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EX-32 - EXHIBIT 32 - SRC Energy Inc.aug10kex32nov-11.txt
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EX-99 - EXHIBIT 99 - SRC Energy Inc.aug10kexh99nov-11.txt

                                    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
                     --------------------------------------
             (Exact name of registrant as specified in its charter)

          COLORADO                                    20-2835920
 ------------------------------               --------------------------
(State or other jurisdiction of                 (I.R.S.Employer
 incorporation or organization)                 Identification No.)

        20203 Highway 60,  Platteville, CO                       80651
     ----------------------------------------             ------------------
     (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
-----------------------------------    ----------------------------------
-----------------------------------    ----------------------------------

           Securities registered pursuant to Section 12(g) of the Act:

----------------------------------------------------------------------------
                                (Title of class)

----------------------------------------------------------------------------
                                (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., 1
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 2
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. 3
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 4
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 6
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. 7
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 8
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