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EX-5 - EXHIBIT 5 - SYNERGY RESOURCES CORPs1amd2ex59-11.txt
EX-23 - EXHIBIT 23.2 - SYNERGY RESOURCES CORPs1amd2ex2329-11.txt
EX-23 - EXHIBIT 23.3 - SYNERGY RESOURCES CORPs1amd2ex2339-11.txt
EX-23 - EXHIBIT 23.1 - SYNERGY RESOURCES CORPs1amd2ex2319-11.txt


As filed with the Securities and Exchange Commission on September __, 2011.


                                                Commission File No. 333-146561

                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM S-1

                                 Amendment No. 2


                          Registration Statement Under
                           THE SECURITIES ACT OF 1933

                          SYNERGY RESOURCES CORPORATION
               (Exact name of registrant as specified in charter)

         Colorado                        1311                   20-2835920
----------------------------   -----------------------   -----------------------
(State or other jurisdiction  (Primary Standard Classi-  (IRS Employer
 of incorporation)             fication Code Number)       I.D. Number)

                                20203 Highway 60
                              Platteville, CO 80651
                                 (970) 737-1073
               -------------------------------------------------
         (Address and telephone number of principal executive offices)

                                20203 Highway 60
                              Platteville, CO 80651
                -------------------------------------------------
(Address of principal place of business or intended principal place of business)

                              William E. Scaff, Jr.
                                20203 Highway 60
                              Platteville, CO 80651
                                 (970) 737-1073
                            ------------------------
           (Name, address and telephone number of agent for service)

         Copies of all communications, including all communications sent
                  to the agent for service, should be sent to:

                              William T. Hart, Esq.
                               Hart & Trinen, LLP
                             1624 Washington Street
                             Denver, Colorado 80203
                                  303-839-0061

 As soon as practicable after the effective date of this Registration Statement
 ------------------------------------------------------------------------------
        APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC:

If any of the  securities  being  registered on this Form are to be offered on a
delayed or continuous  basis  pursuant to Rule 415 under the  Securities  Act of
1933 check the following box: [x]



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