0 million. These
properties include 6 producing oil and gas wells (100% working interest/ 80% net
revenue interest), 2 shut in oil wells (100% working interest/ 80% net revenue
interest), 15 drill sites (net 6.25 wells) and miscellaneous equipment. See
"Transactions with Related Parties" for more information.
In March 2011, we issued 1,125,699 shares of restricted common stock valued
at $2,741,917 for mineral interests comprising 78,805 gross acres (69,274 net
acres) in the D-J Basin.
In February 2011, we acquired oil and gas leases covering 5,724 acres in
Larimer, Park, and Yuma counties, Colorado for approximately $265,000.
In December 2010, we acquired four producing wells in an area that is
adjacent to one of our leases. We paid cash consideration of $400,000 and
assigned the lease rights on 340 net acres in northern PlaceNameplaceWeld
PlaceTypeCounty to the seller.
In a transaction which closed on March 21, 2011, we sold oil and gas leases
covering 3,502 gross acres (2,383 net acres). We received cash proceeds of
$5,244,517 and paid cash costs of $248,700 to record net proceeds of $4,995,817
from the sale.
On May 24, 2011, we acquired interests in 88 oil and gas wells and oil and
gas leases covering approximately 6,968 gross acres from Petroleum Exploration
and Management, LLC ("PEM"), a company owned by Ed Holloway and William E.
Scaff, Jr., two of our officers. The total purchase price, which consisted of
$10 million in cash, 1,381,818 restricted shares of our common stock and a
promissory note in the principal amount of $5.2 million, totaled $19 million,
and is subject to customary post closing adjustments for transactions that
occurred between January 1, 2011 and May 24, 2011. All of the properties
acquired from PEM are located in the Wattenberg Field of the D-J Basin.
On January 11, 2011, we closed on the sale of 9 million shares of common
stock to private investors. The shares were sold at a price of $2.00 per share.
Net proceeds from the sale of the shares were approximately $16.7 million after
deductions for the sales commissions and expenses.
On June 8, 2011, we entered into a revolving line of credit with Bank of
Choice, which allows us to borrow up to $7 million. Amounts borrowed under the
line of credit are secured by certain of our assets as well as 64 oil and gas
wells in which we have a working interest. Principal amounts outstanding under
the line of credit bear interest, payable monthly, at the prime rate plus 2%,
subject to a minimum interest rate of 5.5%.
On June 23, 2011, we issued 159,485 shares of common stock in exchange for
mineral interests in 18,136 gross acres (15,862 net acres). The transactions had
an aggregate value of $526,000.
31
In a transaction which closed on July 21, 2011, we sold undeveloped oil and
gas leases covering 2,400 gross acres (1,355 net acres) for cash proceeds of
$3,386,350.
Well and Production Data
Since September 2008, and through September 15, 2011, we have drilled and
completed 52 oil and gas wells.
During the periods presented, we drilled or participated in the drilling of
the following wells. We did not drill any exploratory wells during these years.
Years Ended August 31, Nine Months
--------------------------- -----------
2010 2009 Ended May 31, 2011
------------- ------------ ------------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Development Wells:
Productive:
Oil 36 23.8 2 0.75 6 5
Gas - - - - - -
Nonproductive - - - - - -
Total Wells: 36 23.8 2 0.75 6 5
As of September 15, 2011 we were drilling one well and were completing 6 (6
net) wells. These wells were all located in the Wattenberg Field of the D.J.
Basin.
The following table shows our net production of oil and gas, average sales
prices and average production costs for the periods presented:
Nine Months
-----------
Years Ended August 31, Ended May 31,
--------------------------- ------------------
2010 2009 2011 2010
------------- ------------ ---- ----
Production
----------
Oil (Bbls) 21,080 1,730 59,749 8,327
Gas (Mcf) 141,154 4,386 297,668 75,340
Average sales price
-------------------
Oil ($/Bbl) $ 68.38 $ 45.59 $ 85.02 $ 70.52
Gas ($/Mcf) $ 5.08 $ 3.48 $ 4.43 $ 5.42
Average production
------------------
costs per BOE $ 1.94 $ 0.85 $ 1.86 $ 2.22
Production costs are substantially similar among our wells as all of our
wells are in the Wattenberg Field and employ the same methods of recovery.
Production costs generally include pumping fees, maintenance, repairs, labor,
utilities and administrative overhead. Taxes on production, including advalorem
and severance taxes, are not included in production costs.
We are not obligated to provide a fixed and determined quantity of oil or
gas to any third party in the future. During the last three fiscal years, we
have not had, nor do we now have, any long-term supply or similar agreement with
any government or governmental authority.
32
Prior to September 1, 2008, we did not drill, or participate in the
drilling, of any oil or gas wells, or produce or sell any oil or gas.
Oil and Gas Properties and Proven Reserves
We evaluate undeveloped oil and gas prospects and participate in drilling
activities on those prospects, which, in the opinion of our management, are
favorable for the production of oil or gas. If, through our review, a
geographical area indicates geological and economic potential, we will attempt
to acquire leases or other interests in the area. We may then attempt to sell
portions of our leasehold interests in a prospect to third parties, thus sharing
the risks and rewards of the exploration and development of the prospect with
the other owners. One or more wells may be drilled on a prospect, and if the
results indicate the presence of sufficient oil and gas reserves, additional
wells may be drilled on the prospect.
We may also:
o acquire a working interest in one or more prospects from others and
participate with the other working interest owners in drilling, and if
warranted, completing oil or gas wells on a prospect, or
o purchase producing oil or gas properties.
Our activities are primarily dependent upon available financing.
Title to properties we acquire may be subject to royalty, overriding
royalty, carried, net profits, working and other similar interests and
contractual arrangements customary in the oil and gas industry, to liens for
current taxes not yet due and to other encumbrances. As is customary in the
industry, in the case of undeveloped properties, little investigation of record
title will be made at the time of acquisition (other than a preliminary review
of local records). However, drilling title opinions may be obtained before
commencement of drilling operations.
The following table shows, as of September 15, 2011, by state, our
producing wells, developed acreage, and undeveloped acreage, excluding service
(injection and disposal) wells:
Productive Wells Developed Acreage Undeveloped Acreage
-------------------- -------------------- ---------------------
State Gross Net Gross Net Gross Net
----------- --------- --------- --------- --------- --------- ----------
Colorado 133 95 5,222 5,222 58,330 39,289
Nebraska - - - - 118,009 116,361
--------- --------- --------- --------- --------- ----------
Total 133 95 5,222 5,222 176,339 155,650
========= ========= ========= ========= ========= ==========
(1) Undeveloped acreage includes leasehold interests on which wells have not
been drilled or completed to the point that would permit the production of
commercial quantities of natural gas and oil regardless of whether the
leasehold interest is classified as containing proved undeveloped reserves.
33
The following table shows, as of September 15, 2011, the status of our
gross acreage:
Held by Not Held by
State Production Production
----------- ----------------- ---------------------
Colorado 6,185 57,367
Nebraska - 118,009
----------------- ---------------------
Total 6,185 175,376
================= =====================
Acres that are Held by Production remain in force so long as oil or gas is
produced from the well on the particular lease. Leased acres which are not Held
By Production often require annual rental payments to maintain the lease until
the first to occur of the following: the expiration of the lease or the time oil
or gas is produced from one or more wells drilled on the leased acreage. At the
time oil or gas is produced from wells drilled on the leased acreage, the lease
is considered to be Held by Production.
The following table shows the years our leases, which are not Held By
Production, will expire, unless a productive oil or gas well is drilled on the
lease.
Leased Expiration
Acres of Lease
------------ -----------
1,229 2012
9,299 2013
10,986 2014
153,862 After 2014
We do not own any significant overriding royalty interests.
Ryder Scott Company, L.P. ("Ryder Scott") prepared the estimates of our
proved reserves, future productions and income attributable to our leasehold
interests for the year ended August 31, 2010. Ryder Scott is an independent
petroleum engineering firm that has been providing petroleum consulting services
worldwide for over seventy years. The estimates of proven reserves, future
production and income attributable to certain leasehold and royalty interests
are based on technical analysis conducted by teams of geoscientists and
engineers employed at Ryder Scott. The report of Ryder Scott is filed as Exhibit
99 to this registration statement. Ryder Scott was selected by two of our
officers, Ed Holloway and William E. Scaff, Jr.
Thomas E. Venglar was the technical person primarily responsible for
overseeing the preparation of the reserve report. Mr. Venglar earned a Bachelor
of Science degree in Petroleum Engineering from PlaceNameTexas PlaceNameA&M
PlaceTypeUniversity and is a registered Professional Engineer in
placeStateColorado. Mr. Venglar has more than 30 years of practical experience
in the estimation and evaluation of petroleum reserves.
Ed Holloway, our President, oversaw the preparation of the reserve
estimates by Ryder Scott. Mr. Holloway has over thirty years experience in oil
34
and gas exploration and development. We do not have a reserve committee and we
do not have any specific internal controls regarding the estimates of our
reserves.
Our proved reserves include only those amounts which we reasonably expect
to recover in the future from known oil and gas reservoirs under existing
economic and operating conditions, at current prices and costs, under existing
regulatory practices and with existing technology. Accordingly, any changes in
prices, operating and development costs, regulations, technology or other
factors could significantly increase or decrease estimates of proved reserves.
Estimates of volumes of proved reserves at year end are presented in
barrels (Bbls) for oil and for, natural gas, in millions of cubic feet (Mcf) at
the official temperature and pressure bases of the areas in which the gas
reserves are located.
The proved reserves attributable to producing wells and/or reservoirs were
estimated by performance methods. These performance methods include decline
curve analysis, which utilized extrapolations of historical production and
pressure data available through August 31, 2010 in those cases where this data
was considered to be definitive. The data used in this analysis obtained from
public data sources and were considered sufficient for calculating producing
reserves.
The proved non-producing and undeveloped reserves were estimated by the
analogy method. The analogy method uses pertinent well data, obtained from
public data sources that were available through August 2010.
Below are estimates of our net proved reserves, all of which are located in
Colorado.
Summary of Oil and Gas Reserves as of August 31, 2010
Oil Gas BOE
--- --- ---
(Bbls) (MCF)
Proved Developed
Producing 125,159 887,290 273,041
Non- Producing 270,294 1,461,737 513,917
Proved Undeveloped 281,232 2,132,024 636,569
------- --------- ----------
676,685 4,481,051 1,423,527
======= ========= =========
As of May 31, 2011, we had estimated proved reserves of 1,721,647 Bbls of
oil and 13,586,923 Mcf of gas.
Below are estimates of our present value of estimated future net revenues
from such reserves based upon the standardized measure of discounted future net
cash flows relating to proved oil and gas reserves in accordance with the
provisions of Accounting Standards Codification Topic 932, Extractive Activities
- Oil and Gas. The standardized measure of discounted future net cash flows is
determined by using estimated quantities of proved reserves and the periods in
which they are expected to be developed and produced based on period-end
economic conditions. The estimated future production is based upon benchmark
prices that reflect the unweighted arithmetic average of the
first-day-of-the-month price for oil and gas during the twelve months period
ended August 31, 2010. The resulting estimated future cash inflows are then
reduced by estimated future costs to develop and produce reserves based on
35
period-end cost levels. No deduction has been made for depletion, depreciation
or for indirect costs, such as general corporate overhead. Present values were
computed by discounting future net revenues by 10% per year.
Proved
--------------------------------------------------
Developed
------------------------- Total
Producing Non-Producing Undeveloped Proved
--------- ------------- ----------- ------
Future gross revenue $12,323,383 $24,126,662 $28,220,857 $64,670,902
Deductions (3,591,012) (10,865,282) (24,687,877) (39,144,171)
Future net cash flow $ 8,732,371 $13,261,380 $ 3,532,980 $25,526,731
Discounted future net
cash flow $ 4,813,654 $ 6,846,165 $ 1,362,578 $13,022,397
In general, the volume of production from our oil and gas properties
declines as reserves are depleted. Except to the extent we acquire additional
properties containing proved reserves or conduct successful exploration and
development activities, or both, our proved reserves will decline as reserves
are produced. Accordingly, volumes generated from our future activities are
highly dependent upon the level of success in acquiring or finding additional
reserves and the costs incurred in doing so.
As of August 31, 2009 our proved developed reserves consisted or 6,430 Bbls
of oil and 25,680 Mcf of gas. As of August 31, 2009 we did not have any proved
undeveloped reserves. Our proved developed and undeveloped reserves increased
substantially during the year ended August 31, 2010, primarily as the result of
our drilling and completing 36 gross (23.8) net wells. The technologies used to
establish the proved reserves associated with these 36 wells were the same as
were used by Ryder Scott to estimate our proved reserves as of August 31, 2010.
Acquisition of Oil and Gas Properties from Petroleum Exploration & Management
On May 24, 2011 we acquired the following oil and gas properties from
Petroleum Exploration and Management, LLC (`PEM"), a company owned equally by Ed
Holloway and William E. Scaff, Jr., two of our officers and directors:
o 87 producing oil and gas wells;
o one shut-in well; and
o oil and gas leases covering approximately 6,968 gross acres.
PEM's working interest in the wells ranges between 3% and 100%. PEM's net
revenue interest in the wells ranges between 2.44% and 80%.
The acquisition was approved by:
o a majority of our disinterested directors, and
o the vote of our shareholders owning a majority of the shares in
attendance at a special meeting of our shareholders held on May 23,
2011, with Mr. Holloway and Mr. Scaff not voting.
36
In consideration for the oil and gas properies we paid PEM $10,000,000 in
cash and issued PEM 1,381,818 shares of our restricted common stock and a
promissory note in the principal amount of $5,200,000. The note pays interest
annually at 5.25%, is due on January 2, 2012, and is secured by the assets
acquired from PEM. We did not assume any of PEM's liabilities.
All of the properties acquired from PEM are located in the Denver-Julesburg
Basin.
Government Regulation
Various state and federal agencies regulate the production and sale of oil
and natural gas. All states in which we plan to operate impose restrictions on
the drilling, production, transportation and sale of oil and natural gas.
The Federal Energy Regulatory Commission ("FERC") regulates the interstate
transportation and the sale in interstate commerce for resale of natural gas.
FERC's jurisdiction over interstate natural gas sales has been substantially
modified by the Natural Gas Policy Act under which FERC continued to regulate
the maximum selling prices of certain categories of gas sold in "first sales" in
interstate and intrastate commerce.
FERC has pursued policy initiatives that have affected natural gas
marketing. Most notable are (1) the large-scale divestiture of interstate
pipeline-owned gas gathering facilities to affiliated or non-affiliated
companies; (2) further development of rules governing the relationship of the
pipelines with their marketing affiliates; (3) the publication of standards
relating to the use of electronic bulletin boards and electronic data exchange
by the pipelines to make available transportation information on a timely basis
and to enable transactions to occur on a purely electronic basis; (4) further
review of the role of the secondary market for released pipeline capacity and
its relationship to open access service in the primary market; and (5)
development of policy and promulgation of orders pertaining to its authorization
of market-based rates (rather than traditional cost-of-service based rates) for
transportation or transportation-related services upon the pipeline's
demonstration of lack of market control in the relevant service market. We do
not know what effect FERC's other activities will have on the access to markets,
the fostering of competition and the cost of doing business.
Our sales of oil and natural gas liquids will not be regulated and will be
at market prices. The price received from the sale of these products will be
affected by the cost of transporting the products to market. Much of that
transportation is through interstate common carrier pipelines.
Federal, state, and local agencies have promulgated extensive rules and
regulations applicable to our oil and natural gas exploration, production and
related operations. Most states require permits for drilling operations,
drilling bonds and the filing of reports concerning operations and impose other
requirements relating to the exploration of oil and gas. Many states also have
statutes or regulations addressing conservation matters including provisions for
the unitization or pooling of oil and natural gas properties, the establishment
of maximum rates of production from oil and gas wells and the regulation of
spacing, plugging and abandonment of such wells. The statutes and regulations of
some states limit the rate at which oil and gas is produced from our properties.
The federal and state regulatory burden on the oil and natural gas industry
increases our cost of doing business and affects its profitability. Because
37
these rules and regulations are amended or reinterpreted frequently, we are
unable to predict the future cost or impact of complying with those laws.
As with the oil and natural gas industry in general, our properties are
subject to extensive and changing federal, state and local laws and regulations
designed to protect and preserve our natural resources and the environment. The
recent trend in environmental legislation and regulation is generally toward
stricter standards, and this trend is likely to continue. These laws and
regulations often require a permit or other authorization before construction or
drilling commences and for certain other activities; limit or prohibit access,
seismic acquisition, construction, drilling and other activities on certain
lands lying within wilderness and other protected areas; impose substantial
liabilities for pollution resulting from our operations; and require the
reclamation of certain lands.
The permits required for many of our operations are subject to revocation,
modification and renewal by issuing authorities. Governmental authorities have
the power to enforce compliance with their regulations, and violations are
subject to fines, injunctions or both. In the opinion of our management, we are
in substantial compliance with current applicable environmental laws and
regulations, and we have no material commitments for capital expenditures to
comply with existing environmental requirements. Nevertheless, changes in
existing environmental laws and regulations or in interpretations thereof could
have a significant impact on us, as well as the oil and natural gas industry in
general. The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA") and comparable state statutes impose strict and joint and several
liabilities on owners and operators of certain sites and on persons who disposed
of or arranged for the disposal of "hazardous substances" found at such sites.
It is not uncommon for the neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment. The Resource Conservation
and Recovery Act ("RCRA") and comparable state statutes govern the disposal of
"solid waste" and "hazardous waste" and authorize imposition of substantial
fines and penalties for noncompliance. Although CERCLA currently excludes
petroleum from its definition of "hazardous substance," state laws affecting our
operations impose clean-up liability relating to petroleum and petroleum related
products. In addition, although RCRA classifies certain oil field wastes as
"non-hazardous," such exploration and production wastes could be reclassified as
hazardous wastes, thereby making such wastes subject to more stringent handling
and disposal requirements.
Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as us, to prepare and implement spill
prevention, control countermeasure and response plans relating to the possible
discharge of oil into surface waters. The Oil Pollution Act of 1990 ("OPA")
contains numerous requirements relating to the prevention of and response to oil
spills into waters of the United States. For onshore and offshore facilities
that may affect waters of the United States, the OPA requires an operator to
demonstrate financial responsibility. Regulations are currently being developed
under federal and state laws concerning oil pollution prevention and other
matters that may impose additional regulatory burdens on us. In addition, the
Clean Water Act and analogous state laws require permits to be obtained to
authorize discharge into surface waters or to construct facilities in wetland
areas. The Clean Air Act of 1970 and its subsequent amendments in 1990 and 1997
also impose permit requirements and necessitate certain restrictions on point
source emissions of volatile organic carbons (nitrogen oxides and sulfur
dioxide) and particulates with respect to certain of our operations. We are
required to maintain such permits or meet general permit requirements. The EPA
38
and designated state agencies have in place regulations concerning discharges of
storm water runoff and stationary sources of air emissions. These programs
require covered facilities to obtain individual permits, participate in a group
or seek coverage under an EPA general permit. Most agencies recognize the unique
qualities of oil and natural gas exploration and production operations. A number
of agencies have adopted regulatory guidance in consideration of the operational
limitations on these types of facilities and their potential to emit pollutants.
We believe that we will be able to obtain, or be included under, such permits,
where necessary, and to make minor modifications to existing facilities and
operations that would not have a material effect on us.
The EPA recently amended the Underground Injection Control, or UIC,
provisions of the federal Safe Drinking Water Act (the "SDWA") to exclude
hydraulic fracturing from the definition of "underground injection." However,
the U.S. Senate and House of Representatives are currently considering the FRAC
Act, which will amend the SDWA to repeal this exemption. If enacted, the FRAC
Act would amend the definition of "underground injection" in the SDWA to
encompass hydraulic fracturing activities, which could require hydraulic
fracturing operations to meet permitting and financial assurance requirements,
adhere to certain construction specifications, fulfill monitoring, reporting,
and recordkeeping obligations, and meet plugging and abandonment requirements.
The FRAC Act also proposes to require the reporting and public disclosure of
chemicals used in the fracturing process, which could make it easier for third
parties opposing the hydraulic fracturing process to initiate legal proceedings
based on allegations that specific chemicals used in the fracturing process
could adversely affect groundwater.
On December 15, 2009, the EPA published its findings that emissions of
carbon dioxide, methane and other greenhouse gases present an endangerment to
human health and the environment because emissions of such gases are, according
to the EPA, contributing to the warming of the earth's atmosphere and other
climatic changes. These findings by the EPA allowed the agency to proceed with
the adoption and implementation of regulations that would restrict emissions of
greenhouse gases under existing provisions of the federal Clean Air Act.
Consequently, the EPA proposed two sets of regulations that would require a
reduction in emissions of greenhouse gases from motor vehicles and, also, could
trigger permit review for greenhouse gas emissions from certain stationary
sources. In addition, on October 30, 2009, the EPA published a final rule
requiring the reporting of greenhouse gas emissions from specified large
greenhouse gas emission sources in the United States beginning in 2011 for
emissions occurring in 2010.
Also, on June 26, 2009, the U.S. House of Representatives passed the
American Clean Energy and Security Act of 2009 (the "ACESA") which would
establish an economy-wide cap-and-trade program to reduce United States
emissions of greenhouse gases including carbon dioxide and methane that may
contribute to the warming of the Earth's atmosphere and other climatic changes.
If it becomes law, ACESA would require a 17% reduction in greenhouse gas
emissions from 2005 levels by 2020 and just over an 80% reduction of such
emissions by 2050. Under this legislation, the EPA would issue a capped and
steadily declining number of tradable emissions allowances to certain major
sources of greenhouse gas emissions so that such sources could continue to emit
greenhouse gases into the atmosphere. These allowances would be expected to
escalate significantly in cost over time. The net effect of ACESA will be to
impose increasing costs on the combustion of carbon-based fuels such as oil,
refined petroleum products and natural gas. The U.S. Senate has begun work on
its own legislation for restricting domestic greenhouse gas emissions and
39
President Obama has indicated his support of legislation to reduce greenhouse
gas emissions through an emission allowance system.
Climate change has emerged as an important topic in public policy debate
regarding our environment. It is a complex issue, with some scientific research
suggesting that rising global temperatures are the result of an increase in
greenhouse gases, which may ultimately pose a risk to society and the
environment. Products produced by the oil and natural gas exploration and
production industry are a source of certain greenhouse gases, namely carbon
dioxide and methane, and future restrictions on the combustion of fossil fuels
or the venting of natural gas could have a significant impact on our future
operations.
Competition and Marketing
We will be faced with strong competition from many other companies and
individuals engaged in the oil and gas business, many are very large, well
established energy companies with substantial capabilities and established
earnings records. We may be at a competitive disadvantage in acquiring oil and
gas prospects since we must compete with these individuals and companies, many
of which have greater financial resources and larger technical staffs. It is
nearly impossible to estimate the number of competitors; however, it is known
that there are a large number of companies and individuals in the oil and gas
business.
Exploration for and production of oil and gas are affected by the
availability of pipe, casing and other tubular goods and certain other oil field
equipment including drilling rigs and tools. We will depend upon independent
drilling contractors to furnish rigs, equipment and tools to drill its wells.
Higher prices for oil and gas may result in competition among operators for
drilling equipment, tubular goods and drilling crews which may affect our
ability expeditiously to drill, complete, recomplete and work-over wells.
The market for oil and gas is dependent upon a number of factors beyond our
control, which at times cannot be accurately predicted. These factors include
the proximity of wells to, and the capacity of, natural gas pipelines, the
extent of competitive domestic production and imports of oil and gas, the
availability of other sources of energy, fluctuations in seasonal supply and
demand, and governmental regulation. In addition, there is always the
possibility that new legislation may be enacted, which would impose price
controls or additional excise taxes upon crude oil or natural gas, or both.
Oversupplies of natural gas can be expected to recur from time to time and may
result in the gas producing wells being shut-in. Imports of natural gas may
adversely affect the market for domestic natural gas.
40
The market price for crude oil is significantly affected by policies
adopted by the member nations of Organization of Petroleum Exporting Countries
("OPEC"). Members of OPEC establish prices and production quotas among
themselves for petroleum products from time to time with the intent of
controlling the current global supply and consequently price levels. We are
unable to predict the effect, if any, that OPEC or other countries will have on
the amount of, or the prices received for, crude oil and natural gas.
Gas prices, which were once effectively determined by government
regulations, are now largely influenced by competition. Competitors in this
market include producers, gas pipelines and their affiliated marketing
companies, independent marketers, and providers of alternate energy supplies,
such as residual fuel oil. Changes in government regulations relating to the
production, transportation and marketing of natural gas have also resulted in
significant changes in the historical marketing patterns of the industry.
Generally, these changes have resulted in the abandonment by many pipelines of
long-term contracts for the purchase of natural gas, the development by gas
producers of their own marketing programs to take advantage of new regulations
requiring pipelines to transport gas for regulated fees, and an increasing
tendency to rely on short-term contracts priced at spot market prices.
General
Our offices are located at 20203 Highway 60, Platteville, CO 80651. Our
office telephone number is (970) 737-1073 and our fax number is (970) 737-1045.
The Platteville office and equipment yard is rented to us pursuant to a
lease with HS Land & Cattle, LLC, a firm controlled by Ed Holloway and William
E. Scaff, Jr., two of our officers. The lease requires monthly payments of
$10,000 and expires on June 1, 2012.
As of September 15, 2011, we had eleven full time employees.
MANAGEMENT
Our officers and directors are listed below. Our directors are generally
elected at our annual shareholders' meeting and hold office until the next
annual shareholders' meeting or until their successors are elected and
qualified. Our executive officers are elected by our directors and serve at
their discretion.
N
Name Age Position
---- --- ---------
Edward Holloway 59 President, Chief Executive Officer and
Director
William E. Scaff, Jr. 54 Vice President, Secretary, Treasurer and
Director
Frank L. Jennings 60 Principal Financial and Accounting Officer
Rick A. Wilber 63 Director
Raymond E. McElhaney 55 Director
Bill M. Conrad 55 Director
R.W. Noffsinger, III 37 Director
George Seward 61 Director
41
Edward Holloway - Mr. Holloway has been an officer and director since September
2008 and was an officer and director of our predecessor between June 2008 and
September 2008. Mr. Holloway co-founded Cache Exploration Inc., an oil and gas
exploration and development company that drilled over 350 wells. In 1987, Mr.
Holloway sold the assets of Cache Exploration to LYCO Energy Corporation. He
rebuilt Cache Exploration and sold the entire company to Southwest Energy a
decade later. In 1997, Mr. Holloway co-founded, and since that date has
co-managed, Petroleum Management, LLC, a company engaged in the exploration,
operations, production and distribution of oil and natural gas. In 2001, Mr.
Holloway co-founded, and since that date has co-managed, Petroleum Exploration
and Management, LLC, a company engaged in the acquisition of oil and gas leases
and the production and sale of oil and natural gas. Mr. Holloway holds a degree
in Business Finance from the University of Northern Colorado and is a past
president of the Colorado Oil & Gas Association.
William E. Scaff, Jr. - Mr. Scaff has been an officer and director since
September 2008 and was an officer and director of our predecessor between June
2008 and September 2008. Between 1980 and 1990, Mr. Scaff oversaw financial and
credit transactions for Dresser Industries, a Fortune 50 oilfield equipment
company. Immediately after serving as a regional manager with TOTAL Petroleum
between 1990 and 1997, Mr. Scaff co-founded, and since that date co-managed,
Petroleum Management, LLC, a company engaged in the exploration, operations,
production and distribution of oil and natural gas. In 2001, Mr. Scaff
co-founded, and since that date has co-managed, Petroleum Exploration and
Management, LLC, a company engaged in the acquisition of oil and gas leases and
the production and sale of oil and natural gas. Mr. Scaff holds a degree in
Finance from the University of Colorado.
Frank L. Jennings - Mr. Jennings has been our Principal Financial and Accounting
Officer since June 2007. Since 2001, Mr. Jennings has been an independent
consultant providing financial accounting services, primarily to smaller public
companies. From 2006 until 2011, he served as the Chief Financial Officer of
Gold Resource Corporation (AMEX:GORO). From 2000 to 2005, he served as the Chief
Financial Officer and a director of Global Casinos, Inc., a publicly traded
corporation, and from 2001 to 2005, he served as Chief Financial Officer and a
director of OnSource Corporation, now known as Ceragenix Pharmaceuticals, Inc.,
also a publicly traded corporation.
Rick A. Wilber - Mr. Wilber has been one of our directors since September 2008.
Since 1984, Mr. Wilber has been a private investor in, and a consultant to,
numerous development stage companies. In 1974, Mr. Wilber was co-founder of
Champs Sporting Goods, a retail sporting goods chain, and served as its
President from 1974-1984. He has been a Director of Ultimate Software Group Inc.
since October 2002 and serves as a member of its audit and compensation
committees. Mr. Wilber was a director of Ultimate Software Group between October
1997 and May 2000. He served as a director of Royce Laboratories, Inc., a
pharmaceutical concern, from 1990 until it was sold to Watson Pharmaceuticals,
Inc. in April 1997 and was a member of its compensation committee.
Raymond E. McElhaney - Mr. McElhaney has been one of our directors since May
2005, and prior to the acquisition of Predecessor Synergy was our President and
Chief Executive Officer. Mr. McElhaney began his career in the oil and gas
industry in 1983 as founder and President of Spartan Petroleum and Exploration,
Inc. Mr. McElhaney also served as a chairman and secretary of Wyoming Oil &
Minerals, Inc., a publicly traded corporation, from February 2002 until 2005.
42
From 2000 to 2003, he served as vice president and secretary of New Frontier
Energy, Inc., a publicly traded corporation. McElhaney is a co-founder of MCM
Capital Management Inc., a privately held financial management and consulting
company formed in 1990 and has served as its president of that company since
inception.
Bill M. Conrad - Mr. Conrad has been one of our directors since May 2005 and
prior to the acquisition of Predecessor Synergy was our Vice President and
Secretary. Mr. Conrad has been involved in several aspects of the oil & gas
industry over the past 20 years. From February 2002 until June 2005, Mr. Conrad
served as president and a director of Wyoming Oil & Minerals, Inc., and from
2000 until April 2003, he served as vice president and a director of New
Frontier Energy, Inc. Since June 2006, Mr. Conrad has served as a director of
Gold Resource Corporation, a publicly traded corporation engaged in the mining
industry. In 1990, Mr. Conrad co-founded MCM Capital Management Inc. and has
served as its vice president since that time.
R.W. "Bud" Noffsinger, III - Mr. Noffsinger was appointed as one of our
directors in September 2009. Mr. Noffsinger has been the President/ CEO of RWN3
LLC, a company involved with investment securities, since February 2009.
Previously, Mr. Noffsinger was the President (2005 to 2009) and Chief Credit
Officer (2008 to 2009) of First Western Trust Bank in Fort Collins, Colorado.
Prior to his association with First Western, Mr. Noffsinger was a manager with
Centennial Bank of the West (now Guaranty Bank and Trust). Mr. Noffsinger's
focus at Centennial was client development and lending in the areas of
commercial real estate, agriculture and natural resources. Mr. Noffsinger is a
graduate of the University of Wyoming and holds a Bachelor of Science degree in
Economics with an emphasis on natural resources and environmental economics.
George Seward - Mr. Seward was appointed as one of our directors on July 8,
2010. Mr. Seward cofounded Prima Energy in 1980 and served as its Secretary
until 2004, when Prima was sold to Petro-Canada for $534,000,000. At the time of
the sale, Prima had 152 billion cubit feet of proved gas reserves and was
producing 55 million cubic foot of gas daily from wells in the D-J Basin in
Colorado and the Powder River Basin of Wyoming and Utah. Since March 2006 Mr.
Seward has been the President of Pocito Oil and Gas, a limited production
company, with operations in northeast Colorado, southwest Nebraska and Barber
County, Kansas. Mr. Seward has also operated a diversified farming operation,
raising wheat, corn, pinto beans, soybeans and alfalfa hay in southwestern
Nebraska and northeast Colorado, since 1982.
We believe Messrs. Holloway, Scaff, McElhaney, Conrad and Seward are
qualified to act as directors due to their experience in the oil and gas
industry. We believe Mr. Messrs. Wilber and Mr. Noffsinger are qualified to act
as directors as result of their experience in financial matters.
Rick Wilber, Raymond McElhaney, Bill Conrad and R.W. Noffsinger, are
considered independent as that term is defined Section 803.A of the NYSE Amex.
The members of our compensation committee are Rick Wilber, Raymond
McElhaney, Bill Conrad, and R.W. Noffsinger. The members of our Audit Committee
are Raymond McElhaney, Bill Conrad and R.W. Noffsinger. Mr. Noffsinger acts as
the financial expert for the Audit Committee of our board of directors.
43
We have adopted a Code of Ethics applicable to all employees.
Executive Compensation
The following table shows the compensation paid or accrued to our executive
officers during each of the three years ended August 31, 2011.
Stock Option All Other
Name and Principal Fiscal Salary Bonus Awards Awards Compensation
Position Year (1) (2) (3) (4) (5) Total
------------------ ---- -------- ----- ------ ------ ------------- -----
Ed Holloway, 2011 9,800 $409,800
Principal
Executive
Officer $400,000 - - -
2010 $175,000 - - - - $175,000
2009 $150,000 - - 5,092,672 - $5,242,672
William E.
Scaff, Jr.,
Vice President,
Secretary and
Treasurer 2011 $400,000 - - - 9,800 $409,800
2010 $175,000 - - - - $175,000
2009 $150,000 - - 5,092,675 - $5,242,675
Frank L
Jennings,
Principal
Financial and
Accounting
Officer 2011 $ 87,391 - 220,000 404,352 - $711,743
2010 $106,225 - - - - $106,225
2009 $ 63,715 - - - - $ 63,715
(1) The dollar value of base salary (cash and non-cash) earned.
(2) The dollar value of bonus (cash and non-cash) earned.
(3) The fair value of stock issued for services computed in accordance with ASC
718 on the date of grant.
(4) The fair value of options granted computed in accordance with ASC 718 on
the date of grant.
(5) All other compensation received that we could not properly report in any
other column of the table.
The compensation to be paid to Mr. Holloway, Mr. Scaff and Mr. Jennings
will be based upon their employment agreements, which are described below. All
material elements of the compensation paid to these officers is discussed below.
On June 11, 2008, we signed employment agreements with Ed Holloway and
William E. Scaff Jr. Each employment agreement provided that the employee would
be paid a monthly salary of $12,500 and required the employee to devote
approximately 80% of his time to our business. The employment agreements expired
on June 1, 2010.
On June 1, 2010, we entered into a new employment agreements with Mr.
Holloway and Mr. Scaff. The new employment agreements, which expire on May 31,
2013, provide that we pay Mr. Holloway and Mr. Scaff each a monthly salary of
$25,000 and require both Mr. Holloway and Mr. Scaff to devote approximately 80%
44
of their time to our business. In addition, for every 50 wells that begin
producing oil and/or gas after June 1, 2010, whether as the result of our
successful drilling efforts or acquisitions, we will issue, to each of Mr.
Holloway and Mr. Scaff, shares of common stock in an amount equal to $100,000
divided by the average closing price of our common stock for the 20 trading days
prior to the date the fiftieth well begins producing.
On June 23, 2011 our directors approved an employment agreement with Frank
L. Jennings, our Principal Financial and Accounting Officer. The employment
agreement provides that we will pay Mr. Jennings a monthly salary of $15,000 and
issue to Mr. Jennings:
o 50,000 shares of our restricted common stock; and
o options to purchase 150,000 shares of our common stock. The options
are exercisable at a price of $4.40 per share, vest over three years
in 50,000 share increments beginning March 6, 2012, and expire on
March 7, 2021.
The employment agreement expires on March 7, 2014 and requires Mr. Jennings
to devote all of his time to our business.
If Mr. Jennings resigns within 90 days of a relocation (or demand for
relocation) of his place of employment to a location more than 35 miles from his
then current place of employment, the employment agreement will be terminated
and Mr. Jennings will be paid the salary provided by the employment agreement
through the date of termination and the unvested portion of any stock options
held by Mr. Jennings will vest immediately.
In the event there is a change in the control, the employment agreement
allows Mr. Jennings to resign from his position and receive a lump-sum payment
equal to 12 months salary. In addition, the unvested portion of any stock
options held by Mr. Jennings will vest immediately. For purposes of the
employment agreement, a change in the control means: (1) our merger with another
entity if after such merger our shareholders do not own at least 50% of the
voting capital stock of the surviving corporation; (2) the sale of substantially
all of our assets; (3) the acquisition by any person of more than 50% of our
common stock; or (4) a change in a majority of our directors which has not been
approved by our incumbent directors.
The employment agreements mentioned above, will terminate upon the
employee's death, or disability or may be terminated by us for cause. If the
employment agreement is terminated for any of these reasons, the employee, or
his legal representatives as the case may be, will be paid the salary provided
by the employment agreement through the date of termination.
For purposes of the employment agreements, "cause" is defined as:
(i) the conviction of the employee of any crime or offense involving,
or of fraud or moral turpitude, which significantly harms us;
(ii) the refusal of the employee to follow the lawful directions of our
board of directors;
45
(iii) the employee's negligence which shows a reckless or willful
disregard for reasonable business practices and significantly
harms us; or
(iv) a breach of the employment agreement by the employee.
We had a consulting agreement with Ray McElhaney and Bill Conrad which
provided that Mr. McElhaney and Mr. Conrad would render, on a part-time basis,
consulting services pertaining to corporate acquisitions and development. For
these services, Mr. McElhaney and Mr. Conrad were paid a monthly consulting fee
of $5,000. The consulting agreement expired on September 15, 2009.
Employee Pension, Profit Sharing or other Retirement Plans. Effective
November 1, 2010 we adopted a defined contribution retirement plan, qualifying
under Section 401(k) of the Internal Revenue Code and covering substantially all
of our employees. We match participant's contributions in cash, not to exceed 4%
of the participant's total compensation. Other than this 401(k) Plan, we do not
have a defined benefit pension plan, profit sharing or other retirement plan.
Stock Option and Bonus Plans
We have a 2011 non-qualified stock option plan, a 2011 incentive stock
option plan, and a 2011 stock bonus plan. A summary description of each plan
follows.
2011 Non-Qualified Stock Option Plan. Our Non-Qualified Stock Option Plan
authorizes the issuance of shares of our common stock to persons that exercise
options granted pursuant to the Plan. Our employees, directors, officers,
consultants and advisors are eligible to be granted options pursuant to the
Plan, provided however that bona fide services must be rendered by such
consultants or advisors and such services must not be in connection with
promoting our stock or the sale of securities in a capital-raising transaction.
The option exercise price is determined by our directors.
2011 Incentive Stock Option Plan. Our Incentive Stock Option Plan
authorizes the issuance of shares of our common stock to persons that exercise
options granted pursuant to the Plan. Our employees, directors, officers,
consultants and advisors are eligible to be granted options pursuant to the
Plan, provided however that bona fide services must be rendered by such
consultants or advisors and such services must not be in connection with
promoting our stock or the sale of securities in a capital-raising transaction.
The option exercise price is determined by our directors.
2011 Stock Bonus Plan. Our Stock Bonus Plan allows for the issuance of
shares of common stock to our employees, directors, officers, consultants and
advisors. However, bona fide services must be rendered by the consultants or
advisors and such services must not be in connection with promoting our stock or
the sale of securities in a capital-raising transaction.
The plans adopted during 2011 replaced a non-qualified stock option plan
and a stock bonus plan originally adopted during 2005 (the "2005 Plans"). No
additional options or shares will be issued under the 2005 Plans.
46
Summary. The following is a summary of options granted or shares issued
pursuant to the Plans as of September 15, 2011. Each option represents the right
to purchase one share of our common stock.
Total
Shares Reserved for Shares Remaining
Reserved Outstanding Issued as Options/Shares
Name of Plan Under Plans Options Stock Bonus Under Plans
------------ ----------- ------------ ----------- --------------
2011 Non-Qualified Stock
Option Plan 2,000,000 0 0 2,000,000
2011 Incentive Stock
Option Plan 2,000,000 0 0 2,000,000
2011 Stock Bonus Plan 2,000,000 0 0 2,000,0
Options
In connection with the acquisition of Predecessor Synergy, we issued
options to the persons shown below in exchange for options previously issued by
Predecessor Synergy. The terms of the options we issued are identical to the
terms of the Predecessor Synergy options. The options were not granted pursuant
to our 2005 Plans. As of September 15, 2011, none of these options have been
exercised.
Grant Shares Issuable Upon Exercise Expiration
Name Date Exercise of Options Price Date
---- ------ -------------------- -------- ----------
Ed Holloway (1) 9-10-08 1,000,000 $ 1.00 6-11-13
William E. Scaff, Jr.(2) 9-10-08 1,000,000 $ 1.00 6-11-13
Ed Holloway (1) 9-10-08 1,000,000 $10.00 6-11-13
William E. Scaff, Jr.(2) 9-10-08 1,000,000 $10.00 6-11-13
(1) Options are held of record by a limited liability company controlled by Mr.
Holloway.
(2) Options are held of record by a limited liability company controlled by Mr.
Scaff.
The following table shows information concerning our outstanding options as
of September 15, 2011.
Shares underlying unexercised
Option which are:
---------------------------
Exercise Expiration
Name Exercisable Unexercisable Price Date
---- ----------- ------------- ------------ ----------
Ed Holloway 1,000,000 -- $ 1.00 6-11-13
William E. Scaff, Jr. 1,000,000 -- $ 1.00 6-11-13
Ed Holloway 1,000,000 -- $10.00 6-11-13
William E. Scaff, Jr. 1,000,000 -- $10.00 6-11-13
Employees 10,000(1) 610,000 (1) (1) (1)
(1) Options were issued to several employees pursuant to our Non-Qualified
Stock Option Plan. The exercise price of the options varies between $2.40
and $4.40 per share. The options expire at various dates between December
2018 and August, 2021.
47
The following table shows the weighted average exercise price of the
outstanding options granted pursuant to our Non-Qualified Stock Option Plan or
otherwise as of August 31, 2011. Prior to 2011, neither our Non-Qualified Stock
Option Plan nor the issuance of any of our other options have been approved by
our shareholders.
Number Remaining Available
of Securities For Future Issuance
be Issued Weighted-Average Under Equity
Upon Exercise Exercise Price of Compensation Plans,
of Outstanding of Outstanding Excluding Securities
Plan category Options Options Reflected in Column
--------------------------------------------------------------------------------
Non-Qualified Stock
Option Plan 620,000 $3.40 1,380,000 (1)
Other Options 4,000,000 $5.50 -
(1) As of May 23, 2011, this Plan was terminated and no further shares will be
issued pursuant to its terms.
Compensation of Directors During Year Ended August 31, 2011
Fees Earned or Stock Option
Paid in Cash Awards (1) Awards (2) Total
------------- --------- ---------- -----
Rick Wilber $20,000 -- -- $20,000
Raymond McElhaney $32,500 -- -- 32,500
Bill Conrad 28,000 -- -- 28,000
R.W. Noffsinger 24,000 -- -- 24,000
George Seward 20,000 -- -- 20,000
-------------- ------ ----------
$124,500 -- $124,500
======== == ========
(1) The fair value of stock issued for services computed in accordance with ASC
718.
(2) The fair value of options granted computed in accordance with ASC 718 on
the date of grant.
PRINCIPAL SHAREHOLDERS
The following table shows, as of September 15, 2011, information with
respect to those persons owning beneficially 5% or more of our common stock and
the number and percentage of outstanding shares owned by each of our directors
and officers and by all officers and directors as a group. Unless otherwise
indicated, each owner has sole voting and investment powers over his shares of
common stock.
Number Percent
Name of Shares (1) of Class(2)
---- ------------- ------------
Ed Holloway 4,760,909 (3) 13.42%
William E. Scaff, Jr. 4,760,909 (4) 13.42%
48
Frank L. Jennings 74,000 *
Rick A. Wilber 536,700 1.5%
Raymond E. McElhaney 245,725 *
Bill M. Conrad 247,225 *
R.W. Noffsinger, III 288,425 *
George Seward 878,080 2.4%
Wayne L. Laufer 2,893,750 8.0%
All officers and directors as a group (8 persons)11,791,973 32.7%
* Less than 1%
(1) Share ownership includes shares issuable upon the exercise of options, all
of which are currently exercisable, held by the persons listed below.
Share
Issuable
Upon Option
Exercise of Exercise Expiration
Name Options Price Date
--------------------- -------------- --------- ----------
Ed Holloway 1,000,000 $ 1.00 6/11/2013
Ed Holloway 1,000,000 $ 10.00 6/11/2013
William E. Scaff, Jr. 1,000,000 $ 1.00 6/11/2013
William E. Scaff, Jr. 1,000,000 $ 10.00 6/11/2013
(2) Computed based upon 36,098,212 shares of common stock outstanding as of
September 15, 2011.
(3) Shares are held of record by various trusts and limited liability companies
controlled by Mr. Holloway.
(4) Shares are held of record by various trusts and limited liability companies
controlled by Mr. Scaff.
TRANSACTIONS WITH RELATED PARTIES
Our two officers, Ed Holloway and William Scaff, Jr., are currently
involved in oil and gas exploration and development. Mr. Holloway and Mr. Scaff,
or their affiliates (collectively the "Holloway/Scaff Parties"), may present us
with opportunities to acquire leases or to participate in drilling oil or gas
wells. The Holloway/Scaff Parties control three entities with which we have
entered into agreements. These entities are Petroleum Management, LLC ("PM"),
Petroleum Exploration and Management, LLC ("PEM"), and HS Land and Cattle, LLC
("HSLC").
Any transaction between us and the Holloway/Scaff Parties must be approved
by a majority of our disinterested directors. In the event the Holloway/Scaff
49
Parties are presented with or become aware of any potential transaction which
they believe would be of interest to us, they are required to provide us with
the right to participate in the transaction. The Holloway/Scaff Parties are
required to disclose any interest they have in the potential transaction as well
as any interest they have in any property which could benefit from our
participation in the transaction, such as by our drilling an exploratory well on
a lease which is in proximity to leases in which the Holloway/Scaff Parties have
an interest. Without our consent, the Holloway/Scaff Parties may participate up
to 25% in a potential transaction on terms which are no different than those
offered to us.
We had a letter agreement with PM and PEM which provided us with the option
to acquire working interests in oil and gas leases owned by these firms and
covering lands on the D-J basin. The oil and gas leases covered 640 acres in
Weld County, Colorado and, subject to certain conditions, would be transferred
to us for payment of $1,000 per net mineral acre. The working interests in the
leases we could acquire varied, but the net revenue interest in the leases,
could not be less than 75%. Between August 2008 and February 2010, we acquired
leases covering 640 gross, 360 net, acres from PM and PEM for $360,000.
Between June 11, 2008 and June 30, 2010, and pursuant to the terms of an
Administrative Services Agreement, PM provided us with office space and
equipment storage in Platteville, Colorado, as well as secretarial, word
processing, telephone, fax, email and related services for a fee of $20,000 per
month. Following the termination of the Administrative Services Agreement, and
since July 1, 2010 we have leased the office space and equipment storage yard in
Platteville from HSLC at a rate of $10,000 per month.
In October 2010, and following the approval of our directors, we acquired
oil and gas properties from PM and PEM, for approximately $1.0 million. The oil
and gas properties we acquired are located in the Wattenberg Field and consisted
of:
o six producing oil and gas wells
o two shut in oil wells
o fifteen drill sites, net 6.25 wells
o miscellaneous equipment
We have a 100% working interest (80% net revenue interest) in the six
producing wells and the two shut in wells.
In 2009, PM and PEM acquired the same oil and gas properties sold to us
from an unrelated third party for $920,000. The difference in the price we paid
for the properties and the price PM and PEM paid for the properties represents
interest on the amount paid by PM and PEM for the properties, closing costs and
equipment improvements.
As more fully described in the section titled "Business-Acquisition of Oil
and Gas Properties from Petroleum Exploration & Management", we acquired all of
the working oil and gas assets owned by PEM in a transaction that closed on May
24, 2011. The purchase price for the transaction was $19 million, subject to
post closing adjustments for events occurring between January 1, 2011, and May
24, 2011. The transaction was approved by the disinterested directors and by a
vote of the shareholders, with Mr. Holloway and Mr. Scaff not voting.
50
Prior to our acquisition of Predecessor Synergy, Predecessor Synergy made
the following sales of its securities:
Name Shares Series A Warrants Consideration
---- ------ ----------------- -------------
Ed Holloway (1) 2,070,000 -- $ 2,070
William E. Scaff, Jr.(1) 2,070,000 -- 2,070
Benjamin Barton (1) 600,000 -- 600
John Staiano (1) 600,000 -- 600
Synergy Energy trust 1,900,000 (2) -- 1,900
Third Parties 660,000 -- 660
Private Investors 1,000,000 1,000,000 $1.00 Per Unit (3)
Private Investors 1,060,000 1,060,000 $1.50 Per Unit (3)
--------- ---------
Total 9,960,000 2,060,000
========= =========
(1) Shares are held of record by entities controlled by this person.
(2) In December 2008, we repurchased 1,000,000 shares from the Synergy Energy
Trust.
(3) Shares and warrants were sold as units, with each unit consisting of one
share of our common stock and one Series A warrant.
In connection with our acquisition of Predecessor Synergy, the 9,960,000
shares of Predecessor Synergy, plus the 2,060,000 Series A warrants, were
exchanged for 9,960,000 shares of our common stock, plus 2,060,000 of our Series
A warrants.
In contemplation of the acquisition of Predecessor Synergy, our directors
declared a dividend of Series A warrants. The dividend provided that each person
owning our shares at the close of business on September 9, 2008 will receive one
Series A warrant for each post-split share which they owned on that date. Mr.
McElhaney and Mr. Conrad, due to their ownership of our common stock on
September 9, 2008, received 271,000 and 247,000 Series A warrants, respectively.
Each Series A warrant entitles the holder to purchase one share of our
common stock at a price of $6.00 per share. The Series A warrants expire on the
earlier of December 31, 2012 or twenty days following written notification from
us that our common stock had a closing bid price at or above $7.00 for any ten
of twenty consecutive trading days.
SELLING SHAREHOLDERS
During December 2010 and January 2011, we sold 9,000,000 shares of our
common stock to a group of private investors at a price of $2.00 per share. By
means of this prospectus, the investors who purchased these shares, and who are
referred to as the "selling shareholders", are offering to sell their shares.
51
The shares owned by selling shareholders may be sold through the NYSE Amex,
any other trading facility on which the shares are traded, or otherwise, at
prices related to the then current market price, or in negotiated transactions.
We will not receive any proceeds from the sale of the securities by the
selling shareholders. We will pay all costs of registering the securities
offered by the selling shareholders. The selling shareholders will pay all sales
commissions and other costs of the sale of the securities offered by them.
Share
Shares To Ownership
Name of Shares Be Sold In After
Selling Shareholder Owned This Offering Offering
------------------- ----- ------------- --------
William T. Ahlborg Jr. Living Trust 25,000 25,000 --
Ronald & Susan Armstrong 123,750 50,000 73,750
IRA C/F Nicholas J. Arthur 50,000 50,000 --
Nicholas J. Arthur & Paddi L. Arthur Family
Trust 150,000 150,000 --
Roth C/F Nicholas J. Arthur 50,000 50,000 --
Sarah D. Atkinson 25,000 25,000 --
Margaret Bathgate 493,874 118,750 375,124
Margaret Bathgate 75,000 0 75,000
Larry Baucke 150,000 150,000 --
Brodie N. Belliveau Jr. and Sally s.
Belliveau JTWROS 25,000 25,000 --
Elizabeth Bernstein IRA 25,000 25,000 --
Saul Bernstein IRA 50,000 50,000 --
Saul & Elizabeth Bernstein JTWROS 50,000 50,000 --
Carmelo Blacconeri 17,000 17,000 --
Christopher R. and Terri A. Blecha 5,000 5,000 --
Carol Boening 27,000 25,000 2,000
Gary W. and Theresa L. Boening 25,000 25,000 --
Reece Bowman 11,900 10,000 1,900
The Burns Partnership LLC 50,000 50,000 --
David R. Burke 50,000 25,000 25,000
Robert L Burrell & Cecilia S. Burrell, JTTEN 5,000 5,000 --
Daniel Q. Callister 25,000 25,000 --
John E. Chandler 50,000 50,000 --
Robert & Sandra Cohn 25,000 25,000 --
Steven K. Compton 25,000 25,000 --
Arturo Creixell 75,000 75,000 --
Ramon Creixell 75,000 75,000 --
Estate of Ramon Creixell, Isabel Creixell
Executrix 50,000 50,000 --
Carol & Charles Dailey JTWROS 37,500 37,500 --
Isabel S. DeCreixell 50,000 50,000 --
John L. Duvieilh 55,000 50,000 5,000
Scott A. & Holly L. Ehrlich 186,000 50,000 136,000
J. Steven Emerson Roth IRA #3950054 FBO
Pershing LLC as Custodian 750,000 450,000 300,000
J. Steven Emerson Roth IRA #3950070 FBO
Pershing LLC as Custodian 750,000 300,000 450,000
Gail A. Frickman Revocable Trust 25,000 25,000 --
The Friedman Living Trust 25,000 25,000 --
52
Galena Oil & Gas LLC 125,000 125,000 --
Harry L. Geller & Nicole A. Geller 25,000 25,000 --
Oppenheimer & Co Inc. C/F Karen Gilder
Rlvr IRA 25,000 25,000 --
Delaware Charter G&T Co. TTEE FBO
Kim J. Gloystein IRA 44652330 7,500 7,500 --
The Goodman Corporation 50,000 50,000 --
Great Northern Properties LLLP 50,000 50,000 --
Eddie L. Hall 25,000 25,000 --
Judd Hansen 25,000 25,000 --
ML Harris Family Partnership LLC 50,000 50,000 --
John and Jean Harvill (Community Property) 25,000 25,000 --
Mark Hess 50,000 50,000 --
High Speed Aggregate Inc. 50,000 50,000 --
Delaware Charter G&T Co. TTEE FBO
John P. Jenkins IRA #44650029 12,500 12,500 --
R. Paul Hoff and JoAnn Hoff JTWROS 10,000 5,000 5,000
James W. Huebner and Robyne L. Huebner JTWROS 5,000 5,000 --
Frank L. Jennings 24,000 20,000 4,000
Stuart & Nancy Johnson 25,000 25,000 --
Greg A. Jones 212,500 150,000 62,500
Elizabeth G. Jordan Trust 25,000 25,000 --
D&P Kelsall Family LLP 75,000 18,750 56,250
Oppenheimer & Co Custodian FBO David A.
Kenkel IRA 25,000 25,000 --
David & Stephanie Kenkel 75,000 75,000 --
Elizabeth Kenkel 25,000 25,000 --
Grace Kenkel Rev Trust 75,000 75,000 --
Stephanie L. Kenkel & David A. Kenkel JT/TIC 65,000 65,000 --
John J. Kopel & Laurie A. Kopel JTTEN 12,500 12,500 --
Jon Kruljac 410,786 500 410,286
Donald Langley & Julia Langley JTWROS 25,000 25,000 --
Edward C. Larkin 5,000 5,000 --
Gayle M. Laufer SEP IRA 50,000 50,000 --
Wayne L. Laufer Revocable Trust 2,500,000 2,500,000 --
Lawrence and Marion Lewin 25,000 25,000 --
Karen G. Lipsey 25,000 25,000 --
Kent J. and Elizabeth A. Lund JTWROS 7,500 7,500 --
M & L Cattle Company 275,000 50,000 225,000
Susan E. Mackel Revocable Trust 25,000 25,000 --
Mario Joseph Mapelli 193,750 25,000 168,750
Terence McAuliffe and Dorothy McAuliffe
JTWROS 50,000 50,000 --
Thomas J. McCabe 37,500 37,500 --
Jerry E. McPherson 62,500 25,000 37,500
Gary E. Mintz 25,000 25,000 --
Moreland Properties, LLC 992,500 250,000 742,500
Mulholland Fund LP 240,300 175,000 65,300
Joseph W. Newton 25,000 25,000 --
Next View Capital LP 125,000 125,000 --
Ronn D. Nolin 25,000 25,000 --
Henry III & Allison O'Connor 25,000 25,000 --
Edward J. Patanian SEP IRA 25,000 25,000 --
Benjamin J. Peress 50,000 25,000 25,000
Paul C. Perryman Revocable Trust 25,000 25,000 --
53
Christopher A. Hakim & Linda S. Petien 25,000 25,000 --
Delaware Charter G&T Co., TTEE FBO
Jerry W. Peterson IRA 44652108 17,500 10,000 7,500
Delaware Charter G&T Co. TTEE FBO
Jerry W. Peterson IRA 44652108 27,500 10,000 17,500
54
Delaware Charter G&T Co. TTEE FBO
Kathrine M. Petersen IRA 44679570 5,000 5,000 --
Delaware Charter G&T Co., TTEE FBO
Steven D. Plissey IRA #44648908 7,500 7,500 --
Bob & Chris Porteous JTWROS 50,000 50,000 --
Porteous Family Foundation 50,000 50,000 --
Porteous Family Investments, LP 100,000 100,000 --
George Resta IRA 25,000 25,000 --
George Resta III and Kathryn Resta 25,000 25,000 --
George Resta Living Trust 75,000 75,000 --
Patricia L. Rowland 25,000 25,000 --
George F. & Mary C. Schmitt 250,000 25,000 225,000
Seaside 88, LP 500,000 500,000 --
George Seward 50,000 50,000 --
David C. Shatzer 122,500 35,000 87,500
Craig D. Sokol 25,000 25,000 --
South Harbor L.P. 25,000 25,000 --
Wallace Sparkman 10,000 10,000 --
John & Ingrid Stonecipher Revocable Trust 25,000 25,000 --
Maurice B. Tobin 25,000 25,000 --
Tymothi O. Tombar 50,000 50,000 --
Jessica M. Vickery 50,000 50,000 --
Oppenheimer & Co. Inc. Custodian FBO
Paul F. Villella IRA 25,000 25,000 --
Howard D. Waldow TTEE Waldow Intervivos
Trust dated 6/30/1995 12,600 12,500 100
Jim Walther & Beth Walther 50,000 50,000 --
Rick J. Whitehead 146,145 20,000 126,145
Jane Widener 250,000 250,000 --
Nancy K. Wieck 37,500 37,500 --
Jeff Wiepking 100,000 100,000 --
Eric L. Wilson 84,000 50,000 34,000
Thomas D. Wolf 2,500 2,500 --
Raad Yassin 25,000 25,000 --
Sara Yassin 75,000 75,000 --
Terry R. Yormark 10,000 10,000 --
YuCo Energy LLC 493,750 150,000 343,750
1357 LLC 100,000 100,000 --
The controlling persons of the non-individual selling shareholders are:
Name of
Selling Shareholder Controlling Person
------------------- ------------------
The Burns Partnership LLC Michael Burns
Galena Oil & Gas LLC F. Steven Mooney
54
The Goodman Corporation Barry Goodman
Great Northern Properties LLLP John Wheeler
ML Harris Family Partnership LLC Mark Harris
High Speed Aggregate Inc. Jeff Ploen
D&P Kelsall Family LLP Douglas and Pamela Kelsall
M & L Cattle Company Steve Winger
Moreland Properties, LLC William D. Moreland
Mulholland Fund LP Thomas J. Laird
Next View Capital LP Stewart Fink
Porteous Family Foundation Bob Porteous
Porteous Family Investments, LP Bob Porteous
Seaside 88, LP William Ritger
South Harbor L.P. Jane Smith
YuCo Energy LLC Mark Roth
1357 LLC Robert E. Murphy
The following selling shareholders have, or had, a material relationship
with us or our officers or directors:
Name of Nature of
Selling Shareholder Relationship
------------------- ------------
Frank L. Jennings Principal Chief Financial and
Accounting Officer
George Seward Director
To our knowledge, no other selling shareholder has, or had, any material
relationship with us, or our officers or directors.
Jon Kruljac, Edward Larkin and David Kenkel are registered representatives
with brokerage firms registered with the Securities and Exchange Commission.
Margaret Bathgate is the wife of a registered representative employed by one of
these brokerage firms. David Kenkel is the trustee of the Grace Kenkel Revocable
Trust. To our knowledge, no other selling shareholder is affiliated with a
securities broker.
Plan of Distribution
The shares of common stock owned by the selling shareholders may be offered
and sold by means of this prospectus from time to time as market conditions
permit.
The shares of common stock may be sold by one or more of the following
methods, without limitation:
o a block trade in which a broker or dealer so engaged will attempt to
sell the securities as agent but may position and resell a portion of
the block as principal to facilitate the transaction;
55
o purchases by a broker or dealer as principal and resale by such broker
or dealer for its account pursuant to this prospectus;
o ordinary brokerage transactions and transactions in which the broker
solicits purchasers; and
o face-to-face transactions between sellers and purchasers without a
broker/dealer.
In competing sales, brokers or dealers engaged by the selling shareholders
may arrange for other brokers or dealers to participate. Brokers or dealers may
receive commissions or discounts from selling shareholders in amounts to be
negotiated. As to any particular broker-dealer, this compensation might be in
excess of customary commissions. Neither we nor the selling stockholders can
presently estimate the amount of such compensation. Notwithstanding the above,
no FINRA member will charge commissions that exceed 8% of the total proceeds
from the sale.
The selling shareholders and any broker/dealers who act in connection with
the sale of their securities may be deemed to be "underwriters" within the
meaning of ss.2(11) of the Securities Acts of 1933, and any commissions received
by them and any profit on any resale of the securities as principal might be
deemed to be underwriting discounts and commissions under the Securities Act.
If any selling shareholder enters into an agreement to sell his or her
securities to a broker-dealer as principal, and the broker-dealer is acting as
an underwriter, we will file a post-effective amendment to the registration
statement, of which this prospectus is a part, identifying the broker-dealer,
providing required information concerning the plan of distribution, and
otherwise revising the disclosures in this prospectus as needed. We will also
file the agreement between the selling shareholder and the broker-dealer as an
exhibit to the post-effective amendment to the registration statement.
The selling stockholders may also sell their shares pursuant to Rule 144
under the Securities Act of 1933.
We have advised the selling shareholders that they, and any securities
broker/dealers or others who sell the common stock or warrants on behalf of the
selling shareholders, may be deemed to be statutory underwriters and will be
subject to the prospectus delivery requirements under the Securities Act of
1933. We have also advised each selling shareholder that in the event of a
"distribution" of the securities owned by the selling shareholder, the selling
shareholder, any "affiliated purchasers", and any broker/dealer or other person
who participates in the distribution may be subject to Rule 102 of Regulation M
under the Securities Exchange Act of 1934 ("1934 Act") until their participation
in that distribution is completed. Rule 102 makes it unlawful for any person who
is participating in a distribution to bid for or purchase securities of the same
class as is the subject of the distribution. A "distribution" is defined in Rule
102 as an offering of securities "that is distinguished from ordinary trading
transactions by the magnitude of the offering and the presence of special
selling efforts and selling methods". We have also advised the selling
shareholders that Rule 101 of Regulation M under the 1934 Act prohibits any
"stabilizing bid" or "stabilizing purchase" for the purpose of pegging, fixing
or stabilizing the price of the common stock in connection with this offering.
56
DESCRIPTION OF SECURITIES
Common Stock
We are authorized to issue 100,000,000 shares of common stock. Holders of
our common stock are each entitled to cast one vote for each share held of
record on all matters presented to the shareholders. Cumulative voting is not
allowed; hence, the holders of a majority of our outstanding common shares can
elect all directors.
Holders of our common stock are entitled to receive such dividends as may
be declared by our Board of Directors out of funds legally available and, in the
event of liquidation, to share pro rata in any distribution of our assets after
payment of liabilities. Our Board of Directors is not obligated to declare a
dividend. It is not anticipated that dividends will be paid in the foreseeable
future.
Holders of our common stock do not have preemptive rights to subscribe to
additional shares if issued. There are no conversion, redemption, sinking fund
or similar provisions regarding the common stock. All outstanding shares of
common stock are fully paid and nonassessable.
Preferred Stock
We are authorized to issue 10,000,000 shares of preferred stock. Shares of
preferred stock may be issued from time to time in one or more series as may be
determined by our Board of Directors. The voting powers and preferences, the
relative rights of each such series and the qualifications, limitations and
restrictions of each series will be established by the Board of Directors. Our
directors may issue preferred stock with multiple votes per share and dividend
rights which would have priority over any dividends paid with respect to the
holders of our common stock. The issuance of preferred stock with these rights
may make the removal of management difficult even if the removal would be
considered beneficial to shareholders generally, and will have the effect of
limiting shareholder participation in transactions such as mergers or tender
offers if these transactions are not favored by our management. As of the date
of this prospectus, we had not issued any shares of preferred stock.
Warrants
See the "Comparative Share Data" section of this prospectus for information
concerning our outstanding warrants.
Transfer Agent
Corporate Stock Transfer
3200 Cherry Creek Drive South, Suite 430
Denver, Colorado 80209
Phone: 303-282-4800
Fax: 303-282-5800
57
LEGAL PROCEEDINGS
We are not involved in any legal proceedings and we do not know of any
legal proceedings which are threatened or contemplated.
INDEMNIFICATION
Our Bylaws authorize indemnification of a director, officer, employee or
agent against expenses incurred by him in connection with any action, suit, or
proceeding to which he is named a party by reason of his having acted or served
in such capacity, except for liabilities arising from his own misconduct or
negligence in performance of his duty. In addition, even a director, officer,
employee, or agent found liable for misconduct or negligence in the performance
of his duty may obtain such indemnification if, in view of all the circumstances
in the case, a court of competent jurisdiction determines such person is fairly
and reasonably entitled to indemnification. Insofar as indemnification for
liabilities arising under the Securities Act of 1933 may be permitted to our
directors, officers, or controlling persons pursuant to these provisions, we
have been informed that in the opinion of the Securities and Exchange
Commission, such indemnification is against public policy as expressed in the
Act and is therefore unenforceable.
AVAILABLE INFORMATION
We have filed with the Securities and Exchange Commission a Registration
Statement on Form S-1 (together with all amendments and exhibits) under the
Securities Act of 1933, as amended, with respect to the securities offered by
this prospectus. This prospectus does not contain all of the information in the
Registration Statement, certain parts of which are omitted in accordance with
the rules and regulations of the Securities and Exchange Commission. For further
information, reference is made to the Registration Statement which may be read
and copied at the Commission's Public Reference Room at 100 F. Street, N.E.,
Washington, D.C. 20549. The public may obtain information on the operation of
the Public Reference Room by calling the Commission at 1-800-SEC-0330. The
registration statement is also available at www.sec.gov, the website of the
Securities and Exchange Commission.
We are subject to the requirements of the Securities Exchange Act of 1934
and are required to file reports, proxy statements and other information with
the Securities and Exchange Commission. Copies of any of these reports, proxy
statements and other information we have filed can be read and copied at the
Commission's Public Reference Room or read and downloaded from the Commission's
website, www.sec.gov.
58
GLOSSARY
BBL. Refers to one stock tank barrel, or 42 placecountry-regionU.S. gallons
liquid volume in reference to crude oil or other liquid hydrocarbons.
BOE. A BOE (i.e. barrel of oil equivalent) combines Bbls of oil and Mcf of
gas by converting each six Mcf of gas to one Bbl of oil.
DEVELOPED ACREAGE. The number of acres that are allocated or assignable to
productive wells or wells capable of production.
HELD BY PRODUCTION. A provision in an oil, gas and mineral lease that
perpetuates an entity's right to operate a property or concession as long as the
property or concession produces a minimum paying quantity of oil or gas.
LANDOWNER'S ROYALTY. A percentage share of production, or the value derived
from production, which is granted to the lessor or landowner in the oil and gas
lease, and which is free of the costs of drilling, completing, and operating an
oil or gas well.
LEASE. Full or partial interests in an oil and gas lease, authorizing the
owner thereof to drill for, reduce to possession and produce oil and gas upon
payment of rentals, bonuses and/or royalties. Oil and gas leases are generally
acquired from private landowners and federal and state governments. The term of
an oil and gas lease typically ranges from three to ten years and requires
annual lease rental payments of $1.00 to $2.00 per acre. If a producing oil or
gas well is drilled on the lease prior to the expiration of the lease, the lease
will generally remain in effect until the oil or gas production from the well
ends. The owner of the lease is required to pay the owner of the leased property
a royalty which is usually between 12.5% and 16.6% of the gross amount received
from the sale of the oil or gas produced from the well.
MCF. Refers to one thousand cubic feet of gas.
NET ACRES OR WELLS. A net well or acre is deemed to exist when the sum of
fractional ownership working interests in gross wells or acres equals one. The
number of net wells or acres is the sum of the fractional working interests
owned in gross wells or acres expressed as whole numbers and fractions.
OPERATING COSTS. The expenses of producing oil or gas from a formation,
consisting of the costs incurred to operate and maintain wells and related
equipment and facilities, including labor costs, repair and maintenance,
supplies, insurance, production, severance and other production excise taxes.
OVERRIDING ROYALTY. A percentage share of production, or the value derived
from production, which is free of all costs of drilling, completing and
operating an oil or gas well, and is created by the lessee or working interest
owner and paid by the lessee or working interest owner to the owner of the
overriding royalty.
PRODUCING PROPERTY. A property (or interest therein) producing oil or gas
in commercial quantities or that is shut-in but capable of producing oil or gas
59
in commercial quantities. Interests in a property may include working interests,
production payments, royalty interests and other non-working interests.
PROSPECT. An area in which a party owns or intends to acquire one or more
oil and gas interests, which is geographically defined on the basis of
geological data and which is reasonably anticipated to contain at least one
reservoir of oil, gas or other hydrocarbons.
PROVED RESERVES. Proved oil and gas reserves are the estimated quantities
of crude oil, natural gas and natural gas liquids which geological and
engineering date demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions (prices and costs held constant as of the date the estimate is made).
SHUT-IN WELL. A well which is capable of producing oil or gas but which is
temporarily not producing due to mechanical problems or a lack of market for the
well's oil or gas.
UNDEVELOPED ACREAGE. Lease acres on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether or not such acreage contains proved
reserves. Undeveloped acreage should not be confused with undrilled acreage
which is "Held by Production" under the terms of a lease.
WORKING INTEREST. A percentage of ownership in an oil and gas lease
granting its owner the right to explore, drill and produce oil and gas from a
tract of property. Working interest owners are obligated to pay a corresponding
percentage of the cost of leasing, drilling, producing and operating a well.
After royalties are paid, the working interest also entitles its owner to share
in production revenues with other working interest owners, based on the
percentage of the working interest owned.
60
SYNERGY RESOURCES CORPORATION
INDEX TO FINANCIAL STATEMENTS
ANNUAL FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm as of
and for the year ended August 31, 2010 F-2
Report of Independent Registered Public Accounting Firm as of
and for the year ended August 31, 2009 F-3
Balance Sheets as of August 31, 2010 and 2009 F-4
Statements of Operations for the years ended August 31, 2010 and 2009 F-5
Statements of Changes in Shareholders' Equity (Deficit)
for the years ended August 31, 2010 and 2009 F-6
Statements of Cash Flows for the years ended August 31, 2010 and 2009 F-7
Notes to Financial Statements F-8
INTERIM FINANCIAL STATEMENTS
Balance Sheets as of May 31, 2011 (unaudited) and August 31, 2010 F-35
Statements of Operations for the three and nine months ended
May 31, 2011, and 2010 (unaudited) F-36
Statements of Cash Flows for the nine months ended
May 31, 2011 and 2010 (unaudited) F-37
Notes to Financial Statements (unaudited) F-38
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Synergy Resources Corporation
We have audited the accompanying balance sheet of Synergy Resources Corporation
(the "Company") of August 31, 2010, and the related statements of operations,
changes in shareholders' (deficit) equity, and cash flows for the year then
ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether 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 audit included consideration of internal control over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company's internal control over financial
reporting. Accordingly, we express no such opinion. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Synergy Resources Corporation
as of August 31, 2010, and the results of its operations and its cash flows for
the year then ended in conformity with U.S. generally accepted accounting
principles.
/s/ Ehrhardt Keefe Steiner & Hottman PC
November 19, 2010
Denver, Colorado
F-2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Shareholders and Board of Directors
Synergy Resources Corporation
We have audited the accompanying balance sheet of Synergy Resources Corporation
(an Exploration Stage Company) as of August 31, 2009, and the related statements
of operations, changes in shareholders' equity, and cash flows for the year then
ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Synergy Resources Corporation
(an Exploration Stage Company) as of August 31, 2009, and the results of its
operations, and its cash flows for the year then ended, in conformity with
accounting principles generally accepted in the United States of America.
/s/ StarkSchenkein, LLP
Denver, Colorado
November 12, 2009
F-3
SYNERGY RESOURCES CORPORATION
BALANCE SHEETS
as of August 31, 2010 and 2009
2010 2009
----------- ----------
ASSETS
Current assets:
Cash and cash equivalents $ 6,748,637 $2,854,659
Accounts receivable:
Oil and gas sales 377,675 84,643
Joint interest billing 1,930,810 -
Related party receivable 867,835 -
Inventory 387,864 1,132,685
Other current assets 12,310 21,105
----------- ----------
Total current assets 10,325,131 4,093,092
----------- ----------
Property and equipment:
Oil and gas properties, full cost
method, net 12,692,194 653,435
Other property and equipment, net 150,789 1,041
----------- ----------
Property and equipment, net
12,842,983 654,476
----------- ----------
Debt issuance costs, net of amortization 1,587,799 -
Other assets 86,000 85,000
----------- ----------
Total assets $24,841,913 $4,832,568
=========== ==========
LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable:
Trade $ 3,015,562 $ 622,734
Related party payable 554,669 -
Accrued expenses 517,921 59,579
Bank loan payable - 1,161,811
----------- ----------
Total current liabilities 4,088,152 1,844,124
Asset retirement obligations 254,648 -
Convertible promissory notes, net of debt discount 12,190,945 -
Derivative conversion liability 9,325,117 -
----------- ----------
Total liabilities 25,858,862 1,844,124
----------- ----------
Commitments and contingencies (See Note 12)
Shareholders' equity (deficit):
Preferred stock - $0.01 par value,
10,000,000 shares authorized:
no shares issued and outstanding - -
Common stock - $0.001 par value,
100,000,000 shares authorized:
13,510,981 and 11,998,000 shares
issued and outstanding as of August
31, 2010, and 2009, respectively 13,511 11,998
Additional paid-in capital 22,308,963 15,521,697
Accumulated (deficit) (23,339,423) (12,545,251)
----------- ----------
Total shareholders' equity (deficit) (1,016,949) 2,988,444
----------- ----------
Total liabilities and shareholders'
equity (deficit) $24,841,913 $4,832,568
=========== ==========
The accompanying notes are an integral part of these financial statements.
F-4
SYNERGY RESOURCES CORPORATION
STATEMENTS OF OPERATIONS
for the years ended August 31, 2010 and 2009
2010 2009
------------ ------------
Oil and gas revenues $ 2,158,444 $ 94,121
------------ ------------
Expenses:
Lease operating expenses 323,520 11,572
Depreciation, depletion, and amortization 701,400 97,605
Impairment of oil and gas properties - 945,079
General and administrative 1,688,382 11,048,591
Services contract - related party 226,667 240,000
Consulting fees - related party - 120,000
------------ ------------
Total expenses 2,939,969 12,462,847
------------ ------------
Operating loss (781,525) (12,368,726)
------------ ------------
Other income (expense):
Accretion of debt discount (1,333,590) -
Amortization of debt issuance costs (453,656) -
Change in fair value of derivative
conversion liability (7,678,457) -
Interest expense, net (551,603) -
Interest income 4,659 16,853
------------ ------------
Total other income (expense) (10,012,647) 16,853
------------ ------------
Loss before taxes (10,794,172) (12,351,873)
Provision for income taxes - -
------------ ------------
Net loss $(10,794,172) $(12,351,873)
============ ============
Net loss per common share:
Basic and Diluted $ (0.88) $ (1.14)
============ ============
Weighted average shares outstanding:
Basic and Diluted 12,213,999 10,831,053
============ ============
The accompanying notes are an integral part of these financial statements.
F-5
SYNERGY RESOURCES CORPORATION
STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY (DEFICIT)
for the years ended August 31, 2010 and 2009
Total
Number of Additional Stock Shareholders'
Common Common Paid - In Subscriptions Accumulated Equity
Shares Stock Capital Receivable (Deficit) (Deficit)
---------- -------- ----------- ------------- ------------ -------------
Balance, September 1, 2008 9,943,571 $ 9,944 $2,477,511 $ (27,650) $ (193,378) $ 2,266,427
Stock subscription received - - - 27,650 - 27,650
Shares issued for net assets of
Brishlin pursuant to September
10, 2008 Exchange Agreement 1,038,000 1,038 10,637 - - 11,675
Stock options exchanged pursuant
to September 10, 2008 Exchange
Agreement - - 10,185,345 - - 10,185,345
Shares issued for cash at $1.50
per share pursuant to July 16,
2008 offering memorandum 16,429 16 24,628 - - 24,644
Shares issued for cash at two
shares for $3.00 pursuant to
December 1, 2008 offering
memorandum 2,000,000 2,000 2,998,000 - - 3,000,000
Offering costs - - (285,600) (285,600)
Repurchase of Founder's shares at
$.001 (1,000,000) (1,000) - - - (1,000)
Share based compensation - - 111,176 - - 111,176
Net (loss) - - - - (12,351,873) (12,351,873)
---------- -------- ----------- --------- ----------- -----------
Balance, August 31, 2009 11,998,000 11,998 15,521,697 - (12,545,251) 2,988,444
Shares issued pursuant to
conversion of debt and accrued
interest at $1.60 per share,
net of $165,212 unamortized
debt discount 1,309,027 1,309 1,927,917 - - 1,929,226
Reclassification of derivative
conversion liability to equity
pursuant to early conversion of
debt - - 1,809,149 - - 1,809,149
Shares issued for services 197,988 198 544,377 - - 544,575
Shares issued in exchange for
mineral leases 5,966 6 16,639 - - 16,645
Series C warrants issued in
connection with sale of convertible
debt at $100,000 per Unit
pursuant to November 27, 2009
offering memorandum - - 1,760,048 - - 1,760,048
Series D warrants issued in
connection with sale of convertible
debt at $100,000 per Unit
pursuant to November 27, 2009
offering memorandum - - 692,478 - - 692,478
Share based compensation - - 36,658 - - 36,658
Net (loss) - - - - (10,794,172) (10,794,172)
---------- -------- ----------- --------- ----------- -----------
Balance, August 31, 2010 13,510,981 $ 13,511 $22,308,963 $ - (23,339,423) $(1,016,949)
========== ======== =========== ========= =========== ===========
The accompanying notes are an integral part of these financial statements.
F-6
SYNERGY RESOURCES CORPORATION
STATEMENTS OF CASH FLOWS
for the years ended August 31, 2010 and 2009
2010 2009
------------ ------------
Cash flows from operating activities:
Net loss $(10,794,172) $(12,351,873)
------------ ------------
Adjustments to reconcile net loss to
net cash used in operating
activities:
Depreciation, depletion, and
amortization 701,400 97,605
Impairment of oil and gas properties - 945,079
Amortization of debt issuance cost 453,656 -
Accretion of debt discount 1,333,590 -
Stock-based compensation 581,233 10,296,521
Change in fair value of derivative
liability 7,678,457 -
Changes in operating assets and
liabilities:
Accounts receivable (3,091,677) (84,643)
Inventory 744,821 (1,132,685)
Accounts payable (518,942) 610,261
Accrued expenses 460,780 18,726
Effect of merger on operating assets
(liabilities) - (31,437)
Other 7,795 6,307
------------ ------------
Total adjustments 8,351,113 10,725,734
------------ ------------
Net cash used in operating activities
(2,443,059) (1,626,139)
------------ ------------
Cash flows from investing activities:
Acquisition of property and equipment (9,152,175) (1,658,035)
Performance assurance deposit - (85,000)
Cash acquired in merger - 3,987
------------ ------------
Net cash used in investing activities (9,152,175) (1,739,048)
------------ ------------
Cash flows from financing activities:
Cash proceeds from convertible
promissory notes 18,000,000 -
Debt issuance costs (1,348,977) -
Cash proceeds from bank loan payable - 1,161,811
Principal repayments (1,161,811) -
Cash proceeds from sale of stock - 3,052,294
Offering costs - (285,600)
Repurchase of shares - (1,000)
------------ ------------
Net cash provided by financing
activities 15,489,212 3,927,505
------------ ------------
Net increase in cash and equivalents 3,893,978 562,318
Cash and equivalents at beginning of period 2,854,659 2,292,341
------------ ------------
Cash and equivalents at end of period $ 6,748,637 $ 2,854,659
============ ============
Supplemental Cash Flow Information (See
Note 14)
The accompanying notes are an integral part of these financial statements.
F-7
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
August 31, 2010 and 2009
1. Organization and Summary of Significant Accounting Policies
Organization: Synergy Resources Corporation (the "Company") represents the
result of a merger transaction on September 10, 2008, between Brishlin
Resources, Inc. ("Predecessor Brishlin"), a public company, and Synergy
Resources Corporation ("Predecessor Synergy"), a private company. The Company is
engaged in oil and gas acquisitions, exploration, development and production
activities, primarily in the area known as the Denver-Julesburg Basin. The
Company has adopted August 31st as the end of its fiscal year.
Merger Transaction: On September 10, 2008, Predecessor Brishlin
consummated an Agreement to Exchange Common Stock ("Exchange Agreement") with
certain shareholders of Predecessor Synergy to acquire approximately 89% of the
outstanding common stock of Predecessor Synergy. In subsequent transactions, all
the remaining outstanding common shares of Predecessor Synergy were acquired.
Although the legal form of the transaction reflects the acquisition of
Predecessor Synergy by Predecessor Brishlin, the Company determined that the
accounting form of the transaction is a "reverse merger", in which Predecessor
Synergy is identified as the acquiring company and Predecessor Brishlin is
identified as the acquired company. At the time of the transaction, Predecessor
Brishlin had ceased most of its operations and liquidated most of its assets and
liabilities. In accordance with SEC regulations, the transaction was recorded as
a capital transaction rather than a business combination. The transaction is
equivalent to the issuance of common stock by Predecessor Synergy in exchange
for the net assets of Predecessor Brishlin and a recapitalization of Predecessor
Synergy. The assets and liabilities of Predecessor Brishlin were not restated to
their estimated fair market values and no goodwill or other intangible assets
were recorded.
Basis of Presentation: The Company prepares its financial statements in
accordance with accounting principles generally accepted in the United States of
America ("US GAAP").
Exploration Stage Company: Prior to August 31, 2009, the Company was
considered an exploration stage company as it had not commenced its planned
principal operations and its primary activities were related to its initial
organization and other preliminary efforts. Subsequent to August 31, 2009, the
Company commenced its planned principal operations and exited from the
exploration stage.
Reclassifications: Certain amounts previously presented for prior periods
have been reclassified to conform to the current presentation. The
reclassifications had no effect on net loss, accumulated deficit, net assets or
total shareholders' equity.
Use of Estimates: The preparation of financial statements in conformity
with US GAAP requires management to make estimates and assumptions that affect
the reported amount of assets and liabilities, including oil and gas reserves,
F-8
and disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Management routinely makes judgments and estimates about the
effects of matters that are inherently uncertain. Management bases its estimates
and judgments on historical experience and on various other factors that are
believed to be reasonable under the circumstances, the results of which form the
basis for making judgments about the carrying values of assets and liabilities
that are not readily apparent from other sources. Estimates and assumptions are
revised periodically and the effects of revisions are reflected in the financial
statements in the period it is determined to be necessary. Actual results could
differ from these estimates.
Cash and Cash Equivalents: The Company considers cash in banks, deposits
in transit, and highly liquid debt instruments purchased with original
maturities of three months or less to be cash and cash equivalents.
Inventory: Inventories consist primarily of tubular goods and well
equipment to be used in future drilling operations or repair operations and are
carried at the lower of cost or market.
Oil and Gas Properties: The Company uses the full cost method of
accounting for costs related to its oil and gas properties. Accordingly, all
costs associated with acquisition, exploration, and development of oil and gas
reserves (including the costs of unsuccessful efforts) are capitalized into a
single full cost pool. These costs include land acquisition costs, geological
and geophysical expense, carrying charges on non-producing properties, costs of
drilling, and overhead charges directly related to acquisition and exploration
activities. Under the full cost method, no gain or loss is recognized upon the
sale or abandonment of oil and gas properties unless non-recognition of such
gain or loss would significantly alter the relationship between capitalized
costs and proved oil and gas reserves.
Capitalized costs of oil and gas properties are amortized using the
unit-of-production method based upon estimates of proved reserves. For
amortization purposes, the volume of petroleum reserves and production is
converted into a common unit of measure at the energy equivalent conversion rate
of six thousand cubic feet of natural gas to one barrel of crude oil.
Investments in unevaluated properties and major development projects are not
amortized until proved reserves associated with the projects can be determined
or until impairment occurs. If the results of an assessment indicate that the
properties are impaired, the amount of the impairment is added to the
capitalized costs to be amortized.
Under the full cost method of accounting, a ceiling test is performed each
quarter. The full cost ceiling test is an impairment test prescribed by SEC
regulations. The ceiling test determines a limit on the book value of oil and
gas properties. The capitalized costs of proved and unproved oil and gas
properties, net of accumulated depreciation, depletion, and amortization, and
the related deferred income taxes, may not exceed the estimated future net cash
flows from proved oil and gas reserves, less future cash outflows associated
with asset retirement obligations that have been accrued, plus the cost of
unevaluated properties not being amortized, plus the lower of cost or estimated
fair value of unevaluated properties being amortized, less (iv) income tax
effects. Prices are held constant for the productive life of each
F-9
well. Net cash flows are discounted at 10%. If net capitalized costs exceed this
limit, the excess is charged to expense and reflected as additional accumulated
depreciation, depletion and amortization. The calculation of future net cash
flows assumes continuation of current economic conditions. Once impairment
expense is recognized, it cannot be reversed in future periods, even if
increasing prices raise the ceiling amount.
For the year ended August 31, 2010, the oil and natural gas prices used to
calculate the full cost ceiling limitation are the 12 month average prices,
calculated as the unweighted arithmetic average of the first day of the month
price for each month within the 12 month period prior to the end of the
reporting period, unless prices are defined by contractual arrangements. Prices
are adjusted for basis or location differentials. Prior to August 31, 2010,
ceiling calculations were based on the spot price on the last day of the
reporting period.
Capitalized Overhead: A portion of the Company's overhead expenses are
directly attributable to acquisition and development activities. Under the full
cost method of accounting, these expenses are capitalized in the full cost pool.
The Company capitalized overhead expenses of approximately $95,475 and nil for
the years ended August 31, 2010 and 2009, respectively.
Oil and Gas Reserves: The determination of depreciation, depletion and
amortization expense, as well as the ceiling test related to the recorded value
of the Company's oil and natural gas properties, will be highly dependent on the
estimates of the proved oil and natural gas reserves. Oil and natural gas
reserves include proved reserves that represent estimated quantities of crude
oil and natural gas which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. There are numerous
uncertainties inherent in estimating oil and natural gas reserves and their
values, including many factors beyond the Company's control. Accordingly,
reserve estimates are often different from the quantities of oil and natural gas
ultimately recovered and the corresponding lifting costs associated with the
recovery of these reserves.
Capitalized Interest: The Company capitalizes interest on expenditures
made in connection with exploration and development projects that are not
subject to current amortization. Interest is capitalized during the period that
activities are in progress to bring the projects to their intended use. During
the years ended August 31, 2010 and 2009, interest capitalized was $269,761, and
$25,442, respectively.
Debt Issuance Costs: Debt issuance costs of $2,041,455 were incurred in
connection with executing Convertible Promissory Notes between December 29,
2009, and March 12, 2010. (See Note 7) Amortization expense, which is being
recognized over the stated three year term, of $453,657 was recorded during the
year ended August 31, 2010.
Fair Value Measurements: Effective September 1, 2008, the company adopted
FASB Accounting Standards Codification ("ASC") "Fair Value Measurements and
Disclosures", which establishes a framework for assets and liabilities measured
at fair value on a recurring basis included in the Company's balance sheets.
Effective September 1, 2009, similar accounting guidance was adopted for assets
and liabilities measured at fair value on a nonrecurring basis. As defined in
F-10
the guidance, fair value is the price that would be received to sell an asset or
be paid to transfer a liability in an orderly transaction between market
participants at the measurement date (exit price).
The Company uses market data or assumptions that market participants would
use in pricing the asset or liability, including assumptions about risk. These
inputs can either be readily observable, market corroborated or generally
unobservable. Fair value balances are classified based on the observability of
the various inputs.
Asset Retirement Obligations: The Company's activities are subject to
various laws and regulations, including legal and contractual obligations to
reclaim, remediate, or otherwise restore properties at the time the asset is
permanently removed from service. The fair value of a liability for the asset
retirement obligation ("ARO") is initially recorded when it is incurred if a
reasonable estimate of fair value can be made. This is typically when a well is
completed or an asset is placed in service. When the ARO is initially recorded,
the Company capitalizes the cost (asset retirement cost or "ARC") by increasing
the carrying value of the related asset. Over time, the liability increases for
the change in its present value (accretion of ARO), while the capitalized cost
decreases over the useful life of the asset. The capitalized ARCs are included
in the full cost pool and subject to depletion, depreciation and amortization.
In addition, the ARCs are included in the ceiling test calculation. Calculation
of an ARO requires estimates about several future events, including the life of
the asset, the costs to remove the asset from service, and inflation factors.
The ARO is initially estimated based upon discounted cash flows over the life of
the asset and is accreted to full value over time using the Company's credit
adjusted risk free interest rate. Estimates are periodically reviewed and
adjusted to reflect changes.
Derivative Conversion Liability: The Company accounts for its embedded
conversion features in its convertible promissory notes in accordance with the
guidance for derivative instruments, which require a periodic valuation of their
fair value and a corresponding recognition of liabilities associated with such
derivatives. The recognition of derivative conversion liabilities related to the
issuance of convertible debt is applied first to the proceeds of such issuance
as a debt discount at the date of the issuance. Any subsequent increase or
decrease in the fair value of the derivative conversion liabilities is
recognized as a charge or credit to other income (expense) in the statements of
operations.
Revenue Recognition: Revenue is recognized for the sale of oil and natural
gas when production is sold to a purchaser and title has transferred. Revenues
from production on properties in which the Company shares an economic interest
with other owners are recognized on the basis of the Company's interest.
Provided that reasonable estimates can be made, revenue and receivables are
accrued and adjusted upon settlement of actual volumes and prices, as payment is
received often sixty to ninety days after production.
Major Customer and Operating Region: The Company operates exclusively
within the United States of America. Except for cash and equivalent instruments,
all of the Company's assets are employed in and all of its revenues are derived
from the oil and gas industry.
F-11
The Company's oil and gas production is purchased by a few customers. The
table below presents the percentage of oil and gas revenue that was purchased by
major customers.
Year Ended August 31,
---------------------
Major Customers 2010 2009
--------------- ------ -------
Company A 13% 100%
Company B 30% 0%
Company C 57% 0%
As there are other purchasers that are capable of and willing to purchase
the Company's oil and gas production and since the Company has the option to
change purchasers on its properties if conditions so warrant, the Company
believes that its oil and gas production can be sold in the market in the event
that it is not sold to the Company's existing customers, but in some
circumstances a change in customers may entail significant transition costs
and/or shutting in or curtailing production for weeks or even months during the
transition to a new customer.
Stock Based Compensation: The Company records stock-based compensation
expense in accordance with the fair value recognition provisions of US GAAP.
Stock based compensation is measured at the grant date based upon the estimated
fair value of the award and the expense is recognized over the required employee
service period, which generally equals the vesting period of the grant. The fair
value of stock options is estimated using the Black-Scholes-Merton
option-pricing model. The fair value of restricted stock grants is estimated on
the grant date based upon the fair value of the common stock.
Earnings Per Share Amounts: Basic earnings per share includes no dilution
and is computed by dividing net income (or loss) by the weighted-average number
of shares outstanding during the period. Diluted earnings per share is
equivalent to basic earnings per share as all dilutive securities have an
antidilutive effect on earnings per share.. The following dilutive securities
could dilute the future earnings per share:
2010 2009
---------- ---------
Convertible promissory
notes 9,942,500 --
Accrued interest 135,068 --
Warrants(1) 15,286,466 5,161,466
Employee stock options 4,220,000 4,100,000
---------- ---------
Total 29,584,034 9,261,466
========== =========
(1) Also as of August 31, 2010 and 2009, the Company had a contingent
obligation to issue 63,466 potentially dilutive securities, all of which were
excluded from the calculation because the contingency conditions had not been
met.
Income Taxes: Deferred income taxes are recorded for timing differences
between items of income or expense reported in the financial statements and
those reported for income tax purposes using the asset/liability method of
accounting for income taxes. Deferred income taxes and tax benefits are
F-12
recognized for the future tax consequences attributable to differences between
the financial statement carrying amounts of existing assets and liabilities and
their respective tax bases, and for tax loss and credit carry-forwards. Deferred
tax assets and liabilities are measured using enacted tax rates expected to
apply to taxable income in the years in which those temporary differences are
expected to be recovered or settled. The Company provides for deferred taxes for
the estimated future tax effects attributable to temporary differences and
carry-forwards when realization is more likely than not. If the Company
concludes that it is more likely than not that some portion or all of the
deferred tax asset will not be realized, the balance of deferred tax assets is
reduced by a valuation allowance.
The Company adheres to the provisions of the ASC regarding uncertainty in
income taxes. No significant uncertain tax positions were identified as of any
date on or before August 31. 2010. Given the substantial net operating loss
carry-forwards at both the federal and state levels, neither significant
interest expense nor penalties charged for any examining agents' tax adjustments
of income tax returns prior to and including the year ended August 31, 2010 are
anticipated since such adjustments would very likely simply reduce the net
operating loss carry-forwards.
Recent Accounting Pronouncements: The Company evaluates the pronouncements
of various authoritative accounting organizations, primarily the Financial
Accounting Standards Board ("FASB"), the Securities and Exchange Commission
("SEC"), and the Emerging Issues Task Force ("EITF"), to determine the impact of
new pronouncements on US GAAP and the impact on the Company.
Accounting Standards Codification - In June 2009 FASB established the
Accounting Standards Codification ("ASC") as the single source of authoritative
US GAAP to be applied by nongovernmental entities. Rules and interpretive
releases of the SEC under authority of federal securities laws are also sources
of authoritative US GAAP for SEC registrants. The ASC did not change current US
GAAP, but was intended to simplify user access to all authoritative US GAAP by
providing all the relevant literature related to a particular topic in one
place. All previously existing accounting standards were superseded and all
other accounting literature not included in the ASC is considered
non-authoritative. New accounting standards issued subsequent to June 30, 2009,
are communicated by the FASB through Accounting Standards Updates ("ASUs"). The
ASC was effective for the Company on September 1, 2009. Adoption of the ASC did
not have an impact on the Company's financial position, results of operations or
cash flows.
The Company has recently adopted the following new accounting standards:
Oil and Gas Disclosures - See the discussion in Note 2 regarding the
Company's adoption of revised oil and gas disclosures.
Subsequent Events - In May 2009 the ASC guidance for subsequent events was
updated to establish accounting and reporting standards for events that occur
after the balance sheet date but before financial statements are issued. The
guidance was amended in February 2010 by ASU No. 2010-09. The ASU for subsequent
F-13
events sets forth: (i) the period after the balance sheet date during which
management of a reporting entity should evaluate events or transactions that may
occur for potential recognition or disclosure in the financial statements, (ii)
the circumstances under which an entity should recognize events or transactions
occurring after the balance sheet in its financial statements, and (iii) the
disclosures that an entity should make about events or transactions occurring
after the balance sheet date in its financial statements. The amended ASC was
effective immediately and its adoption had no impact on the Company's financial
position, results of operations or cash flows.
Fair value measurements and disclosure - In January 2010 the FASB issued
ASU No. 2010-06 - "Improving Disclosures about Fair Value Measurements". This
update amends existing disclosure requirements to require additional disclosures
regarding fair value measurements, including the amounts and reasons for
significant transfers between Level 1 and Level 2 of the fair value hierarchy.
Furthermore, the reconciliation for fair value measurements using significant
unobservable inputs now requires separate information about purchases, sales,
issuances, and settlements. Additional disclosure is also required about the
valuation techniques and inputs used to measure fair value for both recurring
and nonrecurring measurements. Adoption of this amendment required the Company
to disclose additional fair value information, but otherwise did not have an
impact on the Company's financial position, results of operations, or cash
flows.
The following accounting standards updates were recently issued and have
not yet been adopted by the Company. These standards are currently under review
to determine their impact on the Company's financial position, results of
operations, or cash flows.
Derivatives and Hedging - ASU No. 2010-11 was issued in March 2010 and
clarifies that the transfer of credit risk that is only in the form of
subordination of one financial instrument to another is an embedded derivative
feature that should not be subject to potential bifurcation and separate
accounting. This ASU will be effective for the first fiscal quarter beginning
after June 15, 2010, with early adoption permitted, and is expected to be
adopted by the Company effective September 1, 2010.
Compensation - Stock Compensation - ASU No. 2010-13 was issued in April
2010 and will clarify the classification of an employee share based payment
award with an exercise price denominated in the currency of a market in which
the underlying security trades. This ASU will be effective for the first fiscal
quarter beginning after December 15, 2010, with early adoption permitted.
There were various other updates recently issued, most of which
represented technical corrections to the accounting literature or were
applicable to specific industries, and are not expected to have a material
impact on the Company's financial position, results of operations or cash flows.
F-14
2. Modernization of Oil and Gas Reporting
On December 29, 2008, the SEC approved new requirements for reporting oil
and gas reserves. The new rule, titled "Modernization of Oil and Gas Reporting"
was effective for annual reporting periods ending on or after December 31, 2009,
and was implemented by the Company effective August 31, 2010. During 2010 the
FASB issued ASU No. 2010-03 and ASU No. 2010-14 to align the ASC with the SEC's
revised rules. The new disclosure requirements provide for consideration of new
technologies in evaluating reserves, allow companies to disclose their probable
and possible reserves to investors, report oil and gas reserves using an average
price based on the prior 12 month period rather than year-end prices, and revise
the disclosure requirements for oil and gas operations. Accounting for the
limitation on capitalized costs for full cost companies was also revised,
including the provision that subsequent price increases cannot be considered in
the ceiling test calculation.
Adoption of the new rule impacted depreciation, depletion, and
amortization expense for the year ended August 31, 2010, as well as the ceiling
test calculation for oil and gas properties as of August 31, 2010. The new rules
further impacted the oil and gas reserve quantities that were estimated by the
reservoir engineer.
The Company believes that the most significant change in the rules was the
adoption of a new method to estimate selling prices for oil and gas. Under the
new rules prices are determined as an unweighted arithmetic average of the first
day of the month price for each of the preceding twelve months. Under the old
rules, prices were determined as the spot price on the last day of the reporting
period. For the year ended August 31, 2010, the Company used estimated prices of
$69.20 per barrel of oil and $4.76 per Mcf of gas. Had the old rules been
applied as of August 31, 2010, the prices would have been $64.43 per barrel of
oil and $4.47 per Mcf of gas.
The adoption of the new rules is considered a change in accounting
principle inseparable from a change in accounting estimate. The Company does not
believe that provisions of the new guidance, other than pricing, significantly
impacted the financial statements. The Company does not believe that it is
practicable to estimate the effect of applying the new rules on net loss or the
amount recorded for depreciation, depletion and amortization for the year ended
August 31, 2010.
3. Accounts Receivable
Accounts receivable consist primarily of trade receivables from oil and
gas sales and amounts due from other working interest owners which have been
billed for their proportionate share of wells which the Company operates. For
receivables from joint interest owners, the Company typically has the right to
withhold future revenue disbursements to recover outstanding joint interest
billings. As of August 31, 2010 and 2009, major customers (i.e. those with
balances greater than 10% of total receivables) are shown in the following
table.
F-15
As of August 31,
--------------------------
Accounts Receivable from Major Customers 2010 2009
--------------------------------------- ------------- -----------
Company A * 100%
Company D 27% *
* less than 10%
4. Property and Equipment
Capitalized costs of property and equipment at August 31, 2010 and 2009,
consisted of the following:
As of August 31,
-----------------------------
2010 2009
-------------- -------------
Oil and gas properties, full cost method:
Unevaluated costs, not subject to
amortization:
Lease acquisition costs $ 848,696 $ 420,478
Evaluated costs:
Producing and non-producing 12,992,594 689,779
----------- ----------
Total capitalized costs 13,841,290 1,110,257
Less, accumulated depletion (1,149,096) (456,822)
----------- ----------
Oil and gas properties, net 12,692,194 653,435
Other property and equipment:
Vehicles 89,527 --
Leasehold improvements 32,329 --
Office equipment 36,821 1,337
Less, accumulated depreciation (7,888) (296)
----------- ----------
Other property and equipment, net 150,789 1,041
----------- ----------
Total property and equipment, net $12,842,983 $ 654,476
=========== ==========
The capitalized costs of evaluated oil and gas properties are depleted
using the unit-of-production method based on estimated reserves and the
calculation is performed quarterly. Production volumes for the quarter are
compared to beginning of quarter estimated total reserves to calculate a
depletion rate. For the years ended August 31, 2010 and 2009, depletion of oil
and gas properties was $692,274 and $97,309, respectively, which is equivalent
to $15.52 and $39.54 per barrel of oil, respectively.
Periodically, the Company reviews its unevaluated properties and its
inventory to determine if the carrying value of either asset exceeds its market
value. The review for the year ended August 31, 2009, indicated that the market
value of tubular goods was less than the carrying value and the excess carrying
value of $585,566 was reclassified to the full cost pool to be amortized and
included in the ceiling test. The review for the year ended August 31, 2010,
indicated that asset carrying values were less than market values and no
reclassification was required.
F-16
On a quarterly basis the Company performs the full cost ceiling test. As a
result of the ceiling test performed for the year ended August 31, 2009, the
Company recorded an impairment provision of $945,079, including $585,566 related
to tubular goods and $359,513 related to oil and gas properties. The ceiling
tests performed during the year ended August 31, 2010, did not reveal any
impairments.
For the years ended August 31, 2010 and 2009, depreciation of other
property and equipment was $7,592 and $296, respectively.
5. Bank Loan Payable
In May 2009 the Company arranged a credit facility with a commercial bank
that provided for maximum borrowings up to $1,161,811. Proceeds from the
borrowing were used to purchase pipe used to drill and complete oil and gas
wells and the borrowing was collateralized primarily by the pipe. In April 2010
the outstanding balance was paid in full. The credit facility bore interest at
the prime rate plus 0.5% with a minimum interest rate of 5.5%. Interest costs
related to the credit facility of $30,387 and $25,442 were incurred during the
years ended August 31, 2010 and 2009, respectively.
6. Asset Retirement Obligations
During the year ended August 31, 2010, the Company drilled 36 wells and
will have asset removal obligations once the assets are permanently removed from
service. The primary obligations involve the removal and disposal of surface
equipment, plugging and abandoning the wells, and site restoration. For the
purpose of determining the fair value of ARO incurred during the year ended
August 31, 2010, the Company assumed an inflation rate of 5%, an estimated asset
life of 24 years, and a credit adjusted risk free interest rate of 10.53%.
The following table summarizes the change in asset retirement obligations
for the year ended August 31, 2010:
Balance, August 31, 2009 $ --
Liabilities incurred 253,114
Liabilities settled --
Accretion 1,534
Revisions in previous estimates --
-----------
Balance, August 31, 2010 $254,648
===========
F-17
7. Convertible Promissory Notes and Derivative Conversion Liability
Between December 29, 2009, and March 12, 2010, the Company received gross
proceeds of $18,000,000 from the sale of 180 Units at $100,000 per Unit. Each
Unit consists of one convertible promissory note ("Note") in the principal
amount of $100,000 and 50,000 Series C warrants (collectively referenced as a
"Unit"). The Notes bear interest at 8% per year, payable quarterly, and mature
on December 31, 2012, unless earlier converted by the Note holders or repaid by
the Company. Each Series C warrant entitles the holder to purchase one share of
common stock at a price of $6.00 per share and expires on December 31, 2014.
Net cash proceeds of $16,651,023 from the sale of the Units are being used
primarily to drill and complete oil and gas wells in the Wattenburg field,
located in the Denver-Julesburg Basin. The Notes are collateralized by any oil
and gas wells drilled, completed, or acquired with the proceeds from the
offering.
The Notes are considered hybrid debt instruments containing a detachable
warrant and a conversion feature under which the proceeds of the offering are
allocated to the detachable warrants and the conversion feature based on their
fair values. The warrants were determined to be a component of equity, and the
fair value of the warrants was recorded as additional paid in capital. Since the
warrants were recorded as a component of equity, the fair value of $1,760,048
was estimated at inception and will not be re-measured in future periods. The
Notes contain a conversion feature, at an initial conversion price of $1.60 and
subject to adjustment under certain circumstances, which allow the Note holders
to convert the principal balance into a maximum of 11,250,000 common shares,
plus conversion of accrued and unpaid interest into common shares, also at $1.60
per share. The conversion feature was determined to be an embedded derivative
requiring the conversion option to be separated from the host contract and
measured at its fair value. The conversion option will continue to be recorded
at fair value each reporting period until settlement or conversion, with changes
in the fair value reflected in other income (expense) in the statements of
operations. The fair value of the conversion feature was recorded as derivative
conversion liability.
As of March 12, 2010, the estimated fair value of the Series C warrants
was $1,760,048. The estimated fair value of the conversion feature was
$3,455,809. Allocation of value to the components upon issuance of the Notes
resulted in a debt discount of $5,215,857, which will be accreted over the 36
month life of the Notes using the effective interest method. The effective
interest rate on the Notes is 19%. The Company recorded accretion expense of
$1,333,590 during the year ended August 31, 2010, which included the effect of
accelerated accretion on early Note conversions. .
In connection with the sale of the Units, the Company paid fees and
expenses of $1,348,977 and issued 1,125,000 Series D warrants to the placement
agent. The Series D warrants have an exercise price of $1.60 and an expiration
date of December 31, 2014. The warrants were valued at $692,478 using the
Black-Scholes-Merton option pricing model. The Company recorded $2,041,455 of
debt issuance costs, which will be amortized over the three year term of the
Notes. Amortization expense of $453,656 was recorded during the year ended
August 31, 2010.
F-18
During the fourth quarter of 2010, holders of Convertible Promissory Notes
with a face amount of $2,092,000 plus accrued interest of $2,438 elected to
convert the Notes into 1,309,027 shares of common stock at the conversion price
of $1.60 per share. At the time the Notes were converted, the estimated fair
value of the derivative conversion liability apportioned to the converted Notes
totaled $1,809,149, which was reclassified from derivative conversion liability
to additional paid in capital. Similarly, the unamortized debt discount
apportioned to the converted Notes totaled $488,816. The unamortized debt
discount of $323,604 applicable to the conversion option was charged to
accretion of debt discount and the unamortized debt discount of $165,212
applicable to the warrants was reclassified from debt discount to additional
paid in capital. As of August 31, 2010, Notes with a principal amount of
$15,908,000 were outstanding and the debt discount balance was $3,717,055.
The fair value of the derivative conversion liability is adjusted each
quarter to reflect the change in value. The estimated fair value of the
derivative conversion liability as of August 31, 2010, was $9,325,117, an
increase in fair value of $7,678,457, which was recorded as a change in value of
derivative liability since issuance of the Notes.
8. Fair Value Measurements
Assets and liabilities are measured at fair value on a recurring basis for
disclosure or reporting, as required by ASC "Fair Value Measurements and
Disclosures".
A fair value hierarchy was established that prioritizes the inputs used to
measure fair value. The hierarchy gives the highest priority to unadjusted
quoted prices in active markets for identical assets or liabilities (Level 1
measurements) and the lowest priority to unobservable inputs (Level 3
measurements).
Level 1 - Quoted prices are available in active markets for identical
assets or liabilities as of the reporting date. Active markets are those in
which transactions for the asset or liability occur in sufficient frequency and
volume to provide pricing information on an ongoing basis. Level 1 primarily
consists of financial instruments such as exchange-traded derivatives, listed
securities and U.S. government treasury securities.
Level 2 - Pricing inputs are other than quoted prices in active markets
included in Level 1, which are either directly or indirectly observable as of
the reporting date. Level 2 includes those financial instruments that are valued
using models or other valuation methodologies, where substantially all of these
assumptions are observable in the marketplace throughout the full term of the
instrument, can be derived from observable data or are supported by observable
levels at which transactions are executed in the marketplace.
F-19
Level 3 - Pricing inputs include significant inputs that are generally
less observable than objective sources. These inputs may be used with internally
developed methodologies that result in management's best estimate of fair value.
Level 3 includes those financial instruments that are valued using models or
other valuation methodologies, where substantial assumptions are not observable
in the marketplace throughout the full term of the instrument, cannot be derived
from observable data or are not supported by observable levels at which
transactions are executed in the marketplace. At each balance sheet date, the
Company performs an analysis of all applicable instruments and includes in Level
3 all of those whose fair value is based on significant unobservable inputs.
For the most part, the Company's financial instruments consisted of cash
and equivalents, accounts receivable, accounts payable, accrued liabilities, and
bank loan. Due to the short original maturities and high liquidity of cash and
equivalents, accounts receivable, accounts payable, and accrued liabilities,
carrying amounts approximated fair values. The $1,161,811 carrying amount of the
bank loan payable at August 31, 2009, approximated fair value since borrowings
bore interest at variable rates.
During the year ended August 31, 2010, the Company sold Note Units (See
Note 7), that contained fair value elements. As neither the underlying debt nor
the warrants are traded on a public market, the Company developed a methodology
to estimate fair value.
The Company estimated the fair value of the warrants and the conversion
feature of the Notes at inception by using the Black-Scholes-Merton
option-pricing model. The following assumptions were the same for both
components: volatility of 55%, dividend yield of 0%, and interest rate of 1.5%.
The expected term of the derivative conversion liability is 1.5 years and the
expected term of the warrants is 5 years. The Black-Scholes-Merton option
pricing model also requires an assumption about the fair value of the Company's
common stock. It was concluded upon issuance of the Notes that the Company's
stock traded in an illiquid market, and the reported sales prices may not
represent fair value. As a result, a model that estimated the enterprise value
of the Company based upon oil and gas reserve estimates was used to place a
value of $1.39 on the Company's common stock. As the inputs into this model are
not observable in the marketplace, the results are considered a Level 3
valuation.
As the warrants were recorded as a component of equity, their derived fair
values of the Series C warrants issued with the Notes were assigned a value of
$1,760,048. The fair values of the Series C warrants were estimated at inception
and will not be re-measured in future periods. The Series D warrants issued to
the placement agent were recorded at their estimated fair value of $692,478. The
estimated fair value of the conversion feature classified as a long-term
liability on the balance sheet was $3,455,809, and is re-measured each reporting
period with the resulting change included as a component of other expense in the
determination of net income (loss).
Subsequent to the valuation at inception, the model used to value the
derivative conversion liability was changed from the Black-Scholes-Merton option
pricing model to a Monte Carlo Simulation (MCS) model, as permitted by ASC "Fair
Value Measurements and Disclosures" provided that change results in a
measurement that is equally or more representative of fair value in the
circumstances. The Company believes the MCS model provides a more robust method
to determine estimates of the future share prices of the Company's common stock,
which is a significant input to the calculation. Further, the use of a MCS model
allows the use of stochastic methodology which allows for simulations when the
F-20
payoff depends upon the path followed by the underlying variable, i.e., the
common stock price. Payoffs can occur at several times during the life of the
conversion feature rather than at the end of its life. Inputs to this valuation
technique include over-the-counter forward pricing and volatilities for similar
liabilities in active markets as well as credit risk considerations, including
the incorporation of published interest rates and credit spreads. The
assumptions used were: an expected term of 2.3 years, volatility of 53.07%,
which was derived from the expected volatility of the Company's peer group,
dividend yield of 0%, and a discount rate of 6.64%. Upon evaluation of recent
trading of the Company's common stock during the quarter ended August 31, 2010,
the preponderance of evidence indicated that the market for the Company's common
stock had become both active and orderly. As a result, the Company used the
reported closing price of the common stock as a variable in the MCS model to
value the derivative conversion liability during the period ended August 31,
2010. All of the significant inputs are observable, either directly or
indirectly; therefore, the Company's derivative conversion liability is included
within the Level 2 fair value hierarchy.
The change in valuation technique, which is considered a change in
accounting estimate by the ASC, also represents a change in the categorization
of the valuation from Level 3 to Level 2. The revaluation using this new
technique resulted in an increase in derivative conversion liability by
approximately $300,000, which was included in the change in the fair value of
derivative liability reported as other expense in the statement of operations
for the year ended August 31, 2010.
The derivative conversion liability is re-measured each quarter to reflect
the change in fair value. The estimated fair value of the derivative conversion
liability as of August 31, 2010, was $9,325,117, an increase in fair value of
$7,678,457 since issuance of the Notes.
The following table sets forth by level within the fair value hierarchy
the Company's financial assets and financial liabilities as of August 31, 2010,
that were measured at fair value on a recurring basis.
As of
August 31,
2010 Level 1 Level 2 Level 3
------------ ------------ ------------- ------------
Derivative Conversion $ --
Liability $9,325,117 -- $9,325,117 $ --
The Company also measures all nonfinancial assets and liabilities that are
not recognized or disclosed on a recurring basis. As discussed in Note 6, the
recognition of asset retirement obligations totaling $254,648 was necessary at
August 31, 2010, the value of which was determined using Level 3 inputs. The
estimated fair value of the obligations was determined using several assumptions
and judgments about the ultimate settlement amounts, inflation factors, credit
F-21
adjusted discount rates, timing of settlement, and changes in regulations.
Changes in estimates are reflected in the obligations as they occur.
9. Related Party Transactions and Commitments
The Company's executive officers control three entities that have entered
into agreements to provide various services and office space to the Company as
well as an option to acquire certain oil and gas interests. The entities are
Petroleum Management, LLC ("PM"), Petroleum Exploration and Management, LLC
("PEM"), and HS Land & Cattle, LLC ("HSLC").
Effective June 11, 2008, the Company entered into an Administrative
Services Agreement with PM. The Company paid $10,000 per month for leasing
office space and an equipment yard located in Platteville, Colorado, and paid
$10,000 per month for office support services including secretarial service,
word processing, communication services, office equipment and supplies. The
Company paid $206,667 and $240,000 under this agreement for the years ended
August 31, 2010 and 2009, respectively. Effective June 30, 2010, the Company
terminated the agreement.
Effective August 7, 2008, the Company entered into a letter of intent with
the related entities that provides an option to acquire working interests in oil
and gas leases which are owned by PM and/or PEM. The oil and gas leases cover
640 acres in Weld County, Colorado, and subject to certain conditions, will be
transferred to the Company for payment of $1,000 per net mineral acre. The
working interests in the leases vary but the net revenue interest in the leases,
if acquired by the Company, will not be less than 75%. The letter of intent
expired on August 31, 2010. As of August 31, 2010, the Company had exercised its
options on all available leases at a total cost of $360,000.
Effective July 1, 2010, the Company entered into a lease with HSLC, for
office space and an equipment yard located in Platteville, Colorado. The lease
requires monthly payments of $10,000 and terminates on June 30, 2011. The
Company paid $20,000 under this agreement for the year ended August 31, 2010.
On June 1, 2008, the Company entered into an agreement with Energy
Capital Advisors, an entity related through common ownership interests. Energy
Capital Advisors provided certain services directly related to raising
additional capital for the Company. Compensation under the agreement was $30,000
per month through December 31, 2008, and $10,000 per month from January 1, 2009
to May 31, 2009, when the agreement terminated. During the year ended August 31,
2009, the Company paid $170,000 related to this agreement.
During the year ended August 31, 2009, the Company had a consulting
agreement with two directors under which the Company paid $120,000.
In addition to the transactions described above, the Company undertook
various activities with PM and PEM that are related to the development and
operation of oil and gas properties. The Company purchased certain oil and gas
equipment, such as tubular goods and surface equipment, from PM. The Company
reimbursed PM for the original cost of the equipment. PEM is a joint working
F-22
interest owner of certain wells operated by the Company. PEM is charged for
their pro-rata share of costs and expenses incurred on their behalf by the
Company, and similarly PEM is credited for their pro-rata share of revenues
collected on their behalf. The following table summarizes the transactions with
PM and PEM during each of the two years ended August 31, 2010 and 2009:
Year Ended August 31,
-----------------------------
2010 2009
-------------- -------------
Purchase of equipment from PM $1,070,495 $ 1,718,967
Payments to PM for equipment (531,797) (1,718,967)
------------- -----------
Balance due to PM for equipment $ 538,698 $ --
============= ===========
Joint interest costs billed to PEM 1,629,895 $ --
Amounts collected from PEM (762,060) --
------------- -----------
Joint interest billing due from
PEM $ 867,835 $ --
============= ===========
Revenues collected on behalf of
PEM $ 167,499 $ --
Payments to PEM (151,528) --
------------- -----------
Balance due to PEM for revenues $ 15,971 $ --
============= ===========
10. Shareholders' Equity
Preferred Stock: The Company has authorized 10,000,000 shares of preferred
stock with a par value of $0.01 per share. These shares may be issued in series
with such rights and preferences as may be determined by the Board of Directors.
Since inception, the Company has not issued any preferred shares.
Common Stock: The Company has authorized 100,000,000 shares of common
stock with a par value of $0.001 per share.
Issued and Outstanding: The total issued and outstanding common stock at
August 31, 2010, is 13,510,981 common shares, as follows:
i. Effective June 11, 2008, the Company issued 7,900,000 common shares to
its founders at $0.001 per share, for aggregate proceeds of $7,900.
ii. Pursuant to a Private Offering Memorandum dated June 20, 2008, the
Company sold 1,000,000 units at $1.00 per unit. Each unit consists of
one share of restricted common stock and one Series A warrant that
entitles the holder to purchase one share of common stock at $6.00 per
share through December 31, 2012.
iii.Pursuant to a Private Offering Memorandum dated July 16, 2008, the
Company sold 1,060,000 units at $1.50 per unit for total cash proceeds
of $1,590,000. Each unit consists of one share of restricted common
stock and one Series A warrant that entitles the holder to purchase one
share of common stock at $6.00 per share through December 31, 2012.
F-23
iv. Effective September 10, 2008, the Company agreed to issue 1,038,000
common shares to the shareholders of Predecessor Brishlin, on an
exchange basis of one share of Synergy common stock for each share of
Brishlin common stock. In addition, the shareholders of Predecessor
Brishlin received 1,038,000 Series A warrants that entitle the holder
to purchase one share of common stock at $6.00 per share through
December 31, 2012.
v. Effective December 1, 2008, the Company repurchased 1,000,000 shares of
its common stock from one of the original Predecessor Synergy
shareholders for $1,000, the price at which the shares were originally
sold to the shareholder.
vi. Pursuant to a Private Offering Memorandum dated December 1, 2008, the
Company sold 1,000,000 units at $3.00 per unit for total cash proceeds
of $3,000,000. Offering costs associated with the offering aggregated
$285,600, resulting in net cash proceeds of $2,714,400. Each unit
consists of two shares of common stock, one Series A warrant and one
Series B warrant. Each Series A warrant entitles the holder to purchase
one share of common stock at a price of $6.00 per share. The Series A
warrants expire on December 31, 2012, or earlier under certain
conditions. Each Series B warrant entitles the holder to purchase one
share of common stock at a price of $10.00 per share. The Series B
warrants expire on December 31, 2012, or earlier under certain
conditions.
vii.During the quarter ended August 31, 2010, the Company issued 1,309,027
common shares pursuant to the conversion of Notes in the principal
amount of $2,092,000 plus accrued interest of $2,438. The contractual
conversion price is $1.60 per share.
viii. Pursuant to an agreement dated June 25, 2010, the Company issued
5,966 common shares in exchange for mineral leases. The transaction
was recorded at a value of $16,645 based upon the closing price of the
Company's common stock on June 25, 2010.
ix. As partial compensation to its Directors, the Company issued 197,988
common shares on July 12, 2010. The transaction was recorded at a
value of $544,575 based upon the closing price of the Company's common
stock on July 12, 2010.
In addition to the warrant issuances described in the preceding
paragraphs, the Company issued 31,733 placement agent warrants in connection
with the Private Offering Memorandum dated December 1, 2008. Each placement
agent warrant entitles the holder to purchase one unit (which unit is identical
to the units sold under the Private Offering Memorandum dated December 1, 2008,
described in item vi. above) at a price of $3.60. Each unit consisted of two
shares of common stock, one Series A warrant, and one Series B warrant. To
maintain comparability of the placement agent warrants with the other warrants,
the Company presents the placement agent warrants as 63,466 shares at an
F-24
exercise price of $1.80. The Series A and Series B warrants issuable upon
exercise of the placement agent warrants are not considered outstanding for
accounting purposes until such time, if ever, that the placement agent warrants
are exercised, and are disclosed as a commitment in Note 12.
Pursuant to an Offering Memorandum dated November 27, 2009, the Company
sold 180 convertible promissory note units at $100,000 per unit. (See Note 7.)
Each unit consists of one convertible promissory note and 50,000 Series C
warrants. Each Series C warrant entitles the holder to purchase one share of
common stock at a price of $6.00 per share and warrants were issued to purchase
an aggregate of 9,000,000 common shares. The Series C warrants expire on
December 31, 2014. In connection with this transaction, the Company issued
1,125,000 Series D warrants to the placement agent. The Series D warrants are
exercisable at a price of $1.60 per share and expire on December 31, 2014.
The following table summarizes activity for common stock warrants for each
of the two years ended August 31, 2010:
Number of Weighted average
warrants exercise price
---------- ----------------
Outstanding, August 31, 2008 2,043,571 $6.00
Granted 3,117,895 $7.20
Exercised --
----------
Outstanding, August 31, 2009 5,161,466 $6.72
Granted 10,125,000 $5.51
Exercised --
----------
Outstanding, August 31, 2010 15,286,466 $5.92
==========
The following table summarizes information about the Company's issued and
outstanding common stock warrants as of August 31, 2010:
Remaining
Contractual
Number of Life (in Exercise Price times
Exercise Price Shares years) Number of Shares
-------------- ------ ------ ----------------
$ 1.60 1,125,000 4.3 $ 1,800,000
$ 1.80 63,466 2.3 114,239
$ 6.00 4,098,000 2.3 24,588,000
$ 6.00 9,000,000 4.3 54,000,000
$10.00 1,000,000 2.3 10,000,000
---------- --------------
15,286,466 3.7 $90,502,239
================ ==============
11. Stock Based Compensation
The Company accounts for stock option activities as provided by ASC "Stock
Compensation," which requires the Company to expense as compensation the value
F-25
of grants and options as determined in accordance with the fair value based
method prescribed in the guidance. The Company estimates the fair value of each
stock option at the grant date by using the Black-Scholes-Merton option-pricing
model.
The Company recorded stock-based compensation expense of $581,233 and
$10,296,521 for the years ended August 31, 2010 and 2009, respectively. The
components of the expense for the year ended August 31, 2010 include stock
grants of $544,575 to directors and option-based compensation of $36,658.
During June 2008 stock options were granted to purchase 4,000,000 shares
of common stock. Effective June 11, 2008, grants covering 2,000,000 shares were
issued to the executive officers at an exercise price of $10.00 and a term of
five years, and these options will vest over a one year period. The fair value
of these options was determined to be nil based upon the following assumptions:
expected life of 2.5 years, stock price of $1.00 at date of grant, nominal
volatility, dividend yield of 0%, and interest rate of 2.63%. Effective June 30,
2008, grants covering an additional 2,000,000 shares were issued to the
executive officers at an exercise price of $1.00 and a term of five years, and
these options will vest over a one year period. Based upon a fair value
calculation, these options were determined to have a value of $127,000 using the
following assumptions: expected life of 2.5 years, stock price of $1.00 at date
of grant, nominal volatility, dividend yield of 0%, and interest rate of 2.63%.
Stock option compensation expense of $98,800 was recorded for the year ended
August 31, 2009.
In connection with the merger, the Company agreed to issue stock option
grants covering 4,000,000 shares to replace the similar options described in the
preceding paragraph. Using the Black-Scholes-Merton option-pricing model, the
Company estimated that the fair value of the replacement options exceeded the
fair value of the options surrendered by $10,185,345. The assumptions used in
the model were: expected life of 2.5 years, stock price of $3.50 at date of
grant, volatility of 166%, dividend yield of 0%, and interest rate of 2.63%. The
incremental expense of $10,185,345 was recorded as stock option compensation
expense for the year ended August 31, 2009.
Effective December 31, 2008, the Company granted stock options to an
employee to purchase 100,000 shares of common stock at an exercise price of
$3.00 and a term of ten years. These options vest over a five year period. Based
on a fair value calculation, these options were determined to have a value of
$185,640 using the following assumptions: expected life of 5 years, stock price
of $2.00 at date of grant, volatility of 166%, dividend yield of 0%, and
interest rate of 3.13%. Stock option compensation expense of $24,768 and $12,376
were recorded for the years ended August 31, 2010 and 2009, respectively, based
on a pro-ration of the fair value over the vesting period.
Effective July 1, 2010, the Company granted stock options to employees to
purchase 120,000 shares of common stock at an exercise price of $2.50 and a term
of ten years. The options vest over various periods ranging from two to five
years. Based on a fair value calculation, these options were determined to have
a value of $155,544 using the following assumptions: expected life of 5.875
years, stock price of $2.52 at date of grant, volatility of 53.18%, dividend
F-26
yield of 0%, and interest rate of 2.08%. Stock option compensation expense of
$11,890 was recorded for the year ended August 31, 2010, based on a pro-ration
of the fair value over the vesting period.
The estimated unrecognized compensation cost from unvested stock options
as of August 31, 2010, was approximately $292,000, substantially all of which
will be recognized during the next two years.
The following table summarizes activity for stock options for each of the
two years ended August 31, 2010:
Number Weighted average
of shares Exercise price
--------- ----------------
Outstanding August 31, 2008 4,000,000 $5.50
Granted 100,000 $3.00
Exercised --
---------
Outstanding August 31, 2009 4,100,000 $5.44
Granted 120,000 $2.50
Exercised --
---------
Outstanding, August 31, 2010 4,220,000 $5.36
=========
The following table summarizes information about outstanding stock options
as of August 31, 2010:
Remaining Weighted
Contractual Average Aggregate
Exercise Number Life (in Exercise Number Intrinsic
Prices of Shares years) Price Exercisable Value
------------- ---------- ------------- ---------- -------------------------
$10.00 2,000,000 2.8 $10.00 2,000,000 --
$1.00 2,000,000 2.8 $1.00 2,000,000 $2,500,000
$3.00 100,000 8.3 $3.00 10,000 --
--
$2.50 120,000 9.8 $2.50 --
---------- ----------- -----------
4,220,000 3.1 $5.36 4,010,000 $2,500,000
========== =========== ===========
12. Commitments and Contingencies
On June 1, 2010, Synergy entered into new employment agreements with its
executive officers. The employment agreements, which expire on May 31, 2013,
provide that Synergy will pay each executive officer a monthly salary of
$25,000. As additional consideration, the officers will receive shares of the
Company's common stock valued at $100,000 based on the average closing price of
our stock for the previous 20 trading days for every 50 wells that begin
production after June 1, 2010.
F-27
The placement agent warrants issued in connection with the Private
Offering Memorandum dated December 1, 2008, entitle the holder to purchase units
consisting of common stock and warrants. The Series A and Series B warrants
issuable upon exercise of the placement agent warrants are not considered
outstanding for accounting purposes until such time, if ever, that the placement
agent warrants are exercised. In the event that the placement agent warrants are
exercised, the Company will be obligated to issue 31,733 Series A warrants and
31,733 Series B warrants.
13. Income Taxes
The components of the provision for income tax expense (benefit) consist
of the following:
Years Ended August 31,
---------------------------
2010 2009
------------- ------------
Current income taxes $ -- $ --
Deferred income taxes (3,994,000) (4,572,000)
Valuation allowance 3,994,000 4,572,000
----------- -----------
Total tax benefit $ -- $ --
=========== ===========
The change in the valuation allowance from August 31, 2009 to August 31,
2010, includes, as a reconciling item, the $1,515,000 tax effect of amounts
reclassified to equity from the liability as part of the allocation of fair
value from the proceeds of the financing transaction and the corresponding
offset benefit from the release of the valuation allowance.
The tax effects of temporary differences that give rise to significant
components of the deferred tax assets and deferred tax liabilities at August 31,
2010 and 2009, are presented below:
As of August 31,
-----------------------------
2010 2009
------------- -------------
Deferred tax assets:
Net operating loss carry-forward $3,838,000 $ 481,000
Stock-based compensation 3,834,000 3,820,000
Convertible promissory notes 1,876,000 --
Basis of oil and gas properties -- 357,000
Other 10,000 10,000
Less: valuation allowance (7,147,000) (4,668,000)
----------- ------------
Subtotal 2,411,000 --
----------- ------------
Deferred tax liabilities:
Basis of oil and gas properties (2,411,000) --
----------- ------------
Subtotal (2,411,000) --
----------- ------------
Total $ -- $ --
=========== ============
F-28
A reconciliation of expected federal income taxes on income from
continuing operations at statutory rates with the expense (benefit) for income
taxes is follows:
Years Ended August 31,
-----------------------------
2010 2009
------------- -------------
Pre-tax book net income $ (3,670,000) $ (4,200,000)
State taxes (324,000) (372,000)
Change in valuation allowance 3,994,000 4,572,000
------------ ------------
$ -- $ --
============ ============
At August 31, 2010, the Company has a net operating loss carry-forward for
federal and state tax purposes of approximately $10,374,000 that could be
utilized to offset taxable income of future years. Substantially all of the
carry-forward will expire in 2029 and 2030.
The realization of the deferred tax assets related to the net operating
loss carryforward is dependent upon the Company's ability to generate future
taxable income. Given the Company's history of operating losses since inception,
it cannot be assumed that the generation of future taxable income is more likely
than not. The ability of the Company to utilize net operating loss
carry-forwards may be further limited by other provisions of the Internal
Revenue Code. The utilization of such carry-forwards may be limited upon the
occurrence of certain ownership changes, including the purchase or sale of stock
by 5% shareholders and the offering of stock by the Company during any
three-year period resulting in an aggregate change of more than 50% in the
beneficial ownership of the Company. In the event of an ownership change,
Section 382 of the Code imposes an annual limitation on the amount of a
Company's taxable income that can be offset by these carry-forwards.
Accordingly, the Company has established a full valuation allowance
against the deferred tax assets.
14. Supplemental Schedule of Information to the Statements of Cash Flows
The following table supplements the cash flow information presented in the
financial statements for the years ended August 31, 2010 and 2009:
Year Ended August 31,
-------------------------
2010 2009
------------ ------------
Supplemental cash flow information:
Interest paid $ 617,017 $ 5,325
Income taxes paid -- --
Non-cash investing and financing activities:
Conversion of promissory notes into
common stock $2,092,000 $ --
Accrued capital expenditures 3,446,439 --
Warrants issued to placement agent 692,478 --
Asset retirement costs and obligations 253,114 --
Shares issued for mineral leases 16,645 --
Net assets acquired in merger -- 11,675
F-29
15. Supplemental Oil and Gas Information (unaudited)
Costs Incurred: Costs incurred in oil and gas property acquisition,
exploration and development activities for the years ended August 31, 2010 and
2009, were:
Years Ended August 31,
--------------------------
2010 2009
----------- -----------
Acquisition of Property:
Unproved $ 1,530,221 $ 420,478
Proved -- --
Exploration costs -- --
Development costs 10,360,516 2,408,030
Capitalized internal costs 95,475 --
----------- -----------
Total Costs Incurred $11,986,212 $ 2,828,508
=========== ===========
Capitalized Costs Excluded from Amortization: The following table
summarizes costs related to unevaluated properties that have been excluded from
amounts subject to depletion, depreciation, and amortization at August 31, 2010.
There were no individually significant properties or significant development
projects included in the Company's unevaluated property balance. The Company
regularly evaluates these costs to determine whether impairment has occurred.
The majority of these costs are expected to be evaluated and included in the
amortization base within three years.
Period Incurred As of
Year Ended August 31, August 31,
----------------------- ------------
2010 2009 2010
---------- ----------- ------------
Unproved leasehold acquisition
costs $ 554,739 $ 293,957 $ 848,696
Unevaluated development costs -- -- --
---------- ----------- ------------
Total $ 554,739 $ 293,957 $ 848,696
========== =========== ============
Oil and Natural Gas Reserve Information: Proved reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions (prices and costs held constant as of the date the estimate is made).
Proved developed reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Proved
undeveloped reserves are reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion.
F-30
Proved oil and natural gas reserve information at August 31, 2010 and
2009, and the related discounted future net cash flows before income taxes are
based on estimates prepared by Ryder Scott Company LP. Reserve information for
the properties was prepared in accordance with guidelines established by the
SEC.
The reserve estimates as of August 31, 2010, were prepared in accordance
with "Modernization of Oil and Gas Reporting" published by the SEC. The new
guidance included updated definitions of proved developed and proved undeveloped
oil and gas reserves, oil and gas producing activities and other terms. Proved
oil and gas reserves as of August 31, 2010, were calculated based on the prices
for oil and gas during the 12 month period before the reporting date, determined
as the unweighted arithmetic average of the first day of the month price for
each month within such period, rather than the year-end spot prices, which had
been used in prior years. This average price is also used in calculating the
aggregate amount and changes in future cash inflows related to the standardized
measure of discounted future cash flows. Undrilled locations can be classified
as having proved undeveloped reserves only if a development plan has been
adopted indicating that they are scheduled to be drilled within five years. The
new guidance broadened the types of technologies that may be used to establish
reserve estimates. Prior period data presented throughout Note 15 is not
required to be, nor has it been, updated based upon the new guidance.
The following table sets forth information regarding the Company's net
ownership interests in estimated quantities of proved developed and undeveloped
oil and gas reserve quantities and changes therein for the years ended August
31, 2010 and 2009:
Oil (Bbl) Gas (Mcf)
----------- ----------
Balance, August 31, 2008 -- --
Revision of previous estimates -- --
Purchase of reserves in place -- --
Extensions, discoveries, and other
additions 8,160 30,066
Sale of reserves in place -- --
Production (1,730) (4,386)
-------------- --------------
Balance, August 31, 2009 6,430 25,680
Revision of previous estimates 4,318 24,844
Purchase of reserves in place -- --
Extensions, discoveries, and other
additions 687,017 4,571,680
Sale of reserves in place -- --
Production (21,080) (141,154)
-------------- --------------
Balance, August 31, 2010 676,685 4,481,051
============== ==============
Proved developed and undeveloped reserves:
Developed at August 31, 2009 6,430 25,680
Developed at August 31, 2010 395,453 2,349,027
Undeveloped at August 31, 2010 281,232 2,132,024
F-31
Standardized Measure of Discounted Future Net Cash Flows: The following
analysis is a standardized measure of future net cash flows and changes therein
related to estimated proved reserves. Future oil and gas sales have been
computed by applying average prices of oil and gas for August 31, 2010, and the
year-end spot prices for August 31, 2009. Future production and development
costs were computed by estimating the expenditures to be incurred in developing
and producing the proved oil and gas reserves at the end of the year, based on
year-end costs. The calculation assumes the continuation of existing economic
conditions, including the use of constant prices and costs. Future income tax
expenses were calculated by applying year-end statutory tax rates, with
consideration of future tax rates already legislated, to future pretax cash
flows relating to proved oil and gas reserves, less the tax basis of properties
involved and tax credits and loss carry-forwards relating to oil and gas
producing activities. All cash flow amounts are discounted at 10% annually to
derive the standardized measure of discounted future cash flows. Actual future
cash inflows may vary considerably, and the standardized measure does not
necessarily represent the fair value of the Company's oil and gas reserves.
Actual future net cash flows from oil and gas properties will also be affected
by factors such as actual prices the Company receives for oil and gas, the
amount and timing of actual production, supply of and demand for oil and gas,
and changes in governmental regulations or taxation.
The following table sets forth the Company's future net cash flows
relating to proved oil and gas reserves based on the standardized measure
prescribed in the ASC:
Year Ended August 31,
----------------------------------
2010 2009
--------------- -------------
Future cash inflows $ 68,167,917 $ 446,485
Future production costs (19,877,331) (141,134)
Future development costs (15,836,965) --
Future income tax expense (6,926,890) --
------------ -----------
Future net cash flows 25,526,731 305,351
10% annual discount for
estimated timing of cash
flows (12,504,334) (72,394)
------------ -----------
Standardized measure of
discounted future net cash
flows $ 13,022,397 $ 232,957
============ ===========
There have been significant fluctuations in the posted prices of oil and
natural gas during the last two years. Prices actually received from purchasers
of the Company's oil and gas are adjusted from posted prices for location
differentials, quality differentials, and BTU content. Estimates of the
Company's reserves are based on realized prices. The following table presents
the prices used to prepare the estimates, based upon average prices for the year
ended August 31, 2010, and year-end spot prices for the year ended August 31,
2009:
F-32
Natural Gas Oil
(Mcf) (Bbl)
----------- -----
August 31, 2009 (Spot Price) $2.05 $61.24
August 31, 2010 (Average) $4.76 $69.20
Changes in the Standardized Measure of Discounted Future Net Cash Flows:
The principle sources of change in the standardized measure of discounted future
net cash flows are:
Year Ended August 31,
--------------------------------
2010 2009
------------- -------------
Standardized measure, beginning of year $ 232,957 $ --
Sale and transfers, net of production
costs (1,834,924) (82,549)
Net changes in prices and production
costs 131,153 --
Extensions, discoveries, and improved
recovery 17,785,154 315,506
Changes in estimated future development
costs -- --
Development costs incurred during the
period -- --
Revision of quantity estimates 212,851 --
Accretion of discount 30,535 --
Net change in income taxes (3,535,329) --
Purchase of reserves in place -- --
Sale of reserves in place -- --
Other -- --
----------- -------------
Standardized measure, end of year $13,022,397 $ 232,957
============ =============
15. Subsequent Events
The Company evaluated all events subsequent to the balance sheet date of
August 31, 2010, through the date of issuance of these financial statements and
has determined that except as set forth below, there are no subsequent events
that require disclosure.
On October 1, 2010, the Company acquired certain oil and gas properties
from PM and PEM for $1,017,435. As more fully discussed in Note 9, both entities
are controlled by Ed Holloway and William E. Scaff, Jr., both officers and
directors of the Company.
The oil and gas properties consist of:
o 6 producing oil and gas wells (100% working interest/ 80% net revenue
interest)
o 2 shut in oil wells (100% working interest/ 80% net revenue interest)
o 15 drill sites (net 6.25 wells)
o Miscellaneous equipment.
The oil and gas properties are located in the Wattenberg field, which is
part of the Denver-Julesburg Basin.
F-33
SYNERGY RESOURCES CORPORATION
May 31, 2011
Financial Statements
(Unaudited)
F-34
SYNERGY RESOURCES CORPORATION
BALANCE SHEETS
As of As of
May 31, 2011 August 31, 2010
--------------- ---------------
(unaudited)
ASSETS
Current assets:
Cash and cash equivalents $11,096,665 $ 6,748,637
Accounts receivable:
Oil and gas sales 2,400,999 377,675
Joint interest billing 2,660,148 1,930,810
Related party receivable 30,391 867,835
Inventory 706,742 387,864
Other current assets 18,307 12,310
--------------- ---------------
Total current assets 16,913,252 10,325,131
--------------- ---------------
Property and equipment:
Oil and gas properties, full cost method, net 38,582,870 12,692,194
Other property and equipment, net 230,671 150,789
--------------- ---------------
Property and equipment, net 38,813,541 12,842,983
--------------- ---------------
Debt issuance costs, net of amortization - 1,587,799
Other assets 90,000 86,000
--------------- ---------------
Total assets $55,816,793 $24,841,913
=============== ===============
LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable:
Trade $ 3,641,713 $ 3,015,562
Related party payable - 554,669
Accrued expenses 1,334,560 517,921
Notes payable, related party 5,200,000 -
--------------- ---------------
Total current liabilities 10,176,273 4,088,152
Asset retirement obligations 521,081 254,648
Convertible promissory notes, net of debt
discount - 12,190,945
Derivative conversion liability - 9,325,117
--------------- ---------------
Total liabilities 10,697,354 25,858,862
--------------- ---------------
Commitments and contingencies (See Note 8)
Shareholders' equity (deficit):
Preferred stock - $0.01 par value,
10,000,000 shares authorized:
no shares issued and outstanding - -
Common stock - $0.001 par value,
100,000,000 shares authorized:
35,408,632 and 13,510,981 shares
issued and outstanding as of
May 31, 2011, and August 31, 2010,
respectively 35,409 13,511
Additional paid-in capital 81,613,428 22,308,963
Accumulated deficit (36,529,398) (23,339,423)
--------------- ---------------
Total shareholders' equity (deficit) 45,119,439 (1,016,949)
--------------- ---------------
Total liabilities and shareholders'
equity (deficit) $55,816,793 $24,841,913
=============== ===============
The accompanying notes are an integral part of these financial
statements.
F-35
SYNERGY RESOURCES CORPORATION
STATEMENTS OF OPERATIONS
(unaudited)
Three Months Ended May 31, Nine Months Ended May 31,
2011 2010 2011 2010
------------- ------------- ----------- -----------
Revenues:
Oil and gas revenues $ 2,921,910 $ 607,253 $ 6,399,193 $ 995,764
Service revenues 184,426 - 211,715 -
------------- ------------- ----------- -----------
Total revenues 3,106,336 607,253 6,610,908 995,764
------------- ------------- ----------- -----------
Expenses:
Lease operating
expenses 668,683 106,503 1,131,837 161,545
Depreciation,
depletion,
and amortization 830,639 200,890 2,062,825 293,829
General and
administrative 1,059,742 350,954 2,171,721 986,364
------------- ------------- ----------- -----------
Total expenses 2,559,064 658,347 5,366,383 1,441,738
------------- ------------- ----------- -----------
Operating income (loss) 547,272 (51,094) 1,244,525 (445,974)
------------- ------------- ----------- -----------
Other income (expense):
Change in fair
value of
derivative
conversion liability 86,192 (2,764,888) (10,229,229)(2,764,888)
Interest expense, net (950,860) (834,381) (4,246,945)(1,248,517)
Interest income 25,784 551 41,675 4,237
------------- ------------- ----------- -----------
Total other
(expense) (838,884) (3,598,718) (14,434,499)(4,009,168)
------------- ------------- ----------- -----------
Loss before income taxes (291,612) (3,649,812) (13,189,974)(4,455,142)
Provision for income
taxes - - - -
------------- ------------- ----------- -----------
Net loss
$ (291,612) $(3,649,812) $(13,189,974)$(4,455,142)
============= ============= ============ ============
Net loss per common share:
Basic and Diluted (0.01) (0.30) (0.58) (0.37)
============= ============= ============ ============
Weighted average shares
outstanding:
Basic and Diluted 32,813,298 11,998,000 22,713,785 11,998,000
============= ============= ============ ============
The accompanying notes are an integral part of these financial
statements.
F-36
SYNERGY RESOURCES CORPORATION
STATEMENTS OF CASH FLOWS
(unaudited)
Nine Months Ended May 31,
2011 2010
------------- -------------
Cash flows from operating activities:
Net loss $(13,189,974) $ (4,455,142)
------------- -------------
Adjustments to reconcile net loss to
net cash provided by (used in)
operating activities:
Depreciation, depletion, and
amortization 2,062,825 293,829
Amortization of debt issuance cost 1,587,799 283,535
Accretion of debt discount 2,664,138 622,214
Stock-based compensation 563,518 17,790
Change in fair value of derivative
liability 10,229,229 2,764,888
Changes in operating assets and
liabilities:
Accounts receivable (1,915,218) (681,923)
Inventory (318,878) (109,591)
Accounts payable 1,275,804 (64,008)
Accrued expenses 875,636 328,399
Other (9,997) 15,459
------------- -------------
Total adjustments
17,014,856 3,470,592
------------- -------------
Net cash provided by (used in)
operating activities 3,824,882 (984,550)
------------- -------------
Cash flows from investing activities:
Acquisition of property and equipment (21,163,392) (5,717,527)
Proceeds from sales of oil and gas
properties 4,995,817 -
------------- -------------
Net cash used in investing activities
(16,167,575) (5,717,527)
------------- -------------
Cash flows from financing activities:
Cash proceeds from sale of stock 18,000,000 -
Offering costs (1,309,279) -
Cash proceeds from convertible
promissory notes - 18,000,000
Debt issuance costs - (1,348,977)
Principal repayments - (1,161,811)
------------- -------------
Net cash provided by financing
activities 16,690,721 15,489,212
------------- -------------
Net increase in cash and equivalents 4,348,028 8,787,135
Cash and equivalents at beginning of
period 6,748,637 2,854,659
------------- -------------
Cash and equivalents at end of period $ 11,096,665 $ 11,641,794
============= =============
Supplemental Cash Flow Information (See
Note 11)
The accompanying notes are an integral part of these financial statements.
F-37
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
May 31, 2011
(unaudited)
1. Organization and Summary of Significant Accounting Policies
Organization: Synergy Resources Corporation (the "Company") is engaged in
oil and gas acquisitions, exploration, development and production activities,
primarily in the area known as the Denver-Julesburg ("D-J") Basin. The Company
has adopted August 31st as the end of its fiscal year.
Interim Financial Information: The interim financial statements included
herein have been prepared by the Company, without audit, pursuant to the rules
and regulations of the Securities and Exchange Commission ("SEC") as promulgated
in Item 210 of Regulation S-X. The Company prepares its financial statements in
accordance with accounting principles generally accepted in the United States of
America ("US GAAP"). Certain information and footnote disclosures normally
included in financial statements prepared in accordance with US GAAP have been
condensed or omitted pursuant to such SEC rules and regulations. The Company
believes that the disclosures included are adequate to make the information
presented not misleading and recommends that these financial statements be read
in conjunction with the audited financial statements and notes thereto included
in the Company's annual report on Form 10-K for the year ended August 31, 2010.
In management's opinion, the unaudited financial statements contained
herein reflect all adjustments, consisting solely of normal recurring items,
which are necessary for the fair presentation of the Company's financial
position, results of operations, and cash flows on a basis consistent with that
of its prior audited financial statements. However, the results of operations
for interim periods may not be indicative of results to be expected for the full
fiscal year.
Reclassifications: Certain amounts previously presented for prior periods
have been reclassified to conform to the current presentation. The
reclassifications had no net effect on net loss, shareholders' equity (deficit)
or cash flows.
Use of Estimates: The preparation of financial statements in conformity
with US GAAP requires management to make estimates and assumptions that affect
the reported amount of assets and liabilities, including, but not limited to,
oil and gas reserves, and disclosure of contingent assets and liabilities at the
date of the financial statements as well as the reported amounts of revenues and
expenses during the reporting period. Management routinely makes judgments and
estimates about the effects of matters that are inherently uncertain. Management
bases its estimates and judgments on historical experience and on various other
factors that are believed to be reasonable under the circumstances, the results
of which form the basis for making judgments about the carrying values of assets
and liabilities that are not readily apparent from other sources. Estimates and
assumptions are revised periodically and the effects of revisions are reflected
in the financial statements in the period it is determined to be necessary.
Actual results could differ from these estimates.
Cash and Cash Equivalents: The Company considers cash in banks, deposits in
transit, and highly liquid debt instruments purchased with original maturities
of three months or less to be cash and cash equivalents.
F-38
Inventory: Inventories consist primarily of tubular goods and well
equipment to be used in future drilling operations or repair operations and are
carried at the lower of cost or market.
Oil and Gas Properties: The Company uses the full cost method of accounting
for costs related to its oil and gas properties. Accordingly, all costs
associated with acquisition, exploration, and development of oil and gas
reserves (including the costs of unsuccessful efforts) are capitalized into a
single full cost pool. These costs include land acquisition costs, geological
and geophysical expense, carrying charges on non-producing properties, costs of
drilling and overhead charges directly related to acquisition and exploration
activities. Under the full cost method, no gain or loss is recognized upon the
sale or abandonment of oil and gas properties unless non-recognition of such
gain or loss would significantly alter the relationship between capitalized
costs and proved oil and gas reserves.
Capitalized costs of oil and gas properties are depleted using the
units-of-production method based upon estimates of proved reserves. For
depletion purposes, the volume of petroleum reserves and production is converted
into a common unit of measure at the energy equivalent conversion rate of six
thousand cubic feet of natural gas to one barrel of crude oil. Investments in
unevaluated properties and major development projects are not amortized until
proved reserves associated with the projects can be determined or until
impairment occurs. If the results of an assessment indicate that the properties
are impaired, the amount of the impairment is added to the capitalized costs to
be amortized.
Under the full cost method of accounting, a ceiling test is performed each
quarter. The full cost ceiling test is an impairment test prescribed by SEC
regulations. The ceiling test determines a limit on the book value of oil and
gas properties. The capitalized costs of oil and gas properties, adjusted for
accumulated depreciation, depletion, and amortization, and the related deferred
income taxes, may not exceed the estimated future net cash flows from proved oil
and gas reserves, plus the cost of unevaluated properties not being amortized,
plus the lower of cost or estimated fair value of unevaluated properties being
amortized. Prices are held constant for the productive life of each well. Net
cash flows are discounted at 10%. If net capitalized costs exceed this limit,
the excess is charged to expense and reflected as additional accumulated
depreciation, depletion and amortization. The calculation of future net cash
flows assumes continuation of current economic conditions. Once impairment
expense is recognized, it cannot be reversed in future periods, even if
increasing prices raise the ceiling amount. No provision for impairment was
required for either the nine months ended May 31, 2011 or 2010.
The oil and natural gas prices used to calculate the full cost ceiling
limitation are based upon a 12-month rolling average, calculated as the
unweighted arithmetic average of the first day of the month price for each month
within the 12-month period prior to the end of the reporting period, unless
prices are defined by contractual arrangements. Prices are adjusted for basis or
location differentials.
F-39
Oil and Gas Reserves: The determination of depreciation, depletion and
amortization expense, as well as the ceiling test calculation related to the
recorded value of the Company's oil and natural gas properties, will be highly
dependent on the estimates of the proved oil and natural gas reserves. Oil and
natural gas reserves include proved reserves that represent estimated quantities
of crude oil and natural gas which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. There are numerous
uncertainties inherent in estimating oil and natural gas reserves and their
values, including many factors beyond the Company's control. Accordingly,
reserve estimates are often different from the quantities of oil and natural gas
ultimately recovered and the corresponding lifting costs associated with the
recovery of these reserves.
Capitalized Overhead: A portion of the Company's overhead expenses are
directly attributable to acquisition and development activities. Under the full
cost method of accounting, these expenses, which totaled $46,673 and $154,621
for the three and the nine months ended May 31, 2011, respectively, were
capitalized into the full cost pool. No comparable costs were capitalized during
the three and nine month periods ended May 31, 2010.
Capitalized Interest: The Company capitalizes interest on expenditures made
in connection with exploration and development projects that are not subject to
current amortization. Interest is capitalized during the period that activities
are in progress to bring the projects to their intended use. Capitalized
interest totaled $253,887 and $84,154 for the three months ended May 31, 2011
and 2010, respectively, and $594,530 and $139,626 for the nine months ended May
31, 2011 and 2010, respectively.
Debt Issuance Costs: Debt issuance costs of $2,041,455 were incurred in
connection with the convertible promissory notes issued during the year ended
August 31, 2010 (see Note 6). Amortization expense is recognized over the
expected term of the debt and is adjusted for early conversion and redemption.
Amortization expense of $422,528 and $183,398 was recorded for the three months
ended May 31, 2011 and 2010, respectively, and $1,587,799 and $283,535 was
recorded for the nine months ended May 31, 2011 and 2010, respectively.
Fair Value Measurements: Fair value is the price that would be received to
sell an asset or be paid to transfer a liability in an orderly transaction
between market participants at the measurement date (exit price). The Company
uses market data or assumptions that market participants would use in pricing
the asset or liability, including assumptions about risk. These inputs can
either be readily observable, market corroborated or generally unobservable.
Fair value balances are classified based on the observability of the various
inputs (see Note 7).
Asset Retirement Obligations: The Company's activities are subject to
various laws and regulations, including legal and contractual obligations to
reclaim, remediate, or otherwise restore properties at the time the asset is
permanently removed from service. The fair value of a liability for the asset
retirement obligation ("ARO") is initially recorded when it is incurred if a
reasonable estimate of fair value can be made. This is typically when a well is
completed or an asset is placed in service. When the ARO is initially recorded,
F-40
the Company capitalizes the cost (asset retirement cost or "ARC") by increasing
the carrying value of the related asset. Over time, the liability increases for
the change in its present value (accretion of ARO), while the net capitalized
cost decreases over the useful life of the asset. The capitalized ARCs are
included in the full cost pool and subject to depletion, depreciation and
amortization. In addition, the ARCs are included in the ceiling test
calculation. Calculation of an ARO requires estimates about several future
events, including the life of the asset, the costs to remove the asset from
service, and inflation factors. The ARO is initially estimated based upon
discounted cash flows over the life of the asset and is accreted to full value
over time using the Company's credit adjusted risk free interest rate. Estimates
are periodically reviewed and adjusted to reflect changes.
Derivative Conversion Liability: The Company accounts for the embedded
conversion features in its convertible promissory notes in accordance with the
guidance for derivative instruments, which requires a periodic valuation of fair
value and a corresponding recognition of liabilities associated with such
derivatives. The recognition of derivative conversion liabilities related to the
issuance of convertible debt is applied first to the proceeds of such issuance
as a debt discount at the date of the issuance. Any subsequent increase or
decrease in the fair value of the derivative conversion liabilities is
recognized as a charge or credit to other income (expense) in the statements of
operations. As of May 31, 2011, all of the holders of convertible promissory
notes had elected to convert the notes into shares of common stock, thereby
eliminating the derivative conversion liability (see Note 6).
Revenue Recognition: Revenue is recognized for the sale of oil and natural
gas when production is sold to a purchaser and title has transferred. Revenues
from production on properties in which the Company shares an economic interest
with other owners are recognized on the basis of the Company's interest.
Provided that reasonable estimates can be made, revenue and receivables are
accrued and differences between the estimates and actual volumes and prices, if
any, are adjusted upon settlement, which typically occurs sixty to ninety days
after production.
Major Customers and Operating Region: The Company operates exclusively
within the United States of America. Except for cash and equivalent investments,
all of the Company's assets are employed in and all of its revenues are derived
from the oil and gas industry.
The Company's oil and gas production is purchased by a few customers. The
table below presents the percentages of oil and gas revenue that was purchased
by major customers.
Three Months Ended May 31, Nine Months Ended May 31,
------------------------ ------------------------
Major Customers 2011 2010 2011 2010
--------------- ---- ---- ---- -----
Company A 77% 46% 77% 42%
Company B 21% 38% 20% 35%
Company C * 16% * 22%
* less than 10%
F-41
As there are other purchasers that are capable of and willing to purchase
the Company's oil and gas production and because the Company has the option to
change purchasers of its oil and gas if conditions so warrant, the Company
believes that its oil and gas production can be sold in the market in the event
that it is not sold to the Company's existing customers. However, in some
circumstances, a change in customers may entail significant transition costs
and/or shutting in or curtailing production for weeks or even months during the
transition to a new customer.
Stock Based Compensation: Stock based compensation is measured at the grant
date based upon the estimated fair value of the award and the expense is
recognized over the required employee service period, which generally equals the
vesting period of the grant. The fair value of stock options is estimated using
the Black-Scholes-Merton option pricing model. The fair value of restricted
stock grants is estimated on the grant date based upon the fair value of the
common stock.
Earnings Per Share Amounts: Basic earnings per share includes no dilution
and is computed by dividing net income (or loss) by the weighted-average number
of shares outstanding during the period. Diluted earnings per share reflect the
potential dilution of securities that could share in the earnings of the
Company. For the nine months ended May 31, 2010 and 2011, diluted earnings per
share is equivalent to basic earnings per share, as all potentially dilutive
securities have an anti-dilutive effect on earnings per share. The following
potentially dilutive securities could dilute future earnings per share:
Nine Months Ended May 31,
----------------------------
2011 2010
------------- -------------
Convertible promissory notes - 11,250,000
Warrants(1) 14,941,372 15,286,466
Employee stock options 4,470,000 4,100,000
------------- -------------
Total 19,411,372 30,646,466
============= =============
(1) Also, as of May 31, 2011 and 2010, the Company had a contingent
obligation to issue 63,466 potentially dilutive securities, all of which were
excluded from the calculation because the contingency conditions had not been
met.
Income Taxes: Deferred income taxes are recorded for timing differences
between items of income or expense reported in the financial statements and
those reported for income tax purposes using the asset/liability method of
accounting for income taxes. Deferred income taxes and tax benefits are
recognized for the future tax consequences attributable to differences between
the financial statement carrying amounts of existing assets and liabilities and
their respective tax bases and for tax loss and credit carry-forwards. Deferred
tax assets and liabilities are measured using enacted tax rates expected to
apply to taxable income in the years in which those temporary differences are
expected to be recovered or settled. The Company provides for deferred taxes for
the estimated future tax effects attributable to temporary differences and
carry-forwards when realization is more likely than not. If the Company
F-42
concludes that it is more likely than not that some portion or all of the
deferred tax asset will not be realized, the balance of deferred tax assets is
reduced by a valuation allowance. From inception through May 31, 2011, the
Company incurred substantial net operating losses, and provided a full valuation
allowance against deferred tax assets.
The Company follows the provisions of the ASC regarding uncertainty in
income taxes. No significant uncertain tax positions were identified as of any
date on or before May 31, 2011. Given the substantial net operating loss
carry-forwards at both the federal and state levels, neither significant
interest expense nor penalties charged for any examining agents' tax adjustments
of income tax returns are anticipated as any such adjustments would very likely
simply adjust the net operating loss carry-forwards.
Recent Accounting Pronouncements: The Company evaluates the pronouncements
of various authoritative accounting organizations, primarily the Financial
Accounting Standards Board ("FASB"), the Emerging Issues Task Force ("EITF"),
and the SEC to determine the impact of new pronouncements on US GAAP and the
impact on the Company.
In June 2011, the FASB issued ASU 2011-05 - Presentation of Comprehensive
Income ("ASU 2011-05"), which requires entities to present reclassification
adjustments included in other comprehensive income on the face of the financial
statements and allows entities to present the total of comprehensive income, the
components of net income and the components of other comprehensive income either
in a single continuous statement of comprehensive income or in two separate but
consecutive statements. It also eliminates the option for entities to present
the components of other comprehensive income as part of the statement of changes
in stockholders' equity. For public companies, ASU 2011-05 is effective for
fiscal years (and interim periods within those years) beginning after December
15, 2011, with earlier adoption permitted. Adoption of this ASU is not expected
to have a material affect on the Company's financial position, results of
operations, or cash flows.
Effective September 1, 2010, the Company adopted ASU No. 2010-11 -
Derivatives and Hedging, which was issued in March 2010 and clarifies that the
transfer of credit risk that is only in the form of subordination of one
financial instrument to another is an embedded derivative feature that should
not be subject to potential bifurcation and separate accounting. Adoption of
this ASU had no material affect on the Company's financial position, results of
operations, or cash flows.
There were various other accounting standards updates recently issued, most
of which represented technical corrections to the accounting literature or were
applicable to specific industries, and are not expected to a have a material
impact on the Company's financial position, results of operations or cash flows.
2. Accounts Receivable
Accounts receivable consist primarily of trade receivables from oil and gas
sales and amounts due from other working interest owners which have been billed
for their proportionate share of well costs. For receivables from joint interest
owners, the Company typically has the right to withhold future revenue
F-43
disbursements to recover outstanding joint interest billings. As of May 31, 2011
and August 31, 2010, major customers (i.e. those with balances greater than 10%
of total receivables) are shown in the following table:
Accounts Receivable As of May 31, As of August 31,
from Major Customers: 2011 2010
----------------------------- ---------------- ---------------
Company A 36% 27%
Company B 30% *
Company C 21% *
* less than 10%
3. Property and Equipment
Capitalized costs of property and equipment at May 31, 2011 and August 31,
2010, consisted of the following:
As of As of
May 31, 2011 August 31, 2010
------------------- -----------------
Oil and gas properties, full cost method:
Unevaluated costs, not subject to
amortization:
Lease acquisition and other costs $ 5,666,728 $ 848,696
Wells in progress 2,796,165 -
--------------- ---------------
Subtotal, unevaluated costs 8,462,893 848,696
--------------- ---------------
Evaluated costs:
Producing and non-producing 33,203,817 12,992,594
Less, accumulated depletion (3,083,840) (1,149,096)
--------------- ---------------
Subtotal, evaluated costs 30,119,977 11,843,498
--------------- ---------------
Oil and gas properties, net 38,582,870 12,692,194
--------------- ---------------
Other property and equipment:
Vehicles 163,904 89,527
Leasehold improvements 32,917 32,329
Office equipment 81,176 36,821
Less, accumulated depreciation (47,326) (7,888)
--------------- ---------------
Other property and 230,671 150,789
equipment, net
--------------- ---------------
Total property and equipment, net $ 38,813,541 $ 12,842,983
=============== ===============
F-44
The capitalized costs of evaluated oil and gas properties are depleted
using the unit-of-production method based on estimated reserves and the
calculation is performed quarterly. Production volumes for the quarter are
compared to beginning of quarter estimated total reserves to calculate a
depletion rate. Depletion of oil and gas properties was $803,756 and $198,474 or
$18.70 and $13.05 per barrel of oil equivalent, for the three months ended May
31, 2011 and 2010, respectively, and $1,999,311 and $291,191, or $18.59 and
$12.99 per barrel of oil equivalent, for the three months and the nine months
ended May 31, 2011 and 2010, respectively.
Periodically, the Company reviews its unevaluated properties and its
inventory to determine if the carrying value of either asset exceeds its
estimated fair value. The reviews for the three months ended May 31, 2011 and
2010, indicated that asset carrying values were less than estimated fair values
and no reclassification to the full cost pool was required.
On a quarterly basis, the Company performs the full cost ceiling test. The
ceiling tests performed for the three months and the nine months ended May 31,
2011 and 2010, did not reveal any impairment.
On March 21, 2011, the Company completed the sale of its interest in 3,502
unproved gross mineral acres (2,383 net acres) for net cash proceeds of
$4,995,817. No gain was recognized on the sale and all of the proceeds were
credited to the full cost pool. The sale reduced the amortization base of the
full cost pool by approximately 12%, which was determined to be less than the
"significant change" threshold required to recognize a gain on the sale.
On May 24, 2011, the Company acquired interests in various oil and gas
assets from a related party for $19,898,181 (see Note 8).
Depreciation of other property and equipment was $17,700 and $882 for the
three months ended May 31, 2011 and 2010, respectively and $39,438 and $1,104
for the nine months ended May 31, 2011 and 2010, respectively.
4. Interest Expense
The components of interest expense recorded for the three and nine months
ended May 31, 2011 and 2010, consisted of:
Three Months Ended May 31, Nine Months Ended May 31,
-------------------------- -----------------------------
2011 2010 2011 2010
------------ ------------ ------------ -------------
Interest cost, $ 20,083 $ 355,351 $ 589,539 $ 452,006
convertible
promissory notes
Interest cost,
bank loan - 2,915 - 30,388
F-45
Accretion of debt
discount (see
Note 6) 762,136 376,871 2,664,138 622,214
Amortization of
debt issuance
costs 422,528 183,398 1,587,799 283,535
Less, interest
capitalized (253,887) (84,154) (594,530) (139,626)
------------ ------------ ------------ -------------
Interest expense,
net $ 950,860 $ 834,381 $ 4,246,945 $ 1,248,517
============ ============ ============ =============
5. Asset Retirement Obligations
Upon completion or acquisition of wells, the Company recognizes obligations
for its oil and gas operations for anticipated costs to remove and dispose of
surface equipment, plug and abandon wells, and restore sites to their original
uses. The estimated present value of such obligations are determined using
several assumptions and judgments concerning the ultimate settlement amounts,
inflation factors, credit adjusted discount rates, timing of settlement and
changes in regulations. Changes in estimates are reflected in the obligations as
they occur.
On May 24, 2011, the Company acquired certain oil and gas properties from a
related party (see Note 8). The Company evaluated the wells and estimated the
present value of the future costs to plug and abandon the wells. Accordingly,
the Company recognized an additional asset retirement obligation of $165,694.
The following table summarizes the change in asset retirement obligations
for the nine months ended May 31, 2011:
Asset retirement obligations, August 31, 2010 $ 254,648
Liabilities incurred 76,663
Liabilities associated with acquired
properties 165,694
Liabilities settled -
Accretion 24,076
Revisions in estimated liabilities -
--------
Asset retirement obligations, May 31, 2011 $ 521,081
========
6. Convertible Promissory Notes and Derivative Conversion Liability
During the fiscal year ended August 31, 2010, the Company received gross
proceeds of $18,000,000 from the sale of 180 Units at $100,000 per Unit. Each
Unit consisted of one convertible promissory note ("Note") in the principal
amount of $100,000 and 50,000 Series C warrants (collectively referenced as a
("Unit"). The Notes bore interest at 8% per year, payable quarterly, and had a
stated maturity date of December 31, 2012. Each Series C warrant entitles the
holder to purchase one share of common stock at a price of $6.00 per share and
expires on December 31, 2014.
F-46
The Notes were considered hybrid debt instruments containing a detachable
warrant and a conversion feature under which the proceeds of the offering are
allocated to the detachable warrants and the conversion feature based on their
fair values. The Series C warrants were determined to be a component of equity,
and the fair value of the warrants was recorded as additional paid in capital.
Since the warrants were recorded as a component of equity, the fair value of
$1,760,048 was estimated at inception and was not re-measured in future periods.
The Notes contained a conversion feature, at an initial conversion price of
$1.60 that was subject to adjustment under certain circumstances, which allowed
the Note holders to convert the principal balance into a maximum of 11,250,000
common shares, plus conversion of accrued and unpaid interest into common
shares, also at $1.60 per share. The conversion feature was determined to be an
embedded derivative requiring the conversion option to be separated from the
host contract and measured at its fair value. At issuance, the estimated fair
value of the conversion feature was $3,455,809 and was recorded as derivative
conversion liability. The conversion option was re-measured and recorded at fair
value each reporting period, with changes in the fair value reflected in other
income (expense) in the statements of operations.
Allocation of value to the components created a debt discount of
$5,215,857, which was accreted over the life of the Notes using the effective
interest method. The effective interest rate on the Notes was 19%. The Company
recorded accretion expense of $762,136 and $2,664,138 during the three months
and nine months ended May 31, 2011, respectively. Accretion expense includes a
component for the conversion of Notes into common stock, which was $762,136 and
$2,391,245 for the three months and nine months ended May 31, 2011,
respectively.
In connection with the sale of the Units, the Company paid fees and
expenses of $1,348,977 and issued 1,125,000 Series D warrants to the placement
agent. The Series D warrants have an exercise price of $1.60 and an expiration
date of December 31, 2014. The warrants were valued at $692,478 using the
Black-Scholes-Merton option pricing model. The Company recorded $2,041,455 of
debt issuance costs, which is being amortized over the expected term of the
Notes. Amortization expense is adjusted to reflect early conversions.
Amortization expense of $422,528 and $1,587,799 was recorded during the three
months and nine months ended May 31, 2011, respectively. During the nine months
ended May 31, 2011, holders of 345,094 warrants exercised their warrants.
All of the noteholders elected to convert their Notes into common stock
prior to the Note maturity date. As of May 31, 2011, Notes with a face amount of
$18,000,000 had been converted into 11,250,000 shares of the Company's common
stock. At the time the Notes were converted, the estimated fair value of the
derivative conversion liability attributable to the converted notes totaled
$18,646,413, which was reclassified from derivative conversion liability to
additional paid in capital. Similarly, the unamortized debt discount
attributable to the converted notes totaled $3,120,293. The unamortized debt
discount of $2,067,376 applicable to the conversion option was charged to
accretion of debt discount and the unamortized debt discount of $1,052,917
applicable to the warrants was reclassified from debt discount to additional
paid-in capital.
F-47
The fair value of the derivative conversion liability was adjusted each
quarter to reflect the change in value. The estimated fair value of the
derivative conversion liability as of May 31, 2011, was nil, and the change in
fair value of derivative conversion liability was $10,229,229 during the nine
months ended May 31, 2011.
7. Fair Value Measurements
Assets and liabilities are measured at fair value on a recurring basis for
disclosure or. A fair value hierarchy was established that prioritizes the
inputs used to measure fair value. The hierarchy gives the highest priority to
unadjusted quoted prices in active markets for identical assets or liabilities
(Level 1 measurements) and the lowest priority to unobservable inputs (Level 3
measurements).
Level 1 - Quoted prices are available in active markets for identical
assets or liabilities as of the reporting date. Active markets are those in
which transactions for the asset or liability occur in sufficient frequency and
volume to provide pricing information on an ongoing basis. Level 1 primarily
consists of financial instruments such as exchange-traded derivatives, listed
securities and US government treasury securities.
Level 2 - Pricing inputs are other than quoted prices in active markets
included in Level 1, which are either directly or indirectly observable as of
the reporting date. Level 2 includes those financial instruments that are valued
using models or other valuation methodologies, where substantially all of these
assumptions are observable in the marketplace throughout the full term of the
instrument, which can be derived from observable data or are supported by
observable levels at which transactions are executed in the marketplace.
Level 3 - Pricing inputs include significant inputs that are generally less
observable than objective sources. These inputs may be used with internally
developed methodologies that result in management's best estimate of fair value.
Level 3 includes those financial instruments that are valued using models or
other valuation methodologies, where substantial assumptions are not observable
in the marketplace throughout the full term of the instrument, cannot be derived
from observable data or are not supported by observable levels at which
transactions are executed in the marketplace. At each balance sheet date, the
Company performs an analysis of all applicable instruments and includes in Level
3 all of those for which fair value is based on significant unobservable inputs.
A substantial portion of the Company's financial instruments consisted of
cash and equivalents, accounts receivable, accounts payable, and accrued
liabilities. Due to the short original maturities and high liquidity of cash and
equivalents, accounts receivable, accounts payable, and accrued liabilities,
carrying amounts approximated fair values.
As permitted under fair value accounting guidance, the outstanding
principal balance of the Company's convertible promissory notes were not
restated to fair value in the Company's financial statements for each reporting
F-48
period. It is estimated that the fair value of the convertible promissory notes
approximated face value because of the short term to maturity and the Company's
option to prepay the debt at any time after January 1, 2011.
During the fiscal year ended August 31, 2010, the Company issued Units that
included convertible promissory notes, as described in Note 6. These convertible
promissory notes contained an embedded conversion option which was required to
be separated and reported as a derivative conversion liability at fair value
The Company utilized the Monte Carlo Simulation ("MCS") model to value the
derivative conversion liability. Inputs to this valuation technique include the
Company's quoted stock price and published interest rates and credit spreads.
Assumptions used for valuations performed during the quarter ended May 31, 2011,
included: stock price ranging from $3.80 to $4.70 per share, an expected term of
1.8 years, volatility of 45.7%, which was derived from the expected volatility
of comparable companies, dividend yield of 0%, and a discount rate of 6.7%. All
of the significant inputs were observable, either directly or indirectly;
therefore, the Company's derivative conversion liability was included within the
Level 2 fair value hierarchy.
The following table sets forth, by level within the fair value hierarchy,
the Company's financial assets and financial liabilities as of May 31, 2011 and
August 31, 2010 that were measured at fair value on a recurring basis.
As of May 31, 2011 Total Level 1 Level 2 Level 3
----------------------- ------------ ------------ ------------ -----------
Derivative Conversion
Liability $ - $ - $ - $ -
As of August 31, 2010 Total Level 1 Level 2 Level 3
----------------------- ------------ ------------ ------------ -----------
Derivative Conversion
Liability $9,325,117 $ - $ 9,325,117 $ -
The Company also measures all nonfinancial assets and liabilities that are
not recognized or disclosed on a recurring basis. As discussed in Note 5, asset
retirement obligations and costs totaling $521,081 and $254,648 have been
accounted for as long-term liabilities and included in the oil and gas
properties, full cost pool at May 31, 2011, and August 31, 2010, respectively.
The Level 3 inputs used to measure the estimated fair value of the obligations
include assumptions and judgments about the ultimate settlement amounts,
inflation factors, credit adjusted discount rates, timing of settlement, and
changes in regulations.
8. Related Party Transactions and Commitments
Two of the Company's executive officers control three entities that have
entered into agreements to provide various goods, services, and facilities to
the Company. The entities are Petroleum Management, LLC ("PM"), Petroleum
Exploration and Management, LLC ("PEM"), and HS Land & Cattle, LLC ("HSLC").
F-49
Acquisition of Oil and Gas Assets from PEM: On May 24, 2011, the Company
acquired operating (working interest) oil and gas assets owned by PEM, including
interest in 88 oil and gas wells and mineral leases covering approximately 6,968
gross acres. All of the properties acquired from PEM are located in the
Wattenberg Field of the D-J Basin.
The nominal purchase price was $19,000,000, consisting of a cash payment of
$10,000,000, the issuance of 1,381,818 restricted shares of common stock valued
at $3,800,000, and a promissory note in the principal amount of $5,200,000. The
promissory note bears interest at an annual rate of 5.25%, is due on January 2,
2012, and is secured by the properties purchased by the Company. No liabilities
of PEM were assumed in the transaction. Prior to consummating the transaction,
the Company's acquisition committee, consisting of disinterested directors,
reviewed and approved the transaction, and the Company shareholders, not
including Mr. Holloway and Mr. Scaff, approved the transaction.
For accounting purposes, the value of the transaction was determined to be
$19,898,191, all of which were allocated to oil and gas properties. The
transaction is subject to customary post-closing adjustments for events
occurring between January 1, 2011 and May 24, 2011. No gain or loss was recorded
on the transaction. The Company incurred additional general and administrative
costs of approximately $150,000 related to the transaction, all of which were
charged to operating expenses during the nine months ended May 31, 2011.
The following unaudited pro forma financial information presents the
combined results of the Company and the properties acquired from PEM as though
the acquisition had been consummated as of September 1, 2009, the beginning of
the Company's fiscal year, for the two periods indicated below. Since the
Company and PEM do not share a common fiscal year, the pro-forma information
presents nine months of operating results which ended on May 31, 2011 and 2010
for the Company and on March 31, 2011 and 2010 for PEM.
2011 2010
---------------- ----------------
Operating revenues $ 9,345,171 $ 2,631,514
Net loss $ (12,022,017) $ (4,394,288)
Basic and Diluted loss per share $ (0.53) $ (0.37)
The pro forma information does not necessarily reflect the actual results
of operations had the acquisition been consummated at the beginning of the
period indicated nor is it necessarily indicative of future operating results.
The pro forma information does not give effect to any potential revenue
enhancements or operating efficiencies that could result from the acquisition.
Other Related Party Transactions: Effective June 11, 2008, the Company
entered into an Administrative Services Agreement with PM. The Company paid
$10,000 per month for leasing office space and an equipment yard located in
Platteville, Colorado, and paid $10,000 per month for office support services
including secretarial service, word processing, communication services, office
equipment and supplies. The Company paid $180,000 under this
F-50
agreement for the nine months ended May 31, 2010. Effective June 30, 2010, the
Company terminated the agreement.
Effective July 1, 2010, the Company entered into a lease with HSLC for
office space and an equipment yard located in Platteville, Colorado. The lease
requires monthly payments of $10,000 and terminates on June 30, 2011. The
Company paid $90,000 under this agreement for the nine months ended May 31,
2011.
On October 1, 2010, the Company acquired certain oil and gas properties
located in the Wattenberg field, part of the D-J Basin, from PM and PEM for
$1,017,435. The oil and gas properties consist of interest in 6 producing oil
and gas wells and 2 shut in oil wells as well as 15 drill sites and
miscellaneous equipment. The Company acquired a 100% working interest and 80%
net revenue interest in the properties.
In addition to the transactions described above, the Company undertook
various activities with PM and PEM that are related to the development and
operation of oil and gas properties. The Company occasionally purchases services
and certain oil and gas equipment, such as tubular goods and surface equipment,
from PM. The Company reimburses PM for the original cost of the services and
equipment. Prior to the asset acquisition transaction that closed on May 24,
2011, PEM was a joint working interest owner of certain wells operated by the
Company. PEM was charged for its pro-rata share of costs and expenses incurred
on its behalf by the Company, and similarly PEM was credited for its pro-rata
share of revenues collected on its behalf. The following table summarizes the
transactions with PM and PEM during the nine months ended May 31, 2011:
Balance due to PM, August 31, 2010 $ 538,698
Purchases from PM 2,290
Payments to PM (540,988)
-------------
Balance due to PM, May 31, 2011 $ -
=============
Joint interest billing balance due from PEM,
August 31, 2010 867,835
Joint interest costs billed to PEM 376,339
Amounts collected from PEM (1,213,783)
-------------
Joint interest billing due from PEM, May 31, 2011 $ 30,391
=============
Balance due to PEM for revenues, August 31, 2010 $ 15,971
Revenues collected on behalf of PEM 607,477
Payments to PEM for revenues (623,448)
-------------
Balance due to PEM for revenues, May 31, 2011 $ -
=============
F-51
9. Shareholders' Equity
Preferred Stock: The Company has authorized 10,000,000 shares of preferred
stock with a par value of $0.01 per share. These shares may be issued in series
with such rights and preferences as may be determined by the Board of Directors.
Since inception, the Company has not issued any preferred shares.
Common Stock: The Company has authorized 100,000,000 shares of common stock
with a par value of $0.001 per share.
Issued and Outstanding: The total issued and outstanding common stock at
May 31, 2011, is 35,408,632 common shares, representing an increase from August
31, 2010, of 21,897,651 shares, as follows:
On January 11, 2011, the Company completed the sale of 9,000,000 shares of
common stock to private investors. The shares were sold at a price of $2.00 per
share. Net proceeds to the Company from the sale of the shares were $16,690,721
after deductions for the placement agents' commissions and expenses of the
offering.
On May 24, 2011, the Company acquired certain assets from PEM (see Note 8).
As part of the consideration, the Company issued 1,381,818 shares of restricted
common stock valued at $4,698,181.
During the nine months ended May 31, 2011, the Company issued 1,125,699
shares of restricted common stock in consideration for the assignment of oil and
gas leases covering approximately 69,274 net mineral acres valued at $2,741,917,
based upon the fair value of stock at the time the lease was finalized.
During the nine months ended May 31, 2011, the Company issued 9,942,500
common shares pursuant to the conversion of notes in the principal amount of
$15,908,000 at the contractual conversion price of $1.60 per share. In addition,
the Company issued 36,876 common shares pursuant to the conversion of accrued
interest of $58,997.
During the nine months ended May 31, 2011, the Company issued 190,000
restricted common shares as compensation for services. The common shares were
valued at $593,600 based upon the quoted market price of the Company's common
stock on the effective dates of the grants. During the nine months ended May 31,
2011, compensation expense of $430,000 was recorded as general and
administrative expense and stock with a value of $163,600 was recorded as a
component of lease acquisition costs.
During the nine months ended May 31, 2011, the Company issued common shares
pursuant to the exercise of Series D warrants. As the Series D warrants contain
a cashless exercise provision, warrant holders exercised 345,094 warrants in
exchange for 220,758 shares of common stock, and the Company received no cash
proceeds in the transaction.
F-52
There are various warrants outstanding to purchase 14,941,372 shares of
common stock. The following table summarizes information about the Company's
issued and outstanding common stock warrants as of May 31, 2011:
Remaining
Contractual
Number of Life (in Expiration
Description Shares years) Date Strike Proceeds
------------------- --------------- ----------- --------- ----------------
Series A at $6.00 4,098,000 1.6 12/31/2012 $ 24,588,000
Series B at $10.00 1,000,000 1.6 12/31/2012 10,000,000
Series C at $6.00 9,000,000 3.6 12/31/2014 54,000,000
Series D at $1.60 779,906 3.6 12/31/2014 1,247,850
Placement Agent
Warrants at $1.80 63,466 1.6 12/31/2012 114,239
--------------- ----------------
14,941,372 2.9 $ 89,950,089
=============== ================
The following table summarizes activity for common stock warrants for the
nine month period ended May 31, 2011:
Number of Weighted Average
Warrants Exercise Price
------------- -----------------
Outstanding, August 31, 2010 15,286,466 $ 5.92
Granted - -
Exercised (345,094) 1.60
-------------
Outstanding, May 31, 2011 14,941,372 $ 6.02
=============
10. Stock-Based Compensation
The Company recognizes stock based compensation expenses for the grant of
stock options and for restricted stock awards based upon the estimated fair
value of the financial instruments at the date of the grant or award. The
expense is pro-rated over the term of service required under the terms of the
instrument. The following table summarizes the expense recorded during the
interim periods of 2011 and 2010:
Three Months Ended Nine Months Ended May
May 31, 31,
----------------------- ------------------------
2011 2010 2011 2010
----------- --------- ----------- ----------
Stock options $ 82,547 $ 6,962 $ 133,518 $ 17,790
Restricted stock grants 220,000 - 430,000 -
----------- --------- ----------- ----------
Total stock based
compensation $ 302,547 $ 6,962 $ 563,518 $ 17,790
=========== ========= =========== ==========
F-53
The estimated unrecognized compensation cost from unvested stock options as
of May 31, 2011, was approximately $764,000, and will be recognized as the
options vest. Substantially all of the options vest during 2011, 2010, and 2013;
and all options are fully vested by April 2016.
During the nine months ended May 31, 2011, the Company recognized
compensation expense for 150,000 restricted common shares issued in exchange for
services by advisors and employees. The common shares were valued at $430,000
based upon the quoted market price of the Company's common stock on the
effective dates of the grants. The entire value was recorded as general and
administrative expense during the nine months ended May 31, 2011.
During the nine months ended May 31, 2011, the Company granted
non-qualified options to purchase 250,000 shares of common stock to its
employees. All of the options have a contract term of ten years and an exercise
price equal to the closing price on the date of the grant. These options vest
over 3 to 5 years, pursuant to the terms of each grant. The options were
determined to have a fair value of $605,591 using the assumptions outlined in
the table below.
The assumptions used in valuing stock options issued during the nine months
ended May 31, 2011 were as follows:
Expected term (in years) 6.00 - 6.50
Stock fair value $2.40 - $4.40
Expected volatility 53.18-% - 66.026%
Risk-free rate 1.615% - 2.625%
Expected dividend yield 0.00%
The following table summarizes activity for stock options for the period
from August 31, 2010 to May 31, 2011:
Weighted
Average
Number of Exercise
Shares Price
----------- -------------
Outstanding, August 31, 2010 4,220,000 $ 5.36
Granted 250,000 $ 4.00
Exercised - -
-----------
Outstanding, May 31, 2011 4,470,000 $ 5.28
===========
The following table summarizes information about issued and outstanding
stock options as of May 31, 2011:
Remaining Weighted
Contractual Average Aggregate
Exercise Number Life Exercise Number Intrinsic
Price of Shares (in years) Price Exercisable Value
-------------- ---------- ----------- --------- ---------- ----------
$ 1.00 2,000,000 2.0 $ 1.00 2,000,000 $4,800,000
$2.40 to $4.40 470,000 9.1 $ 3.40 35,000 $ 198,000
$ 10.00 2,000,000 2.0 $ 10.00 2,000,000 -
---------- ---------- ----------
4,470,000 2.8 $ 5.28 4,035,000 $4,998,000
========== ========== ==========
F-54
11. Supplemental Schedule of Information to the Statements of Cash Flows
The following table supplements the cash flow information presented in the
financial statements for the nine months ended May 31, 2011 and 2010:
Nine Months Ended May 31,
------------------------------
2011 2010
------------- --------------
Supplemental cash flow information:
Interest paid $ 746,651 $ 255,936
Income taxes paid - -
Non-cash investing and financing
activities:
Conversion of promissory notes into
common stock $15,908,000 $ -
Reclassification of derivative
liability to additional paid in
capital 18,646,413 -
Properties acquired in exchange for
common stock 7,603,698 -
Properties acquired in exchange for
note payable 5,200,000 -
Accrued capital expenditures 2,242,117 1,526,113
Asset retirement costs and
obligations incurred 242,357 182,771
Placement agent warrants issued - 692,478
F-55
12. Subsequent Events
On June 8, 2011, the Company entered into a revolving line of credit with
Bank of Choice , which allows the Company to borrow up to $7 million. Amounts
borrowed under the line of credit are secured by the Company's accounts
receivable, equipment, inventory and fixtures, as well as 64 oil and gas wells.
Principal amounts outstanding under the Credit Facility bear interest, payable
monthly, at the Wall Street Journal Prime Rate plus 2%, subject to a minimum
interest rate of 5.5%. The entire unpaid outstanding balance of principal and
interest is due on June 3, 2012.
On June 23, 2011, the Company issued 159,485 shares of common stock for
mineral interests comprising 18,136 gross acres (15,862 net acres) in the D-J
Basin.
F-56
TABLE OF CONTENTS
Page
PROSPECTUS SUMMARY .................................................... 2
RISK FACTORS .......................................................... 3
MARKET FOR OUR COMMON STOCK ........................ 8
COMPARATIVE SHARE DATA.................................. 9
MANAGEMENT'S DISCUSSION AND ANALYSIS AND PLAN OF OPERATION ............ 11
BUSINESS............................................................... 28
MANAGEMENT ............................................................ 39
PRINCIPAL SHAREHOLDERS................................................. 45
TRANSACTIONS WITH RELATED PARTIES...................................... 46
SELLING SHAREHOLDERS................................................... 48
DESCRIPTION OF SECURITIES.............................................. 53
LEGAL PROCEEDINGS...................................................... 56
INDEMNIFICATION ....................................................... 56
AVAILABLE INFORMATION.................................................. 56
GLOSSARY .............................................................. 57
FINANCIAL STATEMENTS................................................... F-1
No dealer, salesperson or other person has been authorized to give any
information or to make any representation not contained in this prospectus, and
if given or made, such information or representations must not be relied upon as
having been authorized by Synergy Resources Corporation. This prospectus does
not constitute an offer to sell, or a solicitation of an offer to buy, any of
the securities offered in any jurisdiction to any person to whom it is unlawful
to make an offer by means of this prospectus.
PART II
Information Not Required in Prospectus
Item 13. Other Expenses of Issuance and Distribution.
The following table show the costs and expenses payable by the Company in
connection with this registration statement.
SEC Filing Fee $ 3,289
Blue Sky Fees and Expenses 1,000
Printing Expenses 1,000
Legal Fees and Expenses 30,000
Accounting Fees and Expenses 10,000
Miscellaneous Expenses 4,711
--------
TOTAL $50,000
=======
All expenses other than the SEC filing fee are estimated.
Item 14. Indemnification of Officers and Directors
The Colorado Business Corporation provides that the Company may indemnify
any and all of its officers, directors, employees or agents or former officers,
directors, employees or agents, against expenses actually and necessarily
incurred by them, in connection with the defense of any legal proceeding or
threatened legal proceeding, except as to matters in which such persons shall be
determined to not have acted in good faith and in the Company's best interest.
Item 15. Recent Sales of Unregistered Securities.
Note
Reference
---------
In May 2005 the Company issued 600,000 shares of common
stock to Raymond McElhaney and Bill Conrad, its two officers and
directors, and 30,000 shares to a group of private investors for
cash of $6,300. A
In June 2005 the Company sold 250,000 shares to an investor
for cash of $5,000 and issued 6,000 shares to another person in
exchange for a 2% working interest in an oil and gas prospect,
valued at $6,000. A
Between August 2005 and June 2006 the Company sold
212,000 shares of common stock to 21 persons for $424,000.
The shares were purchased by individuals or entities that were
friends, relatives or business contacts of the founders of the
Company. B
Part II-1
On September 21, 2006, the Company issued 20,000 shares
of common stock, valued at $50,000, as well as a promissory note
in the principal amount of $200,000 to Prospector Capital Inc.
in partial payment for an oil and gas property. The promissory
note was converted on December 31, 2006 into 40,000 shares of
common stock. B
Between February 2007, and April 2007, the Company sold
33,000 shares of common stock to eight persons for $165,000. B
On September 10, 2008, the Company acquired approximately
89% of the outstanding shares of Synergy Resources Corporation in
exchange for 8,882,500 shares of the Company's common stock and
1,042,500 Series A warrants. On December 19, 2008 the Company
acquired the remaining shares of Synergy for 1,077,500 shares of
the Company's common stock and 1,017,500 Series A warrants.All but
three of the Synergy shareholders were accredited investors. C
Between December 8, 2008, and June 30, 2009, the Company
sold Units to 1,000,000 investors in a private offering at a price of
$3.00 per unit. Each unit consisted of two shares of the Company's
common stock, one Series A warrant and one Series B warrant. The
Company agreed to pay sales agents participating in the private
offering a commission of up to 10% of the amount the sales agents
raised in this offering. The Company also agreed to issue to
selected sales agents one Sales Agent warrant for each five Units
sold by the selected sales agents. C
Between December 2009, and March 2010, the Company sold 180
Units to a group of private investors. The Units were sold at a price
of $100,000 per Unit. Each Unit consisted of one Promissory Note in
the principal amount of $100,000 and 50,000 Series C warrants. At any
time after May 31, 2010, the Notes can be converted into shares of the
Company's common stock, initially at a conversion price of $1.60 per
share. Each Series C warrant entitles the holder to purchase one share
of the Company's common stock at a price of $6.00 per share at any
time on or before December 31, 2014. In connection with the private
offering the Company paid the placement agent for the offering a
commission of $997,100, plus a non-accountable expense allowance of
$360,000. The Company also issued the Placement Agent 1,125,000 Series
D warrants. Each Series D warrant entitles the holder to purchase one
share of the Company's common stock at a price of $1.60 per share at
any time on or before December 31, 2014. C
Between December 2010 and January 2011, the Company sold
9,000,000 shares of its common stock in a private offering to
accredited investors. The shares were sold at a price of $2.00 per
share. The Company paid the placement agents for this offering a
cash commission of 7% (4% on sales to investors who were directed to
the placement agents by the Company). C
Part II-2
Between April 15, 2011 and September 8, 2011, the Company
issued 1,960,523 shares of its common stock to 32 persons as
consideration for the assignment to the Company of oil and gas
properties. A
A. The Company relied upon the exemption provided by Section 4(2) of the
Securities Act of 1933 with respect to the issuance of these shares. The persons
who acquired these shares were sophisticated investors and were provided full
information regarding the Company. There was no general solicitation in
connection with the offer or sale of these securities. The persons who acquired
these shares acquired them for their own accounts. The certificates representing
these shares bear a restricted legend providing that they cannot be sold except
pursuant to an effective registration statement or an exemption from
registration. No commission or other form of remuneration was given to any
person in connection with the issuance of these shares. Share numbers are
post-split.
B. The Company relied on the exemption from registration provided by Rule 504 of
the Securities and Exchange Commission in connection with the sale of these
shares. The Company did not engage in any general solicitation or advertising.
The shares which were sold or issued were restricted securities as that term is
defined in Rule 144 of the Securities and Exchange Commission. No commission or
other form of remuneration was given to any person in connection with the
issuance of these shares. Share numbers are post-split.
C. The Company relied upon the exemption provided by Rule 506 of the Securities
and Exchange Commission with respect to the issuance of these securities. The
persons who acquired these securities were sophisticated investors and were
provided full information regarding the Company. There was no general
solicitation in connection with the offer or sale of these securities. The
persons who acquired these securities acquired them for their own accounts. The
certificates representing these securities bear a restricted legend providing
that they cannot be sold except pursuant to an effective registration statement
or an exemption from registration. No commission or other form of remuneration
was given to any person in connection with the acquisition of Synergy. The
Company paid commissions to Scottsdale Capital Advisors, GVC Capital, LLC and
Oppenheimer & Co., Inc. in connection with the sale of these securities.
Item 16. Exhibits and Financial Statement Schedules
The following exhibits are filed with this Registration Statement:
Exhibits Page Number
-------- -----------
3.1.1 Articles of Incorporation (1)
3.1.2 Amendment to Articles of Incorporation (2)
3.1.2 Bylaws (1)
5. Opinion of Counsel ___
Part II-3
E
Exhibits Page Number
-------- -----------
10.1 Employment Agreement with Ed Holloway (2)
10.2 Employment Agreement with William E. Scaff, Jr. (2)
10.3 Administrative Services Agreement (3)
10.4 Agreement regarding Conflicting Interest Transactions (3)
10.5 Consulting Services Agreement with Raymond McElhaney and
Bill Conrad (4)
10.6.1 Form of Convertible Note (4)
10.6.2 Form of Subscription Agreement (4)
10.6.3 Form of Series C Warrant (4)
10.7 Purchase and Sale Agreement with Petroleum Exploration and
Management, LLC (wells, equipment and well bore leasehold
assignments) (4)
10.8 Purchase and Sale Agreement with Petroleum Management, LLC
(operations and leasehold) (4)
10.9 Purchase and Sale Agreement with Chesapeake Energy (4)
10.10 Lease with HS Land & Cattle, LLC (4)
10.11 Employment Agreement with Frank L. Jennings (5)
10.12 Purchase and Sale Agreement with Petroleum Exploration and
Management, LLC (6)
14. Code of Ethics (as amended) (7)
23.1 Consent of Hart & Trinen ___
23.2 Consents of Ehrhardt Keefe Steiner & Hottman PC and
Stark Schenkein, LLP ___
23.3 Consent of Ryder Scott Company, L.P. ___
99 Report of Ryder Scott Company, L.P. (4)
(1) Incorporated by reference to the same exhibit filed with the Company's
registration statement on Form SB-2, File #333-146561.
Part II-4
(2) Incorporated by reference to the same exhibit filed with the Company's
transition report on Form 8-K for the period ended August 31, 2008.
(3) Incorporated by reference to the same exhibit filed with the Company's
transition report on Form 10-K for the year ended August 31, 2008.
(4) Incorporated by reference to the same exhibit filed with the Company's
report on Form 10-K/A filed on June 3, 2011.
(5) Incorporated by reference to the same exhibit filed with the Company's
report on Form 8-K filed on June 24, 2011.
(6) Incorporated by reference to Exhibit 10.12 filed with the Company's report
on Form 8-K filed on August 5, 2011.
(7) Incorporated by reference to Exhibit 14 filed with the Company's report on
Form 8-K filed on July 22, 2011.
Item 17. Undertakings
The undersigned registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being made, a
post-effective amendment to this registration statement:
(i) To include any prospectus required by Section l0 (a)(3) of the
Securities Act:
(ii) To reflect in the prospectus any facts or events which,
individually or together, represent a fundamental change in the information in
the registration statement. Notwithstanding the foregoing, any increase or
decrease in volume of securities offered (if the total dollar value of
securities offered would not exceed that which was registered) and any deviation
from the low or high end of the estimated maximum offering range may be
reflected in the form of prospectus filed with the Commission pursuant to Rule
424(b) if, in the aggregate, the changes in volume and price represent no more
than a 20% change in the maximum aggregate offering price set forth in the
"Calculation of Registration Fee" table in the effective registration statement;
and
(iii) To include any material information with respect to the plan
of distribution not previously disclosed in the registration statement or any
material change to such information in the registration statement.
(2) That, for the purpose of determining any liability under the Securities
Act of 1933, each such post-effective amendment shall be deemed to be a new
registration statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be the initial bona
fide offering thereof.
Part II-5
(3) To remove from registration by means of a post-effective amendment any
of the securities that remain unsold at the termination of the offering.
Insofar as indemnification for liabilities arising under the Securities Act
of l933 (the "Act") may be permitted to directors, officers and controlling
persons of the Registrant pursuant to the foregoing provisions or otherwise, the
Registrant has been advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as expressed in the Act
and is, therefore, unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the Registrant of expenses
incurred or paid by a director, officer or controlling person of the Registrant
in the successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities being
registered, the Registrant will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of appropriate
jurisdiction the question of whether such indemnification by it is against
public policy as expressed in the Act and will be governed by the final
adjudication of such issue.
(4) That, for the purpose of determining liability under the Securities Act
of 1933 to any purchaser:
(i) If the registrant is relying on Rule 430B:
(A) Each prospectus filed by the registrant pursuant to Rule
424(b)(3) shall be deemed to be part of the registration statement as of the
date the filed prospectus was deemed part of and included in the registration
statement; and
(B) Each prospectus required to be filed pursuant to Rule 424(b)(2),
(b)(5), or (b)(7) as part of a registration statement in reliance on Rule 430B
relating to an offering made pursuant to Rule 415(a)(1)(i), (vii), or (x) for
the purpose of providing the information required by section 10(a) of the
Securities Act of 1933 shall be deemed to be part of and included in the
registration statement as of the earlier of the date such form of prospectus is
first used after effectiveness or the date of the first contract of sale of
securities in the offering described in the prospectus. As provided in Rule
430B, for liability purposes of the issuer and any person that is at that date
an underwriter, such date shall be deemed to be a new effective date of the
registration statement relating to the securities in the registration statement
to which that prospectus relates, and the offering of such securities at that
time shall be deemed to be the initial bona fide offering thereof. Provided,
however, that no statement made in a registration statement or prospectus that
is part of the registration statement or made in a document incorporated or
deemed incorporated by reference into the registration statement or prospectus
that is part of the registration statement will, as to a purchaser with a time
of contract of sale prior to such effective date, supersede or modify any
statement that was made in the registration statement or prospectus that was
part of the registration statement or made in any such document immediately
prior to such effective date; or
(ii) If the registrant is subject to Rule 430C, each prospectus filed
pursuant to Rule 424(b) as part of a registration statement relating to an
offering, other than registration statements relying on Rule 430B or other than
prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and
included in the registration statement as of the date it is first used after
effectiveness. Provided, however, that no statement made in a registration
statement or prospectus that is part of the registration statement or made in a
document incorporated or deemed incorporated by reference into the registration
Part II-6
statement or prospectus that is part of the registration statement will, as to a
purchaser with a time of contract of sale prior to such first use, supersede or
modify any statement that was made in the registration statement or prospectus
that was part of the registration statement or made in any such document
immediately prior to such date of first use.
(5) That, for the purpose of determining liability of the registrant under
the Securities Act of 1933 to any purchaser in the initial distribution of the
securities:
The undersigned registrant undertakes that in a primary offering of
securities of the undersigned registrant pursuant to this registration
statement, regardless of the underwriting method used to sell the securities to
the purchaser, if the securities are offered or sold to such purchaser bye means
of any of the following communications, the undersigned registrant will be a
seller to the purchaser and will be considered to offer or sell such securities
to such purchaser:
(i) Any preliminary prospectus or prospectus of the undersigned registrant
relating to the offering required to be filed pursuant to Rule 424;
(ii) Any free writing prospectus relating to the offering prepared by or
on behalf of the undersigned registrant or used or referred to by the
undersigned registrant;
(iii) The portion of any other free writing prospectus relating to the
offering containing material information about the undersigned registrant or its
securities provided by or on behalf of the undersigned registrant; and
(iv) Any other communication that is an offer in the offering made by the
undersigned registrant to the purchaser.
Part II-7
SIGNATURES
Pursuant to the requirements of the Securities Act of l933, the registrant
has duly caused this registration statement to be signed on its behalf by the
undersigned, thereunto duly authorized, in the Denver, Colorado on the 23rd day
of September, 2011.
SYNERGY RESOURCES CORPORATION
By: /s/ Ed Holloway
------------------------------------
Ed Holloway, Principal Executive Officer
In accordance with the requirements of the Securities Act of l933, this
registration statement has been signed by the following persons in the
capacities and on the dates indicated:
Signature Title Date
--------- ----- ----
/s/ Ed Holloway Principal Executive September 23, 2011
---------------------- Officer and a Director
Ed Holloway
/s/ William E. Scaff, Jr. Director September 23, 2011
-------------------------
William E. Scaff, Jr.
/s/ Frank L. Jennings Principal Financial September 23, 2011
------------------------- and Accounting Officer
Frank L. Jennings
Director
-------------------------
Rick Wilber
/s/ Raymond E. McElhaney Director September 23, 2011
-------------------------
Raymond E. McElhaney
/s/ Bill M. Conrad Director September 23, 2011
-------------------------
Bill M. Conrad
Director
-------------------------
R.W. Noffsinger, III
/s/ George Seward Director September 23, 2011
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George Seward
EXHIBITS
SYNERGY RESOURCES CORPORATION
REGISTRATION STATEMENT ON FORM S-1
AMENDMENT NO. 2