EX-32 3 form10qfeb2011.txt EXHIBIT 32 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended February 28, 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 80651 ------------------------------------------ (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: 34,086,548 shares outstanding as of April 6, 2011. SYNERGY RESOURCES CORPORATION Index Page ---- Part I - FINANCIAL INFORMATION Item 1. Financial Statements Balance Sheets as of February 28, 2011 (unaudited) and August 31, 2010 3 Statements of Operations for the three and six months ended February 28, 2011 and 2010 (unaudited) 4 Statements of Cash Flows for the six months ended February 28, 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 22 Item 4. Controls and Procedures 33 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. Submission of Matters to a Vote of Security Holders 34 Item 5. Other Information 34 Item 6. Exhibits 34 SIGNATURES 35 SYNERGY RESOURCES CORPORATION BALANCE SHEETS As of As of February 28, 2011 August 31, 2010 (unaudited) ASSETS Current assets: Cash and cash equivalents $ 21,161,538 $ 6,748,637 Accounts receivable: Oil and gas sales 1,847,132 377,675 Joint interest billing 2,046,643 1,930,810 Related party receivable 68,279 867,835 Inventory 506,845 387,864 Other current assets 81,401 12,310 ------------- ----------- Total current assets 25,711,838 10,325,131 ------------- ----------- Property and equipment: Oil and gas properties, full cost method, net 16,500,170 12,692,194 Other property and equipment, net 217,533 150,789 ------------- ----------- Property and equipment, net 16,717,703 12,842,983 ------------- ----------- Debt issuance costs, net of amortization 422,528 1,587,799 Other assets 85,000 86,000 ------------- ----------- Total assets $ 42,937,069 $ 24,841,913 ============= ============ LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT) Current liabilities: Accounts payable: Trade $ 4,961,604 $ 3,015,562 Related party payable - 554,669 Accrued expenses 856,281 517,921 ------------- ----------- Total current liabilities 5,817,885 4,088,152 ------------- ----------- Asset retirement obligations 346,204 254,648 Convertible promissory notes, net of debt discount 4,946,032 12,190,945 Derivative conversion liability 10,246,260 9,325,117 ------------- ----------- Total liabilities 21,356,381 25,858,862 ------------- ----------- Commitments and contingencies (See Notes 8 and 9) 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: 28,763,441 and 13,510,981 shares issued and outstanding as of February 28, 2011, and August 31, 2010, respectively 28,764 13,511 Additional paid-in capital 57,789,711 22,308,963 Accumulated (deficit) (36,237,787) (23,339,423) ------------- ----------- Total shareholders' equity (deficit) 21,580,688 (1,016,949) ------------- ----------- Total liabilities and shareholders' equity (deficit) $ 42,937,069 $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 Six Months Ended February 28, February 28, 2011 2010 2011 2010 ---- ---- ---- ---- Revenues: Oil and gas revenues $ 2,033,687 $ 335,725 $3,477,282 $ 388,511 Service revenues 19,847 - 27,289 - ----------- ---------- ---------- ---------- Total revenues 2,053,534 335,725 3,504,571 388,511 ----------- ---------- ---------- ---------- Expenses: Lease operating expenses 260,480 47,152 463,155 55,042 Depreciation, depletion, and amortization 647,205 64,733 1,232,186 92,939 General and administrative 459,436 354,278 1,111,979 635,410 ----------- ---------- ---------- ---------- Total expenses 1,367,121 466,163 2,807,320 783,391 ----------- ---------- ---------- ---------- Operating income (loss) 686,413 (130,438) 697,251 (394,880) ----------- ---------- ---------- ---------- Other income (expense): Change in fair value of derivative conversion liability (9,926,158) - (10,315,421) - Interest expense, net (2,514,045) (414,136) (3,296,084) (414,136) Interest income 15,430 913 15,891 3,686 ----------- ---------- ---------- ---------- Total other income (expense) (12,424,773) (413,223) (13,595,614) (410,450) ----------- ---------- ---------- ---------- Loss before income taxes (11,738,360) (543,661) (12,898,363) (805,330) Provision for income taxes - - - - ----------- ---------- ---------- ---------- Net loss $ (11,738,360) $ (543,661) $(12,898,363) $ (805,330) ============= =========== ============ ========== Net loss per common share: Basic and Diluted (0.55) (0.05) (0.73) (0.07) ============= =========== ============ ========== Weighted average shares outstanding: Basic and Diluted 21,487,951 11,998,000 17,580,331 11,998,000 ============= =========== ============ ==========
The accompanying notes are an integral part of these financial statements. 4 SYNERGY RESOURCES CORPORATION STATEMENTS OF CASH FLOWS (unaudited) Six Months Ended February 28, 2011 2010 ------------ ----------- Cash flows from operating activities: Net loss $ (12,898,363) $ (805,330) ------------- ----------- Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depreciation, depletion, and amortization 1,232,186 92,939 Amortization of debt issuance cost 1,165,271 100,137 Accretion of debt discount 1,902,002 245,343 Stock-based compensation 260,971 10,829 Change in fair value of derivative liability 10,315,421 - Changes in operating assets and liabilities: Accounts receivable (785,734) (440,421) Inventory (118,981) 333,115 Accounts payable 2,322,788 120,711 Accrued expenses 341,476 91,207 Other (68,091) (31,638) ------------- ----------- Total adjustments 16,567,309 522,222 ------------- ----------- Net cash provided by (used in) operating activities 3,668,946 (283,108) ------------- ----------- Cash flows from investing activities: Acquisition of property and equipment (5,946,766) (3,748,918) ------------- ----------- Net cash used in investing activities (5,946,766) (3,748,918) ------------- ----------- 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 -- 11,761,000 Debt issuance costs -- (765,731) Payment of deferred offering costs -- (942,717) ------------- ----------- Net cash provided by financing activities 16,690,721 10,052,552 ------------- ----------- Net increase in cash and equivalents 14,412,901 6,020,526 Cash and equivalents at beginning of period 6,748,637 2,854,659 ------------- ----------- Cash and equivalents at end of period $ 21,161,538 $ 8,875,185 ============== =========== Supplemental Cash Flow Information (See Note 11) The accompanying notes are an integral part of these financial statements. SYNERGY RESOURCES CORPORATION NOTES TO FINANCIAL STATEMENTS February 28, 2011 (unaudited) 1. Organization and Summary of Significant Accounting Policies Organization: Synergy Resources Corporation (the "Company") represents the result of a merger transaction on September 10, 2008, between Brishlin Resources, Inc. ("Predecessor Brishlin"), a public company, and Synergy Resources Corporation ("Predecessor Synergy"), a private company. The Company is engaged in oil and gas acquisitions, exploration, development and production activities, primarily in the area known as the Denver-Julesburg ("D-J") Basin. The Company has adopted August 31st as the end of its fiscal year. Interim Financial Information: The interim financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") as promulgated in Item 210 of Regulation S-X. The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America ("US GAAP"). Certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been condensed or omitted pursuant to such SEC rules and regulations. The Company believes that the disclosures included are adequate to make the information presented not misleading, and recommends that these financial statements be read in conjunction with the audited financial statements and notes thereto 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 oil and gas reserves, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions are revised periodically and the effects of revisions are reflected in the financial statements in the period it is determined to be necessary. Actual results could differ from these estimates. Cash and Cash Equivalents: The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of three months or less to be cash and cash equivalents. Inventory: Inventories consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market. 6 Oil and Gas Properties: The Company uses the full cost method of accounting for costs related to its oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool. These costs include land acquisition costs, geological and geophysical expense, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves. Capitalized costs of oil and gas properties are depleted using the unit-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 proved oil and gas properties, net of accumulated depreciation, depletion, and amortization, the related deferred income taxes, and the cost of unevaluated properties, may not exceed the estimated future net cash flows from proved oil and gas reserves, less future cash outflows associated with asset retirement obligations that have been accrued, plus the cost of unevaluated properties not being amortized, plus the lower of cost or estimated fair value of unevaluated properties not being amortized, less income tax effects related to differences between the book and tax basis of the cost of properties not being amortized and the cost or estimated fair value of unproved properties included in the cost 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 six months ended February 28, 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. 7 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 $43,228 and $107,948 for the three and the six months ended February 28, 2011, respectively, were capitalized in the full cost pool. 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 was $220,905 and $39,320 for the three months ended February 28, 2011 and 2010, respectively, and $340,644 and $55,472 for the six months ended February 28, 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 $995,150 and $100,137 was recorded for the three months ended February 28, 2011 and 2010, respectively, and $1,165,271 and $100,137 was recorded for the six months ended February 28, 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 8 as a debt discount at the date of the issuance. Any subsequent increase or decrease in the fair value of the derivative conversion liabilities is recognized as a charge or credit to other income (expense) in the statements of operations. Revenue Recognition: Revenue is recognized for the sale of oil and natural gas when production is sold to a purchaser and title has transferred. Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's interest. Provided that reasonable estimates can be made, revenue and receivables are accrued, and differences between the estimates and actual volumes and prices, if any, are adjusted upon settlement, which typically occurs sixty to ninety days after production. Major Customers and Operating Region: The Company operates exclusively within the United States of America. Except for cash and equivalent investments, all of the Company's assets are employed in and all of its revenues are derived from the oil and gas industry. The Company's oil and gas production is purchased by a few customers. The table below presents the percentages of oil and gas revenue that was purchased by major customers. Three Months Ended Six Months Ended February 28, February 28, ----------------------- -------------------- Major Customers 2011 2010 2011 2010 ---------- ---------- -------------------- Suncor Energy Marketing, Inc. 78% 42% 78% 36% DCP Midstream LP 19% 36% 19% 31% Kerr-McGee Oil & Gas Onshore LP * 22% * 33% * less than 10% As there are other purchasers that are capable of and willing to purchase the Company's oil and gas production and since the Company has the option to change purchasers on its properties if conditions so warrant, the Company believes that its oil and gas production can be sold in the market in the event that it is not sold to the Company's existing customers, but in some 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 six months ended February 28, 2011 and 2010, 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: 9 February 28, ---------------------------- 2011 2010 ------------- ------------- Convertible promissory notes 3,810,203 7,350,625 Accrued interest convertible into common stock 49,450 - Warrants(1) 15,247,431 11,777,029 Employee stock options 4,270,000 4,100,000 ------------- ------------- Total 23,377,084 23,227,654 ============= ============= (1) Also as of February 28, 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 February 28, 2011, the Company provided a full valuation allowance against deferred tax assets. The Company anticipates that improving conditions during the latter periods of fiscal 2011 will require an adjustment to the valuation allowance. 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 February 28, 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. Effective September 1, 2010, the Company adopted ASU No. 2010-11 - Derivatives and Hedging, which was issued in March 2010 and clarifies that the transfer of credit risk that is only in the form of subordination of one financial instrument to another is an embedded derivative feature that should not be subject to potential bifurcation and separate accounting. Adoption of this ASU had no material affect on the Company's financial position, results of operations, or cash flows. There were various other accounting standards updates recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, and are not expected to a have a material impact on the Company's financial position, results of operations or cash flows. 10 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 February 28, 2011 and August 31, 2010, major customers (i.e. those with balances greater than 10% of total receivables) are shown in the following table: As of As of Accounts Receivable February 28, August 31, from Major Customers: 2010 2010 ------------------------- ----------- ------------- Noble Energy, Inc. 39% 27% Suncor Energy Marketing, Inc. 23% * DCP Midstream LP 13% * * less than 10% 11 3. Property and Equipment Capitalized costs of property and equipment at February 28, 2011 and August 31, 2010, consisted of the following: As of As of February 28, 2011 August 31, 2010 ----------------- -------------- Oil and gas properties, full cost method: Unevaluated costs, not subject to amortization: Lease acquisition and other costs $ 2,925,850 $ 848,696 Wells in progress 1,526,216 - ------------- ----------- Subtotal, unevaluated costs 4,452,066 848,696 ------------- ----------- Evaluated costs: Producing and non-producing 14,328,188 12,992,594 Less, accumulated depletion (2,280,084) (1,149,096) ------------- ---------- Subtotal, evaluated costs 12,048,104 11,843,498 ------------- ---------- Oil and gas properties, net 16,500,170 12,692,194 ------------- ---------- Other property and equipment: Vehicles 133,066 89,527 Leasehold improvements 32,917 32,329 Office equipment 81,176 36,821 Less, accumulated depreciation (29,626) (7,888) ------------- ---------- Other property and equipment, 217,533 150,789 net ------------- ----------- Total property and equipment, net $ 16,717,703 $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 $627,517 and $64,622 or $18.07 and $10.59 per barrel of oil equivalent, for the three months ended February 28, 2011 and 2010, respectively, and $1,195,555 and $92,717, or $18.52 and $13.19 per barrel of oil equivalent, for the six months ended February 28, 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 February 28, 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 ended February 28, 2011 and 2010, did not reveal any impairment. Subsequent to February 28, 2011, the Company completed certain property acquisition transactions and a property conveyance transaction, all of which will result in changes to the full cost pool during future quarters. 12 Depreciation of other property and equipment was $11,499 and $111 for the three months ended February 28, 2011 and 2010, respectively and $21,738 and $222 for the six months ended February 28, 2011 and 2010, respectively. 4. Interest Expense The components of interest expense recorded for the three and six months ended February 28, 2011 and 2010, consisted of: Three Months Ended February 28, Six Months Ended February 28, ------------------------------ ------------------------------ 2011 2010 2011 2010 -------------- -------------- -------------- -------------- Interest cost, convertible promissory notes $ 258,721 $ 96,655 $ 569,455 $ 96,655 Interest cost, bank loan - 11,321 - 27,473 Accretion of debt discount (see Note 6) 1,481,079 245,343 1,902,002 245,343 Amortization of debt issuance costs 995,150 100,137 1,165,271 100,137 Less, interest capitalized (220,905) (39,320) (340,644) (55,472) ----------- ----------- ----------- ----------- Interest expense, net $ 2,514,045 $ 414,136 $ 3,296,084 $ 414,136 =========== =========== =========== ===========
5. Asset Retirement Obligations Upon completion or acquisition of a well, 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 about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in regulations. Changes in estimates are reflected in the obligations as they occur. The following table summarizes the change in asset retirement obligations for the six months ended February 28, 2011: Asset retirement obligations, August 31, 2010 $ 254,648 Liabilities incurred 76,663 Liabilities settled - Accretion 14,893 Revisions in estimated liabilities - --------- Asset retirement obligations, February 28, 2010 $ 346,204 ========= 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 consists of one convertible promissory note ("Note") in the principal amount of $100,000 and 50,000 Series C warrants (collectively referenced as a ("Unit"). The Notes bear interest at 8% per year, payable quarterly, and mature 13 on 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. Net proceeds of $16,651,023 from the sale of the Units were used primarily to drill and complete oil and gas wells in the Wattenburg field, located in the Denver-Julesburg eBasin. The Notes are collateralized by any oil and gas wells drilled, completed, or acquired with the proceeds from the offering. The Notes are considered hybrid debt instruments containing a detachable warrant and a conversion feature under which the proceeds of the offering are allocated to the detachable warrants and the conversion feature based on their fair values. The 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 will not be re-measured in future periods. The Notes contain a conversion feature, at an initial conversion price of $1.60 that is subject to adjustment under certain circumstances, which allow the Note holders to convert the principal balance into a maximum of 11,250,000 common shares, plus conversion of accrued and unpaid interest into common shares, also at $1.60 per share. The conversion feature was determined to be an embedded derivative requiring the conversion option to be separated from the host contract and measured at its fair value. At issuance, the estimated fair value of the conversion feature was $3,455,809. The conversion option will continue to be recorded at fair value each reporting period until settlement or conversion, with changes in the fair value reflected in other income (expense) in the statements of operations. The fair value of the conversion feature was recorded as derivative conversion liability. Allocation of value to the components created a debt discount of $5,215,857, which is being accreted over the 36 month life of the Notes using the effective interest method. The effective interest rate on the Notes is 19%. The Company recorded accretion expense of $1,481,079 and $1,902,002 during the three months and six months ended February 28, 2011, respectively. Accretion expense includes a component for the conversion of Notes into common stock, which was $1,231,726 and $1,305,239 for the three months and six months ended February 28, 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 $995,150 and $1,165,271 was recorded during the three months and six months ended February 28, 2011, respectively. A total of 39,035 Series D warrants were exercised during the three months ended February 28, 2011. During the six months ended February 28, 2011, holders of convertible promissory notes with a face amount of $9,811,675 converted principal into 6,132,297 shares of common stock at the conversion price of $1.60 per share. At the time the notes were converted, the estimated fair value of the derivative conversion liability attributable to the converted notes totaled $9,394,278, which was reclassified from derivative conversion liability to additional paid in capital. Similarly, the unamortized debt discount attributable to the converted notes totaled $1,969,999. The unamortized debt discount of $1,305,239 applicable to the conversion option was charged to accretion of debt discount and the unamortized debt discount of $664,760 applicable to the warrants was 14 reclassified from debt discount to additional paid in capital. As of February 28, 2011, notes with a principal amount of $6,096,325 were outstanding and the debt discount balance was $1,150,294. The fair value of the derivative conversion liability is adjusted each quarter to reflect the change in value. The estimated fair value of the derivative conversion liability as of February 28, 2011, was $10,246,260, and the change in fair value of derivative conversion liability was $10,315,421 during the six months ended February 28, 2011, including a change of $9,394,278 related to the early conversion of notes. 7. Fair Value Measurements Assets and liabilities are measured at fair value on a recurring basis for disclosure or reporting, as required by ASC "Fair Value Measurements and Disclosures". A fair value hierarchy was established that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed securities and US government treasury securities. Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies, where substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, which can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 3 - Pricing inputs include significant inputs that are generally less observable than objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Level 3 includes those financial instruments that are valued using models or other valuation methodologies, where substantial assumptions are not observable in the marketplace throughout the full term of the instrument, cannot be derived from observable data or are not supported by observable levels at which transactions are executed in the marketplace. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those for which fair value is based on significant unobservable inputs. For the most part, the Company's financial instruments consisted of cash and equivalents, accounts receivable, accounts payable, and accrued liabilities. Due to the short original maturities and high liquidity of cash and equivalents, accounts receivable, accounts payable, and accrued liabilities, carrying amounts approximated fair values. As permitted, the Company's convertible promissory notes are not restated to fair value in the Company's financial statements for each reporting period. 15 As of February 28, 2011, the carrying value of the notes was $4,946,032, and the estimated fair value was equal to the face value of $6,096,325. Because the notes are not traded on a public exchange, the fair value reflects market-based values for debt with similar terms and maturities. The Company's convertible promissory notes (see Note 6) contain an embedded conversion option which is required to be separated and reported as a derivative liability at fair value. The Company utilizes 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 as of February 28, 2011, were: stock price of $4.10, an expected term of 1.9 years, volatility of 45.70%, which was derived from the expected volatility of comparable companies, dividend yield of 0%, and a discount rate of 6.63%. All of the significant inputs are observable, either directly or indirectly; therefore, the Company's derivative conversion liability is included within the Level 2 fair value hierarchy. The derivative conversion liability is re-measured each quarter to reflect the change in fair value. The estimated fair value of the derivative conversion liability as of February 28, 2011, was $10,246,260, and the change in fair value of derivative conversion liability was $10,315,421 during the six months ended February 28, 2011, including a change of $9,394,278 related to the early conversion of notes. The following table sets forth by level within the fair value hierarchy the Company's financial assets and financial liabilities as of February 28, 2011 and August 31, 2010, that were measured at fair value on a recurring basis. As of February 28, 2011 Total Level 1 Level 2 Level 3 ------------------------ ------------ ----------- ----------- --------- Derivative Conversion Liability 10,246,260 - 10,246,260 - 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 $346,204 and $254,648 have been accounted for as long-term liabilities and included in each property's asset value at February 28, 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 The Company's executive officers control three entities that have entered into agreements to provide various services and office space to the Company. The entities are Petroleum Management, LLC ("PM"), Petroleum Exploration and Management, LLC ("PEM"), and HS Land & Cattle, LLC ("HSLC"). Effective June 11, 2008, the Company entered into an Administrative Services Agreement with PM. The Company paid $10,000 per month for leasing office space and an equipment yard located in Platteville, StateColorado, and paid $10,000 per month for office support services including secretarial service, word processing, communication services, office equipment 16 and supplies. The Company paid $120,000 under this agreement for the six months ended February 28, 2010. Effective June 30, 2010, the Company terminated the agreement. Effective July 1, 2010, the Company entered into a lease with HSLC, for office space and an equipment yard located in Platteville, StateColorado. The lease requires monthly payments of $10,000 and terminates on June 30, 2011. The Company paid $60,000 under this agreement for the six months ended February 28, 2011. On October 1, 2010, the Company acquired certain oil and gas properties located in the Wattenberg field, part of the D-J Basin, from PM and PEM for $1,017,435. The oil and gas properties consist of interests 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. The Company is currently contemplating the acquisition of additional oil and gas properties from PEM for a purchase price of $19,000,000 subject to adjustment for changes in assets, liabilities, revenues, and expenses for the period between January 1, 2011, and the closing date, if required. Certain conditions precedent to closing the transaction have not been satisfied, including the approval of disinterested directors and shareholders. 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. PEM is a joint working interest owner of certain wells operated by the Company. PEM is charged for their pro-rata share of costs and expenses incurred on their behalf by the Company, and similarly PEM is credited for their pro-rata share of revenues collected on their behalf. The following table summarizes the transactions with PM and PEM during the six months ended February 28, 2011: Balance due to PM, August 31, 2010 $ 538,698 Purchases from PM 2,290 Payments to PM (540,988) ----------- Balance due to PM, February 28, 2011 $ - =========== Joint interest billing balance due from PEM, August 31, 2010 867,835 Joint interest costs billed to PEM 297,782 Amounts collected from PEM (1,097,338) ----------- Joint interest billing due from PEM, February 28, 2011 $ 68,279 =========== Balance due to PEM for revenues, August 31, 2010 $ 15,971 Revenues collected on behalf of PEM 309,056 Payments to PEM for revenues (325,027) ----------- Balance due to PEM for revenues, February 28, 2011 $ - =========== 17 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 February 28, 2011, is 28,763,441 common shares, representing an increase from August 31, 2010, of 15,252,460 shares, as follows: On January 11, 2011, the Company completed the sale of 9,000,000 shares of common stock to private investors. The shares were sold at a price of $2.00 per share. Net proceeds to the Company from the sale of the shares were $16,690,721 after deductions for the placement agents' commissions and expenses of the offering. During the six months ended February 28, 2011, the Company issued 6,132,297 common shares pursuant to the conversion of notes in the principal amount of $9,811,675 at the contractual conversion price of $1.60 per share. In addition, the Company issued 1,947 common shares pursuant to the conversion of accrued interest of $3,115. During the six months ended February 28, 2011, the Company issued 100,000 common shares in exchange for services. The common shares were valued at $210,000 based upon the quoted market price of the Company's common stock on the effective date of the agreement. The entire value was recorded as general and administrative expense during the six months ended February 28, 2011. During the six months ended February 28, 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 39,035 warrants in exchange for 18,216 shares of common stock, and the Company received no cash proceeds in the transaction. There are various warrants outstanding to purchase 15,247,431 shares of common stock. The following table summarizes information about the Company's issued and outstanding common stock warrants as of February 28, 2011: 18 Remaining Number of Contractual Expiration Strike Description Shares Life (in years) Date Proceeds ------------------- --------- -------------- ---------- ----------- Series A at $6.00 4,098,000 1.8 12/31/2012 $24,588,000 Series B at $10.00 1,000,000 1.8 12/31/2012 10,000,000 Series C at $6.00 9,000,000 3.8 12/31/2014 54,000,000 Series D at $1.60 1,085,965 3.8 12/31/2014 1,738,000 Placement Agent Warrants at $1.80 63,466 1.8 12/31/2012 114,000 ---------- ----------- 15,247,431 2.8 $90,440,000 ========== =========== The following table summarizes activity for common stock warrants for the three month period ended February 28, 2011: Weighted Number Average of Exercise Warrants Price -------- --------- Outstanding, August 31, 2010 15,286,466 $ 5.92 Granted - - Exercised (39,085) 1.60 ---------- -------- Outstanding, February 28, 2011 15,247,431 $ 5.93 ========= ======== 10. Stock-Based Compensation Effective September 27, 2010, the Company granted employee stock options to purchase 50,000 shares of common stock at an exercise price of $2.40 and a term of ten years. The options vest over four years. These options were determined to have a fair value of $63,126 using the assumptions outlined in the table below. For the grant of 100,000 common shares discussed in Note 9, the Company recorded stock-based compensation expense of $nil and $210,000 for the three months and six months ended February 28, 2011. For the grant of various stock options that are currently in the vesting phase, the Company recorded stock-based compensation expense of $25,486 and $50,971 for the three months and six months ended February 28, 2011, respectively. The comparable stock-based compensation expense for the previous fiscal year was $5,415 and $10,829 for the three months and six months ended February 28, 2010, respectively. The estimated unrecognized compensation cost from unvested stock options as of February 28, 2011, was approximately $290,000, and will be recognized ratably through September, 2014. The assumptions used in valuing stock options for the six months ended February 28, 2011 were as follows: Expected term (in years) 6.00 Expected volatility 53.18% Risk free rate 1.62% Expected dividend yield 0.00% 19 The following table summarizes activity for stock options for the period from August 31, 2010 to February 28, 2011: Weighted Average Number of Exercise Shares Price --------- -------- Outstanding, August 31, 2010 4,220,000 $ 5.36 Granted 50,000 $ 2.40 Exercised - - --------- ------- Outstanding, February 28, 2011 4,270,000 $ 5.32 ========= ======= The following table summarizes information about issued and outstanding stock options as of February 28, 2011: Remaining Weighted Number Contractual Average Aggregate Exercise of Life Exercise Number Intrinsic Price Shares (in years) Price Exercisable Value ---------- --------- ----------- --------- ----------- --------- $ 10.00 2,000,000 2.4 $ 10.00 2,000,000 - $ 1.00 2,000,000 2.4 $ 1.00 2,000,000 $6,200,000 $ 3.00 100,000 7.9 $ 3.00 20,000 110,000 $ 2.50 120,000 9.4 $ 2.50 - 192,000 $ 2.40 50,000 9.6 $ 2.40 10,000 85,000 --------- --------- ---------- 4,270,000 2.8 $ 5.32 4,030,000 $6,587,000 ========= ========= ========== 20 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 six months ended February 28, 2011 and 2010: Six Months Ended February 28, --------------------------------- 2011 2010 ------------- ----------- Supplemental cash flow information: Interest paid $ 703,331 $ 39,978 Income taxes paid - - Non-cash investing and financing activities: Conversion of promissory notes into common stock $9,811,675 $ - Reclassification of derivative conversion liability to additional paid in capital 9,394,278 - Accrued capital expenditures 2,515,024 111,114 Asset retirement costs and obligations incurred 76,633 51,000 Placement agent warrants issued - 452,458 12. Subsequent Events Between March 1, 2011 and March 31, 2011, holders of convertible promissory notes with a face amount of $6,096,325 plus accrued interest of $55,882 elected to convert the notes into 3,845,132 shares of common stock at the conversion price of $1.60 per share. In a conveyance transaction which closed on March 21, 2011, the Company sold its mineral lease interest in 3,502 gross acres (2,383 net acres) for cash proceeds of $5,244,517. On March 21, 2011, the Company agreed to issue 1,276,384 shares of common stock for mineral lease interests comprising 89,805 gross acres (80,274 net acres) in the D-J Basin. 21 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 February 28, 2011, and the results of our operations for the three months and six months ended February 28, 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 Colorado and are focused on the acquisition, development, exploitation, exploration and production of oil and natural gas properties primarily located in the Denver-Julesburg ("D-J") Basin. 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 February 28, 2011, we have 56 gross wells including 48 producing wells, 6 wells in progress, and 2 shut in wells (net wells of 42). As of February 28, 2011, we had estimated proved reserves of 641,572 Bbls of oil and 4,313,939 Mcf of gas. We currently have approximately 116,000 gross acres and 100,000 net acres under lease, which includes certain lease acquisitions and disposals occurring subsequent to February 28, 2011, and discussed in the following section on Recent Developments. Our growth plans for 2011 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 $18,000,000 and the sale of mineral interests for $5,244,517 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 January 11, 2011, we closed on 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 from the sale of the shares were approximately $16,700,000 after deductions for the sales commissions and expenses. In December 2010, we acquired four producing wells in an area that is adjacent to our Pratt lease. We paid cash consideration of $400,000 and assigned the lease rights on 340 net acres in northern Weld County to the seller. On February 17, 2011, we acquired 5,724 acres in Larimer, Park, and Yuma Counties, Colorado, for approximately $265,000. 22 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. Through March 31, 2011, the entire original principal balance of $18,000,000 has been converted into 11,250,000 shares of common stock. In a conveyance 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. On March 21, 2011, we agreed to issue 1,276,384 shares of restricted common stock for mineral interest leases comprising 89,805 gross acres (80,274 net acres) in the D-J Basin. Potential Acquisition of Oil and Gas Properties from Petroleum Exploration & Management We have a nonbinding letter of intent with Petroleum Exploration & Management LLC ("PEM"), a company owned by Ed Holloway and William E. Scaff, Jr., two of our officers, to potentially acquire oil and gas properties located in the Wattenberg Field of the D-J Basin. The assets under purchase consideration include interests in 88 gross wells (87 producing and 1 shut-in) and oil and gas leases covering 6,968 gross acres in the D-J Basin. We have completed our preliminary evaluation of the value of the assets and estimate that the transaction will be approximately $19,000,000, subject to adjustment for various contingencies. Our evaluation included consideration of the estimated proved reserves of the oil and gas properties, the value of undeveloped leases, and the potential advantages to the Company of adding these properties to our existing oil and gas assets. We considered whether new well stimulation technologies developed since these wells were drilled could be applied to increase the future value of the properties. At this time, we anticipate that the structure of the payment price will consist of a combination of cash, a promissory note, and shares of common stock. PEM is currently undergoing an audit of its financial statements and obtaining an independent reserve analysis. Certain members from our Board of Directors are serving as an independent acquisition committee to review the potential transaction. Proceeding with the acquisition would be contingent upon numerous factors, including satisfactory completion of due diligence, approval of disinterested directors and approval by our shareholders, and availability of suitable financing. RESULTS OF OPERATIONS For the three months ended February 28, 2011, compared to the three months ended February 28, 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 February 28, 2011, we reported a net loss of $11,738,360, or $0.55 per share, compared to a net loss of $543,661, or $0.05 per share, for the three months ended February 28, 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 $686,413 in 2011 compared to an operating loss of $130,438 in 2010. Improved operating income was offset by interest expense related to the $18,000,000 financing transaction that closed in March 2010. 23 Oil and Gas Production and Revenues - For the three months ended February 28, 2011, we recorded total oil and gas revenues of $2,033,687 compared to $335,725 for the three months ended February 28, 2010, as summarized in the following table: Three Months Ended February 28, ----------------------- 2011 2010 ------ ------- Production: Oil (Bbls) 19,511 2,857 Gas (Mcf) 91,333 19,480 Total production in BOE 34,733 6,104 Revenues: Oil $1,631,905 $ 198,392 Gas 401,782 137,333 ---------- ---------- Total $2,033,687 $ 335,725 ========== ========== Average sales price: Oil (Bbls) $ 83.64 $ 69.44 Gas (Mcf) $ 4.40 $ 7.05 "Bbl" refers to one stock tank barrel, or 42 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons. "Mcf" refers to one thousand cubic feet. A BOE (i.e. barrel of oil equivalent) combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil. Net oil and gas production for the three months ended February 28, 2011, was 34,733 BOE, or 386 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 20% and decreased the realized sales price of natural gas by 38%. 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 February 28, 2011, we recorded revenue generated from the management of wells owned by third parties of $19,847. 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 February 28, ------------------------------- 2011 2010 ---- ---- Production costs $ 55,471 $ 13,345 Severance and ad valorem taxes 205,009 33,807 ----------- ---------- Total lease operating expenses $ 260,480 $ 47,152 =========== ========== 24 Per BOE: Production costs $ 1.60 $ 2.19 Severance and ad valorem taxes 5.90 5.54 ----------- ---------- Total per BOE $ 7.50 $ 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 13% in the three months ended February 28, 2011, and 14% in the respective period in 2010. Depreciation, Depletion, and Amortization ("DDA") - DDA expense is summarized in the following table: Three Months Ended February 28, -------------------------------- 2011 2010 ---- ---- Depletion $ 627,517 $ 64,622 Depreciation and amortization 11,499 111 Accretion of asset retirement obligations 8,189 ---------- --------- Total DDA $ 647,205 $ 64,733 ========== ========= Depletion per BOE $ 18.07 $ 10.59 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 February 28, 2011, production volumes of 34,733 BOE and estimated net proved reserves of 1,395,295 BOE were the basis of the depletion rate calculation. For the three months ended February 28, 2010, production volumes of 6,104 BOE and estimated net proved reserves of 136,000 BOE were the basis of the depletion rate calculation. General and Administrative - The following table summarizes the components of general and administration expenses: Three Months Ended February 28, --------------------------------- 2011 2010 ---- ---- Stock based compensation $ 25,486 $ 6,188 Other general and administrative 477,178 348,090 Capitalized general and administrative (43,228) - --------- --------- Totals $ 459,436 $ 354,278 ========= ========= 25 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 $129,000 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 $140,000 as we increased the number of employees from three to seven, and we incurred additional professional fees of approximately $14,000 related to increased compliance requirements of our business. 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) - The issuance of $18,000,000 of convertible promissory notes and Series C warrants during the year ended August 31, 2010, generated a significant increase in other expenses for the three months ended February 28, 2011, compared to the three months ended February 28, 2010. Interest expense of $258,721 was recognized during the three months ended February 28, 2011. Accretion of debt discount was $1,481,079 during the three months ended February 28, 2011, and amortization of debt issuance costs was $995,150. The notes contain a conversion feature, at an initial conversion price of $1.60 that is subject to adjustment under certain circumstances, which allow the noteholders to convert the $18,000,000 principal balance into a maximum of 11,250,000 common shares, plus conversion of accrued and unpaid interest into common shares, also at $1.60 per share. This conversion feature, considered an embedded derivative and recorded as a liability at its estimated fair value, when marked-to-market, over time is reflected as a non-cash item in the statement of operations. A non-cash expense of $9,926,158 was reflected in the statement of operations for the three months ended February 28, 2011, as the change in the fair value of the derivative conversion liability during the period. Income Taxes - Our effective tax rate is currently zero. We have reported a net loss every year since inception and for tax purposes have a net operating loss carry forward ("NOL") of approximately $10,000,000. The NOL is available to offset future taxable income, if any. At such time, if ever, that we are able to demonstrate that it is more likely than not that we will be able to realize the benefits of our tax assets, we will recognize the benefits in our financial statements. If operational results for the remainder of the fiscal year continue to improve, we may recognize the benefits of certain tax assets during the latter periods of the year. For the six months ended February 28, 2011, compared to the six months ended February 28, 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 six months ended February 28, 2011, we reported a net loss of $12,893,363, or $0.73 per share, compared to a net loss of $805,330, or $0.07 per share, for the six months ended February 28, 2010. The comparison between 26 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 $697,251 in 2011 compared to an operating loss of $394,880 in 2010. Improved operating income was offset by interest expense related to the $18,000,000 financing transaction that closed in March 2010. Oil and Gas Production and Revenues - For the six months ended February 28, 2011, we recorded total oil and gas revenues of $3,477,282 compared to $388,511 for the six months ended February 28, 2010, as summarized in the following table: Six Months Ended February 28, ---------------------------- 2011 2010 ---- ---- Production: Oil (Bbls) 35,450 3,491 Gas (Mcf) 174,639 21,226 Total production in BOE 64,557 7,029 Revenues: Oil $ 2,785,683 $ 244,596 Gas 691,599 143,915 ----------- --------- Total $ 3,477,282 $ 388,511 =========== ========= Average sales price: Oil (Bbls) $ 78.58 $ 70.06 Gas (Mcf) $ 3.96 $ 6.78 "Bbl" refers to one stock tank barrel, or 42 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons. "Mcf" refers to one thousand cubic feet. A BOE (i.e. barrel of oil equivalent) combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil. Net oil and gas production for the six months ended February 28, 2011, was 64,557 BOE, or 357 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 12% and decreased the realized sales price of natural gas by 42%. We do not currently engage in any commodity hedging activities, although we may do so in the future. Service Revenue- For the six months ended February 28, 2011, we recorded revenue generated from the management of wells owned by third parties of $27,289. 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: Six Months Ended February 28, ---------------------------- 2011 2010 ---- ---- Production costs $ 117,348 $ 15,919 Severance and ad valorem taxes 345,807 39,123 ----------- ---------- Total lease operating expenses $ 463,155 $ 55,042 =========== ========== 27 Per BOE: Production costs $ 1.82 $ 2.26 Severance and ad valorem taxes 5.36 5.57 ----------- ---------- Total per BOE $ 7.18 $ 7.83 =========== ========== 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 13% in the six months ended February 28, 2011, and 14% in the respective period in 2010. Depreciation, Depletion, and Amortization ("DDA") - DDA expense is summarized in the following table: Six Months ended February 28, ----------------------------------- 2011 2010 --------------- ----------------- Depletion $ 1,195,555 $ 92,717 Depreciation and amortization 21,738 222 Accretion of asset retirement obligations 14,893 - -------------- ------------ Total DDA $ 1,232,186 $ 92,939 =============== ============= Depletion per BOE $ 18.52 $ 13.19 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 six months ended February 28, 2011, production volumes of 64,557 BOE and estimated net proved reserves of 1,425,119 BOE were the basis of the depletion rate calculation. For the six months ended February 28, 2010, production volumes of 7,029 BOE and estimated net proved reserves of 137,000 BOE were the basis of the depletion rate calculation. General and Administrative - The following table summarizes the components of general and administration expenses: Six Months ended February 28, ------------------------------------ 2011 2010 ----------------- ---------------- Stock based compensation $ 260,971 $ 10,829 Other general and administrative 958,956 624,581 Capitalized general and administrative (107,948) - ----------------- --------------- Totals $ 1,111,979 $ 635,410 ================= ================ 28 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. During the six months ended February 28, 2011, we issued 100,000 restricted shares of common stock with a value of $210,000 to a service provider. Other general and administrative expenses, which include salaries, benefits, professional fees, and other corporate overhead, increased approximately $334,000 during the current six-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 $332,000 as we increased the number of employees from three to seven, reservoir engineering fees increased by approximately $30,000, and we incurred additional professional fees of approximately $70,000 related to increased compliance requirements of our business. The increased expenses in these areas were somewhat offset by a $60,000 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) - The issuance of $18,000,000 of convertible promissory notes and Series C warrants during the year ended August 31, 2010, generated a significant increase in other expenses for the six months ended February 28, 2011, compared to the six months ended February 28, 2010. Interest expense of $569,455 was recognized during the six months ended February 28, 2011. Accretion of debt discount was $1,902,002 during the six months ended February 28, 2011, and amortization of debt issuance costs was $1,165,271. The notes contain a conversion feature, at an initial conversion price of $1.60 that is subject to adjustment under certain circumstances, which allow the noteholders to convert the $18,000,000 principal balance into a maximum of 11,250,000 common shares, plus conversion of accrued and unpaid interest into common shares, also at $1.60 per share. This conversion feature, considered an embedded derivative and recorded as a liability at its estimated fair value, when marked-to-market, over time is reflected as a non-cash item in the statement of operations. A non-cash expense of $10,315,421 was reflected in the statement of operations for the six months ended February 28, 2011, to represent the change in the fair value of the derivative conversion liability during the period. Income Taxes - Our effective tax rate is currently zero. We have reported a net loss every year since inception and for tax purposes have a net operating loss carry forward ("NOL") of approximately $10,000,000. The NOL is available to offset future taxable income, if any. At such time, if ever, that we are able to demonstrate that it is more likely than not that we will be able to realize the benefits of our tax assets, we will recognize the benefits in our financial statements. If operational results for the remainder of the fiscal year continue to improve, we may recognize the benefits of certain tax assets during the latter periods of the year. 29 LIQUIDITY AND CAPITAL RESOURCES On January 11, 2011, we completed the sale of 9,000,000 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. During the prior year ended August 31, 2010, we 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 in the principal amount of $100,000 and 50,000 Series C warrants. The notes bore interest at 8% per year, payable quarterly, and were payable on December 31, 2012. Each Series C warrant entitles the holder to purchase one share of our common stock at a price of $6.00 per share and expires on December 31, 2014. Net proceeds of $16,651,023 from the sale of the Units were used primarily to drill and complete 36 oil and gas wells in the Wattenburg field. The Notes are collateralized by any oil and gas wells drilled, completed, or acquired with the proceeds from the sale of the Units. In non-cash transactions during the six months ended February 28, 2011, holders of convertible promissory notes with a face amount of $9,811,675 converted principal into 6,132,297 shares of our common stock ($1.60 conversion price). Between March 1, 2011 and March 31, 2011, all of the remaining holders of convertible promissory notes with a face amount of $6,096,325 plus accrued interest of $55,882 elected to convert the notes into 3,845,132 shares of our common stock. Our sources and (uses) of funds for the six months ended February 28, 2011 and 2010, are shown below: Six Months ended February 28, ------------------------------------ 2011 2010 ----------------- ---------------- Cash provided by (or used in) operations $ 3,668,946 $ (283,108) Acquisition of oil and gas properties, and equipment (5,946,766) (3,748,918) Net cash proceeds from sale of stocK 16,690,721 Net cash proceeds from sale of convertible notes 10,052,552 ----------- ------------ Net increase in cash $ 14,412,901 $ 6,020,526 ============ ============ Net cash provided by operating activities was $3,668,946 for the six months ended February 28, 2011, while operating activities used net cash of $283,108 for the six months ended February 28, 2010. Non-cash expenses had a $14,875,851 and $449,248 impact on net loss for the six months ended February 28, 2011 and 2010, respectively. Changes in working capital items caused by the timing of payments and receipts of cash had an impact of $1,691,458 and $72,974 for the six months ended February 28, 2011 and 2010, respectively. Cash payments for the acquisition of oil and gas properties, drilling costs, and other development activities for the six months ended February 28, 2011 and 2010, were $5,946,766 and $3,748,918, respectively. These amounts differ from the amounts reported as the increase in capitalized costs during the period, which differences reflect 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: 30 Six Months ended February 28, ------------------------------------ 2011 2010 ----------------- ---------------- Cash payments $ 5,946,766 $ 3,748,918 Accrued costs, beginning of period (3,446,439) - Accrued costs, end of period 2,515,024 111,114 Asset retirement obligation 76,663 - ------------- -------------- Increase in capitalized costs $ 5,092,014 $ 3,860,032 ============= ============== In addition to completion activities on the wells drilled during the 2010 drilling program, capital expenditures for the six months ended February 28, 2011, included the acquisition of eight existing wells and fifteen drill sites and associated equipment for a purchase price of $1,017,435. We believe that these wells are good candidates for enhanced recovery techniques. We also acquired four producing wells in Southern Weld County for cash of $400,000 plus an assignment of certain leasehold interests in Northern Weld County. We commenced drilling an additional 14 wells in Southern Weld County and expect to bring those wells on-stream during the summer. At the State of Colorado auction in February 2011 we acquired mineral leases on approximately 5,725 acres for cash of $265,000. In a conveyance 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. 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 tentative capital expenditure budget approximates $27,000,000, 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 $18,000,000, plus our recent sale of mineral lease interests for cash proceeds of $5,200,000, 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. Our budget is tentatively allocated to acquisition of proved and unproved properties of approximately $12,000,000 (either from PEM or unrelated third parties) and drilling activities of approximately $15,000,000, which include drilling new wells and reworking existing 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 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. 31 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. 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; 32 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 February 28, 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 February 28, 2011, that materially affected or are reasonably likely to materially affect our internal control over financial reporting. 33 PART II Item 1. Legal Proceedings. None. Item 2. Unregistered Sales of Equity Securities and Use of Proceeds. During the three months ended February 28, 2011, holders of convertible promissory notes in the principal amount of $9,311,675, plus accrued interest elected to convert into 5,821,744 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. Item 3. Default Upon Senior Securities. None. Item 4. Submission of Matters to a Vote of Securities Holders. None. Item 5. Other Information. None. 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. 34 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: April 11, 2011 By: /s/ Ed Holloway ----------------------------------- Ed Holloway, President and Principal Executive Officer Date: April 11, 2011 By: /s/ Frank L. Jennings ----------------------------------- Frank L. Jennings, Principal Financial and Accounting Officer 35