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EX-32 - EXHIBIT 32 - SRC Energy Inc.mayamend10qexh328-11.txt
EX-31 - EXHIBIT 31 - SRC Energy Inc.mayamend10qexh318-11.txt


                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                   FORM 10-Q/A
(Mark One)

[X]   QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
      ACT OF 1934

                 For the quarterly period ended May 31, 2011

[   ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
      ACT OF 1934

               For the transition period from _____ to _______

                       Commission File Number: 333-146561

                          SYNERGY RESOURCES CORPORATION
             (Exact Name of Registrant as Specified in its Charter)

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

                20203 Highway 60, Platteville, Colorado Code80651
      ---------------------------------------------------------------------
               (Address of Principal Executive Offices) (Zip Code)

      Registrant's telephone number including area code:  (970) 737-1073

                                       N/A
           -----------------------------------------------------------
         Former name, former address, and former fiscal year, if changed
                                since last report

Indicate by check mark whether the registrant (1) filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the past 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes [X] No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
definition of "large accelerated filer", "accelerated filer" and "smaller
reporting company" in Rule 12b-2 of the Exchange Act. Yes [ ] No [ ]

Larger accelerated filer  [ ]        Accelerated filer           [ ]
Non-accelerated filer     [ ]      Smaller reporting company   [X]

Indicate by check mark whether registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
Yes [ ]     No [X]

Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date: 35,568,117 shares outstanding
as of July 8, 2011.

                                       1

SYNERGY RESOURCES CORPORATION Index Page ---- Part I - FINANCIAL INFORMATION Item 1. Financial Statements Balance Sheets as of May 31, 2011 (unaudited) and August 31, 2010 3 Statements of Operations for the three and nine months ended May 31, 2011 and 2010 (unaudited) 4 Statements of Cash Flows for the nine months ended May 31, 2011 and 2010 (unaudited) 5 Notes to Financial Statements (unaudited) 6 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 23 Item 4. Controls and Procedures 34 Part II - OTHER INFORMATION Item 1. Legal Proceedings 34 Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 34 Item 3. Defaults Upon Senior Securities 34 Item 4. Removed and Reserved 34 Item 5. Other Information 35 Item 6. Exhibits 36 SIGNATURES 37 EXPLANATORY NOTE This amendment to Form 10-Q was prepared to include the disclosures required under Part I - Item 4, Controls and Procedures, that were inadvertently omitted from the original filing on July 14, 2011. 2
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. 3
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. 4
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. 5
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 country-regionplaceUnited 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. 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 6
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. 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. 7
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, 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 8
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 country-regionplaceUnited 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% 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 ============= ============= 9
(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 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 10
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 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% 11
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 =============== =============== 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 12
$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 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. 13
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. 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. 14
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. 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 country-regionplaceUS 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 15
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 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 16
the Company. The entities are Petroleum Management, LLC ("PM"), Petroleum Exploration and Management, LLC ("PEM"), and HS Land & Cattle, LLC ("HSLC"). Acquisition of Oil and Gas Assets from PEM: 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 CityplacePlatteville, StateColorado, 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 agreement for the nine months ended May 31, 2010. Effective June 30, 2010, the Company terminated the agreement. 17
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 PlaceNameplaceD-J PlaceTypeBasin, 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 $ - ============= 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: 18
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. 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 =============== ================ 19
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 =========== ========= =========== ========== 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. 20
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 ========== ========== ========== 21
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 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. 22
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operation Introduction The following discussion and analysis was prepared to supplement information contained in the accompanying financial statements and is intended to provide certain details regarding our financial condition as of May 31, 2011, and the results of our operations for the three months and nine months ended May 31, 2011 and 2010. It should be read in conjunction with the unaudited financial statements and notes thereto contained in this report as well as the audited financial statements included in the Form 10-K for the fiscal year ended August 31, 2010. Overview We are an independent oil and gas operator in StateColorado 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 placeStateColorado. 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. We currently have approximately 139,000 gross acres and 123,000 net acres under lease, which include certain lease transactions which occurred subsequent to May 31, 2011. Our growth plans for 2011 and 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 sale of mineral interests for $5.2 million will satisfy most of our capital needs for fiscal year 2011. 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. Recent Developments 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 March 21, 2011, we agreed to issue 1,125,699 shares of restricted common stock for mineral interest comprising 78,805 gross acres (69,274 net acres) in the D-J Basin. 23
On February 17, 2011, we acquired 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 our mineral interest in 3,502 gross acres (2,383 net acres) for cash proceeds of $5,244,517. Effective March 31, 2011, all of the holders of Convertible Promissory Notes not previously converted elected to convert the principal balance into shares of common stock. As of March 31, 2011, the entire original principal balance of $18 million has been converted into 11,250,000 shares of common stock. 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 Credit Facility bear interest, payable monthly, at the Wall Street Journal 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 interest in 18,136 gross acres (15,862 net acres). RESULTS OF OPERATIONS For the three months ended May 31, 2011, compared to the three months ended May 31, 2010 Material changes of certain items in our statements of operations included in our financial statements for the comparative periods are discussed below. 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 years 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 years, 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. 24
Oil and Gas Production and Revenues - For the three months ended May 31, 2011, we recorded total oil and gas revenues of $2,921,910 compared to $607,253 for the three months ended May 31, 2010, as summarized in the following table: 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 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 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. 25
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 expenses $ 668,683 $ 106,503 ============= ============ 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. 26
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. 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 27
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. For the nine months ended May 31, 2011, compared to the nine months ended May 31, 2010 Material changes of certain items in our statements of operations included in our financial statements for the comparative periods are discussed below. 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 years 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 years, 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. Oil and Gas Production and Revenues - For the nine months ended May 31, 2011, we recorded total oil and gas revenues of $6,399,193 compared to $995,764 for the nine months ended May 31, 2010, as summarized in the following table: 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.%. We do not currently engage in any commodity hedging activities, although we may do so in the future. 28
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 expenses $ 1,131,837 $ 161,545 ============= ============ 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 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 29
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 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 30
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 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 closed on a transaction to sell our mineral interest in 3,502 gross acres (2,383 net acres) for cash proceeds of $5,244,517. On March 31, 2011, holders of our 8% convertible promissory notes completed the conversion of $18,000,000 in principal into 11,250,000 shares of common stock at the conversion price of $1.60 per share. 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, and a $5,200,000 promissory note that matures on January 2, 2012. Our sources and (uses) of funds for the nine months ended May 31, 2011 and 2010, are shown below: Nine Months Ended May 31, ------------------------------ 2011 2010 -------------- ------------ Cash provided by (or used in) operations $ 3,824,882 $ (984,550) Mineral property acquisitions (21,163,392) (5,717,527) Mineral property sales 4,995,817 - Cash proceeds from sale of stock or units 16,690,721 16,651,023 Debt principal payments - (1,161,811) -------------- ------------- Net increase in cash $ 4,348,028 $ 8,787,135 ============== ============= Non-cash expenses had a $17,107,509 and $3,982,256 impact on net loss for the nine months ended May 31, 2011 and 2010, respectively. Changes in working capital items caused by the timing of payments and receipts of cash had an impact of $92,656 and $511,664 for the nine months ended May 31, 2011 and 2010, respectively. 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: 31
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. In addition to the transactions described in "Recent Developments", capital expenditures for the nine months ended May 31, 2011, included the acquisition of 8 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 in fiscal 2011 will be to fund our acquisition and drilling program. Our capital expenditure estimate approximates $27 million subject to significant adjustment for drilling success, acquisition opportunities, operating cash flow, and available capital resources. Although our recent sale of securities for gross proceeds of $18 million plus our recent sale of mineral interests for cash proceeds of $5.2 million plus our recent acquisition of mineral interests in exchange for shares of common stock will provide substantially all of the capital resources required to fund our capital expenditure plans, we may seek additional funding to expand our plans or to provide 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. 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 32
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. TREND AND OUTLOOK The factors that will most significantly affect our results of operations include (i) activities on properties that we operate, (ii) the marketability of our production, (iii) our ability to satisfy our substantial capital requirements, (iv) completion of acquisitions of additional properties and reserves, (v) competition from larger companies and (vi) prices for oil and gas. Our revenues will also be significantly impacted by our ability to maintain or increase oil or gas production through exploration and development activities. It is expected that our principal source of cash flow will be from the production and sale of oil and gas reserves which are depleting assets. Cash flow from the sale of oil and gas production depends upon the quantity of production and the price obtained for the production. An increase in prices will permit us to finance our operations to a greater extent with internally generated funds, may allow us to obtain equity financing more easily or on better terms, and lessens the difficulty of obtaining financing. However, price increases heighten the competition for oil and gas prospects, increase the costs of exploration and development, and, because of potential price declines, increase the risks associated with the purchase of producing properties during times that prices are at higher levels. A decline in oil and gas prices (i) will reduce our cash flow which in turn will reduce the funds available for exploring for and replacing oil and gas reserves, (ii) will increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of oil and gas prospects which have reasonable economic terms, (iv) may cause us to permit leases to expire based upon the value of potential oil and gas reserves in relation to the costs of exploration, (v) may result in marginally productive oil and gas wells being abandoned as non-commercial, and (vi) may increase the difficulty of obtaining financing. However, price declines reduce the competition for oil and gas properties and, correspondingly, reduce the prices paid for leases and prospects. Other than the foregoing, we do not know of any trends, events or uncertainties that will have had or are reasonably expected to have a material impact on our sales, revenues or expenses. CRITICAL ACCOUNTING POLICIES There have been no material changes in our critical accounting policies since August 31, 2010, and a detailed discussion of the nature of our accounting practices can be found in the section titled "Critical Accounting Policies" in Part II, Item 7 of our Annual Report on Form 10-K for the year ended August 31, 2010. CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS This report contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as "believes", "expects", "anticipates", "intends", "plans", "estimates", "should", "likely" or similar expressions, indicates a forward-looking statement. 33
The identification in this report of factors that may affect our future performance and the accuracy of forward-looking statements is meant to be illustrative and by no means exhaustive. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty. Factors that could cause our actual results to differ materially from those expressed or implied by forward-looking statements include, but are not limited to: o The success of our exploration and development efforts; o The price of oil and gas; o The worldwide economic situation; o Any change in interest rates or inflation; o The willingness and ability of third parties to honor their contractual commitments; o Our ability to raise additional capital, as it may be affected by current conditions in the stock market and competition in the oil and gas industry for risk capital; o Our capital costs, as they may be affected by delays or cost overruns; o Our costs of production; o Environmental and other regulations, as the same presently exist or may later be amended; o Our ability to identify, finance and integrate any future acquisitions; and o The volatility of our stock price. Item 4. Controls and Procedures. Evaluation of Disclosure Controls and Procedures An evaluation was carried out under the supervision and with the participation of our management, including our Principal Financial Officer and Principal Executive Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report on Form 10-Q. Disclosure controls and procedures are procedures designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, such as this Form 10-Q, is recorded, processed, summarized and reported, within the time period specified in the Securities and Exchange Commission's rules and forms, and that such information is accumulated and is communicated to our management, including our Principal Executive Officer and Principal Financial Officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure. Based on that evaluation, our management concluded that, as of May 31, 2011, our disclosure controls and procedures were effective. Changes in Internal Control Over Financial Reporting There were no changes in our internal control over financial reporting during the quarter ended May 31, 2011, that materially affected or are reasonably likely to materially affect our internal control over financial reporting. PART II Item 1. Legal Proceedings. None. Item 2. Unregistered Sales of Equity Securities and Use of Proceeds. 34
1. During the three months ended May 31, 2011, holders of convertible promissory notes in the principal amount of $6,096,325, plus accrued interest of $55,882, elected to convert their notes into 3,845,132 shares of the Company's common stock. The Company relied upon the exemption provided by Section 3(a)(9) of the Securities Act of 1933 in connection with the issuance of these shares. 2. During the three months ended May 31, 2011, the Company agreed to issue an aggregate of 1,125,699 shares of restricted common stock as consideration for several mineral interests. These interests, which include an aggregate of 78,815 gross acres (69,274 net acres), are located in the D-J Basin and were acquired through leases with several private parties. The Company relied upon the exemption provided by Section 4(2) of the Securities Act of 1933 in connection with the issuance of these shares. 3. On May 24, 2011, the Company issued 1,381,818 shares of common stock pursuant to the purchase of certain oil and gas properties from Petroleum Exploration and Management, LLC. These shares were valued at $3,800,000 in accordance with the terms of the purchase and sale agreement and represent partial consideration for the transaction The Company relied upon the exemption provided by Section 4(2) of the Securities Act of 1933 in connection with the issuance of these shares. Item 3. Default Upon Senior Securities. None. Item 4. (Removed and Reserved) Item 5. Other Information On May 23, 2011, the Company held a Special Meeting of Shareholders in CityplacePlatteville, StateColorado. Of the 33,495,519 shares of common stock issued and outstanding as of the record date, 23,316,861 shares of common stock (approximately 70%) were present or represented by proxy at the Special Meeting. The Company's shareholders approved a proposal to acquire oil and gas properties from Petroleum Exploration and Management LLC ("PEM"), the adoption of the Company's 2011 Incentive Stock Option Plan, the adoption of the Company's 2011 Non-Qualified Stock Option Plan, the adoption of the Company's 2011 Stock Bonus Plan and an amendment of the Company's Articles of Incorporation. The results of voting on the aforementioned matters were as follows: 1. Approval of the acquisition of oil and gas properties from Petroleum Exploration and Management, LLC: FOR AGAINST ABSTAIN ------------------ ------------------- ------------------ 18,730,523 154,947 4,315,260 2. Approval of the adoption of the Company's 2011 Incentive Stock Option Plan, which provides that up to 2,000,000 shares of common stock may be issued upon the exercise of options granted pursuant to the Incentive Stock Option Plan: FOR AGAINST ABSTAIN ------------------ ------------------- ------------------ 18,020,015 4,070,711 1,110,004 3. Approval of the adoption of the Company's 2011 Non-Qualified Stock Option Plan, which provides that up to 2,000,000 shares of common stock may be issued upon the exercise of options granted pursuant to the Non-Qualified Stock Option Plan: 35
FOR AGAINST ABSTAIN ------------------ ------------------- ------------------ 16,902,243 5,197,404 1,101,083 4. Approval of the adoption of the Company's 2011 Stock Bonus Plan, which provides that up to 2,000,000 shares of common stock may be issued to persons granted Stock Bonuses pursuant to the Stock Bonus Plan: FOR AGAINST ABSTAIN ------------------ ------------------- ------------------ 16,615,144 5,405,140 1,180,446 5. Approval of the amendment of the Company's Articles of Incorporation to allow shareholders owning less than all of the Company's common stock to take action without meeting consistent with Colorado Revised Statute 7-107-104. FOR AGAINST ABSTAIN ------------------ ------------------- ------------------ 21,915,238 684,122 601,370 36
Item 6. Exhibits a. Exhibits 31.1 Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 for Ed Holloway. 31.2 Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 for Frank L. Jennings. 32 Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 for Ed Holloway and Frank L. Jennings. 37
SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. SYNERGY RESOURCES CORPORATION Date: August 11, 2011 By: /s/ Ed Holloway ----------------------------------- Ed Holloway, President and Principal Executive Officer Date: August 11, 2011 By: /s/ Frank L. Jennings ----------------------------------- Frank L. Jennings, Principal Financial and Accounting Officer 38