Attached files
FORM 10-K
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, 2011
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission file number: 001-35245
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:
Title of each class Name of each exchange on which registered
Common Stock NYSE AMEX
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Securities registered pursuant to Section 12(g) of the Act:
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(Title of class)
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(Title of class)
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 weather the registrant has submitted electronically and
posted on its corporate Website, if any, every Interactive Data File required to
be submitted and posted pursuant to Rule 405 of Regulations S-T (232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such filing). 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 [X]
Non-accelerated filer [ ] Smaller reporting company [ ]
(Do not check if a smaller reporting company)
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, 2011, was approximately $90,388,000.
As of November 1, 2011, the Registrant had 36,098,212 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. We serve as the operator for most of our wells and
focus our efforts on those prospects in which we have a significant net revenue
interest. As of October 31, 2011, we had 183,584 gross and 162,461 net acres
under lease, substantially all of which are located in the D-J Basin. Of this
acreage, 7,110 gross acres are held by production. Between September 1, 2008 and
October 31, 2011, we drilled and completed 56 development wells that we own and
operate. Additionally, during this timeframe we acquired interests in 72
producing wells.
At August 31, 2011, our estimated net proved oil and gas reserves, as
prepared by our independent reserve engineering firm, Ryder Scott Company, L.P.,
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were 2,069.7 MBbls of oil and condensate and 14.3 Bcf of natural gas. We
operated 95 wells and had an ownership interest in 141 gross wells (103 net
wells).
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 and around the D-J Basin,
where we have significant operating experience. All of our current
wells are located within the D-J Basin and our undeveloped acreage is
located either in or adjacent to 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 October 31, 2011, we have identified over 400 development and
extension drilling locations and over 20 recompletion/work-over
projects on our existing properties and wells.
o Complete selective acquisitions. We seek to acquire undeveloped and
producing oil and gas properties, primarily in the D-J Basin and
certain adjacent areas. 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
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within the D-J Basin. Members of our management
team have drilled, participated in drilling, and/or operated over 350
wells in the D-J Basin.
o Balanced oil and natural gas reserves and production. At August 31,
2011, approximately 47% of our estimated proved reserves were oil and
condensate and 53% were natural gas and liquids. 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 three 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 October 31, 2011 our directors and executive
officers beneficially owned approximately 33% of our outstanding
shares of common stock, providing a strong alignment of interest
between management, the board of directors and our outside
shareholders.
Recent Developments
We expanded our business during the fiscal year ended August 31, 2011. We
increased our producing wells, our reserves, and our undeveloped acreage.
Significant developments are described below.
Acquisition of Oil and Gas Properties from Petroleum Exploration &
Management LLC - In May 2011, we acquired interests in 88 gross oil and gas
wells (40 net) in the Wattenberg Field, and interests in oil and gas leases
covering approximately 6,968 gross acres. These oil and gas interests were
acquired from Petroleum Exploration and Management, LLC ("PEM"), a company owned
by Ed Holloway and William E. Scaff, Jr., two of our officers, for consideration
of a cash payment of $10 million, a promissory note payable of $5.2 million, and
1,381,818 shares of restricted common stock. The transaction was approved by the
disinterested directors and by a vote of the shareholders, with Mr. Holloway and
Mr. Scaff not voting. Some of the 88 gross wells acquired were wells operated by
us and in which PEM held a minority interest.
On October 1, 2010, we completed the acquisition of oil and gas properties
in the Wattenberg Field from Petroleum Management, LLC (also owned by Ed
Holloway and William E. Scaff) and PEM for approximately $1.0 million. These
properties include 8 oil and gas wells (100% working interest / 80% net revenue
interest), 15 drill sites (net 6.25 wells) and miscellaneous equipment.
We expanded our growth strategy to include an area of interest in eastern
Colorado (including Yuma and Washington counties) and western Nebraska
(including Hayes, Dundy, and Chase counties). We designate the area of interest
as the Shallow Niobrara Acreage. Our acquisitions totaled 166,434 gross (147,849
net) undeveloped acres. The majority of these oil and gas lease interests were
acquired in exchange for 1,849,838 shares of our common stock. George Seward,
one of our directors, has extensive experience in the area. We look forward to
evaluating this area as it could provide excellent growth opportunities and may
yield a significant return on investment.
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On May 26, 2011, we entered into a farm-in agreement with an unrelated
third party pertaining to a 640-acre lease in the Wattenberg Filed. Pursuant to
the terms of the agreement, we were required to commence drilling five wells on
the lease by August 15, 2011. Drilling operations began on August 1, 2011 and
were completed for these five wells on August 31, 2011. Subsequent to the
completion of these five wells, we have the option of drilling additional wells
on the lease in accordance with the following schedule:
o five wells by February 15, 2012
o five wells by August 15, 2012
o five wells by February 15, 2013.
If we do not adhere to the foregoing drilling schedule our right to drill
any additional wells on the lease will terminate. For each well drilled, we will
receive an assignment of the lease covering the 40 acres surrounding the well.
However, if we drill and complete all 20 wells allowed by the farm-in agreement,
we will receive an assignment of the entire lease. We will have a 100% working
interest (80% net revenue interest) in any acreage assigned to us and in any
wells we drill on the leased acreage. We estimate the aggregate cost of drilling
and completing our option wells on this lease will be approximately $10 million.
On January 11, 2011, we closed on the sale of 9 million shares of common
stock to private investors. The shares were sold at a price of $2.00 per share.
Net proceeds from the sale of the shares were approximately $16.7 million after
deductions for the sales commissions and expenses.
On June 8, 2011, we entered into a revolving line of credit with Bank of
Choice, which allows us to borrow up to $7 million. Amounts borrowed under the
line of credit are secured by certain of our assets as well as 64 oil and gas
wells in which we have a working interest. Principal amounts outstanding under
the line of credit bear interest, payable monthly, at the prime rate plus 2%,
subject to a minimum interest rate of 5.5%.
All of the persons holding our 8% convertible promissory notes elected to
convert their notes into shares of common stock at a rate of $1.60 per common
share, thereby converting an $18 million convertible note liability into equity.
In addition, there was a derivative conversion liability associated with the
notes that was converted into equity at the same time, which significantly
strengthened our balance sheet and eliminated future impact on our statement of
operations from changes in fair value of the financial instruments.
We received cash proceeds from two separate sales of undeveloped oil and
gas leases covering an aggregate of 5,902 gross acres (3,738 net acres) for $8.4
million. These acres were outside our core area of interest.
Our development efforts during the year focused on completing and bringing
on-line 14 wells drilled as part of our 2010 drilling program and new well
development on existing prospects. In December 2010, we acquired four producing
wells in an area that is adjacent to our Pratt prospect. We subsequently
commenced drilling on our Pratt prospect, and we successfully drilled and
completed 14 development wells. Our development activities on our Pratt prospect
resulted in the conversion of 90,996 Bbls and 1,006,188 Mcf of proved
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undeveloped reserves reported at August 31, 2010 into proved producing reserves
of 271,813 Bbls and 1,317,117 Mcf as of August 31, 2011.
In August 2011, we commenced a 21-well drilling program on various other
lease prospects. We anticipate the drilling of these wells to be completed by
December 2011, with completion following shortly thereafter.
Well and Production Data
Since September 2008, and through October 31, 2011, we have drilled and
completed 56 gross oil and gas wells which we own and operate. We have not
drilled any dry holes. We have acquired interests in 72 gross wells. We have
participated with other operators in the drilling and completion of 13 gross
wells. These wells were all located in the Wattenberg Field of the D-J Basin.
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,
-----------------------------------------------------------------
2011 2010 2009
--------------------- --------------------- -------------------
Gross Net Gross Net Gross Net
---------- --------- --------- ---------- --------- --------
Development
Wells:
Productive:
Oil 31 22.4 36 23.8 2 0.75
Gas -- -- -- -- -- --
Nonproductive -- -- -- -- -- --
As of October 31, 2011, we were drilling 1 gross (1 net) well and were
completing 15 gross (15 net) wells. These wells are all located in the
Wattenberg Field of the D-J Basin.
The following table shows our net production of oil and gas, average sales
prices and average production costs for the periods presented:
Years Ended August 31,
--------------------------------------
2011 2010 2009
------------- --------- -----------
Production:
Oil (Bbls) 89,917 21,080 1,730
Gas (Mcf) 450,831 141,154 4,386
Average sales price:
Oil ($/Bbl) $83.07 $68.38 $45.59
Gas ($/Mcf) $ 5.12 $ 5.08 $ 3.48
Average production cost per $ 2.13 $ 1.94 $ 0.85
BOE
"Bbl" refers to one stock tank barrel, or 42 U.S. gallons liquid volume in
reference to crude oil or other liquid hydrocarbons.
5
"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.
Production costs are substantially similar among our wells as all of our
wells are in the Wattenberg Field and employ the same methods of recovery.
Production costs generally include pumping fees, maintenance, repairs, labor,
utilities and administrative overhead. Taxes on production, including advalorem
and severance taxes, are not included in production costs.
We are not obligated to provide a fixed and determined quantity of oil or
gas to any third party in the future. During the last three fiscal years, we
have not had, nor do we now have, any long-term supply or similar agreement with
any government or governmental authority.
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, and subject 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 October 31, 2011, by state, our producing
wells, developed acreage, and undeveloped acreage, excluding service (injection
and disposal) wells:
Productive Wells Developed Acreage Undeveloped Acreage
------------------- -------------------- -------------------
State Gross Net Gross Net Gross Net
----------- --------- -------- --------- --------- --------- --------
Colorado 151 112.6 6,148 6,122 58,947 39,497
Nebraska - - - - 118,329 116,682
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Wyoming - - - - 160 160
--------- -------- --------- --------- --------- --------
Total 151 112.6 6,148 6,122 177,436 156,339
========= ======== ========= ========= ========= ========
(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 October 31, 2011, the status of our gross
acreage:
State Held by Not Held by
Production Production
----------- --------------- --------------
Colorado 7,110 57,985
Nebraska - 118,329
Wyoming - 160
--------------- --------------
Total 7,110 176,474
=============== ==============
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 Expiration
Acres of Lease
--------------- -----------
995 2012
6,922 2013
10,602 2014
157,955 After 2014
The overriding royalty interests which we own are not material to our
business.
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, 2011. Ryder Scott is an independent
petroleum engineering firm that has been providing petroleum consulting services
worldwide for over seventy years. The estimates of drilled 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 of 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, 2011 in those cases where this data
was considered to be definitive. The data used in this analysis was 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 2011.
Below are estimates of our net proved reserves at August 31, 2011, all of
which are located in Colorado:
Oil Gas
(Bbls) (Mcf) BOE
---------- ----------- ---------
Proved:
Producing 613,180 4,497,733 1,362,802
Nonproducing 170,641 1,080,334 350,697
Undeveloped 1,285,884 8,683,091 2,733,066
---------- ----------- ---------
Total 2,069,705 14,261,158 4,446,565
========== =========== =========
Below are estimates of our present value of estimated future net revenues
from such reserves based upon the standardized measure of discounted future net
cash flows relating to proved oil and gas reserves in accordance with the
provisions of Accounting Standards Codification Topic 932, Extractive Activities
- Oil and Gas. The standardized measure of discounted future net cash flows is
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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 years ended August 31,
2011 and 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.
As of August 31, 2011 and 2010, our standardized oil and gas measurements
were as follows:
Proved - August 31, 2011
----------------------------------------------------------------
Developed
------------------------------- Total
Producing Nonproducing Undeveloped Proved
-------------- --------------- --------------- --------------
Future gross revenue $71,027,480 $ 18,819,100 $145,392,300 $ 235,238,880
Deductions (14,298,253) (5,647,380) (61,736,015) (81,681,648)
Future net cash flow 56,729,227 13,171,720 83,656,285 153,557,232
Discounted future net
cash flow (pre-tax) $ 33,946,592 $ 6,995,878 $ 30,815,373 $ 71,757,843
Standardized measure
of discounted future
net cash flows (after
tax) $ 57,550,414
Proved - August 31, 2010
----------------------------------------------------------------
Developed
------------------------------ Total
Producing Nonproducing Undeveloped Proved
-------------- -------------- --------------- --------------
Future gross revenue $ 12,323,383 $ 24,126,662 $ 28,220,857 $ 64,670,902
Deductions (2,955,552) (8,942,579) (20,319,150) (32,217,281)
Future net cash flow 9,367,831 15,184,083 7,901,707 32,453,621
Discounted future net
cash flow (pre-tax) $ 6,120,468 $ 8,704,767 $ 1,732,491 $ 16,557,726
Standardized measure
of discounted future
net cash flows (after
tax) $ 13,022,397
For standardized oil and gas measurement purposes, our drilling,
acquisition, and participation activities during the year ended August 31, 2011
generated increases in projected future gross revenue from proved reserves of
$170,567,978 and future net cash flow of $121,103,611 from August 31, 2010.
During that same period, when applying a 10% discount rate to our future net
cash flows, our discounted future net cash flow from proved reserves increased
by $55,200,117. Our standardized measure of discounted future net cash flows
increased by $44,528,017 from August 31, 2010 to August 31, 2011. Increases in
our standardized oil and gas measures were the result of our expenditures during
the year ended August 31, 2011 of approximately $36.5 million for the
development of oil and gas properties and acquisitions of in place reserves,
which directly related to proved oil and gas reserves.
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
9
highly dependent upon the level of success in acquiring or finding additional
reserves and the costs incurred in doing so.
As of August 31, 2011 our proved developed reserves consisted of 2,069,705
Bbls of oil and 14,261,158 Mcf of gas. Our proved developed and undeveloped
reserves increased substantially during the year ended August 31, 2011,
primarily as the result of our drilling and completing 21 gross (14.8) net
wells, the acquisition of oil and gas properties from Petroleum Exploration and
Management, LLC.
Government Regulation
Various state and federal agencies regulate the production and sale of oil
and natural gas. All states in which we plan to operate impose restrictions on
the drilling, production, transportation and sale of oil and natural gas.
The Federal Energy Regulatory Commission ("FERC") regulates the interstate
transportation and the sale in interstate commerce for resale of natural gas.
FERC's jurisdiction over interstate natural gas sales has been substantially
modified by the Natural Gas Policy Act under which FERC continued to regulate
the maximum selling prices of certain categories of gas sold in "first sales" in
interstate and intrastate commerce.
FERC has pursued policy initiatives that have affected natural gas
marketing. Most notable are (1) the large-scale divestiture of interstate
pipeline-owned gas gathering facilities to affiliated or non-affiliated
companies; (2) further development of rules governing the relationship of the
pipelines with their marketing affiliates; (3) the publication of standards
relating to the use of electronic bulletin boards and electronic data exchange
by the pipelines to make available transportation information on a timely basis
and to enable transactions to occur on a purely electronic basis; (4) further
review of the role of the secondary market for released pipeline capacity and
its relationship to open access service in the primary market; and (5)
development of policy and promulgation of orders pertaining to its authorization
of market-based rates (rather than traditional cost-of-service based rates) for
transportation or transportation-related services upon the pipeline's
demonstration of lack of market control in the relevant service market. We do
not know what effect FERC's other activities will have on the access to markets,
the fostering of competition and the cost of doing business.
Our sales of oil and natural gas liquids will not be regulated and will be
at market prices. The price received from the sale of these products will be
affected by the cost of transporting the products to market. Much of that
transportation is through interstate common carrier pipelines.
Federal, state, and local agencies have promulgated extensive rules and
regulations applicable to our oil and natural gas exploration, production and
related operations. Most states require permits for drilling operations,
drilling bonds and the filing of reports concerning operations and impose other
requirements relating to the exploration of oil and gas. Many states also have
statutes or regulations addressing conservation matters including provisions for
the unitization or pooling of oil and natural gas properties, the establishment
of maximum rates of production from oil and gas wells and the regulation of
spacing, plugging and abandonment of such wells. The statutes and regulations of
some states limit the rate at which oil and gas is produced from our properties.
The federal and state regulatory burden on the oil and natural gas industry
10
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
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
11
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,
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
12
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.
Hydraulic Fracturing
We operate in the Wattenberg Field of the D-J Basin, where the rock
formations are typically tight and it is a common practice to utilize hydraulic
fracturing ("frack" or "fracking") to allow for or increase hydrocarbon
production. Fracking involves the process of forcing a mixture of fluid and
proppant into a formation to create pores and fractures, thus creating a
passageway for the release of oil and gas. All of our producing wells were
fracked and we expect to frack all future wells that we drill.
We outsource all fracking related services to service providers with
significant fracking experience, and whom we deem to be competent and
responsible. Our fracking service providers supply all personnel, equipment and
materials needed to perform each frack, including the mixtures that are injected
into our wells. These mixtures primarily consist of water and sand, with nominal
amounts of other ingredients that include chemical compounds commonly found in
consumer products. This mixture is injected into our wells at pressures of
5,500-6,000 psi at injection rates that that range between 25-55 barrels of
mixture per minute. On average, a typical fracking job will utilize
approximately 4,500 barrels of water and 125,000 pounds of sand.
The fracking service companies we hire indemnify us against incidents
occurring in connection with their fracking activities. Our service providers
are responsible for obtaining any regulatory permits necessary for them to
perform their services in the respective geographic location. The Company has
not had any incidents, citations or lawsuits relating to any environmental
issues resulting from fracking and is not presently aware of any such matters.
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
13
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.
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, 2012.
As of October 31, 2011, we had 11 full time employees.
Neither we, nor any of our properties, are subject to any pending legal
proceedings.
ITEM 1A. RISK FACTORS
Not applicable
14
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable
ITEM 2. PROPERTIES
See Item 1 of this report.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4. (REMOVED AND RESERVED)
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
On February 27, 2008, our common stock began trading on the OTC Bulletin
Board under the symbol "BRSH." There was no established trading market for our
common stock prior to that date.
On September 22, 2008, a 10-for-1 reverse stock split, approved by our
shareholders on September 8, 2008, became effective on the OTC Bulletin Board
and our trading symbol was changed to "SYRG.OB.". On July 27, 2011, our common
stock began trading on the NYSE Amex under the symbol "SYRG".
Shown below is the range of high and low closing prices for our common
stock for the periods indicated as reported by the OTC Bulletin Board prior to
July 27, 2011 and by the NYSE Amex on and after July 27, 2011. The market
quotations reflect inter-dealer prices, without retail mark-up, mark-down or
commissions and may not necessarily represent actual transactions.
Quarter Ended High Low
------------- ---- ---
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
Quarter Ended High Low
------------- ---- ---
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
15
Quarter Ended High Low
------------- ---- ---
November 30, 2010 $2.40 $1.95
February 28, 2011 $4.74 $2.25
May 31, 2011 $4.90 $3.20
August 31, 2011 $3.69 $2.55
As of October 31, 2011, the closing price of our common stock on the NYSE
Amex was $2.96.
As of October 31, 2011, we had 36,098,212 outstanding shares of common
stock and 293 shareholders of record. The number of beneficial owners of our
common stock is approximately 925.
Holders of our common stock are entitled to receive dividends as may be
declared by our board of directors. Our board of directors is not restricted
from paying any dividends but is not obligated to declare a dividend. No cash
dividends have ever been declared and it is not anticipated that cash dividends
will ever be paid.
Our articles of incorporation authorize our board of directors to issue up
to 10,000,000 shares of preferred stock. The provisions in the articles of
incorporation relating to the preferred stock allow our directors to issue
preferred stock with multiple votes per share and dividend rights which would
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 October 31, 2011 upon the exercise of outstanding options or
warrants or the issuance of shares for oil and gas leases.
Number of Note
Shares Reference
--------- ---------
Shares issuable upon the exercise of Series C
warrants 9,000,000 A
Shares issuable upon the exercise of Series D
placement agents' warrants 769,601 A
16
Shares issuable upon exercise of Series A warrants
that were granted to those persons owning shares
of our common stock prior to the acquisition of
Predecessor Synergy 1,038,000 B
Shares issuable upon exercise of Series A warrants
sold in prior private offering. 2,060,000 C
Shares issuable upon exercise of Series A and Series
B warrants 2,000,000 D
Shares issuable upon exercise of sales agent warrants 126,932 D
Shares issuable upon exercise of options held by our
officers and employees 4,645,000 E
Shares issuable upon the closing of proposed transactions
to acquire mineral interests 287,244 F
A. Between December 2009 and March 2010, we sold 180 Units at a price of
$100,000 per Unit to private investors. Each Unit consisted of one $100,000 note
and 50,000 Series C warrants. The notes were converted into shares of our common
stock at a conversion price of $1.60 per share, at the option of the holder.
Each Series C warrant entitles the holder to purchase one share of our common
stock at a price of $6.00 per share at any time prior to December 31, 2014. As
of the interim reporting period ended May 31, 2011, all notes had been converted
into 11,250,000 shares of our common stock.
We paid Bathgate Capital Partners (now named GVC Capital), the placement
agent for the Unit offering, a commission of 8% of the amount Bathgate Capital
raised in the Unit offering. We also sold to the placement agent, for a nominal
price, warrants to purchase 1,125,000 shares of our common stock at a price of
$1.60 per share. The placement agent's warrants expire on December 31, 2014. As
of the reporting period ended August 31, 2011, warrants to purchase 355,399
shares had been exercised by their holders.
B. Each shareholder of record on the close of business on September 9, 2008
received one Series A warrant for each share which they owned on that date (as
adjusted for a reverse split of our common stock which was effective on
September 22, 2008). Each Series A warrant entitles the holder to purchase one
share of our common stock at a price of $6.00 per share at any time prior to
December 31, 2012.
C. Prior to our acquisition of Predecessor Synergy, Predecessor Synergy sold
2,060,000 Units to a group of private investors at a price of $1.00 per Unit.
Each Unit consisted of one share of Predecessor Synergy's common stock and one
Series A warrant. In connection with the acquisition of Predecessor Synergy,
these Series A warrants were exchanged for 2,060,000 of our Series A warrants.
The Series A warrants are identical to the Series A warrants described in Note B
above.
17
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 Note 11 to the Financial Statements included with this report for
information regarding shares issuable upon exercise of options held by our
officers and employees.
F. We may issue up to 287,244 shares of common stock in exchange for the
acquisition of oil and gas leases.
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.
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,
2011, and the results of operations for the years ended August 31, 2011, and
2010. It should be read in conjunction with the audited financial statements and
notes thereto contained in this report.
Overview
We are an independent oil and gas company working to acquire, develop, and
produce crude oil and natural gas in and around the Denver-Julesburg Basin ("D-J
Basin"). All of our producing wells are in the Wattenberg Field, which has a
well-developed infrastructure and takeaway capacity. During 2011, we expanded
our undeveloped acreage holdings in eastern Colorado and western Nebraska, and
may commence development activities in that area.
18
Since commencing active operations in September 2008, we have undergone
significant growth. Specifically, we have drilled or acquired 141 producing oil
and gas wells, as follows:
o Participated in two wells during fiscal 2009;
o Drilled and completed 22 wells during fiscal 2010:
o Acquired interests in 72 wells, completed 28 wells, and participated
in eight wells during fiscal 2011:
As of October 31, 2011, we were drilling or completing 16 wells.
Our activities have increased our estimated proved reserves to 2,069,705
Bbls of oil and 14,261,158 Mcf of gas as of August 31, 2011, including reserves
associated with the acquisition of producing properties. In addition, during the
year ended August 31, 2011, we drilled and completed 14 developmental wells on
our Pratt prospect, thereby converting 90,906 Bbls and 1,006,188 Mcf of proved
undeveloped reserves as of August 31, 2010, into proved producing reserves of
271,813 Bbls and 1,317,117 Mcf as of August 31, 2011.
As of August 31, 2011, in the area known as the Wattenberg Field, our
acreage position was 11,277 gross (9,172 net). In addition, we had an inventory
of 166,031 gross undeveloped acres (147,447 net acres) in eastern Colorado and
western Nebraska (the "Shallow Niobrara Acreage"), substantially all of which
was acquired during 2011 at an average cost of $54 per net acre. Industry
interest and activity in this area has recently increased and we are currently
evaluating our development plans for the Shallow Niobrara Acreage.
During fiscal 2009, we issued 8% convertible promissory notes with a face
value of $18,000,000, which could be converted into shares of common stock at a
rate of $1.60 per share. All of the noteholders elected to convert, and, as of
March 31, 2011, the entire principal balance had been converted into 11,250,000
shares of common stock. In addition, during fiscal 2011, we completed the sale
of 9,000,000 shares of common stock at an offering price of $2.00 per share.
In June 2011 we obtained a one year commitment for a $7,000,000 revolving
line of credit from Bank of Choice, with interest payable at the prime rate plus
2%..
Our strategy for continued growth includes additional drilling activities,
acquisition of existing wells, and recompletion of wells that provide good
prospects for improved hydraulic stimulation techniques. We attempt to maximize
our return on assets invested by drilling and operating development wells in
which we have a significant net revenue interest. We attempt to limit our risk
by drilling in proven areas. To date, we have not drilled any dry holes. All of
our current wells are relatively low-risk vertical or directional wells, and we
do not currently have any horizontal wells. However, the success rate of
horizontal wells drilled by other operators has recently improved and we expect
to drill or participate in horizontal wells in the future. Historically, our
cash flow from operations was not sufficient to fund our growth plans and we
relied on proceeds from the sale of debt and equity securities. Our cash flow
from operations is increasing, and we plan to finance an increasing percentage
of our growth with internally generated funds. Ultimately, implementation of our
growth plans will be dependent upon the success of our operations and the amount
of financing we are able to obtain.
19
Significant Developments
Acquisition from Petroleum Exploration and Management, LLC - On May 24,
2011 we significantly expanded our position in the Wattenberg Field by acquiring
all of the operating oil and gas assets owned by Petroleum Exploration and
Management, LLC (`PEM"), a company owned equally by Ed Holloway and William E.
Scaff, Jr., two of our officers and directors. The oil and gas assets included
interests in 88 gross (40 net) oil and gas wells in the Wattenberg Field, and
interests in oil and gas leases covering approximately 6,968 gross acres. The
transaction was approved by the disinterested directors and by a vote of our
shareholders owning a majority of the shares in attendance at a special meeting
of our shareholders held on May 23, 2011, with Mr. Holloway and Mr. Scaff not
voting.
In consideration for the oil and gas properies we paid PEM $10,000,000 in
cash and issued PEM 1,381,818 shares of our restricted common stock and a
promissory note in the principal amount of $5,200,000. The note pays interest
annually at 5.25%, is due on January 2, 2012, and is secured by the assets
acquired from PEM. We did not assume any of PEM's liabilities.
Expansion of oil and gas lease interests in the Shallow Niobrara Acreage -
During 2011, we expanded our growth strategy to include the Shallow Niobrara
Acreage. Our Shallow Niobrara Acreage is primarily located in eastern Colorado
(Yuma and Washington counties), and western Nebraska (Chase, Dundy, and Hayes
counties). We believe the area provides excellent growth opportunities and has
the potential to yield a significant return on investment. George Seward, our
director, has extensive experience in the area. We acquired significant
interests in the area and at August 31, 2011, our holdings totaled 166,434 gross
(147,849 net) undeveloped acres with an average cost of $54 per net acre. Many
of the leases were acquired in exchange for shares of our common stock. Our
primary leases within this area have an initial term of 10 years to provide us
with enough time to complete a thorough evaluation.
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.
For the year ended August 31, 2011, compared to the year ended August 31, 2010
For the year ended August 31, 2011, we reported a net loss of $11,600,158,
or $0.45 per share, compared to a net loss of $10,794,172, or $0.88 per share
for the period ended August 31, 2010. As explained below, the net loss for each
year is significantly affected by non-cash charges related to the convertible
promissory notes and the derivative conversion liability. The following
discussion also expands upon items of inflow and outflow that affect operating
income. In most cases, the nature of the change from 2010 to 2011 involves the
significant growth in number of producing properties and activities to acquire
additional undeveloped acreage and proved properties.
Oil and Gas Production and Revenues - For the year ended August 31, 2011,
we recorded total oil and gas revenues of $9,777,172 compared to $2,158,444 for
the year ended August 31, 2010, as summarized in the following table:
20
Year Ended August 31,
----------------------------
2011 2010
------------- --------------
Production:
Oil (Bbls) 89,917 21,080
Gas (Mcf) 450,831 141,154
Total production in BOE 165,056 44,606
Revenues:
Oil $ 7,469,709 $ 1,441,562
Gas 2,307,463 716,882
------------- --------------
Total $ 9,777,172 $ 2,158,444
============= ==============
Average sales price:
Oil (Bbls) $ 83.07 $ 68.38
Gas (Mcf) $ 5.12 $ 5.08
"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, 2011 was 165,056
BOE, or 452 BOE per day, as compared with 44,606 BOE, or 122 BOE per day, for
the year ended August 31, 2010. The significant increase in production from the
prior year resulted from realizing a full year of production from wells at the
beginning of the year, and the addition of wells, including new wells drilled
and those acquired in the PEM acquisition. Production for the fourth quarter
averaged 577 BOE per day.
Service Revenue - The Company provides certain services to other well
owners, including supervision of drilling operations and management of producing
properties. There activities have not been, and are not expected to become, a
significant component of the Company's business.
Lease Operating Expenses - As summarized in the following table, our lease
expenses include the direct operating costs of producing oil and natural gas,
taxes on production and properties, and well work-over costs:
Year ended August 31,
------------------------------
2011 2010
---------------- ------------
Severance and ad valorem
taxes $ 955,705 $ 236,966
Production costs 350,853 86,554
Work-over
Other 86,797 -
46,463 -
---------------- ------------
Total lease operating
expenses $ 1,439,818 $ 323,520
================ ============
Per BOE:
Severance and ad valorem
taxes $ 5.79 $ 5.31
21
Production costs 2.13 1.94
Work-over 0.53 -
Other 0.28 -
---------------- ------------
Total per BOE $ 8.73 $ 7.25
================ ============
Lease operating and work-over 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 10% in
2011 and 11% in 2010.
Depreciation, Depletion, and Amortization ("DDA") - DDA expense is
summarized in the following table:
Year ended August 31,
------------------------------------
2011 2010
------------------ ----------------
DDA - oil and gas assets $ 2,743,441 $ 692,274
DDA - other assets 57,138 7,592
Accretion of asset retirement
obligations 37,728 1,534
------------------ ----------------
Total DDA $ 2,838,307 $ 701,400
================== ================
Depletion expense per BOE $ 16.62 $ 15.52
The determination of depreciation, depletion and amortization expense is
highly dependent on the estimates of the proved oil and natural gas reserves and
actual production volumes. As of August 31, 2011, we had 4,446,565 BOE of
estimated net proved reserves with a Standardized Measure of $57,550,414 (based
on SEC average prices of $5.07 Mcf and $84.90 Bbl). For comparative purposes, at
the end of the prior year we had 1,423,524 BOE of estimated net proved reserves
with a Standardized Measure of $13,022,397 (based on SEC average prices of $4.76
Mcf and $69.20 Bbl). Depletion expense per BOE increased approximately 7%. We
are currently experiencing cost increases across all of our operating sectors,
including costs incurred for lease acquisition, drillings, and well completion.
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 years ended August 31, 2011 and
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. The ceiling test is performed each quarter and there is the
possibility for impairments to be recognized in future periods. Once impairment
is recognized, it cannot be reversed.
General and Administrative - The following table summarizes the components
of general and administration expenses:
22
Year Ended August 31,
---------------------------------------
2011 2010
------------------ -------------------
Cash based compensation $ 1,260,688 $ 536,627
Share based compensation 627,486 581,233
Professional fees 716,210 419,588
Insurance 78,127 62,528
Other general and administrative 427,025 410,548
Capitalized general and
administrative (206,233) (95,475)
------------------ -------------------
Totals $ 2,903,303 $ 1,915,049
================== ===================
Cash based compensation includes payments to employees. The increase of
$724,061 from 2010 to 2011 reflects the expansion of our business, including the
addition of 5 employees during the year. Stock-based compensation includes
compensation paid to employees, directors, and service providers in the form of
stock options or shares of common stock. The amount of expense recorded for
stock options is calculated by using the Black-Scholes-Merton option pricing
model. The amount of expense recorded for shares of common stock is calculated
based upon the closing market value of the shares.
The increase in professional fees includes certain accounting fees and
investment banking fees related to the acquisition of assets from PEM. In
addition, our progression from smaller reporting company to accelerated filer
required additional professional services related to our compliance with the
rules and regulations of Sarbanes -Oxley.
Pursuant to the requirements under the full cost accounting method for oil
and gas properties, we identify all general and administrative costs that relate
directly to the acquisition of undeveloped mineral leases and the development of
properties. Those costs are reclassified from general and administrative
expenses and capitalized into the full cost pool. The increase in capitalized
costs from 2010 to 2011 reflects our increasing activities to acquire leases and
develop the properties.
Operating Income (Loss) - For the year ended August 31, 2011, we generated
operating income of $2,820,240, as compared with an operating loss of $781,525
for the year ended August 31, 2010. This increase of $3,601,765 resulted
primarily from the increasing contribution of wells brought into production
during the last two years, which includes wells drilled under the 2011 and 2010
drilling programs, the acquisition of producing properties from PEM and other
parties, and increased production from older wells that were recompleted using
newer hydraulic fracturing techniques. Increased revenues more than offset
increased costs incurred by us to accomplish these objectives.
Other Income (Expense) - During the year ended August 31, 2011, we
recognized $14,420,398 in other expense compared to $10,012,647 during the
comparable period in 2010. The amounts included in other income (expense) are
primarily related to components of the 8% convertible promissory notes. The 8%
convertible promissory notes contained a conversion feature which was considered
an embedded derivative and recorded as a liability at its initial estimated fair
value. This derivative conversion liability was then marked-to-market over time,
with the resulting change in fair value recorded as a non-cash item in the
statement of operations. By March 31, 2011, all of the notes had been converted,
thereby eliminating the derivative conversion liability. The Company recognized
a non-cash expense of $10,229,229 and $7,678,457 during the years ending August
23
31, 2011 and 2010, respectively, related to the change in fair value of the
derivative conversion liability.
Interest expense, net, contains several components related to the 8%
convertible promissory notes. In addition to the 8% coupon rate, we recorded
amortization of debt issue costs of $1,587,799 and accretion of debt discount of
$2,664,137 during the year ended August 31, 2011. During the year ended August
31, 2010, amortization of debt issue costs was $453,656 and accretion of debt
discount was $1,333,590. In connection with the conversion of the remaining 8%
convertible promissory notes outstanding during 2011, the Company accelerated
its recognition of all remaining amounts for unamortized debt issuance costs and
debt discount and the acceleration is included in the amounts presented above.
Income Taxes - Income taxes do not currently have an impact on our results
of operations as we have reported a net loss every year since inception and for
tax purposes have a net operating loss carry forward ("NOL") of approximately
$11.3 million. The NOL is available to offset future taxable income, if any. At
such time, if ever, that we are able to demonstrate that it is more likely than
not that we will be able to realize the benefits of our tax assets, we will
begin to recognize the impact of taxes in our financial statements.
Liquidity and Capital Resources
Our sources and (uses) of funds for the years ended August 31, 2011 and
2010, are shown below:
Year Ended August 31,
------------------------------
2011 2010
-------------- --------------
Cash provided by (used in) operations $ 7,916,308 $ (2,443,059)
Acquisition of oil and gas properties
and equipment (30,247,327) (9,152,175)
Proceeds from sales of oil and gas
properties 8,382,167 -
Proceeds from sale of convertible notes,
net of debt issuance costs - 16,651,023
(Repayment) / proceeds from bank loan - (1,161,811)
Proceeds from sale of common stock, net
of offering costs 16,690,721 -
-------------- --------------
Net increase in cash $ 2,741,869 $ 3,893,978
============== ==============
Net cash provided by (used in) operating activities was $7,916,308 and
($2,443,059) for the years ended August 31, 2011 and 2010, respectively. The
significant improvement reflects the operating contribution from 2010 wells that
were producing for the entire year, plus the contribution from wells that began
production during 2011. In addition to our analysis using amounts included in
the cash flow statement, we evaluate operations using a non-GAAP measure called
"adjusted cash flow from operations", which adjusts for cash flow items that
merely reflect the timing of certain cash receipts and expenditures. Adjusted
cash flow from operations was $6,346,800 for the year ended August 31, 2011,
compared to usage of $45,836 for the prior year. The improvement of $6,392,636
under that measure is closely correlated to, and primarily explained by,
increased revenues of $7,843,224 less increased direct costs of $2,104,552.
24
The cash flow statement reports actual cash expenditures for capital
expenditures, which differs from total capital expenditures on a full accrual
basis. Specifically, cash paid for acquisition of property and equipment as
reflected in the statement of cash flows excludes non-cash capital expenditures
and includes an adjustment (plus or minus) to reflect the timing of when the
capital expenditure obligations are incurred and when the actual cash payment is
made. On a full accrual basis, capital expenditures totaled $47,237,827 and
$12,888,373 for the years ended August 31, 2011 and 2010, respectively, compared
to cash payments of $30,247,327 and $9,152,175, respectively. A reconciliation
of the differences is summarized in the following table:
Year Ended August 31,
---------------------------------
2011 2010
---------------- ---------------
Cash payments $ 30,247,327 $ 9,152,175
Accrued costs, beginning of period (3,466,439) -
Accrued costs, end of period 4,967,368 3,466,439
Properties acquired in exchange for
common stock 9,938,487 16,645
Properties acquired in exchange for
note payable 5,200,000 -
Asset retirement obligation 351,083 253,114
---------------- ---------------
Capital expenditures $ 47,237,826 $ 12,888,373
================ ===============
Capital expenditures included the cost of proved properties of $21,250,000,
leasehold acquisition costs of $8,546,000, drilling and completion costs on
completed wells of $10,534,000, costs incurred on wells in progress of
$4,814,000, and all other expenditures, including capitalized interest,
capitalized overhead, and asset retirement obligations, of $2,094,000.
Financing for our capital expenditures was provided by several sources. In
addition to cash flow from operations, on January 11, 2011, we completed the
sale of 9 million shares of our common stock in a private offering. The shares
were sold at a price of $2.00 per share. Proceeds to us from the sale of the
shares were $16,690,721 after deductions for sales commissions and expenses.
In two separate transactions, we sold oil and gas leases covering 5,902
gross acres (3,738 net acres) for net cash proceeds of $8,382,167, after the
deduction of selling costs of $248,700.
We acquired certain mineral interests in exchange for 1,849,838 shares of
restricted common stock with a market value of $5,240,307.
The structure of the agreement to acquire assets from PEM included a cash
payment of $10,000,000, a promissory note with a principal amount of $5,200,000,
and 1,381,818 shares of common stock with a value of $4,698,181.
In June 2011 we obtained a commitment for a $7,000,000 revolving line of
credit from Bank of Choice.
25
Our primary need for cash during the fiscal year ending August 31, 2012
will be to fund our acquisition and drilling program. Subsequent to August 31,
2011, we filed a registration statement on Form S-3 that provides for the future
sale of securities up to $75 million. As market conditions are not currently
conducive to an offering, we have not undertaken an offering at this time.
However, we continue to monitor market conditions and may proceed with an
offering if conditions are favorable. If we do not obtain additional financing,
we estimate that capital expenditures for the year will approximate $31.7
million, primarily for the drilling of 28 wells in which we own a majority
interest, participation with other operators in 14 wells, recompletion of 20
wells that indicate good potential for additional hydraulic stimulation, and
acquisition of undeveloped acreage and proved properties. We have identified
additional opportunities that could expand our capital expenditures to $70.1
million under certain circumstances, which would require additional funding. If
we increase our capital budget to $70.1 million, it could expand our lease
acquisition program by $1.7 million, increase by 32 the number of wells drilled,
and include an acquisition of several producing properties aggregating $17
million. Our capital expenditure estimate is subject to significant adjustment
for drilling success, acquisition opportunities, operating cash flow, and
available capital resources.
We plan to generate profits by drilling or acquiring productive oil or gas
wells. However, we may need to raise some of the funds required to drill new
wells through the sale of our securities, from loans from third parties or from
third parties willing to pay our share of drilling and completing the wells. We
may not be successful in raising the capital needed to drill or acquire oil or
gas wells. Any wells which may be drilled by us may not produce oil or gas in
commercial quantities.
Non-GAAP Financial Measures
We use "adjusted cash flow from operations" and "adjusted EBITDA," non-GAAP
financial measures, for internal managerial purposes, when evaluating
period-to-period comparisons. These measures are not measures of financial
performance under U.S. GAAP and should be considered in addition to, not as a
substitute for, cash flows from operations, investing, or financing activities,
nor as a liquidity measure or indicator of cash flows reported in accordance
with U.S. GAAP. The non-GAAP financial measures that we use may not be
comparable to measures with similar titles reported by other companies. Also, in
the future, we may disclose different non-GAAP financial measures in order to
help our investors more meaningfully evaluate and compare our future results of
operations to our previously reported results of operations. We strongly
encourage investors to review our financial statements and publicly filed
reports in their entirety and to not rely on any single financial measure. See
Reconciliation of Non-GAAP Financial Measures below for a detailed description
of these measures as well as a reconciliation of each to the nearest U.S. GAAP
measure.
Reconciliation of Non-GAAP Financial Measures
Adjusted cash flow from operations. We define adjusted cash flow from
operations as the cash flow earned or incurred from operating activities without
regard to the collection or payment of associated receivables and payables. We
believe it is important to consider adjusted cash flow from operations as well
as cash flow from operations, as we believe it often provides more transparency
into what drives the changes in our operating trends, such as production,
prices, operating costs, and related operational factors, without regard to
whether the earned or incurred item was collected or paid during the period. We
also use this measure because the collection of our receivables or payment of
26
our obligations has not been a significant issue for our business, but merely a
timing issue from one period to the next, with fluctuations generally caused by
significant changes in commodity prices. See the Statements of Cash Flows in
this report.
Adjusted EBITDA. We define adjusted EBITDA as net income (loss) plus
interest expense, net of interest income, income taxes, and depreciation,
depletion and amortization for the period plus/minus the change in fair value of
our derivative conversion liability. We believe adjusted EBITDA is relevant
because it is a measure of cash available to fund our capital expenditures and
service our debt and is a widely used industry metric which allows comparability
of our results with our peers.
The following table presents a reconciliation of each of our non-GAAP
financial measures to its nearest GAAP measure.
Year Ended August 31,
---------------------------------
2011 2010
--------------- ----------------
Adjusted cash flow from operations:
Adjusted cash flow from operations $ 6,346,800 $ (45,836)
Changes in assets and liabilities 1,569,508 (2,397,223)
--------------- ----------------
Net cash provided by (used in) operating
activities $ 7,916,308 $ (2,443,059)
=============== ================
Adjusted EBITDA:
Adjusted EBITDA $ 5,658,547 $ (80,125)
Interest expense and related items, net (4,191,169) (2,334,190)
Change in fair value of derivative
conversion liability (10,229,229) (7,678,457)
Depreciation, depletion and amortization (2,838,307) (701,400)
--------------- ----------------
Net loss $(11,600,158) $ (10,794,172)
=============== ================
Contractual Obligations
The following table summarizes our contractual obligations as of August 31,
2011:
Less than One to Three to
One Year Three Years Five Years Total
----------- ----------- ------------ ------------
Note payable, related
party (1) 5,200,000 - - 5,200,000
Employment Agreements
780,000 770,000 - 1,550,000
Operating Leases
110,000 - - 110,000
Rig Contract (2)
2,647,774 - - 2,647,774
----------- ----------- ------------ ------------
Total
8,737,774 770,000 - 9,507,774
=========== =========== ============ ============
(1) See "Acquisition of Oil and Gas Properties from Petroleum Exploration
& Management LLC" in Item 1 of this report for information concerning
this note.
27
(2) In August 2011 we entered in a contract with Ensign United States
Drilling, Inc. which provided that Ensign would drill and complete 21
wells in the Wattenberg Field on our behalf. As of October 31, 2011 we
had reached total depth on 15 wells pursuant to the agreement. We
expect that the remaining 6 wells we committed to drill will be
drilled, and if warranted, completed by December 31, 2011 at a cost of
approximately $189,000 per well, or $1,134,000 in total.
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.
28
Critical Accounting Policies
The discussion and analysis of our financial condition and results of
operations are based upon our financial statements, which have been prepared in
accordance with accounting principles generally accepted in the United States.
The preparation of these financial statements requires us to make estimates and
assumptions that affect the reported amounts of assets, liabilities, including
oil and gas reserves, and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Management routinely makes judgments and
estimates about the effects of matters that are inherently uncertain. Management
bases its estimates and judgments on historical experience and on various other
factors that are believed to be reasonable under the circumstances, the results
of which form the basis for making judgments about the carrying values of assets
and liabilities that are not readily apparent from other sources. Estimates and
assumptions are revised periodically and the effects of revisions are reflected
in the financial statements in the period it is determined to be necessary.
Actual results could differ from these estimates.
We provide expanded discussion of our more significant accounting policies,
estimates and judgments below. We believe these accounting policies reflect our
more significant estimates and assumptions used in preparation of our financial
statements. See Note 1 of the Notes to the Financial Statements for a discussion
of additional accounting policies and estimates made by management.
Oil and Gas Properties: We use the full cost method of accounting for costs
related to its oil and gas properties. Accordingly, all costs associated with
acquisition, exploration, and development of oil and gas reserves (including the
costs of unsuccessful efforts) are capitalized into a single full cost pool.
These costs include land acquisition costs, geological and geophysical expense,
carrying charges on non-producing properties, costs of drilling, and overhead
charges directly related to acquisition and exploration activities. Under the
full cost method, no gain or loss is recognized upon the sale or abandonment of
oil and gas properties unless non-recognition of such gain or loss would
significantly alter the relationship between capitalized costs and proved oil
and gas reserves.
Capitalized costs of oil and gas properties are amortized using the
unit-of-production method based upon estimates of proved reserves. For
amortization purposes, the volume of petroleum reserves and production is
converted into a common unit of measure at the energy equivalent conversion rate
of six thousand cubic feet of natural gas to one barrel of crude oil.
Investments in unevaluated properties and major development projects are not
amortized until proved reserves associated with the projects can be determined
or until impairment occurs. If the results of an assessment indicate that the
properties are impaired, the amount of the impairment is added to the
capitalized costs to be amortized.
Under the full cost method of accounting, a ceiling test is performed each
quarter. The full cost ceiling test is an impairment test prescribed by SEC
regulations. The ceiling test determines a limit on the book value of oil and
gas properties. The capitalized costs of proved and unproved oil and gas
properties, net of accumulated depreciation, depletion, and amortization, and
the related deferred income taxes, may not exceed the estimated future net cash
flows from proved oil and gas reserves, less future cash outflows associated
with asset retirement obligations that have been accrued, plus the cost of
unevaluated properties not being amortized, plus the lower of cost or estimated
fair value of unevaluated properties being amortized, less income tax effects.
Prices are held constant for the productive life of each well. Net cash flows
29
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 changing conditions
raise the ceiling amount.
Oil and Gas Reserves: The determination of depreciation, depletion and
amortization expense, as well as the ceiling test related to the recorded value
of our oil and natural gas properties, will be highly dependent on the estimates
of the proved oil and natural gas reserves. Oil and natural gas reserves include
proved reserves that represent estimated quantities of crude oil and natural gas
which geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic and
operating conditions. There are numerous uncertainties inherent in estimating
oil and natural gas reserves and their values, including many factors beyond our
control. Accordingly, reserve estimates are often different from the quantities
of oil and natural gas ultimately recovered and the corresponding lifting costs
associated with the recovery of these reserves.
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. In connection
with the conversion of convertible promissory notes into shares of the Company's
common stock, during the years ended August 31, 2011 and 2010 the derivative
conversion liability balances were reclassified to additional paid-in-capital.
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 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 to recognize delivery of
30
product to the purchaser. Payment is typically received sixty to ninety days
after production. Differences between estimates and actual volumes and prices,
if any, are adjusted upon final settlement.
Stock Based Compensation: We record stock-based compensation expense in
accordance with the fair value recognition provisions of US GAAP. Stock based
compensation is measured at the grant date based upon the estimated fair value
of the award and the expense is recognized over the required employee service
period, which generally equals the vesting period of the grant. The fair value
of stock options is estimated using the Black-Scholes-Merton option-pricing
model. The fair value of restricted stock grants is estimated on the grant date
based upon the fair value of the common stock.
Recent Accounting Pronouncements: We evaluate the pronouncements of various
authoritative accounting organizations, primarily the Financial Accounting
Standards Board ("FASB"), the Securities and Exchange Commission ("SEC"), and
the Emerging Issues Task Force ("EITF"), to determine the impact of new
pronouncements on US GAAP and the impact on the Company.
We have recently adopted the following new accounting standards:
Effective March 1, 2011, the Company adopted ASU No. 2010-29 - Business
Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for
Business Combinations--A consensus of the FASB Emerging Issues Task Force. This
update provides clarification requiring public companies that have completed
material acquisitions to disclose the revenue and earnings of the combined
business as if the acquisition took place at the beginning of the comparable
prior annual reporting period, and also expands the supplemental pro forma
disclosures to include a description of the nature and amount of material,
nonrecurring pro forma adjustments directly attributable to the business
combination included in the reported pro forma revenue and earnings. See Note 9
for the Company's disclosures of business combinations.
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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See the financial statements and accompanying notes included with this
report.
31
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
An evaluation was carried out under the supervision and with the
participation of our management, including our Principal Executive Officer and
Principal Financial 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, 2011, 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, 2011 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.
Based on this evaluation, management concluded that our internal control
over financial reporting was effective as of August 31, 2011.
32
Changes in Internal Control Over Financial Reporting
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, our internal control over
financial reporting.
Attestation Report of Registered Public Accounting Firm
The attestation report required under this Item 9A is set forth under the
caption "Report of Independent Registered Public Accounting Firm" which is
included with the financial statements and supplemental data required by Item 8.
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 59 President, Principal Executive Officer and
Director
William E. Scaff, Jr. 54 Vice President, Secretary, Treasurer and
Director
Frank L. Jennings 60 Principal Financial and Accounting Officer
Rick A. Wilber 64 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. 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 Production 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
33
2008 and September 2008. Between 1980 and 1990, Mr. Scaff oversaw financial and
credit transactions for Dresser Industries, a Fortune 50 oilfield equipment
company. Immediately after serving as a regional manager with TOTAL Petroleum
between 1990 and 1997, Mr. Scaff co-founded, and since that date co-managed,
Petroleum Management, LLC, a company engaged in the exploration, operations,
production and distribution of oil and natural gas. In 2001, Mr. Scaff
co-founded, and since that date has co-managed, Petroleum Exploration and
Management, LLC, a company engaged in the acquisition of oil and gas leases and
the production and sale of oil and natural gas. Mr. Scaff holds a degree in
Finance from the University of Colorado.
Frank L. Jennings - Mr. Jennings began his service as our Principal Financial
and Accounting Officer on a part-time basis in June 2007. In March 2011 he
joined us on a full-time basis. From 2001 until 2011, Mr. Jennings was an
independent consultant providing financial accounting services, primarily to
smaller public companies. From 2006 until 2011, he also served as the Chief
Financial Officer of Gold Resource Corporation (AMEX:GORO). From 2000 to 2005,
he served as the Chief Financial Officer and a director of Global Casinos, Inc.,
a publicly traded corporation, and from 1994 to 2001 he served as Chief
Financial Officer of American Educational Products, Inc. (NASDAQ:AMEP), before
it was purchased by Nasco International. After his graduation from Austin
College with a degree in economics and from Indiana University with an MBA in
finance, he joined the Houston office of Coopers & Lybrand. He also spent four
years as the manager of internal audit for The Walt Disney Company.
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. Wilber and Noffsinger are qualified to act as
directors as result of their experience in financial matters.
Rick Wilber, Raymond McElhaney, Bill Conrad and R.W. Noffsinger, are
considered independent as that term is defined Section 803.A of the NYSE Amex
Rules.
The members of our compensation committee are Rick Wilber, Raymond
McElhaney, Bill Conrad, and R.W. Noffsinger. The members of our Audit Committee
are Raymond McElhaney, Bill Conrad and R.W. Noffsinger. Mr. Noffsinger acts as
the financial expert for the Audit Committee of our board of directors.
We have adopted a Code of Ethics applicable to all employees.
ITEM 11. EXECUTIVE COMPENSATION
The following table shows the compensation paid or accrued to our executive
officers during each of the three years ended August 31, 2011.
Name and Stock Option All Other
Principal Fiscal Salary Bonus Awards Awards Compensation
Position Year (1) (2) (3) (4) (5) Total
----------------- ------- ---------- -------- --------- --------- ------------ ------------
Ed Holloway, 2011 $300,000 100,000 - - 9,800 $ 409,800
Principal 2010 $175,000 - - - - $ 175,000
Executive 2009 $150,000 - - 5,092,672 - $5,242,672
Officer
35
William E. 2011 $300,000 100,000 - - 9,800 $ 409,800
Scaff, Jr., 2010 $175,000 - - - - $ 175,000
Vice President, 2009 $150,000 - - 5,092,672 - $5,242,672
Secretary and
Treasurer
Frank L 2011 $ 87,391 - 220,000 404,352 - $ 711,743
Jennings, 2010 $106,225 - - - - $ 106,255
Principal 2009 $ 63,715 - - - - $ 63,715
Financial and
Accounting
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, Mr. Scaff and Mr. Jennings
will be based upon their employment agreements, which are described below. All
material elements of the compensation paid to these officers is discussed below.
On June 11, 2008, we signed employment agreements with Ed Holloway and
William E. Scaff Jr. Each employment agreement provided that the employee would
be paid a monthly salary of $12,500 and required the employee to devote
approximately 80% of his time to our business. The employment agreements expired
on June 1, 2010.
On June 1, 2010, we entered into a new employment agreements with Mr.
Holloway and Mr. Scaff. The new employment agreements, which expire on May 31,
2013, provide that we pay Mr. Holloway and Mr. Scaff each a monthly salary of
$25,000 and require both Mr. Holloway and Mr. Scaff to devote approximately 80%
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, a cash payment of $100,000 or 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 50th well begins producing.
On June 23, 2011 our directors approved an employment agreement with Frank
L. Jennings, our Principal Financial and Accounting Officer. The employment
agreement provides that we will pay Mr. Jennings a monthly salary of $15,000 and
issue to Mr. Jennings:
o 50,000 shares of our restricted common stock; and
o options to purchase 150,000 shares of our common stock. The options
are exercisable at a price of $4.40 per share, vest over three years
in 50,000 share increments beginning March 6, 2012, and expire on
March 7, 2021.
36
The employment agreement expires on March 7, 2014 and requires Mr. Jennings
to devote all of his time to our business.
If Mr. Jennings resigns within 90 days of a relocation (or demand for
relocation) of his place of employment to a location more than 35 miles from his
then current place of employment, the employment agreement will be terminated
and Mr. Jennings will be paid the salary provided by the employment agreement
through the date of termination and the unvested portion of any stock options
held by Mr. Jennings will vest immediately.
In the event there is a change in the control, the employment agreement
allows Mr. Jennings to resign from his position and receive a lump-sum payment
equal to 12 months' salary. In addition, the unvested portion of any stock
options held by Mr. Jennings will vest immediately. For purposes of the
employment agreement, a change in the control means: (1) our merger with another
entity if after such merger our shareholders do not own at least 50% of the
voting capital stock of the surviving corporation; (2) the sale of substantially
all of our assets; (3) the acquisition by any person of more than 50% of our
common stock; or (4) a change in a majority of our directors which has not been
approved by our incumbent directors.
The employment agreements mentioned above, will terminate upon the
employee's death, or disability or may be terminated by us for cause. If the
employment agreement is terminated for any of these reasons, the employee, or
his legal representatives as the case may be, will be paid the salary provided
by the employment agreement through the date of termination.
For purposes of the employment agreements, "cause" is defined as:
(i) the conviction of the employee of any crime or offense involving,
or of fraud or moral turpitude, which significantly harms us;
(ii) the refusal of the employee to follow the lawful directions of our
board of directors;
(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.
37
Employee Pension, Profit Sharing or other Retirement Plans. Effective
November 1, 2010 we adopted a defined contribution retirement plan, qualifying
under Section 401(k) of the Internal Revenue Code and covering substantially all
of our employees. We match participant's contributions in cash, not to exceed 4%
of the participant's total compensation. Other than this 401(k) Plan, we do not
have a defined benefit pension plan, profit sharing or other retirement plan.
Stock Option and Bonus Plans
We have a 2011 non-qualified stock option plan, a 2011 incentive stock
option plan, and a 2011 stock bonus plan. A summary description of each plan
follows.
2011 Non-Qualified Stock Option Plan. Our Non-Qualified Stock Option Plan
authorizes the issuance of shares of our common stock to persons that exercise
options granted pursuant to the Plan. Our employees, directors, officers,
consultants and advisors are eligible to be granted options pursuant to the
Plan, provided however that bona fide services must be rendered by such
consultants or advisors and such services must not be in connection with
promoting our stock or the sale of securities in a capital-raising transaction.
The option exercise price is determined by our directors.
2011 Incentive Stock Option Plan. Our Incentive Stock Option Plan
authorizes the issuance of shares of our common stock to persons that exercise
options granted pursuant to the Plan. Our employees, directors, officers,
consultants and advisors are eligible to be granted options pursuant to the
Plan, provided however that bona fide services must be rendered by such
consultants or advisors and such services must not be in connection with
promoting our stock or the sale of securities in a capital-raising transaction.
The option exercise price is determined by our directors.
2011 Stock Bonus Plan. Our Stock Bonus Plan allows for the issuance of
shares of common stock to our employees, directors, officers, consultants and
advisors. However, bona fide services must be rendered by the consultants or
advisors and such services must not be in connection with promoting our stock or
the sale of securities in a capital-raising transaction.
The plans adopted during 2011 replaced a non-qualified stock option plan
and a stock bonus plan originally adopted during 2005 (the "2005 Plans"). No
additional options or shares will be issued under the 2005 Plans.
Summary. The following is a summary of options granted or shares issued
pursuant to the Plans as of October 31, 2011. Each option represents the right
to purchase one share of our common stock.
Total
Shares Reserved for Shares Remaining
Reserved Outstanding Issued as Options/Shares
Name of Plan Under Plans Options Stock Bonus Under Plans
------------ ----------- ------------ ----------- -------------
2011 Non-Qualified Stock
Option Plan 2,000,000 150,000 0 1,850,000
2011 Incentive Stock
Option Plan 2,000,000 0 0 2,000,000
2011 Stock Bonus Plan 2,000,000 0 0 2,000,000
38
Options
In connection with the acquisition of Predecessor Synergy, we issued
options to the persons shown below in exchange for options previously issued by
Predecessor Synergy. The terms of the options we issued are identical to the
terms of the Predecessor Synergy options. The options were not granted pursuant
to our 2005 Plans. As of October 31, 2011, none of these options have been
exercised.
Grant Shares Issuable Upon Exercise Expiration
Name Date Exercise of Options Price Date
---- ------- -------------------- -------- ----------
Ed Holloway (1) 9-10-08 1,000,000 $ 1.00 6-11-13
William E. Scaff, Jr. (2) 9-10-08 1,000,000 $ 1.00 6-11-13
Ed Holloway (1) 9-10-08 1,000,000 $10.00 6-11-13
William E. Scaff, Jr. (2) 9-10-08 1,000,000 $10.00 6-11-13
(1) Options are held of record by a limited liability company controlled
by Mr. Holloway.
(2) Options are held of record by a limited liability company controlled
by Mr. Scaff.
The following table shows information concerning our outstanding options as
of October 31, 2011.
Shares underlying unexercised
Option which are:
--------------------------- Exercise Expiration
Name Exercisable Unexercisable Price Date
---- ----------- ------------- -------- -----------
Ed Holloway 1,000,000 -- $ 1.00 6-11-13
William E. Scaff, Jr. 1,000,000 -- $ 1.00 6-11-13
Ed Holloway 1,000,000 -- $10.00 6-11-13
William E. Scaff, Jr. 1,000,000 -- $10.00 6-11-13
Employees 10,000(1) 610,000 (1) (1) (1)
(1) Options were issued to several employees pursuant to our Non-Qualified
Stock Option Plan. The exercise price of the options varies between
$2.40 and $4.40 per share. The options expire at various dates between
December 2018 and August, 2021.
The following table shows the weighted average exercise price of the
outstanding options granted pursuant to our Non-Qualified Stock Option Plan or
otherwise as of August 31, 2011. Prior to 2011, neither our Non-Qualified Stock
Option Plan nor the issuance of any of our other options have been approved by
our shareholders.
39
1 2 3
Number of Securities
Number Remaining Available
of Securities For Future Issuance
be Issued Weighted-Average Under Equity
Upon Exercise Exercise Price Compensation Plans,
of Outstanding of Outstanding Excluding Securities
Plan category Options Options Reflected in Column 1
--------------------------------------------------------------------------------------
Non-Qualified Stock Option Plan 620,000 $3.40 1,380,000 (1)
Other Options 4,000,000 $5.50 -
(1) As of May 23, 2011, this Plan was terminated and no further options
will be issued pursuant to its terms.
Compensation of Directors During Year Ended August 31, 2011
Fees Earned or Stock Option
Paid in Cash Awards (1) Awards (2) Total
-------------- ---------- ---------- -----
Rick Wilber $20,000 -- -- $20,000
Raymond McElhaney $32,500 -- -- 32,500
Bill Conrad 28,000 -- -- 28,000
R.W. Noffsinger 24,000 -- -- 24,000
George Seward 20,000 -- -- 20,000
-------- --- --------
$124,500 -- $124,500
======== === ========
(1) The fair value of stock issued for services computed in accordance
with ASC 718.
(2) The fair value of options granted computed in accordance with ASC 718
on the date of grant.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The following table shows, as of October 31, 2011, information with respect
to those persons owning beneficially 5% or more of our common stock and the
number and percentage of outstanding shares owned by each of our directors and
officers and by all officers and directors as a group. Unless otherwise
indicated, each owner has sole voting and investment powers over his shares of
common stock.
Number Percent
Name of Shares (1) of Class(2)
---- ------------- -----------
Ed Holloway 4,760,909 (3) 13.19%
William E. Scaff, Jr. 4,760,909 (4) 13.19%
40
Frank L. Jennings 74,000 *
Rick A. Wilber 536,700 1.49%
Raymond E. McElhaney 245,725 *
Bill M. Conrad 247,225 *
R.W. Noffsinger, III 288,425 *
George Seward 909,080 2.52%
Wayne L. Laufer 2,893,750 8.02%
All officers and directors as a group
(8 persons) 11,822,973 32.75%
* Less than 1%
(1) Share ownership includes shares issuable upon the exercise of options,
all of which are currently exercisable, held by the persons listed
below.
Share
Issuable
Upon Option
Exercise of Exercise Expiration
Name Options Price Date
--------------------- -------------- --------- ----------
Ed Holloway 1,000,000 $ 1.00 6/11/2013
Ed Holloway 1,000,000 $10.00 6/11/2013
William E. Scaff, Jr. 1,000,000 $ 1.00 6/11/2013
William E. Scaff, Jr. 1,000,000 $10.00 6/11/2013
(2) Computed based upon 36,098,212 shares of common stock outstanding as
of October 31, 2011.
(3) Shares are held of record by various trusts and limited liability
companies controlled by Mr. Holloway.
(4) Shares are held of record by various trusts and limited liability
companies controlled by Mr. Scaff.
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
41
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 acquired all of the working oil and gas assets owned by PEM in a
transaction that closed on May 24, 2011. In total, we acquired interests in 88
gross (40 net) oil and gas wells in the Wattenberg Field, and interests in oil
and gas leases covering approximately 6,968 gross acres in the Wattenberg Field
and the Eastern D-J Basin (eastern Colorado and western Nebraska). These oil and
gas interests were acquired from Petroleum Exploration and Management, LLC
("PEM"), a company owned by Ed Holloway and William E. Scaff, Jr., two of our
officers, for approximately $19.0 million. The transaction was approved by the
disinterested directors and by a vote of the shareholders, with Mr. Holloway and
Mr. Scaff not voting.
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.
We had a letter agreement with PM and PEM which provided us with the option
to acquire working interests in oil and gas leases owned by these firms and
covering lands on the D-J basin. The oil and gas leases covered 640 acres in
Weld County, Colorado and, subject to certain conditions, would be transferred
to us for payment of $1,000 per net mineral acre. The working interests in the
leases we could acquire varied, but the net revenue interest in the leases,
could not be less than 75%. Under this letter agreement, through February 2010
we acquired leases covering 640 gross (360 net) acres from PM and PEM for
$360,000.
Pursuant to the terms of an Administrative Services Agreement, through June
30, 2010 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.
42
During the year ended August 31, 2011, we acquired oil and gas leases from
George Seward, a member of our board of directors. In total, we purchased lease
interests covering 22,066 gross (19,717 net) undeveloped acres, located in
eastern Colorado and western Nebraska, in exchange for 353,817 shares of our
common stock. Based on the market price of our common stock on the transaction
dates, these acquisitions were valued at $788,676.
Prior to our acquisition of Predecessor Synergy, Predecessor Synergy made
the following sales of its securities:
Name Shares Series A Warrants Consideration
---- ------ ----------------- -------------
Ed Holloway (1) 2,070,000 -- $ 2,070
William E. Scaff, Jr.(1) 2,070,000 -- 2,070
Benjamin Barton (1) 600,000 -- 600
John Staiano (1) 600,000 -- 600
Synergy Energy trust 1,900,000 (2) -- 1,900
Third Parties 660,000 -- 660
Private Investors 1,000,000 1,000,000 $1.00 Per Unit (3)
Private Investors 1,060,000 1,060,000 $1.50 Per Unit (3)
--------- ---------
Total 9,960,000 2,060,000
========= =========
(1) Shares are held of record by entities controlled by this person.
(2) In December 2008, we repurchased 1,000,000 shares from the Synergy
Energy Trust.
(3) Shares and warrants were sold as units, with each unit consisting of
one share of our common stock and one Series A warrant.
In connection with our acquisition of Predecessor Synergy, the 9,960,000
shares of Predecessor Synergy, plus the 2,060,000 Series A warrants, were
exchanged for 9,960,000 shares of our common stock, plus 2,060,000 of our Series
A warrants.
In contemplation of the acquisition of Predecessor Synergy, our directors
declared a dividend of Series A warrants. The dividend provided that each person
owning our shares at the close of business on September 9, 2008 will receive one
Series A warrant for each post-split share which they owned on that date. Mr.
McElhaney and Mr. Conrad, due to their ownership of our common stock on
September 9, 2008, received 271,000 and 247,000 Series A warrants, respectively.
Each Series A warrant entitles the holder to purchase one share of our
common stock at a price of $6.00 per share. The Series A warrants expire on the
earlier of December 31, 2012 or twenty days following written notification from
us that our common stock had a closing bid price at or above $7.00 for any ten
of twenty consecutive trading days.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
For each of the two years ended August 31, 2011 and 2010, Ehrhardt Keefe
Steiner Hottman P.C. ("EKS&H") served as our independent registered public
accounting firm.
43
Year Ended Year Ended
August 31, 2011 August 31, 2010
--------------- ---------------
Audit Fees $ 119,514 $ 72,213
Audit-Related Fees $ 35,993 $ 7,500
Tax Fees $ 43,157 $ 3,800
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 EKS&H to render audit or non-audit services, each
engagement was approved by our audit committee.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Exhibits Page Number
-------- -----------
3.1.1 Articles of Incorporation (1)
3.1.2 Amendment to Articles of Incorporation (2)
3.1.3 Bylaws (1)
10.1 Employment Agreement with Ed Holloway (2)
10.2 Employment Agreement with William E.
Scaff, Jr. (2)
10.3 Administrative Services Agreement (3)
10.4 Agreement regarding Conflicting Interest
Transactions (3)
10.5 Consulting Services Agreement with
Raymond McElhaney and Bill Conrad (4)
10.6.1 Form of Convertible Note (4)
10.6.2 Form of Subscription Agreement (4)
10.6.3 Form of Series C Warrant (4)
10.7 Purchase and Sale Agreement with Petroleum
Exploration and Management, LLC (wells,
equipment and well bore leasehold assignments) (4)
10.8 Purchase and Sale Agreement with Petroleum
Management, LLC (operations and
leasehold) (4)
44
10.9 Purchase and Sale Agreement with Chesapeake Energy (4)
10.10 Lease with HS Land & Cattle, LLC (4)
10.11 Employment Agreement with Frank L. Jennings (5)
10.12 Purchase and Sale Agreement with Petroleum
Exploration and Management, LLC (6)
14. Code of Ethics (7)
23 Consent of Accountants
31 Rule 13a-14(a) Certifications
32 Section 1350 Certifications
99 Report of Ryder Scott Company, L.P.
(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 the Company's
transition report on Form 8-K for the period ended August 31, 2008.
(3) Incorporated by reference to the same exhibit filed with our transition
report on Form 10-K for the year ended August 31, 2008.
(4) Incorporated by reference to the same exhibit filed with the Company's
report on Form 10-K/A filed on June 3, 2011.
(5) Incorporated by reference to the same exhibit filed with the Company's
report on Form 8-K filed on June 24, 2011.
(6) Incorporated by reference to Exhibit 10.12 filed with the Company's report
on Form 8-K filed on August 5, 2011.
(7) Incorporated by reference to Exhibit 14 filed with the Company's report on
Form 8-K filed on July 22, 2011.
45
SYNERGY RESOURCES CORPORATION
INDEX TO FINANCIAL STATEMENTS
Index to Financial Statements F-1
Report of Independent Registered Public Accounting Firm F-2
Balance Sheets as of August 31, 2011 and 2010 F-3
Statements of Operations for the years ended August 31, 2011 and 2010 F-4
Statements of Changes in Shareholders' Equity (Deficit)
for the years ended August 31, 2011 and 2010 F-5
Statements of Cash Flows for the years ended August 31, 2011 and 2010 F-6
Notes to Financial Statements F-7
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Synergy Resources Corporation
We have audited the accompanying balance sheets of Synergy Resources Corporation
("the Company") as of August 31, 2011 and 2010, and the related statements of
operations, changes in shareholders' equity, and cash flows for each of years
then ended. We have also audited the Company's internal control over financial
reporting as of August 31, 2011, based on criteria established in Internal
Control - Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The Company's management is
responsible for these financial statements, for maintaining effective internal
control over financial reporting, and for its assessment of the effectiveness of
internal control over financial reporting. Our responsibility is to express an
opinion on these financial statements and an opinion on the Company's internal
control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement and whether effective
internal control over financial reporting was maintained in all material
respects. Our audits of the financial statements included examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
Our audit of internal control over financial reporting included obtaining an
understanding of internal control over financial reporting, assessing the risk
that a material weakness exists, and testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary
in the circumstances. We believe that our audits provide a reasonable basis for
our opinions.
A company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Synergy Resources Corporation
as of August 31, 2011 and 2010, and the results of its operations and its cash
flows for each of the years then ended in conformity with accounting principles
generally accepted in the United States of America. Also in our opinion, Synergy
Resources Corporation, in all material respects, maintained effective internal
control over financial reporting as of December August 31, 2011, based on
criteria established in Internal Control - Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO).
/s/ Ehrhardt Keefe Steiner & Hottman PC
Ehrhardt Keefe Steiner & Hottman PC
Denver, Colorado
November 11, 2011
F-2
SYNERGY RESOURCES CORPORATION
BALANCE SHEETS
As of August 31, 2011 and 2010
2011 2010
------------ ----------
ASSETS
Current assets:
Cash and cash equivalents $ 9,490,506 $ 6,748,637
Accounts receivable:
Oil and gas sales 2,185,051 377,675
Joint interest billing 2,406,473 1,930,810
Related party receivable - 867,835
Inventory 459,592 387,864
Other current assets 89,336 12,310
------------ -----------
Total current assets 14,630,958 10,325,131
------------ -----------
Property and equipment:
Oil and gas properties, full cost method, net 48,614,857 12,692,194
Other property and equipment, net 283,207 150,789
------------ -----------
Property and equipment, net 48,898,064 12,842,983
------------ -----------
Debt issuance costs, net of amortization - 1,587,799
Other assets 168,863 86,000
------------ -----------
Total assets $ 63,697,885 $24,841,913
============ ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade $ 6,620,561 $ 3,015,562
Related party payable - 554,669
Accrued expenses 2,125,852 517,921
Notes payable, related party 5,200,000 -
------------ -----------
Total current liabilities 13,946,413 4,088,152
Asset retirement obligations 643,459 254,648
Convertible promissory notes, net of debt
discount - 12,190,945
Derivative conversion liability - 9,325,117
------------ -----------
Total liabilities 14,589,872 25,858,862
------------ -----------
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: 36,098,212 and 13,510,981
shares issued and outstanding as of August 31,
2011 and 2010, respectively 36,098 13,511
Additional paid-in capital 84,011,496 22,308,963
Accumulated deficit (34,939,581) (23,339,423)
------------ -----------
Total shareholders' equity (deficit) 49,108,013 (1,016,949)
------------ -----------
Total liabilities and shareholders' equity $ 63,697,885 $24,841,913
============ ===========
The accompanying notes are an integral part of these financial statements.
F-3
SYNERGY RESOURCES CORPORATION
STATEMENTS OF OPERATIONS
For the years ended August 31, 2011 and 2010
2011 2010
-------------- --------------
Revenues:
Oil and gas revenues $ 9,777,172 $ 2,158,444
Service revenues 224,496 -
------------ ------------
Total revenues 10,001,668 2,158,444
------------ ------------
Expenses:
Lease operating expenses 1,439,818 323,520
Depreciation, depletion, and amortization 2,838,307 701,400
General and administrative 2,903,303 1,915,049
------------ ------------
Total expenses 7,181,428 2,939,969
------------ ------------
Operating income (loss) 2,820,240 (781,525)
------------ ------------
Other income (expense):
Change in fair value of derivative
conversion liability (10,229,229) (7,678,457)
Interest expense, net (4,246,945) (2,338,849)
Interest income 55,776 4,659
------------ ------------
Total other (expense) (14,420,398) (10,012,647)
------------ ------------
Loss before income taxes (11,600,158) (10,794,172)
Provision for income taxes - -
------------ ------------
Net loss $(11,600,158) $(10,794,172)
============ ============
Net loss per common share:
Basic and diluted $ (0.45) $ (0.88)
============ ============
Weighted average shares outstanding:
Basic and diluted 26,009,283 12,213,999
============ ============
The accompanying notes are an integral part of these financial statements.
F-4
SYNERGY RESOURCES CORPORATION
STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY (DEFICIT)
for the years ended August 31, 2011 and 2010
Total
Number of Additional Shareholders'
Common Common Paid-In Accumulated Equity
Shares Stock Capital (Deficit) (Deficit)
---------- -------- ---------- ----------- ------------
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)
Shares issued pursuant to conversion
of debt and accrued interest at
$1.60 per share, net of $1,052,917
unamortized debt discount 9,979,376 9,979 14.904.100 - 14,914,079
Reclassification of derivative
conversion liability to equity
pursuant to early conversion of debt - - 19,554,346 - 19,554,346
Shares issued for services 150,000 150 429,850 - 430,000
Shares issued in exchange for mineral
leases 1,849,838 1,850 5,238,457 - 5,240,307
Shares issued in exchange for oil and
gas assets, related party 1,381,818 1,382 4,696,799 - 4,698,181
Shares issued for cash at $2.00 per
share pursuant to November 30, 2010
offering memorandum, net of offering
costs 9,000,000 9,000 16,681,721 - 16,690,721
Shares issued pursuant to conversion
of Series D warrants on a cashless basis 226,199 226 (226) - -
Share based compensation - - 197,486 - 197,486
Net (loss) - - - (11,600,158) (11,600,158)
----------- -------- ---------- ------------ ------------
Balance, August 31, 2011 36,098,212 $ 36,098 $84,011,496 $(34,939,581) $ 49,108,013
=========== ======== =========== ============ ============
The accompanying notes are an integral part of these financial statements.
F-5
SYNERGY RESOURCES CORPORATION
STATEMENTS OF CASH FLOWS
for the years ended August 31, 2011 and 2010
2011 2010
------------ ----------
Cash flows from operating activities:
Net loss $(11,600,158) $(10,794,172)
------------ -------------
Adjustments to reconcile net loss to
net cash used in operating activities:
Depreciation, depletion, and amortization 2,838,307 701,400
Amortization of debt issuance cost 1,587,799 453,656
Accretion of debt discount 2,664,138 1,333,590
Stock-based compensation 627,486 581,233
Change in fair value of derivative liability 10,229,229 7,678,457
Changes in operating assets and liabilities:
Accounts receivable (1,415,204) (3,091,677)
Inventory (71,728) 744,821
Accounts payable 1,549,400 (518,942)
Accrued expenses 1,666,928 460,780
Other (159,889) 7,795
------------ -------------
Total adjustments 19,516,466 8,351,113
------------ -------------
Net cash provided by (used in)
operating activities 7,916,308 (2,443,059)
------------ -------------
Cash flows from investing activities:
Acquisition of property and equipment (30,247,327) (9,152,175)
Net proceeds from sales of oil and
gas properties 8,382,167 -
------------ -------------
Net cash (used in) investing activities (21,865,160) (9,152,175)
------------ -------------
Cash flows from financing activities:
Cash proceeds from sale of stock 18,000,000 -
Offering costs (1,309,279) -
Cash proceeds from convertible promissory notes - 18,000,000
Debt issuance costs - (1,348,977)
Principal repayments - (1,161,811)
------------ -------------
Net cash provided by financing activities 16,690,721 15,489,212
------------ -------------
Net increase in cash and equivalents 2,741,869 3,893,978
Cash and equivalents at beginning of period 6,748,637 2,854,659
------------ -------------
Cash and equivalents at end of period $ 9,490,506 $ 6,748,637
============ =============
Supplemental Cash Flow Information (See Note 14)
The accompanying notes are an integral part of these financial statements.
F-6
SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
August 31, 2011 and 2010
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.
Basis of Presentation: The Company prepares its financial statements in
accordance with accounting principles generally accepted in the United States of
America ("US GAAP"). In June 2009 the Financial Accounting Standards Board
("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 Securities and Exchange Commission ("SEC")
under authority of federal securities laws are also sources of authoritative US
GAAP for SEC registrants. New accounting standards are communicated by FASB
through Accounting Standards Updates ("ASU's").
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 effect
the reported amount of assets and 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.
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.
F-7
Oil and Gas Properties: The Company uses the full cost method of accounting
for costs related to its oil and gas properties. Accordingly, all costs
associated with acquisition, exploration, and development of oil and gas
reserves (including the costs of unsuccessful efforts) are capitalized into a
single full cost pool. These costs include land acquisition costs, geological
and geophysical expense, carrying charges on non-producing properties, costs of
drilling, and overhead charges directly related to acquisition and exploration
activities. Under the full cost method, no gain or loss is recognized upon the
sale or abandonment of oil and gas properties unless non-recognition of such
gain or loss would significantly alter the relationship between capitalized
costs and proved oil and gas reserves.
Capitalized costs of oil and gas properties are amortized using the
unit-of-production method based upon estimates of proved reserves. For
amortization purposes, the volume of petroleum reserves and production is
converted into a common unit of measure at the energy equivalent conversion rate
of six thousand cubic feet of natural gas to one barrel of crude oil.
Investments in unevaluated properties and major development projects are not
amortized until proved reserves associated with the projects can be determined
or until impairment occurs. If the results of an assessment indicate that the
properties are impaired, the amount of the impairment is added to the
capitalized costs to be amortized.
Under the full cost method of accounting, a ceiling test is performed each
quarter. The full cost ceiling test is an impairment test prescribed by SEC
regulations. The ceiling test determines a limit on the book value of oil and
gas properties. The capitalized costs of proved and unproved oil and gas
properties, net of accumulated depreciation, depletion, and amortization, and
the related deferred income taxes, may not exceed the estimated future net cash
flows from proved oil and gas reserves, less future cash outflows associated
with asset retirement obligations that have been accrued, plus the cost of
unevaluated properties not being amortized, plus the lower of cost or estimated
fair value of unevaluated properties being amortized, less 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 changing conditions
raise the ceiling amount.
For the years ended August 31, 2011 and 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.
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 $206,233 and $95,475
for the years ended August 31, 2011 and 2010, respectively.
F-8
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, is 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 acquisition of mineral interests 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.
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). As a result of the conversion of all
outstanding convertible promissory notes into shares of the Company's common
stock, all debt issuance costs have been recognized as a component of interest
expense through August 31, 2011.
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
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
F-9
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. In connection with the conversion of convertible promissory notes
into shares of the Company's common stock, during the years ended August 31,
2011 and 2010 derivative conversion liabilities of $19,554,346 and $1,809,149
were reclassified to additional paid-in-capital, respectively.
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 to recognize delivery of product to the purchaser. Payment is typically
received sixty to ninety days after production. Differences between estimates
and actual volumes and prices, if any, are adjusted upon final settlement.
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.
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 2011 2010
--------------- ---------- ---------
Company A 75% 57%
Company B 21% 30%
Company C * 13%
* less than 10%
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
F-10
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:
2011 2010
------------- -------------
Convertible promissory notes - 9,942,500
Accrued interest - 135,068
Warrants(1) 14,931,067 15,286,466
Employee stock options 4,645,000 4,220,000
------------- -------------
Total 19,576,067 29,584,034
============= =============
(1) Also as of August 31, 2011 and 2010, the Company had a contingent
obligation to issue 63,466 potentially dilutive securities, all of which were
excluded from the calculation because the contingency conditions had not been
met.
Income Taxes: Deferred income taxes are recorded for timing differences
between items of income or expense reported in the financial statements and
those reported for income tax purposes using the asset/liability method of
accounting for income taxes. Deferred income taxes and tax benefits are
recognized for the future tax consequences attributable to differences between
the financial statement carrying amounts of existing assets and liabilities and
their respective tax bases, and for tax loss and credit carry-forwards. Deferred
tax assets and liabilities are measured using enacted tax rates expected to
apply to taxable income in the years in which those temporary differences are
expected to be recovered or settled. The Company provides for deferred taxes for
the estimated future tax effects attributable to temporary differences and
carry-forwards when realization is more likely than not. If the Company
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. 2011. Given the substantial net operating loss
carry-forwards at both the federal and state levels, neither significant
interest expense nor penalties charged for any examining agents' tax adjustments
F-11
of income tax returns prior to and including the year ended August 31, 2011 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 to determine the impact of new
pronouncements on US GAAP and the impact on the Company.
The Company has recently adopted the following new accounting standards:
Business Combinations - Effective March 1, 2011, the Company adopted ASU
No. 2010-29 - Business Combinations (Topic 805): Disclosure of Supplementary Pro
Forma Information for Business Combinations. This update provides clarification
requiring public companies that have completed material acquisitions to disclose
the revenue and earnings of the combined business as if the acquisition took
place at the beginning of the comparable prior annual reporting period, and also
expands the supplemental pro forma disclosures to include a description of the
nature and amount of material, nonrecurring pro forma adjustments directly
attributable to the business combination included in the reported pro forma
revenue and earnings. Adoption of this ASU had no material effect on the
Company's financial position, results of operations, or cash flows. See Note 9
for the Company's disclosures of business combinations.
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.
Presentation of Comprehensive Income - In June 2011, the FASB issued ASU
2011-05 - Presentation of Comprehensive Income ("ASU 2011-05"), which requires
entities to present reclassification adjustments included in other comprehensive
income on the face of the financial statements and allows entities to present
the total of comprehensive income, the components of net income and the
components of other comprehensive income either in a single continuous statement
of comprehensive income or in two separate but consecutive statements. It also
eliminates the option for entities to present the components of other
comprehensive income as part of the statement of changes in stockholders'
equity. For public companies, ASU 2011-05 is effective for fiscal years (and
interim periods within those years) beginning after December 15, 2011, with
earlier adoption permitted. Adoption of this ASU is not expected to have a
material effect on the Company's financial position, results of operations, or
cash flows.
There were various other updates recently issued, most of which represented
technical corrections to the accounting literature or were applicable to
specific industries, and are not expected to have a material impact on the
Company's financial position, results of operations or cash flows.
F-12
2. Accounts Receivable
Accounts receivable consist primarily of trade receivables from oil and gas
sales and amounts due from other working interest owners which have been billed
for their proportionate share of 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, 2011 and 2010, major customers (i.e. those with
balances greater than 10% of total receivables) were as follows:
As of August 31,
---------------------------
Major Customer or Joint Interest Owner 2011 2010
-------------------------------------- ----------- -------------
Company A 31% 27%
Company B 31% *
Company C 13% *
* less than 10%
F-13
3. Property and Equipment
Capitalized costs of property and equipment at August 31, 2011 and 2010
consisted of the following:
As of August 31,
-----------------------------
2011 2010
-------------- -------------
Oil and gas properties, full cost method:
Unevaluated costs, not subject to
amortization:
Lease acquisition costs $ 9,942,908 $ 848,696
Wells in progress 4,813,749 --
-------------- -------------
14,756,657 848,696
Evaluated costs:
Producing and non-producing 37,750,737 12,992,594
-------------- -------------
Total capitalized costs 52,507,394 13,841,290
Less, accumulated depletion (3,892,537) (1,149,096)
-------------- -------------
Oil and gas properties, net 48,614,857 12,692,194
-------------- -------------
Other property and equipment:
Vehicles
163,904 89,527
Leasehold improvements 35,490 32,329
Office equipment
105,089 36,821
Land 43,750 --
Less, accumulated depreciation (65,026) (7,888)
-------------- -------------
Other property and equipment, net 283,207 150,789
-------------- -------------
Total property and equipment, net $ 48,898,064 $ 12,842,983
============== =============
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, 2011 and 2010, depletion of oil
and gas properties was $2,743,441 and $692,274, respectively, which is
equivalent to $16.62 and $15.52 per barrel of oil equivalent, respectively.
Periodically, the Company reviews its unevaluated properties and its
inventory to determine if the carrying value of either asset exceeds its fair
value. The review for the years ended August 31, 2011 and 2010, indicated that
asset carrying values were less than fair values and no impairment was required.
On a quarterly basis the Company performs the full cost ceiling test. The
quarterly ceiling tests performed during the years ended August 31, 2011 and
2010 did not reveal any impairments.
F-14
During the year ended August 31, 2011, the Company sold oil and gas leases
covering 5,902 gross acres (3,738 net acres) for net cash proceeds of
$8,382,167, after the deduction of selling costs of $248,700. No gains were
recognized on the sales and all of the proceeds were credited to the full cost
pool. The sale reduced the amortization base of the full cost pool by
approximately 7%, which was determined to be less than the "significant change"
threshold required to recognize a gain on the sale.
For the years ended August 31, 2011 and 2010, depreciation of other
property and equipment was $57,138 and $7,592, respectively.
4. Interest Expense
The components of interest expense recorded for the years ended August 31,
2011 and 2010, consisted of:
2011 2010
------------ ----------------
Convertible promissory notes $ 589,539 $790,976
at 8%
Related party note payable at 74,047 -
5.25%
Bank credit facility, variable 41,559 30,388
rate
Accretion of debt discount 2,664,138 1,333,590
(see Note 7)
Amortization of debt issuance 1,587,799 453,656
costs
Less, interest capitalized (710,137) (269,761)
------------- --------------
Interest expense, net $4,246,945 $2,338,849
============= ==============
5. Bank Credit Facility
In June 2011, the Company entered into a revolving line of credit facility
with Bank of Choice ("2011 LOC"), which provides for borrowings up to $7
million. The 2011 LOC expires on June 3, 2012. Amounts borrowed under the 2011
LOC are subject to a security interest in the Company's oil and gas assets.
Principal amounts outstanding under the 2011 LOC bear interest, payable monthly,
at the Wall Street Journal Prime Rate plus 2%, subject to a minimum interest
rate of 5.5%. As of August 31, 2011, the Company had available borrowing
capacity of $6,975,000 under the 2011 LOC.
In previous years, the Company maintained a similar revolving line of
credit facility that provided for borrowings up to $1,161,811. In April 2010,
all borrowings under the facility were paid in full.
6. Asset Retirement Obligations
During the years ended August 31, 2011 and 2010, the Company brought 66 net
wells into productive status and will have asset removal obligations once the
wells 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
F-15
incurred during the years ended August 31, 2011 and 2010, the Company used the
following assumptions:
2011 2010
----------- -----------
Inflation rate 4.0% 5.0%
Estimated asset life (years) 24 24
Credit adjusted risk free 11.64% 10.53%
interest rate
In connection with the acquisition of certain oil and gas properties on May
24, 2011 (see Note 9) the Company assumed the future responsibility to plug and
abandon the producing wells and recorded the associated ARO for these
properties, which had a present value of $179,410 at the date of acquisition.
The following table summarizes the changes in asset retirement obligations
associated with our oil and gas properties for the years ended August 31, 2011
and 2010:
2011 2010
------------- -------------
Beginning asset retirement obligation $ 254,648 $ --
Liabilities incurred 351,083 253,114
Liabilities settled -- --
Accretion expense 37,728 1,534
Revisions in previous estimates -- --
------------- -------------
Ending asset retirement obligation $ 643,459 $ 254,648
============= =============
7. Convertible Promissory Notes and Derivative Conversion Liability
During the fiscal year ended August 31, 2011, the Company received gross
proceeds of $18,000,000 from the sale of 180 Units at $100,000 per Unit. Each
Unit consisted of one convertible promissory note ("Note") in the principal
amount of $100,000 and 50,000 Series C warrants (collectively referenced as a
"Unit"). The Notes bore interest at 8% per year, payable quarterly, and had a
stated maturity date of December 31, 2012. Each Series C warrant entitles the
holder to purchase one share of common stock at a price of $6.00 per share and
expires on December 31, 2014. Through August 31, 2011, all of the Notes had been
converted into shares of the Company's common stock.
The Notes were considered hybrid debt instruments containing a detachable
warrant and a conversion feature under which the proceeds of the offering were
allocated to the detachable warrants and the conversion feature based on their
fair values. The Series C warrants were determined to be a component of equity,
and the fair value of the warrants was recorded as additional paid-in capital.
Since the warrants were recorded as a component of equity, the fair value of
$1,760,048 was estimated at issuance and not re-measured in subsequent periods.
The Notes contained a conversion feature, at an initial conversion price of
$1.60 that was subject to adjustment under certain circumstances, which allowed
the Note holders to convert the principal balance into a maximum of 11,250,000
common shares, plus conversion of accrued and unpaid interest into common
F-16
shares, also at $1.60 per share. The conversion feature was determined to be an
embedded derivative requiring the conversion option to be separated from the
host contract and measured at its fair value. At issuance, the estimated fair
value of the conversion feature was $3,455,809 and was recorded as derivative
conversion liability. The conversion option was re-measured and recorded at fair
value each subsequent reporting period, with changes in the fair value reflected
in other income (expense) in the statements of operations. Allocation of value
to the components created a debt discount of $5,215,857, which was accreted over
the life of the Notes, subject to early Note conversions, using the effective
interest method. The effective interest rate on the Notes was 19%.
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 was being amortized over the expected term of the
Notes, with accelerated amortization recognition on early Note conversions. For
the years ended August 31, 2011 and 2010, the Company recorded amortization
expense for debt issuance costs of $1,587,799 and $453,656, respectively.
At the time the Notes were converted, the estimated fair value of the
derivative conversion liability attributable to the converted notes totaled
$19,554,346, which was reclassified from derivative conversion liability to
additional paid-in capital. Similarly, the unamortized debt discount
attributable to the converted notes totaled $3,120,293. The unamortized debt
discount of $2,067,376 applicable to the conversion option was charged to
accretion of debt discount and the unamortized debt discount of $1,052,917
applicable to the warrants was reclassified from debt discount to additional
paid-in capital. The Company recorded accretion expense for debt discount of
$2,664,138 and $1,333,590 for the years ended August 31, 2011 and 2010,
respectively.
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.
F-17
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.
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.
A substantial portion of the Company's financial instruments consisted of
cash and equivalents, accounts receivable, accounts payable, and accrued
liabilities. Due to the short original maturities and high liquidity of cash and
equivalents, accounts receivable, accounts payable, and accrued liabilities,
carrying amounts approximated fair values.
As permitted under fair value accounting guidance, the outstanding
principal balance of the Company's Notes were not restated to fair value in the
Company's financial statements for each reporting period that the Notes were
outstanding. Due to the short term to maturity and the Company's option to
prepay the debt at any time after January 1, 2011, it was estimated that the
fair value of the Notes approximated face value. The Notes contained an embedded
conversion option which was required to be separated and reported as a
derivative conversion liability at fair value. As a result of the conversion of
all Notes into shares of the Company's common stock, the derivative conversion
liability at the time of conversion was reclassified to additional paid-in
capital.
The Company utilized the Monte Carlo Simulation ("MCS") model to value the
derivative conversion liability. Inputs to this valuation technique include the
Company's quoted stock price and published interest rates and credit spreads.
All of the significant inputs utilized were observable, either directly or
indirectly; therefore, the Company's derivative conversion liability was
included within the Level 2 fair value hierarchy.
The following table presents, for each hierarchy level, our assets and
liabilities, including both current and non-current portions, measured at fair
value on a recurring basis as of August 31, 2011 and 2010.
F-18
As of August 31, 2011 Total Level 1 Level 2 Level 3
----------------------- ------------ ------------ ------------- -----------
Derivative Conversion
Liability $ - $ - $ - $ -
As of August 31, 2010 Total Level 1 Level 2 Level 3
----------------------- ------------ ------------ ------------- -----------
Derivative Conversion
Liability $ 9,325,117 $ - $ 9,325,117 $ -
The Company also measures all nonfinancial assets and liabilities that are
not recognized or disclosed on a recurring basis. As discussed in Note 6, asset
retirement obligations and costs totaling $351,083 and $253,114 have been
accounted for as long-term liabilities and included in the oil and gas
properties, full cost pool at August 31, 2011 and 2010, respectively. The Level
3 inputs used to measure the estimated fair value of the obligations include
assumptions and judgments about the ultimate settlement amounts, inflation
factors, credit adjusted discount rates, timing of settlement, and changes in
regulations. Changes in estimates are reflected in the obligations as they
occur.
9. Related Party Transactions and Commitments
Two of the Company's executive officers control three entities that have
entered into agreements to provide various goods, services, and facilities to
the Company. The entities are Petroleum Management, LLC ("PM"), Petroleum
Exploration and Management, LLC ("PEM"), and HS Land & Cattle, LLC ("HSLC").
Acquisition of Oil and Gas Assets from PEM: In two separate transactions,
the Company purchased oil and gas assets from PEM.
On May 24, 2011, the Company acquired operating (working interest) oil and
gas assets owned by PEM, including interest in 88 gross oil and gas wells
(approximately 40 net wells) and mineral leases covering approximately 6,968
gross acres. All of the producing properties acquired from PEM are located in
the Wattenberg Field of the D-J Basin. Some of the undeveloped leases are
located in Yuma County, Colorado.
The purchase price consisted of a cash payment of $10,000,000, the issuance
of 1,381,818 restricted shares of common stock, and a promissory note in the
principal amount of $5,200,000. The transaction is subject to customary
post-closing adjustments for events occurring between January 1, 2011 and May
24, 2011. The promissory note bears interest at an annual rate of 5.25%, is due
on January 2, 2012, and is secured by the properties purchased by the Company.
No liabilities of PEM were assumed in the transaction. Prior to consummating the
transaction, the Company's acquisition committee, consisting of disinterested
directors, reviewed and approved the transaction, and the Company shareholders,
not including Mr. Holloway and Mr. Scaff, approved the transaction.
For accounting purposes, the value of the transaction was determined to be
$19,358,392, which includes the impact of post-closing adjustments. The
F-19
accounting value, which is subject to further post-closing adjustments, if any,
includes an updated valuation of 1,381,818 shares of common stock to $4,698,181
based upon the closing price of the Company's common stock on May 24, 2011, and
reflects net cash receipts of $539,799 for transactions that occurred between
January 1 and May 24, 2011. The entire purchase price was allocated to oil and
gas properties. No gain or loss was recorded on the transaction. The Company
incurred additional general and administrative costs of approximately $150,000
related to the transaction, all of which were charged to operating expenses
during the year ended August 31, 2011.
The results of operations from the assets acquired from PEM have been
included in the financial statements since the date of acquisition. Revenue and
operating income generated from the assets acquired from May 24, 2011 to August
31, 2011 were $615,635 and $455,242, respectively.
The following unaudited pro forma financial information presents the
combined results of the Company and the properties acquired from PEM as though
the acquisition had been consummated as of September 1, 2009, the beginning of
the Company's fiscal year, for the two periods indicated below:
2011 2010
------------- ------------
Operating revenues $ 12,592,535 $ 3,981,590
Net loss $ (10,476,234) $ (11,360,440)
Basic and Diluted loss per $ (0.39) $ (0.84)
share
The pro forma information does not necessarily reflect the actual results
of operations had the acquisition been consummated at the beginning of the
period indicated nor is it necessarily indicative of future operating results.
The pro forma information does not give effect to any potential revenue
enhancements or operating efficiencies that could result from the acquisition.
On October 1, 2010, the Company acquired certain mineral assets located in
the Wattenberg field, part of the D-J Basin, from PM and PEM for $1,017,435 in
cash. The oil and gas properties consist of a 100% working interest (80% net
revenue interest) in 8 oil and gas wells, as well as 15 drill sites and
miscellaneous equipment.
Other Related Party Transactions: The Company leases office space and an
equipment yard from HSLC in Platteville, Colorado for $10,000 per month. The
twelve month lease arrangement with HSLC commenced July 1, 2010 and was renewed
on July 1, 2011, for another year. Under these leases, the Company paid HSLC a
total of $120,000 and $20,000 for the years ended August 31, 2011 and 2010,
respectively.
From June 2008 through June 2010, the Company received certain services
under 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 $200,000 under this
F-20
agreement during the year ended August 31, 2010. Effective June 30, 2010, the
Company terminated the agreement.
In addition to the transactions described above, the Company undertook
various activities with PM and PEM that are related to the development and
operation of oil and gas properties. The Company occasionally purchases services
and certain oil and gas equipment, such as tubular goods and surface equipment,
from PM. The Company reimburses PM for the original cost of the services and
equipment. Prior to the asset acquisition transaction that closed on May 24,
2011, PEM was a joint working interest owner of certain wells operated by the
Company. PEM was charged for its pro-rata share of costs and expenses incurred
on its behalf by the Company, and similarly PEM was credited for its pro-rata
share of revenues collected on its behalf. The following table summarizes the
transactions with PM and PEM during the years ended August 31, 2011 and 2010:
Years Ended August 31,
-----------------------------
2011 2010
-------------- -------------
Purchase of equipment from PM $ 2,290 $ 1,070,495
Payments to PM for equipment (540,988) (531,797)
-------------- -------------
Balance due to PM for equipment $ - $ 538,698
============== =============
Joint interest costs billed to PEM $ 396,469 $ 1,629,895
Amounts collected from PEM (1,264,060) (762,060)
-------------- -------------
Joint interest billing due from $ - $ 867,835
PEM
============== =============
Revenues collected on behalf of
PEM $ 794,726 $ 167,499
Payments to PEM (810,697) (151,528)
-------------- -------------
Balance due to PEM for revenues $ - $ 15,971
============== =============
During the year ended August 31, 2011, the Company acquired oil and gas
leases from George Seward, a member of the Company's board of directors. In
total, lease interests covering 22,066 gross (19,717 net) undeveloped acres,
located in eastern Colorado and western Nebraska, were acquired in exchange for
353,817 shares of the Company's common stock. Based on the market price of the
Company's common stock on the transaction dates, these acquisitions were valued
at $788,676.
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.
F-21
Issued and Outstanding: The Company's total issued and outstanding common
shares were 36,098,212 and 13,510,981 at August 31, 2011 and 2010, respectively.
Issuance of shares of the Common stock during the two years ended August 31,
2011 is as follows:
i. Common stock issued for conversions of Notes: During the two years
ended August 31, 2011, holders of convertible promissory Notes with a
face value of $18,000,000 converted the Notes into 11,250,000 shares
of common stock at the contractual conversion price of $1.60 per
share.
ii. Sale of common stock: In January 2011, the Company completed the sale
of 9,000,000 shares of common stock to private investors. The shares
were sold at a price of $2.00 per share. Net proceeds to the Company
from the sale of the shares were $16,690,721 after deductions for the
placement agents' commissions and expenses of the offering.
iii. Common stock issued for mineral leases: The Company issued 1,849,838
and 5,966 common shares in exchange for mineral leases during the
years ended August 31, 2011 and 2010, respectively. The aggregate
value for these transactions was $5,240,307 and $16,645 during the
years ended August 31, 2011 and 2010, respectively, which was
determined using the market price of the Company's common stock.
iv. Common stock issued in connection with PEM acquisition: In May 2011,
the Company acquired certain assets from PEM (see Note 9). As part of
the consideration, the Company issued 1,381,818 shares of restricted
common stock valued at $4,698,181, based on the market price of the
Company's common stock.
v. Common stock issued for warrants exercised: During the year ended
August 31, 2011, the Company issued common shares pursuant to the
exercise of Series D warrants. As the Series D warrants contain a
cashless exercise provision, warrant holders exercised 355,399
warrants in exchange for 226,199 shares of common stock, and the
Company received no cash proceeds in the transaction.
vi. Common stock issued for services: During the year ended August 31,
2011, the Company issued a total of 150,000 shares of common stock,
with a fair market value of $430,000, to individuals as compensation
for services provided to the Company. During the year ended August 31,
2010, the Company issued 197,988 shares of common stock, with a fair
market value of $544,575 as partial compensation to its directors.
During the year ended August 31, 2010, the Company issued Series C and
Series D warrants in connections with the sale of 180 convertible promissory
note units at $100,000 per unit. (See Note 7) 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. Each Series D warrant entitles
the holder to purchase one share of common stock at a price of $1.60 per share
F-22
and warrants were issued to purchase an aggregate of 1,125,000 common shares.
The Series D warrants contain a cashless exercise provision and expire on
December 31, 2014.
In connection with various transactions during the years ended August 31,
2009 and 2008, the Company issued Series A warrants to purchase 4,098,000 shares
of common stock and issued Series B warrants to purchase 1,000,000 shares of
common stock and issued sales agent warrants to purchase 63,466 shares of common
stock. The Series A warrants entitle the holder to purchase one share of common
stock at a price of $6.00 per share, and they expire on December 31, 2012, or
earlier under certain conditions. The Series B warrants entitle the holder to
purchase one share of common stock at a price of $10.00 per share, and they
expire on December 31, 2012, or earlier under certain conditions. The sales
agent warrants entitle the holder to purchase one share of common stock at a
price of $1.80 per share, and they expire on December 31, 2012.
The following table summarizes activity for common stock warrants for each
of the two years ended August 31, 2011:
Number of Weighted average
warrants exercise price
--------- ----------------
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
Granted --
Exercised 355,399 $1.60
-------------
Outstanding, August 31, 2011 14,931,067 $6.02
=============
The following table summarizes information about the Company's issued and
outstanding common stock warrants as of August 31, 2011:
Exercise
Remaining Price times
Exercise Number of Contractual Number of
Price Description Shares Life (in years) Shares
----- ----------- ------ --------------- ------
$1.60 Series D 769,601 3.3 $ 1,231,362
$1.80 Sales Agent Warrants 63,466 1.3 114,239
$6.00 Series A 4,098,000 1.3 24,588,000
$6.00 Series C 9,000,000 3.3 54,000,000
$10.00 Series B 1,000,000 1.3 10,000,000
------------ --------------
14,931,067 2.6 $ 89,933,601
============ ==============
11. Stock Based Compensation
During the year ended August 31, 2011, the Company's shareholders approved
the 2011 Incentive Stock Option Plan and the 2011 Non-Qualified Stock Option
F-23
Plan to replace a previous plan. The shareholders authorized the issuance of
options to purchase up to 2,000,000 shares of common stock under each plan.
The Company accounts for stock option activities as provided by ASC "Stock
Compensation," which requires the Company to expense as compensation the value
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 $627,486 and
$581,233 for the years ended August 31, 2011 and 2010, respectively. The
components of the expense for the year ended August 31, 2011 include stock
grants of $430,000 to an employee and a consultant, and option-based
compensation of $197,486. 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.
The weighted-average grant date fair value per share for stock options
granted during the years ended August 31, 2011 and 2010 were $2.33 and $1.30,
respectively. The following table summarizes the assumptions used in the
Black-Scholes-Merton option pricing model to calculate the grant date fair
values for stock options granted during the years ended August 31, 2011 and
2010:
2011 2010
--------------- -------------
Volatility 53.18 - 69.43% 53.18%
Expected option term
(years) 6.0 - 6.5 5.875
Risk-free interest rate 1.48 - 2.63% 2.08%
Expected dividend yield 0% 0%
The expected volatility is estimated using the calculated volatility of
public companies with characteristics similar to the Company (industry, company
size, and life cycle) at the grant date, as the trading history for the
Company's common stock is less than the expected term of stock options granted.
The expected term of options granted is estimated in accordance with the
simplified method prescribed in SEC Staff Accounting Bulletin ("SAB") No. 107
and SAB No. 110. The risk-free interest rate is determined at the time stock
options are granted using rates for U.S Treasury notes with maturities
corresponding to the expected term of stock options.
The estimated unrecognized compensation cost from unvested stock options as
of August 31, 2011, was approximately $1,068,100, substantially all of which
will be recognized during the next four years.
F-24
The following table summarizes activity for stock options for years ended
August 31, 2011 and 2010:
2011 2010
---------------------- -------------------------
Weighted Weighted
Number Average Average
of Exercise Number of Exercise
Options Price Options Price
------- -------- --------- ----------
Outstanding at beginning
of year 4,220,000 $ 5.36 4,100,000 $ 5.50
Granted 425,000 $ 3.79 120,000 $ 2.50
Exercised - $ - - $ -
Cancelled - $ - - $ -
--------- -------- --------- --------
Outstanding at end of
year 4,645,000 $ 5.21 4,220,000 $ 5.36
========= ======== ========= ========
Exercisable at August 31, 4,089,000 $ 5.44 4,010,000 $ 5.49
========= ======== ========= ========
The following table summarizes information about outstanding stock options
as of August 31, 2011:
Outstanding Vested
Options Options
---------- --------
Number of shares
4,645,000 4,089,000
Weighted average remaining
contractual life 2.8 years 1.9 years
Weighted average exercise price $ 5.21 $ $5.44
Aggregate intrinsic value $4,339,700 $4,262,790
The following table summarizes changes in the unvested options for the
years ended August 31, 2011 and 2010:
Weighted
Average
Number of Grant Date
Options Fair Value
------------ -----------
Non-vested September 1, 2010 210,000 $ 1.53
Granted 425,000 $ 2.33
Vested (79,000) $ 1.38
Cancelled - $ -
------- ---------
Non-vested, August 31, 2011 556,000 $ 2.16
======= =========
12. Commitments and Contingencies
In connection with a 2008 private offering, the Company issued placement
agent warrants which entitle the holder to purchase units consisting of common
stock and warrants (Series A and B) at a price of $3.60 per unit. 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.
F-25
13. Income Taxes
The components of the provision for income tax expense (benefit) consist
of the following:
Years Ended August 31,
----------------------------------
2011 2010
----------------- --------------
Current income taxes $ -- $ --
Deferred income taxes (4,620,000) (3,994,000)
Valuation allowance 4,620,000 3,994,000
----------- -----------
Total tax benefit $ -- $ --
=========== ===========
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,
---------------------------------
2011 2010
-------------- ----------------
Federal income taxes $(3,944,000) $(3,670,000)
State income taxes (354,000) (324,000)
Other (322,000) --
Change in valuation allowance 4,620,000 3,994,000
----------- -----------
$ -- $ --
=========== ===========
The Company reported a change in valuation allowance of $4,620,000 for the
year ended August 31, 2011, which differs from the amount obtained from
calculating the difference between the balance sheet amounts from $7,147,000 at
August 31, 2010 to $4,911,000 at August 31, 2011. The reconciling item is the
tax effect of $6,856,000 representing 37% of amounts reclassified directly from
liabilities to equity as a result of the early conversion of the convertible
promissory notes and the related derivative conversion liability into shares of
the Company's common stock.
F-26
The tax effects of temporary differences that give rise to significant
components of the deferred tax assets and deferred tax liabilities at August 31,
2011 and 2010, are presented below:
As of August 31,
-----------------------------
2011 2010
------------- -------------
Deferred tax assets:
Net operating loss carry-forward $4,176,000 $3,838,000
Stock-based compensation 3,913,000 3,834,000
Convertible promissory notes -- 1,876,000
Other 69,000 10,000
Less: valuation allowance (4,911,000) (7,147,000)
------------ -----------
Subtotal 3,247,000 2,411,000
------------ -----------
Deferred tax liabilities:
Basis of oil and gas properties (3,247,000) (2,411,000)
------------ -----------
Subtotal
(3,247,000) (2,411,000)
------------ -----------
Total $ -- $ --
============ ===========
At August 31, 2011, the Company has a net operating loss carry-forward for
federal and state tax purposes of approximately $11,300,000 that could be
utilized to offset taxable income of future years. Substantially all of the
carry-forward will expire between 2029 and 2031.
The realization of the deferred tax assets related to the net operating
loss carry-forwards is dependent upon the Company's ability to generate future
taxable income. Given the Company's history of book and tax operating losses
since inception, and the expectation of future tax deductions associated with
planned drilling activities, 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 Code. Accordingly, the Company has established a full valuation allowance
against the deferred tax assets.
F-27
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, 2011 and 2010:
Years Ended August 31,
---------------------------
2011 2010
----------- ----------
Supplemental cash flow information:
Interest paid $ 788,211 $617,017
Income taxes paid -- --
Non-cash investing and financing activities:
Conversion of promissory notes into common
stock $ 15,908,000 $ 2,092,000
Mineral leases acquired for common stock 5,240,307 16,645
Assets acquired for note payable, related
party 5,200,000 --
Accrued capital expenditures 4,967,369 3,446,439
Assets acquired for common stock, related
party 4,698,181 --
Asset retirement costs and obligations 351,083 253,114
Placement agent commission in the form of
warrants -- 692,478
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, 2011 and
2010, were:
Years Ended August 31,
-----------------------------
2011 2010
-------------- --------------
Acquisition of Property:
Unproved $ 9,198,417 $ 1,625,696
Proved 21,251,032 --
Exploration costs -- --
Development costs 15,347,982 10,360,516
----------- -----------
Total Costs Incurred $45,797,431 $11,986,212
=========== ===========
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, 2011.
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.
F-28
Period Incurred
------------------------------ Total at
2011 2010 2009 August 31, 2011
----- ------ ------ ---------------
Unproved leasehold
acquisition costs $9,003,134 $705,391 $234,383 $9,942,908
Unevaluated development
costs - - - -
---------- -------- -------- ----------
Total $9,003,134 $705,391 $234,383 $9,942,908
========== ======== ======== ==========
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.
Proved oil and natural gas reserve information at August 31, 2011 and
2010, 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 prepared as of August 31, 2011 and 2010 were
prepared in accordance with "Modernization of Oil and Gas Reporting" published
by the SEC. The recent 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, 2011 and 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 recent guidance broadened the types of
technologies that may be used to establish reserve estimates.
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, 2011 and 2010:
Oil (Bbl) Gas (Mcf)
-------------- --------------
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)
--------- -----------
F-29
Balance, August 31, 2010 676,685 4,481,051
Revision of previous estimates 323,704 611,517
Purchase of reserves in place 967,302 8,466,714
Extensions, discoveries, and other
additions 191,931 1,152,708
Sale of reserves in place -- --
Production (89,917) (450,831)
--------- ----------
Balance, August 31, 2011 2,069,705 14,261,158
========= ==========
Proved developed and undeveloped reserves:
Developed at August 31, 2010 395,453 2,349,027
Undeveloped at August 31, 2010 281,232 2,132,024
--------- ----------
676,685 4,481,051
========= ==========
Developed at August 31, 2011 783,821 5,578,067
Undeveloped at August 31, 2011 1,285,884 8,683,091
--------- ----------
2,069,705 14,261,158
========= ==========
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 during the years ended August
31, 2011 and 2010. 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.
F-30
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,
-------------------------------
2011 2010
-------------- -----------
Future cash inflows $235,238,880 $ 64,670,902
Future production costs (41,277,367) (16,380,316)
Future development costs (40,404,280) (15,836,965)
Future income tax expense (30,737,928) (6,926,890)
------------ ------------
Future net cash flows 122,819,305 25,526,731
10% annual discount for estimated timing of
cash flows (65,268,891) (12,504,334)
------------ ------------
Standardized measure of discounted future
net cash flows $ 57,550,414 $ 13,022,397
============ ============
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
years ended August 31, 2011 and 2010:
Natural Gas Oil
(Mcf) (Bbl)
----------- -----
August 31, 2010 (Average) $4.76 $69.20
August 31, 2011 (Average) $5.07 $84.90
F-31
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,
-----------------------------
2011 2010
-------------- ------------
Standardized measure, beginning of year $ 13,022,397 $ 232,957
Sale and transfers, net of production costs (8,337,354) (1,834,924)
Net changes in prices and production costs 15,483,714 131,153
Extensions, discoveries, and improved
recovery 13,692,899 17,785,154
Changes in estimated future development
costs (20,471,127) --
Development costs incurred during the period 16,251,935 --
Revision of quantity estimates 15,424,097 212,851
Accretion of discount 3,245,362 30,535
Net change in income taxes (12,011,643) (3,535,329)
Purchase of reserves in place 21,250,134 --
Sale of reserves in place -- --
------------ -----------
Standardized measure, end of year $ 57,550,414 $13,022,397
============ ===========
16. Subsequent Events
On September 30, 2011, the Company filed a registration statement under
Form S-3 that provides for the potential sale of securities for proceeds up to
$75,000,000. The registration statement was declared effective on October 7,
2011. At such time as the Company determines that it is appropriate to offer
securities under the terms of the registration statement, a supplement will be
filed containing additional details about the offering, including the nature of
the securities, the number of securities, and the offering price.
F-32
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 11th day of November, 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, Principal Executive November 11, 2011
---------------------- Officer and Director
Ed Holloway
/s/ Frank L. Jennings Principal Financial and November 11, 2011
---------------------- Accounting Officer
Frank L. Jennings
/s/ William E. Scaff, Jr. Director November 11, 2011
------------------------
William E. Scaff, Jr.
/s/ Rick Wilber Director November 11, 2011
----------------------
Rick Wilber
/s/ Raymond E. McElhaney Director November 11, 2011
------------------------
Raymond E. McElhaney
/s/ Bill M. Conrad Director November 11, 2011
----------------------
Bill M. Conrad
/s/ R.W. Noffsinger, III Director November 11, 2011
------------------------
R. W. Noffsinger, III
/s/ George Seward Director November 11, 2011
----------------------
George Seward
SYNERGY RESOURCES CORPORATION
FORM 10-K
EXHIBITS