Attached files
FORM 10-K/A
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended August 31, 2010.
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission file number: None
SYNERGY RESOURCES CORPORATION
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(Exact name of registrant as specified in its charter)
COLORADO 20-2835920
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(State or other jurisdiction of (I.R.S.Employer
incorporation or organization) Identification No.)
20203 Highway 60, Platteville, CO 80651
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (970) 737-1073
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act. [ ]
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act. [ ]
Indicate by check mark whether the registrant (1) has filed all reports to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
the definitions of "large accelerated filer," "accelerated filer" and "smaller
reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer [ ] Accelerated filer [ ]
Non-accelerated filer [ ]
(Do not check if a smaller reporting company) Smaller reporting company [X]
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act): [ ] Yes [X] No
The aggregate market value of the voting stock held by non-affiliates of the
registrant, based upon the closing sale price of the registrant's common stock
on February 28, 2010, as quoted on the OTC Bulletin Board, was approximately
$11,200,000.
As of November 15, 2010, the Registrant had 13,823,481 issued and outstanding
shares of common stock.
Documents Incorporated by Reference: None
PART I
Cautionary Statement Concerning Forward-Looking Statements
This report contains "forward-looking statements" within the meaning of the
Private Securities Litigation Reform Act of 1995. These statements are subject
to risks and uncertainties and are based on the beliefs and assumptions of
management and information currently available to management. The use of words
such as "believes", "expects", "anticipates", "intends", "plans", "estimates",
"should", "likely" or similar expressions, indicates a forward-looking
statement.
The identification in this report of factors that may affect our future
performance and the accuracy of forward-looking statements is meant to be
illustrative and by no means exhaustive. All forward-looking statements should
be evaluated with the understanding of their inherent uncertainty.
Factors that could cause our actual results to differ materially from
those expressed or implied by forward-looking statements include, but are not
limited to:
o The success of our exploration and development efforts;
o The price of oil and gas;
o The worldwide economic situation;
o Any change in interest rates or inflation;
o The willingness and ability of third parties to honor their contractual
commitments;
o Our ability to raise additional capital, as it may be affected by
current conditions in the stock market and competition in the oil and
gas industry for risk capital;
o Our capital costs, as they may be affected by delays or cost overruns;
o Our costs of production;
o Environmental and other regulations, as the same presently exist or
may later be amended;
o Our ability to identify, finance and integrate any future acquisitions;
and
o The volatility of our stock price.
ITEM 1. BUSINESS
Overview
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 ofNovember 15, 2010 we had 19,792 gross and
13,556 net acres under lease, all of which are located in the D-J Basin. Of this
acreage, 1,507 gross acres are held by production. During the year ended August
31, 2010, we drilled and completed 36 development wells on our acreage. At
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 672.8 MBbls of oil and condensate.
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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
November 15, 2010, we have identified over sixty 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 PlaceNameplaceD-J
PlaceTypeBasin. 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.
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.
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.
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o Balanced oil and natural gas reserves and production. At August 31,
2010, 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 November 15, 2010 our directors and executive
officers beneficially owned approximately 71 % of our outstanding
shares of common stock, providing a strong alignment of interest
between management, the board of directors and our outside
shareholders.
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 Item
13 of this report for more information regarding our affiliation with Petroleum
Management and Petroleum Exploration & Management.
On October 14, 2010, we announced the results of initial 24 hour flow
tests of four wells on our M&T Farms lease. These initial results are listed in
the table below.
Primary SYRG
Producing Working
Well Name Formation Interest Oil (Bbls) Gas (Mcf) BOE
--------- --------- -------- ---------- --------- -----
#33-10 D Codell 72.50% 130.0 210.9 165.2
#10 DD Codell 72.50% 165.3 353.8 224.3
#43-10 D Codell 72.50% 187.9 285.8 235.5
#10 XD Codell 36.25% 162.8 390.8 227.9
#10 TD J-Sand 36.25% * * *
#34-10 J-Sand 72.50% * * *
* Initial results are not available as of November 15, 2010 as the wells were
in the process of being completed.
4
"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.
Well and Production Data
Since September 2008, we have drilled and completed 36 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,
--------------------------------------
2010 2009
--------------- ----------------
Gross Net Gross Net
Development Wells:
Productive:
Oil 36 23.8 2 0.75
Gas -- -- -- --
Nonproductive -- -- -- --
Total Wells:
Productive:
Oil 36 23.8 2 0.75
Gas -- -- -- --
Nonproductive -- -- -- --
As of November 15, 2010 two (1.2 net wells) were in the process of
completion.
The following table shows our net production of oil and gas, average sales
prices and average production costs for the periods presented:
Years Ended August 31,
----------------------
2010 2009
---- ---
Production
Oil (Bbls) 21,080 1,730
Gas (Mcf) 141,154 4,386
Average sales price
Oil ($/Bbl) $68.38 $45.59
Gas ($/Mcf) $5.08 $3.48
Average production costs per BOE $1.94 $0.85
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Production costs may vary substantially among wells depending on the
methods of recovery employed and other factors, but generally include severance
taxes, administrative overhead, maintenance and repair, labor and utilities.
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.
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 November 15, 2010, by state, our
producing wells, developed acreage, and undeveloped acreage, excluding service
(injection and disposal) wells:
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State Productive Wells Developed Acreage Undeveloped Acreage(1)
----- ------------------ ------------------- -----------------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Colorado 46 32.6 1,387 1,096 15,630 9,685
Nebraska - - - - 2,560 2,560
Wyoming - - - - 215 215
-- ---- ----- ----- ------ ------
Total 46 32.6 1,387 1,096 18,405 12,460
== ==== ===== ===== ====== ======
(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.
The following table shows, as of November 15, 2010, the status of our
gross acreage.
State Held by Production Not Held by Production
----- ------------------ ----------------------
Colorado 1,507 15,510
Nebraska -- 2,560
Wyoming -- 215
-- ---
Total 1,507 18,285
===== ======
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 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 Acres Expiration of Lease
------------ -------------------
1,100 2012
915 2013
4,750 2014
11,520 After 2014
We do not own any 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 report. Ryder Scott was selected by two of our officers, Ed Holloway
and William E. Scaff, Jr.
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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 Texas A&M University and is a
registered Professional Engineer in Colorado. 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
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
======= ========= =========
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
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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
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 conducts 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.
Potential Acquisition of Oil and Gas Properties from Petroleum Exploration &
Management
We have a nonbinding letter of intent with Petroleum Exploration &
Management LLC, a company owned equally by Ed Holloway and William E. Scaff,
Jr., two of our officers, to potentially acquire oil and gas properties located
in the Wattenberg Field of the D-J Basin.
The assets which we may acquire consist of the following:
o 87 producing oil and gas wells;
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o one shut-in well; and
o oil and gas leases covering 6,968 gross acres in the D-J Basin.
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%.
Although, as of November 15, 2010, we had not reached any agreement with
Mr. Holloway and Mr. Scaff as to the amount we may pay for PEM's oil and gas
properties, or how the purchase price will be paid (which may include a
combination of cash, shares of our common or preferred stock, or debt), we
estimate the cost of acquiring these assets will range between approximately
$14.0 million and $17.0 million, and will be based on the following:
o estimated proved reserves of the oil and gas properties, discounted
at 10% value of undeveloped leases;
o value of undeveloped leases;
o value of related oil and gas equipment, including tank batteries,
compressors, and distribution lines.
It is our intention not to assume any of PEM's liabilities. However, we
may find it advantageous to assume PEM's liabilities, in which case we would
need to pay the liabilities as they became due, but the price we would pay for
PEM's properties would be reduced.
In our opinion, it would be advantageous to acquire the oil and gas
properties from PEM since we believe that the future value of the properties,
assuming our efforts to stimulate production from PEM's wells are successful,
will be substantially higher than the price we are ultimately willing to pay for
these properties.
The completion of the acquisition would be contingent upon the following:
o the approval of the transaction by a majority of our disinterested
directors
o the approval of the transaction, at a special meeting of our
shareholders, by the vote of shareholders owning a majority
of the shares in attendance at the meeting, whether in person
or by proxy, with Mr. Holloway and Mr. Scaff not voting, and
o the receipt of "fairness opinion" concerning the price we plan to
pay PEM for its oil and gas properties.
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.
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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
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
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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
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,
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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
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.
13
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.
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.
14
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 July 1, 2011.
As of November 15, 2010, we had seven full time employees.
Neither we, nor any of our properties, are subject to any pending legal
proceedings.
ITEM 1A. RISK FACTORS
Not applicable
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable
ITEM 2. PROPERTIES
See Item 1 of this report.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY
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."
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. The
market quotations reflect inter-dealer prices, without retail mark-up, mark-down
or commissions and may not necessarily represent actual transactions.
15
Quarter Ended High Low
------------- ---- ---
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
As of November 15, 2010, we had 13,823,481 outstanding shares of common
stock and 110 shareholders of record. The number of beneficial owners of our
common stock is substantially higher.
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
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.
Additional Shares Which May be Issued
The following table lists additional shares of our common stock, which may
be issued as of November 15, 2010 upon the conversion of outstanding notes,
the exercise of outstanding options or warrants or the issuance of shares for
oil and gas leases:
16
Number of Note
Shares Reference
--------- ---------
Shares issuable upon the conversion of certain
promissory notes 9,630,000 A
Shares issuable upon the exercise of Series C
warrants 9,000,000 A
Shares issuable upon the exercise of placement
agents' warrants 1,125,000 A
Shares issuable upon exercise of Series A warrants
that were sold 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 4,270,000 E
Shares which we may issue for oil and gas leases 2,250,000 F
---------
Total 31,499,932
==========
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 can be converted into shares of our
common stock, initially 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 stock at a price of $6.00 per share at any time prior to December
31, 2014. As of November 15, 2010, notes in the principal amount of $2,592,000
had been converted into 1,620,000 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.
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 with 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.
17
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 Item 11 of this report for information regarding shares issuable upon
exercise of options held by our officers and employees.
F. As of November 15, 2010 we had six non-binding letters of intent relating to
the potential acquisition of leases in exchange for approximately 2,250,000
shares of our common stock. The leases which are the subject of these letters of
intent cover approximately 110,000 acres in the D-J Basin. The acquisition of
any of these leases is subject to a number of conditions, including satisfactory
review of title to the leased acreage.
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.
ITEM 6. SELECTED FINANCIAL DATA
Not applicable.
18
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Introduction
The following discussion and analysis was prepared to supplement
information contained in the accompanying financial statements and is intended
to explain certain items regarding the financial condition as of August 31,
2010, and the results of operations for the years ended August 31, 2010, and
2009. It should be read in conjunction with the audited financial statements and
notes thereto contained in this report.
Overview
We have undergone significant growth since we began our operations. Since
September 2008 we have drilled and completed 38 oil and gas wells. Our first oil
and gas well began producing in February 2009. Prior to that time we did not
have any revenue from the sale of oil or gas. As of August 31, 2010, we had:
o twenty four producing oil and gas wells; and
o fourteen wells which were in the process of completion.
Since August 31, 2010, we acquired eight additional wells, two of which
were shut-in as of November 15, 2010.
During the year ended August 31, 2010, we received net cash proceeds of
$16.7 million from the sale of convertible promissory notes and warrants. The
proceeds were used to fund the 2010 drilling program and to provide working
capital.
We reported net losses for every year since inception and we expect to
report losses until such time, if ever, that we begin to generate significant
revenue from operations.
Our future plans will be dependent upon the amount of capital we are able
to raise and the cash flow from our producing properties. We expect that most of
our wells will be drilled in the D-J Basin.
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.
Exploration Stage Company. The Company was considered an exploration stage
company for accounting purposes until September 1, 2009, as we had not commenced
planned principle operations. During the year ended August 31, 2010, the Company
drilled 36 development wells, all of which encountered commercially productive
formations. Accordingly, our financial statements are presented to reflect our
exit from the exploration stage.
For the year ended August 31, 2010, compared to the year ended August 31, 2009
19
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) cash proceeds and associated costs from 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
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 is a function of worldwide commodity prices, which currently
trend upward for crude oil (posted price of $82.42 per Bbl as of November 18,
2010) and currently trend downward for natural gas (posted price of $4.18 per
Mcf as of November 18, 2010). We do not currently engage in any commodity
hedging transactions, but may do so in the future.
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:
20
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:
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.
21
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
============ ============
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, 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
22
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 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.
Between September 1, 2010 through November 15, 2010, holders of notes with
a face amount of $500,000 converted principal into 312,500 shares of the
Company's common stock. After these conversions, notes in the principal amount
of $15,408,000 were outstanding.
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
23
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.
Liquidity and Capital Resources
Our sources and (uses) of funds for the years ended August 31, 2010 and
2009, are shown below:
Year Ended August 31,
2010 2009
---- ----
Cash used in operations $(2,443,059) $(1,626,139)
Acquisition of oil and gas properties
and equipment (9,152,175) (1,558,035)
Option on oil and gas properties -- (100,000)
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, net
of offering costs -- 2,766,694
Other -- 2,987
----------- ----------
Net increase in cash $ 3,893,978 $ 562,318
=========== ==========
Net cash used in operating activities was $2,443,059 and $1,626,139 for
the years ended August 31, 2010 and 2009, respectively. Among other uses, the
increase in cash employed in operations reflects outstanding joint interest
billings to other interest owners for wells in progress.
Capital expenditures totaled $12,635,259 and $1,697,160 for the years
ended August 31, 2010 and 2009, respectively, which include cash payments of
$9,152,175 and $1,658,035, respectively. Cash paid for acquisition and
development as reflected in the statement of cash flows differs from the amount
reported herein primarily due to the timing of when the capital expenditures are
incurred and when the actual cash payment is made. At August 31, 2010, there
were $3,466,439 of accrued capital expenditures related to the wells in progress
and $16,645 of mineral leases acquired in exchange for common shares of the
Company.
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 bear
interest at 8% per year, payable quarterly, and mature on December 31, 2012. At
any time after May 31, 2010, the notes can be converted into shares of our
common stock, initially 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.
24
As of November 15, 2010 notes in the principal amount of approximately $2.6
million had been converted into 1,620,000 shares of our common stock.
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. The notes
are secured by the 36 gas wells we drilled during the year ended August 31,
2010.
In May 2009 we entered into a loan agreement with a commercial bank which
allowed us to borrow up to approximately $1.2 million. The loan was
collateralized primarily by pipe used to drill and complete oil and gas wells.
In April 2010, the remaining outstanding balance was paid in full. We do not
currently have a credit facility with a financial institution.
Our operating cash requirements currently approximate $300,000 per month,
which amount includes salaries and corporate overhead costs of $150,000, debt
servicing costs of $100,000, and lease operating expenses of $50,000. Through
August 31, 2010, we had not generated meaningful cash flow from operations.
However, the revenue from wells placed into production late in the year ended
August 31, 2010 and early in fiscal 2011 is expected to improve our cash flow
and we expect to meet our operating cash requirements with cash flow from
operations sometime during fiscal 2011.
Our primary need for cash in fiscal 2011 will be to fund our acquisition
and drilling program. Our tentative capital expenditure budget approximates
$27,000,000, subject to significant adjustment for drilling success, acquisition
opportunities, operating cash flow, and available capital resources. As we do
not currently have access to sufficient capital resources to fund our tentative
expenditures, we will be required to seek additional funding. Our budget is
tentatively allocated to acquisition of proved and unproved properties of
approximately $12,000,000 and drilling activities of approximately $15,000,000,
which include drilling new wells and reworking existing wells. In October 2010,
we acquired eight producing wells for approximately $1.0 million. See additional
details about these wells in Item 13.
We plan to generate profits by drilling productive oil or gas wells.
However, we will need to raise 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 do not have
any commitments or arrangements from any person to provide us with any
additional capital. If additional financing is not available when needed, we may
need to curtail operations. We may not be successful in raising the capital
needed to drill oil or gas wells. Any wells which may be drilled by us may not
produce oil or gas.
Contractual Obligations
The following table summarizes our contractual obligations as of August
31, 2010:
25
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
Interest - Convertible
Promissory Notes $ 1,233,000 $ 1,233,000 $ 617,000 $ 3,083,000
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.
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.
26
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 consolidated 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
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 oil and gas properties, net of
accumulated depreciation, depletion, and amortization, the related deferred
income taxes, and the cost of unevaluated properties, 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 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.
28
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. This change is a result of the newly approved SEC requirements
for reporting oil and gas activities. 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 us effective August 31, 2010
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. For the year ended August 31, 2010, we 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. We do not believe
that provisions of the new guidance, other than pricing, significantly impacted
the financial statements. We do 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.
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.
29
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
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 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.
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.
30
We have recently adopted the following new accounting standards:
Oil and Gas Disclosures - 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 us
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.
Fair value measurements and disclosure - In January 2010 the FASB issued
ASU No. 2010-06, which 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 us to disclose additional fair value information, but otherwise did not
have an impact on our financial position, results of operations, or cash flows.
The following accounting standards updates were recently issued and have
not yet been adopted by us. These standards are currently under review to
determine their impact on our 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 us 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 our financial position, results of operations or cash flows.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
Not applicable.
31
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See the financial statements and accompanying notes included with this
report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
The information required by this item was previously disclosed in our 8-K
report dated December 31, 2009.
ITEM 9A. CONTROLS AND PROCEDURES
An evaluation was carried out under the supervision and with the
participation of our management, including our Principal Financial Officer and
Principal Executive Officer, of the effectiveness of our disclosure controls and
procedures as of the end of the period covered by this report on Form 10-K.
Disclosure controls and procedures are procedures designed with the objective of
ensuring that information required to be disclosed in our reports filed under
the Securities Exchange Act of 1934, such as this Form 10-K, is recorded,
processed, summarized and reported, within the time period specified in the
Securities and Exchange Commission's rules and forms, and that such information
is accumulated and is communicated to our management, including our Principal
Executive Officer and Principal Financial Officer, or persons performing similar
functions, as appropriate, to allow timely decisions regarding required
disclosure. Based on that evaluation, our management concluded that, as of
August 31, 2010, our disclosure controls and procedures were effective.
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate
internal control over financial reporting and for the assessment of the
effectiveness of internal control over financial reporting. As defined by the
Securities and Exchange Commission, internal control over financial reporting is
a process designed by, or under the supervision of our principal executive
officer and principal financial officer and implemented by our Board of
Directors, management and other personnel, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of our
financial statements in accordance with U.S. generally accepted accounting
principles.
Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.
Ed Holloway, our Principal Executive Officer and Frank L. Jennings, our
Principal Financial Officer, evaluated the effectiveness of our internal control
over financial reporting as of August 31, 2010 based on criteria established in
Internal Control - Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission, or the COSO Framework. Management's
assessment included an evaluation of the design of our internal control over
financial reporting and testing of the operational effectiveness of those
controls.
32
Based on this evaluation, management concluded that our internal control
over financial reporting was effective as of August 31, 2010.
There was no change in our internal control over financial reporting that
occurred during the period covered by this report that has materially affected,
or is reasonably likely to materially affect, the our internal control over
financial reporting.
ITEM 9B. OTHER INFORMATION
None.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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.
Name Age Position
---- --- --------
Edward Holloway 58 President, Chief Executive Officer and Director
William E. Scaff, Jr. 53 Vice President, Secretary, Treasurer and Director
Frank L. Jennings 59 Principal Financial and Accounting Officer
Benjamin J. Barton 47 Director
Rick A. Wilber 62 Director
Raymond E. McElhaney 55 Director
Bill M. Conrad 55 Director
R.W. Noffsinger, III 37 Director
George Seward 61 Director
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,
33
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 managing and financial services, primarily to smaller
public companies. 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.
Benjamin J. Barton - Mr. Barton has been one of our directors since September
2008 and was a director of our predecessor between June 2008 and September 2008.
Between 2003 and 2005, Mr. Barton was a private wealth manager with Merrill
Lynch. Since 1986, Mr. Barton has been active in all aspects of venture capital
and public stock offerings. Since 2005, Mr. Barton has been the Managing
Director of Strategic Capital Partners, LLC, a private investment company
specializing in energy companies. Prior to earning an MBA in Finance from UCLA,
Mr. Barton received his Bachelor of Science degree in Political Science from
Arizona State University.
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.
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.
34
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 Messrs. Barton, Wilber and Noffsinger are qualified to act
as directors as result of their experience in financial matters.
With the exception of Mr. Noffsinger and Mr. Seward, none of our directors
are 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, Ben Barton 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.
We have adopted a Code of Ethics applicable to our senior executive and
financial officers.
ITEM 11. EXECUTIVE COMPENSATION
The following table shows the compensation paid or accrued to our
executive officers during the years ended August 31, 2010 and 2009.
Stock Option All Other
Name and Principal Fiscal Salary Bonus Awards Awards Compensation
Position Year (1) (2) (3) (4) (5) Total
------------------ ---- ------ ----- ------ ------ ------------- -----
Ed Holloway, 2010 $175,000 -- -- -- -- $ 175,000
Principal Executive 2009 $150,000 -- -- $5,092,672 -- $5,242,672
Officer
35
William E. Scaff, Jr. 2010 $175,000 -- -- -- -- $ 175,000
Vice President, 2009 $150,000 -- -- $5,092,672 -- $5,242,672
Secretary and
Treasurer
Frank L. Jennings, 2010 $106,225 -- -- -- -- $ 106,225
Principal Financial 2009 $ 63,716 -- -- -- -- $ 63,716
Officer
(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 and Mr. Scaff will be based
upon their employment agreements, which are described below. All material
elements of the compensation paid to these officers is discussed below. The
compensation we expect to pay to Mr. Jennings will be based upon the time spent
each fiscal year by Mr. Jennings on our business.
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%
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.
The employment agreements 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;
36
(ii) the refusal of the employee to follow the lawful directions of our
board of directors;
(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 Plan
We have a stock option and a stock bonus plan. A summary description of
each plan follows.
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.
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.
Summary. The following is a summary of options granted or shares issued
pursuant to the Plans as of November 15, 2010. 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
------------ ----------- ------------ ----------- --------------
Non-Qualified Stock
Option Plan 2,000,000 270,000 N/A 1,730,000
Stock Bonus Plan 500,000 N/A -- 500,000
37
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 Non-Qualified Stock Option Plan. As of November 15, 2010, 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 November 15, 2010.
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) 260,000(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 $3.00 per share. The options expire at various dates between December
2018 and October 2020.
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, 2010. Neither our Non-Qualified Stock Option Plan nor
the issuance of any of our other options have been approved by our shareholders.
Number of Securities
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 220,000 $2.73 1,780,000
Other Options 4,000,000 $5.50 -
38
Compensation of Directors During Year Ended August 31, 2010
Fees Earned
or Paid Stock Option
in Cash Awards (1) Awards (2) Total
Benjamin Barton -- $ 88,762 -- $ 88,762
Rick Wilber -- 88,762 -- 88,762
Raymond McElhaney $2,000 92,763 -- 94,763
Bill Conrad $4,000 92,763 -- 96,763
R.W. Noffsinger -- 92,763 -- 92,763
George Seward -- 88,762 -- 88,762
------ -------- --------
$6,000 $544,575 $550,575
====== ======== ========
(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.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The following table shows, as of November 15, 2010, 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 4,070,000 (3) 25.7%
William E. Scaff, Jr. 4,070,000 (4) 25.7%
Frank L. Jennings 4,000 *
Benjamin Barton 688,762 (5) 5.0%
Rick A. Wilber 465,191 3.4%
Raymond E. McElhaney 304,763 2.2%
Bill M. Conrad 319,763 2.3%
R.W. Noffsinger, III 342,763 2.5%
George Seward 526,262 3.8%
All officers and directors as a group
(9 persons) 10,791,504 70.6%
* 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.
39
Share Issuable Option
Upon Exercise Exercise Expiration
Name of Options Price Date
---- -------------- --------- ----------
Ed Holloway 1,000,000 $ 1.00 6-11-13
Ed Hollway 1,000,000 $ 10.00 6-11-13
William E. Scaff, Jr. 1,000,000 $ 1.00 6-11-13
William E. Scaff, Jr. 1,000,000 $ 10.00 6-11-13
(2) Computed based upon 13,823,481 shares of common stock outstanding as of
November 15, 2010.
(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.
(5) Shares are held of record by a partnership controlled by Mr. Barton.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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
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 provide 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.
40
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.
In addition to the above, and as mentioned in Item 1 of this report, we
have a nonbinding letter of intent relating to the potential acquisition of oil
and gas properties from PEM.
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.
41
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.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
For the year ended August 31, 2010, Ehrhardt Keefe Steiner Hottman P.C.
("EKS&H") served as our independent registered public accounting firm. Stark
Schenkein LLP (previously Stark Winter Schenkein & Co., LLP) served as our
independent registered public accounting firm for the year ended August 31,
2009. The following table shows the aggregate fees billed to us for these
periods by EKS&H and Stark Schenkein LLP.
Year Ended Year Ended
August 31, 2010 August 31, 2009
--------------- ---------------
Audit Fees $72,213 $53,620
Audit-Related Fees $ 7,500 $ 1,688
Tax Fees $ 3,800 $ 5,700
All Other Fees -- --
Audit fees represent amounts billed for professional services rendered for
the audit of our annual financial statements and the reviews of the financial
statements included in our Form 10-Q and Form 10-K reports. Audit-related fees
include amounts billed for the review of our registration statement on Form S-1.
Prior to contracting with either EKS&H or Stark Schenkein LLP to render audit or
non-audit services, each engagement was approved by our directors.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Exhibits Page Number
-------- -----------
3.1.1 Articles of Incorporation (1)
3.1.2 Amendment to Articles of Incorporation
3.1.2 Bylaws (1)
10.1 Employment Agreement with Ed Holloway (2)
42
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
10.6 Form of Convertible Note
10.7 Purchase and Sale Agreement with Petroleum
Exploration and Management, LLC (wells,
equipment and well bore leasehold assignments)
10.8 Purchase and Sale Agreement with Petroleum
Management, LLC (operations and
leasehold)
10.9 Purchase and Sale Agreement with Chesapeake Energy
10.10 Lease with HS Land & Cattle, LLC
14. Code of Ethics (3)
31 Rule 13a-14(a) Certifications
32 Section 1350 Certifications
99 Letter regarding oil and gas reserves
(1) Incorporated by reference to the same exhibit filed with our registration
statement on Form SB-2, File #333-146561.
(2) Incorporated by reference to the same exhibit filed with our report on Form
8-K filed June 4, 2010.
(3) Incorporated by reference to the same exhibit filed with our transition
report on Form 10-K for the year ended August 31, 2008.
43
SYNERGY RESOURCES CORPORATION
INDEX TO FINANCIAL STATEMENTS
Index to Financial Statements F-1
Report of Independent Registered Public Accounting Firm as of
August 31, 2010 F-2
Report of Independent Registered Public Accounting Firm as of
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
F-1
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.
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 opinions.
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 for the year then ended, in conformity
with accounting principles generally accepted in the United States of America.
/s/ Stark Schenkein, 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 oil and gas properties, net of
accumulated depreciation, depletion, and amortization, the related deferred
income taxes, and the cost of unevaluated properties, 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 not 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
During the period subsequent to August 31, 2010, holders of convertible
promissory notes in the face amount of $500,000, converted principal into
312,500 shares of the Company's common stock. After these conversions, notes in
the principal amount of $15,408,000 were outstanding.
F-34
SIGNATURES
In accordance with Section 13 or 15(a) of the Exchange Act, the Registrant
has caused this Report to be signed on its behalf by the undersigned, thereunto
duly authorized on the 6th day of May, 2011.
SYNERGY RESOURCES CORPORATION
By: /s/ Ed Holloway
------------------------------------
Ed Holloway, President
Pursuant to the requirements of the Securities Exchange Act of l934, this
Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ Ed Holloway President, Chief Executive May 6, 2011
---------------------- Officer and Director
Ed Holloway
/s/ Frank L. Jennings Principal Financial and May 6, 2011
---------------------- Accounting Officer
Frank L. Jennings
/s/ William E. Scaff Jr. Director May 6, 2011
------------------------
William E. Scaff, Jr.
/s/ Benjamin Barton Director May 6, 2011
----------------------
Benjamin Barton
Director
----------------------
Rick Wilber
/s/ Raymond E. McElhaney Director May 6, 2011
------------------------
Raymond E. McElhaney
/s/ Bill M. Conrad Director May 6, 2011
----------------------
Bill M. Conrad
Director
-----------------------
R. W. Noffsinger, III
Director
----------------------
George Seward
SYNERGY RESOURCES CORPORATION
FORM 10-K
EXHIBITS
SYNERGY RESOURCES CORPORATION
FORM 10-K/A
EXHIBITS
