SYNERGY RESOURCES CORPORATION

NOTES TO CONDENSED FINANCIAL STATEMENTS

~~May 31,~~November 30, 2015

(unaudited)


1.	Organization and Summary of Significant Accounting Policies

~~Organization:~~ Organization: Synergy Resources Corporation ("we", "us", "Synergy", or the ~~Company"~~“Company”) is engaged in oil and gas acquisition, exploration, development, and production activities, primarily in the Denver-Julesburg Basin ("D-J Basin") of Colorado. The ~~Company's~~Company’s common stock is listed and traded on the NYSE MKT under the symbol ~~"SYRG."~~“SYRG.”

Basis of Presentation: The Company has adopted August 31^st as the end of its fiscal year. The Company does not utilize any special purpose entities. The Company operates in one business segment, and all of its operations are located in the United States of America.

The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America ("(“US ~~GAAP"~~GAAP”) ~~for interim financial information.~~.

Interim Financial Information: The unaudited condensed interim financial statements included herein have been prepared by the Company ~~without audit,~~ pursuant to the rules and regulations of the SEC as promulgated in Rule 10-01 of Regulation S-X. The condensed balance sheet as of August 31, ~~2014~~2015 was derived from the Company's Annual Report on Form 10-K for the year ended August 31, ~~2014.~~2015. Accordingly, 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 condensed financial statements be read in conjunction with the audited financial statements and notes thereto for the year ended August 31, ~~2014.~~2015.

In management's opinion, the unaudited condensed 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 effect on net income, working capital or equity previously reported.

~~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 goodwill, the 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 less than three months to be cash and cash equivalents.~~

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~~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 expenses, 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 unproved 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.

Properties under development represent the costs associated with the development of oil and gas properties that have yet to be proved as of May 31, 2015. Since the properties were not classified as proved as of May 31, 2015, they were classified within unproved oil and gas properties and were withheld from the depletion calculation and ceiling test. The costs for these properties will be transferred into proved properties when they are proved and will become subject to depletion and the ceiling test calculation in subsequent periods.

Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC regulations. The ceiling test determines a limit on the book value of oil and gas properties. The capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion, depreciation, and amortization, and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, less future cash outflows associated with asset retirement obligations that have been accrued, plus the cost of unproved properties not being amortized, plus the lower of cost or estimated fair value of unproven 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. 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.

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:~~ Oil and gas reserves represent theoretical, estimated quantities of crude oil and natural gas which geological and engineering data estimate 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 gas reserves and their values, including many factors beyond the Company's control. Accordingly, reserve estimates are different from the future quantities of oil and gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

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The determination of depletion and amortization expenses, as well as the ceiling test calculation related to the recorded value of the Company's oil and natural gas properties, is highly dependent on estimates of proved oil and natural gas reserves.

~~Capitalized Interest:~~ The Company capitalizes interest on expenditures made in connection with acquisition of mineral interests and development projects that are not subject to current amortization. Interest is capitalized during the period that activities are in progress to bring the projects to their intended use. See Note 9 for additional information.

~~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 in the amounts shown in the table below were capitalized in the full cost pool (in thousands):

Three Months Ended
May 31,

Nine Months Ended
May 31,

2015 2014 2015 2014
Capitalized Overhead $ 486 $ 300 $ 1,623 $ 921

~~Well Costs Payable:~~ The costs of wells in progress are recorded as incurred, generally based upon invoiced amounts or joint interest billings ("JIB"). For those instances in which an invoice or JIB is not received on a timely basis, estimated costs are accrued to oil and gas properties, generally based on the authorization for expenditure.

~~Other Property and Equipment:~~ Support equipment (including such items as vehicles, well servicing equipment, and office furniture and equipment) is stated at the lower of cost or market. Depreciation of support equipment is computed using primarily the straight-line method over periods ranging from five to seven years.

~~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. Calculation of an asset retirement obligation ("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.

The present value of a liability for the 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. ARCs related to wells are capitalized to the full cost pool and subject to depletion. 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, as depletion expense is recognized. In addition, ARCs are included in the ceiling test calculation for valuing the full cost pool.

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~~Business Combinations:~~ The Company accounts for its acquisitions using the acquisition method under ASC 805, Business Combinations. Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain.

~~Oil and Gas Sales:~~ The Company derives revenue primarily from the sale of crude oil and natural gas produced on its properties. 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 pro-rata interest. Revenues are reported on a gross basis for the amounts received before taking into account production taxes and lease operating costs, which are reported as separate expenses. Revenue is recorded and receivables are accrued in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser. Payment is generally received between thirty and ninety days after the date of production. Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.

Major Customers:The Company sells production to a small number of customers, as is customary in the industry. As a result, during the three ~~and nine month periods~~months ended ~~May 31,~~November 30, 2015 and 2014, certain of the ~~Company's~~Company’s customers represented 10% or more of its oil and gas revenue ("(“major ~~customers"~~customers”). For the three months ended ~~May 31,~~November 30, 2015, the Company had three major customers, which represented ~~58%~~60%, 15%, and ~~10%~~12% of its revenue during the period. For the three months ended ~~May 31,~~November 30, 2014, the Company had ~~four~~two major customers, which represented ~~45%, 13%, 12%~~68% and 12% of its revenue during the period. For the nine months ended May 31, 2015, the Company had two major customers, which represented 62% and 11% of its revenue during the period. For the nine months ended May 31, 2014, the Company had three major customers, which represented 45%, 15% and 10% of its revenue during the period.

Based on the current demand for oil and natural gas, the availability of other buyers, and the Company having the option to sell to other buyers 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~~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.

Accounts receivable consist primarily of trade receivables from oil and gas sales and amounts due from other working interest owners ~~whom~~who are liable for their proportionate share of well costs. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners.

Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table:

Major Customers
As of
May 31, 2015

As of
August 31, 2014
Company A 29% 37%
Company B 12%
⁽¹⁾

⁽¹⁾ ~~Balance was less than 10% of total receivable balances during the period.~~

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	As of	As of
Major Customers	November 30, 2015	August 31, 2015
Company A	10%	30%

~~Lease Operating Expenses:~~ ~~Costs incurred to operate~~The Company operates exclusively within the United States of America and, ~~maintain wells~~except for cash and ~~related equipment~~short-term investments, all of the Company’s assets are employed in, and ~~facilities~~all of its revenues are ~~expensed as incurred. Lease operating expenses (also referred to as production or lifting costs) include~~derived from, the ~~costs of labor to operate the wells~~oil and related equipment and facilities, repairs and maintenance, materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities, property taxes and insurance applicable to proved properties and wells and related equipment and facilities.gas industry.

~~Stock-Based Compensation:~~Goodwill: The Company’s goodwill represents the excess of the purchase price over the fair value of net identifiable assets acquired in a business combination. Goodwill is not amortized and is tested for impairment annually or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. When evaluating goodwill for impairment, the Company ~~recognizes all equity-based compensation as stock-based compensation expense based on~~may first perform an assessment of qualitative factors to determine if the fair value of the ~~compensation measured at~~reporting unit is more-likely-than-not greater than its carrying amount. If, based on the ~~grant date, calculated using the Black-Scholes-Merton option pricing model. The expense is recognized over the vesting period~~review of the ~~grant. See Note 11 for additional information.~~

~~Income Tax:~~ ~~Income taxes are computed using~~qualitative factors, the ~~asset and liability method. Accordingly, deferred tax assets and liabilities are recognized for~~Company determines it is not more-likely-than-not that the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, their respective tax bases as well as the effect of net operating losses, tax credits and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled. The effect on deferred tax assets and liabilitiesfair value of a ~~change in income tax rates~~reporting unit is ~~recognized in~~less than its carrying value, the ~~results of operations in the period that includes the enactment date.~~

No significant uncertain tax positions were identified as of any date on or before May 31, 2015. The Company's policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of May 31, 2015,required two-step impairment test can be bypassed. If the Company ~~has~~does not ~~recognized any interest~~perform a qualitative assessment or ~~penalties related to uncertain tax benefits.~~

~~Financial Instruments~~: The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents. A substantial portion of the Company's financial instruments consist of cash and cash equivalents, short-term investments, accounts receivable, trade accounts payable, accrued expenses, and obligations under the revolving line of credit facility, all of which are considered to be representative of their fair value due to the short-term and highly liquid nature of these instruments.

Financial instruments, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board, 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).

As discussed in Note 5, the Company incurred asset retirement obligations during the periods presented, the value of which was determined using unobservable pricing inputs (or Level 3 inputs). The Company uses the income valuation technique to estimateif the fair value of the ~~obligation using several~~reporting unit is not more-likely-than-not greater than its carrying value, the Company must perform the first step of the two-step impairment test and calculate the estimated fair value of the reporting unit. If the carrying value of the reporting unit exceeds the estimated fair value, there is an indication that impairment may exist, and the second step must be performed to measure the amount of impairment loss. The amount of impairment for goodwill is measured as the amount by which the carrying amount of the goodwill exceeds the implied fair value of the goodwill. As a result of declining oil prices, the Company performed an interim goodwill test in conjunction with the preparation of its financial statements for the three months ended November 30, 2015 which did not result in an impairment. The Company utilized a market approach in estimating the fair value of the reporting unit. The primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time and ~~judgments about~~contain considerable management judgments. Changes in these assumptions or future economic conditions could impact the ~~ultimate settlement amounts, inflation factors, credit adjusted discount rates,~~Company's conclusion regarding an impairment of goodwill and ~~timing of settlement.~~potentially result in a non-cash impairment loss in a future period.

~~Commodity Derivative Instruments:~~Transportation Commitment Charge: The Company has entered into ~~commodity derivative instruments, primarily utilizing swaps, puts,~~ several agreements that require us to deliver minimum amounts of crude oil to a third party marketer and/or ~~"no premium" collars~~other counterparties that transport crude oil via pipelines. See Note 15 for additional information. Pursuant to ~~reduce~~these agreements, we must deliver specific amounts, either from our own production or from oil we acquire. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements, or we may have to purchase oil from third parties to fulfill our delivery obligations. When we incur penalties of this type, we recognize the ~~effect of price changes on~~expense as a ~~portion of its future oil and gas production. The Company's commodity derivative instruments are measured at fair value and are included~~transportation commitment charge in the ~~accompanying balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values~~Statement of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the statement of operations. The Company values its derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors, as well as other relevant economic measures. The Company compares the valuations calculated by it to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 7.Operations.

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~~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. The number of potential shares outstanding relating to stock options and warrants is computed using the treasury stock method. Potentially dilutive securities outstanding are not included in the calculation when such securities would have an anti-dilutive effect on earnings per share.

~~The following table sets forth the share calculation of diluted earnings per share:~~

Three Months Ended
May 31,

Nine Months Ended
May 31,

2015 2014 2015 2014

Weighted-average shares outstanding-basic 104,234,519 77,176,420 91,105,035 75,689,903
Potentially dilutive common shares from:
Stock options Anti-dilutive 515,530 699,218 432,170
Warrants - 1,316,669 - 1,177,383
- 1,832,199 699,218 1,609,553
Weighted-average shares outstanding - diluted 104,234,519 79,008,619 91,804,253 77,299,456

As a result of the net loss reported for the three months ended May 31, 2015, the calculation of basic and diluted Earnings per Share used the same number of weighted-average common shares outstanding in the denominator, as the inclusion of common share equivalents was anti-dilutive.

The following potentially dilutive securities outstanding for the periods presented were not included in the respective earnings per share calculation above; as such securities had an anti-dilutive effect on earnings per share:

Three Months Ended
May 31,

Nine Months Ended
May 31,

2015 2014 2015 2014

Employee stock options 4,101,500 478,000 2,710,500 503,000
Recently Adopted Accounting Pronouncements:

~~Recent Accounting Pronouncements:~~ ~~We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new pronouncements on US GAAP and the impact on us.~~

In ~~April~~November 2015, the ~~Financial Accounting Standards Board ("FASB")~~FASB issued Accounting Standards Update ~~2015-03, "Simplifying the Presentation~~(“ASU”) 2015-17, “Balance Sheet Classification of ~~Debt Issuance Costs" ("ASU 2015-03"),~~Deferred Taxes,” which requires that ~~debt issuance costs related~~deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position to simplify the presentation of deferred income taxes. The standard is effective prospectively for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. As of September 1, 2015, we elected to early adopt the pronouncement on a ~~recognized debt liability~~prospective basis. Adoption of this amendment did not have an effect on the Company's financial position or results of operations, and prior periods were not retrospectively adjusted.

In September 2015, FASB issued ASU 2015-16, “Simplifying the Accounting for Measurement-Period Adjustments,” which eliminates the requirement to restate prior period financial statements for measurement period adjustments. The new guidance requires that the cumulative impact of a measurement period adjustment (including the impact on prior periods) be ~~presented~~recognized in the ~~balance sheet as a direct deduction from~~reporting period in which the ~~carrying amount of that debt liability, consistent with debt discounts. For public business entities, the ASU~~adjustment is identified. The standard is effective prospectively for ~~financial statements issued for~~fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, ~~and interim periods within those fiscal years. Entities should apply~~with early adoption permitted. On September 1, 2015, we elected to early adopt the ~~new guidance on a retrospective basis, wherein~~pronouncement. This amendment will be applied prospectively to measurement period adjustments that occur after the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. Upon transition, entities are required to comply with the applicable disclosures for a change in an accounting principle. The Company is currently evaluating the impact of the adoptioneffective date. Adoption of this ~~standard~~amendment did not have an effect on ~~its consolidated~~the Company's financial ~~statements.~~

~~Table~~position or results of ~~Contents~~

operations.

In January 2015, the ~~Financial Accounting Standards Board ("FASB")~~FASB issued ~~Accounting Standards Update~~ASU 2015-01, ~~"Simplifying~~“Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary ~~Items" ("ASU 2015-01"),~~Items,” which eliminates from US GAAP the concept of extraordinary items, while retaining certain presentation and disclosure guidance for items that are unusual in nature or occur infrequently. The standard is effective prospectively for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted provided the guidance is applied from the beginning of the fiscal year of adoption. On September 1, 2015, we elected to early adopt the pronouncement. This amendment will be applied prospectively to extraordinary items that occur after the effective date. Adoption of ~~ASU 2015-01 is~~this amendment did not ~~expected to~~ have ~~a material~~an effect on the Company's financial position or results of ~~operations, or cash flows.~~operations.

In August 2014, the FASB issued ASU No. 2014-15, which requires management of public and private companies to evaluate whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued (or available to be issued when applicable) and, if so, to disclose that fact. Management will be required to make this evaluation for both annual and interim reporting periods, if applicable. ASU No. 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods within annual periods beginning after

December 15, 2016, with early adoption permitted. On September 1, 2015, we elected to early adopt the pronouncement. Adoption of this amendment did not have an effect on the Company's financial position or results of operations.

In April 2014, the FASB issued ASU No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 modifies the criteria for disposals to qualify as discontinued operations and expands related disclosures. The guidance is effective for annual and interim reporting periods beginning after December 15, 2014, with early adoption permitted. On September 1, 2015, we elected to adopt the pronouncement. This amendment will be applied prospectively to disposals that occur after the effective date. Adoption of this amendment did not have an effect on the Company's financial position or results of operations.

Recently Issued Accounting Pronouncements: We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us.

In November 2014, the FASB issued ~~Accounting Standards Update~~ASU 2014-16, ~~"Determining~~“Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to ~~Equity" ("~~Equity” (“ASU ~~2014-16"~~2014-16”), which clarifies how to evaluate the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. Specifically, ASU 2014-16 requires that an entity consider all relevant terms and features in evaluating the nature of the host contract and clarifies that the nature of the host contract depends upon the economic characteristics and the risks of the entire hybrid financial instrument. An entity should assess the substance of the relevant terms and features, including the relative strength of the debt-like or equity-like terms and features given the facts and circumstances, when considering how to weight those terms and features. ASU 2014-16 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted. ~~The Company is~~We are currently evaluating the impact of the adoption of this standard on ~~its~~our consolidated financial statements.

In May 2014, the FASB issued ~~Accounting Standards Update~~ASU 2014-09, ~~"Revenue~~“Revenue from Contracts with Customers (Topic 606)~~" ("~~” (“ASU ~~2014-09"~~2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. ASU 2014-09 allows for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, ~~2016~~2017 including interim periods within that period. Early adoption is not permitted. ~~The Company is~~We are currently evaluating which transition approach to use and the impact of the adoption of this standard on ~~its~~our consolidated financial statements.

There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on ~~the Company's~~our reported financial position, results of operations, or cash flows.

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2.	Property and Equipment ~~and Full Cost Ceiling Impairment~~

The capitalized costs related to the ~~Company's~~Company’s oil and gas producing activities were as follows (in thousands):

As of As of
May 31, 2015 August 31, 2014
Oil and gas properties, full cost method:
   Unproved properties, not subject to amortization:
      Lease acquisition and other costs $ 139,012 $ 41,531
      Properties under development 31,627 53,747
         Subtotal 170,639 95,278

   Proved producing and non-producing properties 513,677 329,926
         Total capitalized costs 684,316 425,204
      Less, accumulated depletion (103,101 ) (54,908 )
      Less, full cost ceiling impairment (3,000 ) -
           Oil and gas properties, net 578,215 370,296

Land 4,478 3,898
Other property and equipment 867 5,961
Less, accumulated depreciation (534 ) (755 )
            Other property and equipment, net 4,811 9,104

Total property and equipment, net $ 583,026 $ 379,400



	As of			As of
	November 30, 2015			August 31, 2015
Oil and gas properties, full cost method:
Costs of unproved properties, not subject to amortization:
Lease acquisition and other costs	$	97,017		$	58,068
Unproved wells in progress	9,904			19,496
Subtotal, unproved properties	106,921			77,564

Costs of proved properties:
Producing and non-producing	656,562			577,500
Proved wells in progress	35,070			11,302
Less, accumulated depletion and full cost ceiling impairments	(276,050		)	(136,409		)
Subtotal, proved properties, net	415,582			452,393

Costs of other property and equipment:
Land	4,478			4,478
Other property and equipment	1,187			875
Less, accumulated depreciation	(572		)	(570		)
Subtotal, other property and equipment, net	5,093			4,783

Total property and equipment, net	$	527,596		$	534,740

The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value.

For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs. Under the ceiling test, the value of the ~~Company's~~Company’s reserves ~~are~~is calculated using the average of the published spot prices for ~~West Texas Intermediate (WTI)~~WTI oil (per barrel) as of the first day of each of the previous twelve months, as well as the average of the published spot prices for Henry Hub (per MMBtu) as of the first day of each of the previous twelve months, each adjusted by lease or field for quality, transportation fees and regional price differentials. The ceiling test as of November 30, 2015 used average realized prices of ~~$64.26~~$42.54 per barrel and ~~$4.14~~$2.77 per ~~MMBtu.~~Mcf. The oil prices used at ~~May~~November 30, 2015 were approximately 20% lower than the August 31, 2015 price of $53.27, and the gas prices were approximately 16% lower than the ~~prices used at February 28, 2015.~~

August 31, 2015 price of $3.28. Using these prices, the Company's net capitalized costs offor oil and natural gas properties exceeded the ceiling amount by ~~$3.0~~$125.2 million at ~~May 31,~~November 30, 2015, resulting in immediate recognition of a ceiling test impairment. No such ceiling test impairment was recognized during the three months ended November 30, 2014.

The Company also reviews the fair value of its unproved properties. The reviews for the three months ~~and nine months~~ ended ~~May 31,~~November 30, 2015 and 2014 indicated that estimated fair values of such assets exceeded the carrying ~~values, thus revealing~~values. Therefore, no ~~impairment~~reclassifications to proved property were recognized during either period to impair the carrying value of the unproved properties.

Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities. Under the full cost method of accounting, these expenses, in ~~either period.~~the amounts shown in the table below, were capitalized in the full cost pool (in thousands):

In addition, during the nine months ended May 31, 2015, certain amounts previously recorded were reclassified from one category to another without changing the total amounts recorded as property and equipment. Specifically, costs associated with the disposal well and related equipment were reclassified from other property and equipment into producing oil and gas properties to more closely reflect use of the disposal well to process flow-back water from oil and gas operations. Similarly, accumulated depreciation associated with the disposal well was reclassified from accumulated depreciation to accumulated depletion. The updated classification for the disposal well, related equipment, and accumulated depreciation did not require a change to previously reported depletion, depreciation, and amortization expense ("DDA"). Secondly, as discussed in Note 3, the analysis of assets acquired in the 2014 business combination transactions with Apollo and Trilogy was completed and fair values associated with probable horizontal well development were reclassified from proved properties into unproved properties.



	Three Months Ended November 30,
	2015		2014
Capitalized overhead	$	916	$	503

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3.	Acquisitions

On ~~December 15, 2014,~~October 20, 2015, the Company completed the acquisition of certain assets from ~~three independent oil and gas companies (collectively known as "Bayswater"~~K.P. Kauffman Company, Inc. ("Kauffman") for a total purchase price of ~~$125.1~~$85.2 million, net of customary closing adjustments. The purchase price was composed of ~~$74.2~~$35.0 million in cash and ~~$48.4~~$49.8 million in restricted common stock plus the assumption of certain liabilities.

The ~~Bayswater~~Kauffman acquisition encompassed ~~5,040 gross (4,053 net)~~approximately 4,300 net acres ~~with rights~~of oil and gas leasehold interests and related assets in the D-J Basin of Colorado and net production of approximately 1,200 barrels of oil equivalent per day (BOED). The purpose of the transaction was to provide additional mineral acres upon which the Company could drill wells and produce hydrocarbons. It is believed that the transaction will improve the Company's cash flow.

The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of October 20, 2015. Transaction costs related to the Codell and Niobrara formations, and 2,400 gross (1,739 net) acres with rights to other formations including the Sussex, Shannon and J-Sand. Additionally, the Company acquired non-operated working interests in 17 horizontal wells and 73 operated vertical wellsacquisition were expensed as well as working interests in 11 non-operated vertical wells. The working interests in the horizontal wells range from 6% to 40% while the working interests in the vertical wells range from 5% to 100%.

incurred. The following allocation of the purchase price is preliminary and includes significant use of estimates. The fair values of the assets acquired and liabilities assumed are preliminary and are subject to revision as the Company continues to evaluate the fair value of this acquisition. Accordingly, the allocation will change as additional information becomes available and is assessed, and the impact of such changes may be material. The following table summarizes the preliminary purchase price and preliminary estimated fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price December 15, 2014
Consideration Given
Cash $ 74,221
Synergy Resources Corp. Common Stock (1) 48,434
Liabilities assumed, including asset retirement obligations 2,467
Total consideration given $ 125,122

Allocation of Purchase Price
Proved oil and gas properties (2) $ 51,400
Unproved oil and gas properties 73,722
Total fair value of oil and gas properties acquired $ 125,122



Preliminary Purchase Price	October 20, 2015
Consideration given:
Cash	$	35,045
Synergy Resources Corp. Common Stock (1)	49,840
Net liabilities assumed, including asset retirement obligations	299
Total consideration given	$	85,184

Preliminary Allocation of Purchase Price
Proved oil and gas properties (2)	$	46,342
Unproved oil and gas properties	37,766
Other assets, including accounts receivable	1,076
Total fair value of assets acquired	$	85,184

(1) The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of ~~December 15, 2014 (4,648,136~~October 20, 2015 (4,418,413 shares at ~~$10.42~~$11.28 per share).

(2) Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of ~~10%~~12%, and assumptions onregarding the timing and amount of future development and operating costs.

~~Table~~The results of ~~Contents~~

operations of the acquired assets from the October 20, 2015 closing date through November 30, 2015, representing approximately $0.6 million of revenue and $0.4 million of operating income, have been included in the Company's consolidated statement of operations for the three months ended November 30, 2015.

The following table presents the unaudited pro forma combined results of operations for the three ~~and nine~~ months ended ~~May 31,~~November 30, 2015 and 2014 as if the ~~Bayswater~~Kauffman transaction had occurred on September 1, ~~2013,~~2014, the first day of our ~~2014~~2015 fiscal year. The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock and cash, additional depreciation expense, costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

Three Months Ended
May 31,

Nine Months ended
May 31,

2015 2014 2015 2014

Oil and Gas Revenues $ 26,033 $ 26,766 $ 99,157 $ 71,550
Net income $ (2,481 ) $ 6,889 $ 25,102 $ 17,997

Earnings per common share
Basic $ (0.02 ) $ 0.08 $ 0.26 $ 0.22
Diluted $ (0.02 ) $ 0.08 $ 0.26 $ 0.22

~~Apollo and Trilogy transactions~~

During the year ended August 31, 2014, the Company closed on two transactions that qualified as Business Combinations under ASC 805. The initial accounting treatment of the transactions was based upon the preliminary analysis of the assets acquired. During the first fiscal quarter of 2015, the Company completed its analysis and finalized the allocation of purchase price to the assets acquired. The following tables present the final fair values.

On September 16, 2013, the Company entered into a definitive purchase and sale agreement with Trilogy Resources, LLC ("Trilogy"), for its interests in 21 producing oil and gas wells and approximately 800 net mineral acres (the "Trilogy Assets"). On November 12, 2013, the Company closed the transaction for a combination of cash and stock. Trilogy received 301,339 shares of the Company's common stock valued at $2.9 million and cash consideration of approximately $15.9 million. ~~No material transaction costs were incurred in connection with this acquisition.~~

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The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of November 12, 2013. The following table summarizes the final purchase price and the final fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price
November 12,
2013

Consideration Given
Cash $ 15,902
Synergy Resources Corp. Common Stock * 2,896

Total consideration given $ 18,798

Allocation of Purchase Price
Proved oil and gas properties $ 11,514
Unproved oil and gas properties $ 7,725
Total fair value of oil and gas properties acquired 19,239

Working capital $ (83 )
Asset retirement obligation (358 )

Fair value of net assets acquired $ 18,798

Working capital acquired was estimated as follows:
Accounts receivable 536
Accrued liabilities and expenses (619 )

Total working capital $ (83 )

* The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of November 12, 2013. (301,339 shares at $9.61 per share)

On August 27, 2013, the Company entered into a definitive purchase and sale agreement ("the Agreement"), with Apollo Operating, LLC ("Apollo"), for its interests in 38 producing oil and gas wells, partial interest (25%) in one water disposal well (the "Disposal Well"), and approximately 3,639 gross (1,000 net) mineral acres ("the Apollo Operating Assets"). On November 13, 2013, the Company closed the transaction for a combination of cash and stock. Apollo received cash consideration of approximately $11.0 million and 550,518 shares of the Company's common stock valued at $5.2 million. Following the acquisition of the Apollo Operating Assets, the Company acquired all other remaining interests in the Disposal Well (the "Related Interests") through several transactions with the individual owners of such interests. The Company acquired the Related Interests for approximately $3.7 million in cash consideration and 20,626 shares of the Company's common stock, valued at $0.2 million. ~~No material transaction costs were incurred in connection with this acquisition.~~

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The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of November 13, 2013. ~~The following table summarizes the final purchase price and the final fair values of assets acquired and liabilities assumed (in thousands):~~

Purchase Price
November 13,
2013

Consideration Given
Cash $ 14,688
Synergy Resources Corp. Common Stock * 5,432

Total consideration given $ 20,120

Allocation of Purchase Price
Proved oil and gas properties $ 13,284
Unproved oil and gas properties $ 7,577
Total fair value of oil and gas properties acquired 20,861

Working capital $ (507 )
Asset retirement obligation (234 )

Fair value of net assets acquired $ 20,120

Working capital acquired was estimated as follows:
Accounts receivable 662
Accrued liabilities and expenses (1,169 )

Total working capital $ (507 )

The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock prices on the measurement dates (including 550,518 shares at $9.49 per share on November 13, 2013 plus 20,626 shares at various measurement dates at an average per share price of $10.08).

The motivation for both the Trilogy and Apollo acquisitions was the expectation that each was accretive to cash flow and earnings per share. The acquisitions qualify as a business combination, and as such, the Company estimated the fair value of each property as of the acquisition date (the date on which the Company obtained control of the properties). Fair value measurements utilize assumptions of market participants. To determine the fair value of the oil and gas assets, the Company used an income approach based on a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. The Company determined the appropriate discount rates used for the discounted cash flow analyses by using a weighted-average cost of capital from a market participant perspective plus property-specific risk premiums for the assets acquired. The Company estimated property-specific risk premiums taking into consideration the Gas to Oil Ratio ("GOR") of the related reserves, among other items. Given the unobservable nature of the significant inputs, they are deemed to be Level 3 in the fair value hierarchy. The working capital assets acquired were determined to be at fair value due to their short-term nature.

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The preliminary analysis and allocation of the purchase price focused on the values inherent in the proved producing wells and the associated proved undeveloped reserves. All of the producing wells acquired in the transactions were vertical wells and the initial estimates allocated 100% of the fair value to proved properties associated with vertical well development. The final analysis also considered the additional value provided by the virtue of the ability to drill horizontal wells in the acquired acreage. Adding horizontal wells to the development plan required a further evaluation as to the classification of the horizontal reserves, as reserves classified as proved under a vertical well drilling plan may be classified differently under a horizontal drilling plan. In the subject acres, the horizontal well reserves are classified as unproved even though the vertical well reserves are proved. Thus, the final analysis attributed $15.3 million of fair value to unproved horizontal properties and $24.8 million of fair value to proved properties.

Differences between the preliminary allocation and final allocation of acquired fair value have been treated as a change in accounting estimate, and no retroactive adjustments were made to the previously reported financial statements. Furthermore, since the reclassification of $15.3 million from proved properties subject to amortization to unproved properties not subject to amortization represents approximately 2% of the full cost amortization base, no prior period adjustment was recorded during the current year.



	Three Months Ended November 30,
(in thousands)	2015			2014
Oil and gas revenues	$	27,354		$	44,748
Net (loss) income	$	(122,091	)	$	22,552

Net (loss) income per common share
Basic	$	(1.11	)	$	0.27
Diluted	$	(1.11	)	$	0.27


4.	Depletion, depreciation, accretion, and amortization ~~("DDA"~~(“DDA”)

Depletion, depreciation, accretion, and amortization consisted of the following (in thousands):

Three Months Ended
May 31,

Nine Months ended
May 31,

2015 2014 2015 2014
Depletion $ 16,200 $ 7,569 $ 47,849 $ 20,550
Depreciation and amortization 197 227 508 556
Total DDA Expense $ 16,397 $ 7,796 $ 48,357 $ 21,106



	Three Months Ended November 30,
	2015		2014
Depletion of oil and gas properties	$	14,376	$	16,304
Depreciation, accretion, and amortization	298		150
Total DDA Expense	$	14,674	$	16,454

Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter. For the three months ended ~~May 31,~~November 30, 2015, production of ~~738,357 barrels~~959 MBOE represented 1.5% of ~~oil equivalent ("BOE") represented 1.7% of the~~ estimated total proved reserves. For the ~~nine~~three months ended ~~May 31, 2015,~~November 30, 2014, production of ~~2,188,737 BOE~~753 MBOE represented ~~4.9%~~2.3% of ~~the~~ estimated total proved reserves.

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DDA expense was $15.30 per BOE and $21.84 per BOE for the three months ended November 30, 2015 and 2014, respectively.


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 the wells, and restore the drilling sites to their original use. The estimated present value of such obligations is 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. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. For the purpose of determining the fair value of ARO incurred during the periods, the Company used the following assumptions:

For The Nine Months Ended
May 31,
2015 2014
Inflation rate 3.9% 3.9 - 4.0%
Estimated asset life 25.0 - 39.0 years 20.0 - 40.0 years
Credit adjusted risk free interest rate 8.0% 8.0%

The following table summarizes the ~~change~~changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands):.

Asset retirement obligations, August 31, 2014 $ 4,730
  Liabilities incurred 744
  Liabilities assumed 1,913
  Accretion expense 385
Asset retirement obligations, May 31, 2015 $ 7,772



Asset retirement obligations, August 31, 2015	$	12,334
Obligations incurred with development activities	230
Obligations assumed with acquisitions	229
Accretion expense	262
Obligations discharged with asset retirements	(611		)
Revisions in previous estimates	—
Asset retirement obligations, November 30, 2015	$	12,444


6.	Revolving Credit Facility

Our production ~~increased~~decreased from ~~7,745 barrels of oil equivalent ("BOE") per day~~10,925 BOED for the ~~fiscal quarter ending February 28,~~three months ended August 31, 2015 to ~~8,026 BOE per day~~10,540 BOED for the ~~fiscal quarter ending May 31,~~three months ended November 30, 2015. The additional production volumes from recently completed wells ~~more than~~and the K.P. Kauffman acquisition did not offset the natural decline of our existing wells and the loss of non-operated production due to asset swaps. The increase was achieved despite continuing mid-stream constraints, high line pressures in the northern portion of the Wattenberg Field, and the loss of production from shut-in wells due to offset operator completion activities.wells.

Market Conditions

Market prices for our products significantly impact our revenues, net income, and cash flow. The market prices for crude oil and natural gas are inherently volatile. To provide historical perspective, the following table presents the average annual ~~New York Mercantile Exchange ("NYMEX")~~NYMEX prices for oil and natural gas for each of the last five fiscal years.

Years Ended August 31,
2014 2013 2012 2011 2010
Average NYMEX prices
Oil (per bbl) $ 100.39 $ 94.58 $ 94.88 $ 91.79 $ 76.65
Natural gas (per mcf) $ 4.38 $ 3.55 $ 2.82 $ 4.12 $ 4.45



	Years Ended August 31,
	2015		2014		2013		2012		2011
Average NYMEX prices
Oil (per Bbl)	$	60.65	$	100.39	$	94.58	$	94.88	$	91.79
Natural gas (per Mcf)	$	3.12	$	4.38	$	3.55	$	2.82	$	4.12

For the periods presented in this report, the following table presents the Reference Price (derived from average NYMEX prices weighted to reflect monthly sales volumes) as well as the differential between the Reference Price and the wellhead prices realized by us.

Three Months Ended Nine Months Ended
May 31, May 31,
Oil (NYMEX WTI)
2015 2014 2015 2014
Reference Price $ 55.23 $ 101.44 $ 64.97 $ 99.79
Realized Price $ 45.77 $ 90.91 $ 54.88 $ 90.13
Differential $ (9.46 ) $ (10.53 ) $ (10.09 ) $ (9.66 )

Gas (NYMEX Henry Hub)

Reference Price $ 2.90 $ 4.71 $ 3.32 $ 4.45
Realized Price $ 3.16 $ 5.15 $ 3.76 $ 5.34
Differential $ 0.26 $ 0.44 $ 0.44 $ 0.89



	Three Months Ended November 30,
	2015			2014
Oil (NYMEX WTI)
Average NYMEX Price	$	44.70		$	84.47
Realized Price	$	36.72		$	73.69
Differential	$	(7.98	)	$	(10.78	)

Gas (NYMEX Henry Hub)
Average NYMEX Price	$	2.36		$	3.94
Realized Price	$	2.49		$	4.74
Differential	$	0.13		$	0.80

Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX. The negative differential between the prices actually received by us at the wellhead, and the published indices reflects deductions imposed upon us by the purchasers for location and quality adjustments. We continue to negotiate with crude oil purchasers to obtain better differentials. With regard to the sale of natural gas and liquids, we ~~are~~were able to sell production at prices greater than the prices posted for dry gas, primarily because prices we receive include payment for the natural gas liquids produced with the gas.

~~Table of Contents~~Trends and Outlook

~~There has been a significant decline in the price of oil since the summer of 2014. As reflected in published data, the price for West Texas Intermediate (WTI) oil settled~~Oil traded at ~~$95.96/bbl~~$49.20 per Bbl on ~~Friday,~~Monday, August ~~29, 2014,~~31, 2015, the last ~~trading~~ day of our 2014 fiscal year. The price of WTI then declined 48% during the first six months of our fiscal year, settling at $49.76/bbl on Friday, February 27, 2015. The price of oil settled at $60.30/bbl on Friday, May 29, 2015, signaling a modest price recovery during our third fiscal quarter. The third quarter price remains approximately 37% below the benchmark price at the start of our 2015 fiscal ~~year. Our revenues, results~~year, but declined more than 20% through November 2015. This decline has resulted in a reduction of ~~operations, profitability~~operating cash flow and ~~future growth, and the carrying value of our oil and natural gas properties depend primarily on the prices we receive for our oil and natural gas production.~~

A decline in oil and natural gas prices will adversely affect our financial condition and results of operations. Furthermore, low oil and natural gas prices can result in an impairment of the value of our properties and the calculation of the "ceiling test" required under the accounting principles for companies following the "full cost" method of accounting. We review our oil and gas properties for impairment at each quarterly reporting period. For the third quarter, thecontributed to a ceiling test ~~resulted in an~~ impairment charge of ~~$3.0 million, and future impairments may occur.~~

~~RESULTS OF OPERATIONS~~

~~For the three months ended May 31, 2015, compared to the three months ended May 31, 2014~~

For the three months ended May 31, 2015, we reported a net loss of $2.5 million compared to net income of $7.2 million during the three months ended May 31, 2014, driven in part by a $3.0 million full cost ceiling impairment, as discussed previously under the heading "Significant Developments." Loss per basic and diluted share was $0.02 for the three months ended May 31, 2015 compared to net income of $0.09 per basic and diluted share for the three months ended May 31, 2014. Other significant differences between the two periods include the rapid growth in reserves, producing wells and daily production totals, as well as the impact of changing prices on our revenues and our commodity hedge positions. The following discussion expands upon significant items of inflow and outflow that affected results of operations.

~~Oil and Gas Production and Revenues~~ ~~– For the three months ended May 31, 2015 we recorded total oil and gas revenues of $26.0 million compared to $25.7~~$125.2 million for the three months ended ~~May 31, 2014,~~November 30, 2015. Subsequent to the end of the quarter, crude oil prices have continued to decline, making it likely we will need to recognize additional impairment charges in the future. As an ~~increase~~example, had the ceiling test computation used the lower price deck of $0.3$38.93 per barrel and $2.54 per Mcf as derived from market conditions subsequent to November 30, 2015, an additional impairment of approximately $74 million ~~or 1.4%.~~would be recorded.

Year over year, we added 36 net horizontal wells, including 3 (net) Bayswater horizontal wells, increasing our reserves, producing wells and daily production totals. Although the three months ended May 31, 2015 yielded almost twice as much BOE production compared to the three months ended May 31, 2014, our revenues during the 2015 quarter increased only modestly as a result of declining oil prices.

~~Net~~A continuing decline in oil and gas ~~production~~prices (i) will reduce our cash flow which, in turn, will reduce the funds available for exploring and replacing oil and gas reserves, (ii) will potentially reduce our current Revolver borrowing base capacity and increase the ~~three months ended May 31, 2015 averaged 8,026 BOE per day. For~~difficulty of obtaining equity and debt financing and worsen the ~~three months ended May 31, 2014, production averaged 4,120 BOE per day, a year-over-year increase of 95%. As a further comparison, average BOE production was 7,745 per day during~~terms on which such financing may be obtained, (iii) will reduce the ~~quarter ended February 28, 2015, a quarter-over-quarter increase of 4%. When the price~~number of oil ~~declined in 2014, we temporarily postponed~~and gas prospects which have reasonable economic returns, (iv) may cause us to allow leases to expire based upon the ~~final completion~~value of ~~certain wells under development. The majority of the temporarily delayed wells has either commenced production or is expected to commence production during the third and fourth quarters.~~

Our revenues are sensitive to changes in commodity prices. As shown in the following table, there has been a decrease of nearly 48% in average realized prices between the periods presented. This decline in average sales prices mostly offset the effects of increased production.

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~~The following table presents actual realized prices, without the effect of hedge transactions. The impact of hedge transactions is presented later in this discussion.~~

~~Key production information is summarized in the following table:~~

Three Months Ended May 31,
2015 2014 Change
Production:
Oil (Bbls¹)
448,906 232,571 93 %
Gas (Mcf²)
1,736,702 879,062 98 %

Total production in BOE³
738,357 379,081 95 %

Revenues (in thousands):
Oil $ 20,546 $ 21,143 -3 %
Gas 5,487 4,529 21 %
$ 26,033 $ 25,672 1 %
Average sales price:
Oil $ 45.77 $ 90.91 -50 %
Gas $ 3.16 $ 5.15 -39 %
BOE $ 35.26 $ 67.72 -48 %

¹ ~~"Bbl" refers to one stock tank barrel, or 42 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.~~

² ~~"Mcf" refers to one thousand cubic feet of natural gas.~~

³ ~~"BOE" refers to barrel of oil equivalent, which combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil.~~

~~Lease Operating Expenses ("LOE")~~ ~~– Direct operating costs of producing~~potential oil and ~~natural~~ gas ~~are reported as follows (in thousands):~~

Three Months Ended
May 31,
2015 2014
Production Costs $ 3,533 $ 2,252
Workover 37 51
Total LOE $ 3,570 $ 2,303

Per BOE:
Production costs $ 4.79 $ 5.94
Workover 0.05 0.13
Total LOE $ 4.84 $ 6.07

~~Lease operating and workover costs tend to increase or decrease primarily~~reserves in relation to the ~~number~~costs of ~~wells~~exploration, (v) may result 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. During the third quarter of fiscal 2015, we continued to experience elevated production cost per BOE in connection with additional costs to operate horizontal wells. Production from certain wells was intermittently restricted during the quarter as midstream infrastructure providers struggled to increase the efficiency and capacity of the gas gathering system. We continue to work diligently to mitigate production difficulties within the Wattenberg Field.

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~~Production taxes~~ – During the three months ended May 31, 2015, production taxes were $2.2 million, or $3.04 per BOE, compared to $2.4 million, or $6.27 per BOE, during the three months ended May 31, 2014. Taxes tend to increase or decrease primarily based on the value ofmarginally productive oil and gas ~~sold. As~~wells being abandoned as non-commercial, and (vi) may cause a ~~percent of revenues, taxes were 8.6% and 9.3% for~~ceiling test impairment. However, price declines reduce the ~~three months ended May 31, 2015 and 2014, respectively.~~

~~Depletion, Depreciation, and Amortization ("DDA")~~ ~~– The following table summarizes the components of DDA:~~

Three Months Ended
May 31,
(in thousands) 2015 2014
Depletion $ 16,200 $ 7,569
Depreciation and amortization 197 227
Total DDA $ 16,397 $ 7,796

DDA expense per BOE $ 22.21 $ 20.57

For the three months ended May 31, 2015, depletion of oil and gas properties was $22.21 per BOE compared to $20.57 per BOE for the three months ended May 31, 2014. The increase in the DDA rate was the result of an increase in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning-of-quarter estimated total reserves determine the depletion rate. For both 2015 and 2014, production represented 1.7% of the reserve base. Since DDA expense represents amortization of historical costs, our recently implemented reductions in well costs are not fully reflected in the rate.

~~Full cost ceiling impairment –~~ During the three months ended May 31, 2015, we recognized an impairment of $3.0 million, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling. See "Oil and Gas Properties, including Ceiling Test," included in the discussion of Critical Accounting Policies below.

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~~General and Administrative ("G&A")~~ ~~–The following table summarizes G&A expenses incurred and capitalized during the periods presented:~~

Three Months Ended
May 31,
(in thousands) 2015 2014
G&A costs incurred $ 4,372 $ 2,238
Capitalized costs (486 ) (300 )
Total G&A $ 3,886 $ 1,938

G&A Expense per BOE $ 5.26 $ 5.11

G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. In an effort to minimize overhead costs, we employ a total staff of 36 employees and use consultants, advisors, and contractors to perform certain tasks when it is cost effective.

Although G&A costs have increased as we grow the business, we strive to maintain an efficient overhead structure. For the quarter ended May 31, 2015, G&A was $5.26 per BOE compared to $5.11 per BOE for the quarter ended May 31, 2014.

Our G&A expense for the quarter ended May 31, 2015 includes stock-based compensation of $1.4 million compared to $0.7 million for the quarter ended May 31, 2014. Stock-based compensation includes a calculated value for stock options or shares of common stock that we grant for compensatory purposes. It is a non-cash charge, which, for stock options, is calculated using the Black-Scholes-Merton option pricing model to estimate the fair value of options. Amounts are pro-rated over the vesting terms of the option agreements, which are generally three to five years.

~~Pursuant to the requirements under the full cost accounting method~~competition for oil and gas properties ~~we identify all general~~ and ~~administrative costs that relate directly to~~correspondingly reduce the ~~acquisition of undeveloped mineral~~prices paid for leases and the development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from 2014 to 2015 reflects our increasing activities to acquire leases and develop the properties.prospects.

~~Commodity derivative gains (losses) –~~ As more fully described in the paragraphs titled "Oil and Gas Commodity Contracts" and "Hedge Activity Accounting," located in "Liquidity and Capital Resources," we use commodity contracts to mitigate the risks inherent in the price volatility of oil and natural gas. For the quarter ended May 31, 2015, we realized a cash settlement gain of $7.1 million, including gains of $2.1 million from the settlement of contracts at their scheduled maturity dates and gains of $5.0 million from the early liquidation of "in-the-money" contracts. For the prior year quarter ended May 31, 2014, we realized a cash settlement loss of $826,000.

In addition, for the quarter ended May 31, 2015, we recorded an unrealized loss of $8.3 million to recognize the mark-to-market change in fair value of our commodity contracts for the quarter ended May 31, 2015. In comparison, in the quarter ended May 31, 2014, we reported an unrealized loss of $179,000. Unrealized gains and losses are non-cash items.

~~Income taxes~~ – We reported income tax benefit of $1.8 million for the three months ended May 31, 2015, calculated at an effective tax rate of 42%. During the comparable prior year period, we reported income tax expense of $3.0 million, calculated at an effective tax rate of 30%. For both periods, we anticipateOther factors that ~~the tax liability~~ will be substantially deferred into future years. During both fiscal years the effective tax rate differed from the federal and state statutory rate primarily by the impact of deductions for percentage depletion.

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~~For the nine months ended May 31, 2015, compared to the nine months ended May 31, 2014~~

For the nine months ended May 31, 2015, we reported net income of $23.3 million compared to net income of $18.4 million during the nine months ended May 31, 2014. Net income per basic and diluted share were $0.26 and $0.25, respectively, for the nine months ended May 31, 2015 compared to earnings per share of $0.24 per basic and diluted share for the nine months ended May 31, 2014. Revenues increased $24.3 million during the nine months ended May 31, 2015 compared to the comparable period ended May 31, 2014 due to rapid growth in reserves, producing wells and daily production totals, as discussed previously. As of May 31, 2015, we had 558 gross producing wells, compared to 388 gross producing wells as of May 31, 2014. However, although our production more than doubled during the comparable periods, our revenues during the 2015 period increased only 35.8% as a result of declining oil and gas prices. The impact of changing prices on our commodity hedge positions also drove significant differences inmost significantly affect our results of operations ~~between~~include (i) activities on properties that we operate, (ii) the ~~two periods.~~marketability of our production, (iii) our ability to satisfy our financial obligations, (iv) completion of acquisitions of additional properties and reserves, and (v) competition from larger companies. Our revenues will also be significantly impacted by our ability to maintain or increase oil or gas production through exploration and development activities.

The ~~following discussion expands upon significant items of inflow and outflow that affected results of operations.~~

~~Oil and Gas Production and Revenues~~ – For the nine months ended May 31, 2015, we recorded total oil and gas revenues of $92.3 million compared to $68.0 million for the nine months ended May 31, 2014, an increase of $24.3 million or 35.8%.

During the nine months ended May 31, 2015, our BOE production was 114% higher than during the same period in 2014, largely as a result of increases in the number of gross producing wells. However, our revenues are sensitive to changesdecline in commodity ~~prices. As shown~~prices has led to a corresponding decline in service costs, which directly relate to our drilling and completion costs. On average, we reduced drilling and completion costs during fiscal 2015 due to a combination of optimizing well designs, moving to day-rate drilling, negotiating lower contract rates for drilling rigs, and securing lower completion costs. These cost reductions helped support well-level economics in spite of the ~~following table, there has been a decrease of approximately 37%~~severe price drop in ~~average realized BOE prices between the periods presented. These price declines have had a direct impact on the amount of revenue we have been able to achieve, despite our production growth.~~

~~The following table presents actual realized prices, without the effect of hedge transactions. The impact of hedge transactions is presented later in this discussion.~~

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~~Key production information is summarized in the following table:~~

Nine Months Ended May 31,
2015 2014 Change
Production:
Oil (Bbls¹)
1,328,031 605,471 119 %
Gas (Mcf²)
5,164,238 2,508,311 106 %

Total production in BOE³
2,188,737 1,023,523 114 %

Revenues (in thousands):
Oil $ 72,880 $ 54,569 34 %
Gas 19,404 13,397 45 %
$ 92,284 $ 67,966 36 %
Average sales price:
Oil $ 54.88 $ 90.13 -39 %
Gas $ 3.76 $ 5.34 -30 %
BOE $ 42.16 $ 66.40 -37 %

¹ ~~"Bbl" refers to one stock tank barrel, or 42 U.S. gallons liquid volume in reference to~~ crude ~~oil or other liquid hydrocarbons.~~

² ~~"Mcf" refers to one thousand cubic feet of natural gas.~~

³ ~~"BOE" refers to barrel of oil equivalent, which combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil.~~

~~Lease Operating Expenses ("LOE")~~ ~~– Direct operating costs of producing~~ oil and natural gas ~~are reported as follows (in thousands):~~we experienced over the year. We continue to strive to reduce drilling and completion costs going forward to offset the negative impacts associated with lower commodity prices, but we do not believe we can achieve the same percentage reduction in costs during fiscal 2016, and well-level rates of return may be lower, particularly if commodity prices continue to decline.

Nine Months Ended
May 31,
2015 2014
Production Costs $ 10,227 $ 5,252
Workover 73 130
Total LOE $ 10,300 $ 5,382

Per BOE:
Production costs $ 4.68 $ 5.13
Workover 0.03 0.14
Total LOE $ 4.71 $ 5.27

~~Lease operating and workover costs tend~~From time to ~~increase or decrease primarily in relation to the number of wells in~~time, our production ~~and, to a lesser extent, on fluctuation in oil field service costs and changes~~has been adversely impacted by high natural gas gathering line pressures, especially in the ~~production mix~~northern area of ~~crude oil~~the Wattenberg Field. Where it is cost effective, we install wellhead compression to enhance our ability to inject gas into the gathering system and ~~natural gas.~~

~~During~~in some instances install larger gathering lines to help mitigate the ~~first nine months of fiscal 2015, we continued to experience elevated production cost per BOE in connection with additional costs to~~impacts. Additionally, midstream companies that operate ~~horizontal wells. Production from certain wells was intermittently restricted during the period as midstream infrastructure providers struggled to increase the efficiency and capacity of~~ the gas gathering ~~system. We~~pipelines in the area continue to ~~work diligently~~make significant capital investments to ~~mitigate~~increase their capacities. While these actions have helped reduce overall line pressures in the field, several of our producing locations have been shut-in on occasion due to line pressures exceeding system limits.

We are evaluating the use of oil gathering lines to certain production ~~difficulties within~~locations. We anticipate these gathering systems would be owned and operated by independent third party companies, but we would commit specific wellhead production to these systems. We believe oil gathering lines would have several benefits including, a) reduced need to use trucks to gather our oil, thereby reducing truck traffic in and around our production locations, b) potentially lower gathering costs as pipeline gathering tends to be more efficient, c) less on-site oil storage capacity, resulting in lower production location facility costs, and d) generally less noise and dust.

Oil transportation and takeaway capacity has recently increased with the expansion of certain interstate pipelines servicing the Wattenberg ~~Field.~~

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~~Production taxes~~ ~~– During~~field. This has reversed the nine months ended May 31, 2015, production taxes were $8.6 million, or $3.92 per BOE, compared to $6.6 million, or $6.49 per BOE, during the nine months ended May 31, 2014. Taxes tend to increase or decrease primarily based on the valueprior imbalance of oil production exceeding the combination of local refinery demand and ~~gas sold. As a percent~~the capacity of ~~revenues, taxes were approximately 9.3%~~pipelines to move the oil to other markets. Depending on transportation commitments, local refinery demand, and ~~9.8% for the nine months ended May 31, 2015 and 2014, respectively.~~

~~Depletion, Depreciation, and Amortization ("DDA")~~ ~~– The following table summarizes the components of DDA:~~

Nine Months Ended
May 31,
(in thousands) 2015 2014
Depletion $ 47,849 $ 20,550
Depreciation and amortization 508 556
Total DDA $ 48,357 $ 21,106

DDA expense per BOE $ 22.09 $ 20.62

For the nine months ended May 31, 2015, depletion of oil and gas properties was $22.09 per BOE compared to $20.62 for the nine months ended May 31, 2014. The increase in the DDA rate was the result of an increase in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio ofour production volumes, for the quarter to beginning-of-quarter estimated total reserves determine the depletion rate. For the nine months ended May 31, 2015, production represented 4.9% of the reserve base compared to 4.5% for the nine months ended May 31, 2014. Since DDA expense represents the amortization of historical costs, our recently implemented reductions in well costs are not fully reflected in the rate.

~~Full cost ceiling impairment –~~ ~~During the nine months ended May 31, 2015,~~ we recognized an impairment of $3.0 million, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling. See "Oil and Gas Properties, including Ceiling Test," included in the discussion of Critical Accounting Policies below.

~~General and Administrative ("G&A")~~ ~~–The following table summarizes G&A expenses incurred and capitalized during the periods presented:~~

Nine Months Ended
May 31,
(in thousands) 2015 2014
G&A costs incurred $ 13,698 $ 7,797
Capitalized costs (1,623 ) (921 )
Total G&A $ 12,075 $ 6,876

G&A expense per BOE $ 5.52 $ 6.72

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Our G&A expense for the nine months ended May 31, 2015 includes stock-based compensation of $3.3 million compared to $1.6 million for the nine months ended May 31, 2014. As discussed previously, stock-based compensation is a non-cash charge related to options we grant for compensatory purposes and is based on a calculated value using the Black-Scholes-Merton option pricing model. See also Note 11 to our financial statements.

As discussed previously, pursuant to the full cost accounting method for oil and gas properties, we capitalize into the full cost pool all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the development of properties. The increase in capitalized costs between the 2014 and 2015 periods reflects our increasing activities to acquire leases and develop the properties.

~~Commodity derivative gains (losses) –~~ As more fully described in the paragraphs titled "Oil and Gas Commodity Contracts" and "Hedge Activity Accounting" located in "Liquidity and Capital Resources," we use commodity contracts to mitigate the risks inherent in the price volatility of oil and natural gas. For the nine months ended May 31, 2015, we realized a cash settlement gain of $20.9 million, including gains of $11.3 million from the settlement of contracts at their scheduled maturity dates and gains of $9.6 million from the early liquidation of "in-the-money" contracts. In comparison, in the nine months ended May 31, 2014, we realized a cash settlement loss of $1.4 million.

In addition, for the nine months ended May 31, 2015, we recorded an unrealized gain of $5.6 million to recognize the mark-to-market change in fair value of our commodity contracts for the period. In comparison, in the nine months ended May 31, 2014, we reported an unrealized gain of $0.7 million. Unrealized gains and losses are non-cash items.

~~Income taxes~~ – We reported income tax expense of $13.1 million for the nine months ended May 31, 2015, calculated at an effective tax rate of 36%. During the comparable prior year period, we reported income tax expense of $8.8 million, calculated at an effective tax rate of 32%. For both periods, it appears that the tax liability will be substantially deferred into future years. During both fiscal years the effective tax rate differed from the federal and state statutory rate primarily by the impact of deductions for percentage depletion.

~~For tax purposes, we have a net operating loss ("NOL") carryover of $42.7 million, which is available to offset future taxable income. The NOL will begin to expire, if not used, in 2031.~~

Each year, management evaluates all the positive and negative evidence regarding our tax position and reaches a conclusion on the most likely outcome. During 2015 and 2014, we concluded that it was more likely than not that we wouldmay be able to ~~realize a benefit from~~reduce the ~~net operating loss carry-forward,~~negative differential we have historically realized on our oil production. We anticipate there will continue to be excess pipeline takeaway capacity as additional pipelines are expected to begin operations in the second half of calendar 2016. Further details regarding posted prices and ~~have therefore included it~~average realized prices are discussed in ~~our inventory of deferred tax assets.~~

the section entitled “Market Conditions,” presented in this Item 2.

~~Table~~Other than the foregoing, we do not know of ~~Contents~~

~~LIQUIDITY AND CAPITAL RESOURCES~~any trends, events, or uncertainties that will have had or are reasonably expected to have a material impact on our sales, revenues, expenses, liquidity, or capital resources.

Liquidity and Capital Resources

Historically, our primary sources of capital have been net cash provided by the sale of equity and debt securities, cash flow from operations, proceeds from the sale of properties, and borrowings under bank credit facilities. Our primary use of capital has been for the exploration, development, and acquisition of oil and natural gas properties. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us.

We believe our capital resources, including cash on hand, amounts available under our revolving credit facility, and cash flow from operating activities, will be sufficient to fund our planned capital expenditures and operating expenses for the next twelve months. To the extent actual operating results differ from our anticipated results, or available borrowings under our credit facility are reduced, or we experience other unfavorable events, our liquidity could be adversely impacted. Terms of future financings may be unfavorable, and we cannot assure investors that funding will be available on acceptable terms.

As operator of the majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled and/or completed. This allows us to modify our capital spending as our financial resources allow and market conditions support. Additionally, our relatively low utilization of debt enhances our financial flexibility as it provides a potential source of future liquidity and enables us to make capital decisions with limited restrictions imposed by debt covenants, lender oversight and/or mandatory repayment schedules.

Sources and Uses

Our sources and uses of capital are heavily influenced by the prices that we receive for our production. ~~Over~~During the ~~past year,~~first fiscal quarter of 2016, the ~~NYMEX—WTI~~NYMEX-WTI oil price ranged from a high of ~~$108~~$49.20 per Bbl on Monday, August 31, 2015, the last day of our 2015 fiscal year, to a ~~recent~~ low of ~~$43~~$39.27 per Bbl near the end of November 2015, while the ~~NYMEX—Henry~~NYMEX-Henry Hub natural gas price ranged from a high of ~~$ 4.71~~$2.76 per MMBtu in the middle of September to a ~~recent~~ low of ~~$2.50~~$2.03 per ~~MMBtu.~~MMBtu near the end of October. These markets will likely continue to be volatile in the future. To deal with the volatility in commodity prices, we maintain a flexible capital investment program and seek to maintain a high operating interest in our leaseholds with limited long-term capital commitments. This enables us to accelerate or decelerate our activities quickly in response to changing industry environments. ~~Additionally, we believe our conservative use of leverage and corresponding strong balance sheet helps mitigate the potentially negative impact from lower commodity prices.~~

At ~~May 31,~~November 30, 2015, we had cash and cash equivalents of ~~$190.2~~$80.7 million and an outstanding balance of ~~$141.0~~$78.0 million under our revolving credit facility, leaving $85.0 million available under our revolving credit facility. Our sources and (uses) of funds for the ~~nine~~three months ended ~~May 31,~~November 30, 2015 and 2014 are summarized below (in thousands):



	Three Months Ended November 30,
	2015			2014
Cash provided by operations	$	21,087		$	34,435
Acquisitions and development of oil and gas properties and equipment	(74,118		)	(66,137		)
Cash used in other investing activities	—			(6,250		)
Cash (used in) provided by equity financing activities	(154		)	10,310
Net borrowings on Revolver	—			40,000
Net (decrease) increase in cash and equivalents	$	(53,185	)	$	12,358

Nine Months Ended
May 31,
2015 2014
Cash provided by operations $ 86,942 $ 46,745
Net acquisition of oil and gas properties and equipment (238,207 ) (111,451 )
Short-term investments - 60,018
Equity financing activities 205,017 �� 33,204
Net borrowings 101,700 -
Net increase in cash and cash equivalents $ 155,452 $ 28,516

Net cash provided by operating activities was ~~$86.9~~$21.1 million and ~~$46.7~~$34.4 million for the ~~nine~~three months ended ~~May 31,~~November 30, 2015 and 2014, respectively. The ~~significant improvement~~decline in cash from operating activities reflects the ~~operating contribution from new wells that were drilled and producing wells that were acquired.~~

~~During the nine months ended May 31, 2015, we received cash proceeds of $15.4 million from the exercise of Series C warrants. As of May 31, 2015, all Series C warrants had been exercised.~~

During the nine months ended May 31, 2015, we also received cash proceeds of approximately $190.8 million (after underwriting discounts, commissions and expenses) from our public offering of 18,613,952 shares (including the shares sold pursuant to an over-allotment option exerciseddecline in commodity prices which was partially offset by the ~~underwriters) at a price to the public of $10.75 per share. We plan to use these proceeds to fund additional asset acquisitions~~increase in ~~the Wattenberg Field which may become available from time to time, to pay down outstanding indebtedness under our revolving credit facility and for corporate purposes, including working capital.~~

During the first nine months of our 2015 fiscal year, we drew net proceeds of $101.7 million under our revolving credit facility, including $66.2 million drawn concurrently with the December 15, 2014 Bayswater acquisition. Subsequent to May 31, 2015, we repaid $54 million on this revolving credit facility, reducing the total outstanding principal balance to $87 million at July 1, 2015.

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production.

Credit Arrangements

We maintain a borrowing arrangement with a banking syndicate. The arrangement, in the form of a revolving credit facility, was most recently amended with the Sixth Amendment to the credit facility on June 2, 2015. The arrangement provides for a maximum loan commitment of $500 million; however, the maximum amount we can ~~borrow~~have outstanding at any one time is subject to a borrowing base limitation, which stipulates that we may borrow up to the lesser of the maximum loan commitment or the borrowing base. The borrowing base can increase or decrease based upon the value of the collateral, which secures any amounts borrowed under the line of credit. ~~For the most part, the~~The value of the collateral will generally be derived ~~utilizing~~with reference to the estimated future net cash flows from our proved oil and gas reserves, discounted by 10%. Amounts borrowed under the facility are secured by substantially all of our producing wells and developed oil and gas leases.

As of ~~July 1,~~November 30, 2015, our borrowing base was ~~$175~~$163 million, and we had ~~$87~~$78.0 million outstanding under the facility. The maturity date of the ~~borrowing arrangement~~facility is December 15, 2019. The next semi-annual redetermination of the borrowing base has been rescheduled for January 2016.

Interest on our revolving line of credit accrues at a variable rate, which will equal or exceed the minimum rate of 2.5%. The interest rate pricing grid contains a graduated escalation ~~in applicable margin~~ for increased utilization.

Capital Expenditures

The majority of capital expenditures during the three months ended November 30, 2015 were associated with the acquisition of the Kauffman assets and the costs of drilling and completing wells that we operate. As of November 30, 2015, we had drilled, completed and brought into productive status 5 wells in our 2016 drilling program. In addition, we had drilled 25 gross (22 net) wells that had not been brought into productive status. All of the wells in progress are scheduled to commence production before August 31, 2016.

~~Reconciliation of Cash Payments~~With respect to ~~Capital Expenditures~~our ownership interest in wells operated by other companies, we participated in drilling and completion activities on 7 gross (less than 1 net) wells during the first quarter.

Capital expenditures reported in the statement of cash flows are calculated on a strict cash basis, which differs from the ~~"all-inclusive"~~accrual basis used to calculate other amounts reported in our financial statements. Specifically, cash payments for acquisition of property and equipment as reflected in the statement of cash flows excludes non-cash capital expenditures and includes an adjustment (plus or minus) to reflect the timing of when the capital expenditure obligations are incurred and when the actual cash payment is made. On the ~~"all-inclusive"~~accrual basis, capital expenditures totaled ~~$254.6~~$134.7 million and ~~$146.5~~$64.2 million for the ~~nine~~three months ended ~~May 31,~~November 30, 2015 and 2014, respectively. A reconciliation of the differences between cash payments and the ~~"all-inclusive"~~accrual basis amounts is summarized in the following table (in thousands):

Nine Months Ended
May 31,
2015 2014
Cash payments for capital expenditures $ 238,207 $ 112,155
Accrued costs, beginning of period (71,849 ) (25,491 )
Accrued costs, end of period 26,491 47,489
Non-cash acquisitions, common stock 58,968 11,185
Other 2,781 1,117
All-inclusive capital expenditures $ 254,598 $ 146,455

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	Three Months Ended November 30,
	2015			2014
Cash payments for acquisition	$	35,045		$	—
Cash payments for capital expenditures	39,073			66,137
Accrued costs, beginning of period	(33,071		)	(71,849		)
Accrued costs, end of period	41,746			69,511
Non-cash acquisitions, common stock	49,840			—
Other	2,056			383
Accrual basis capital expenditures	$	134,689		$	64,182

~~Capital Expenditures~~

The majority of capital expenditures during the nine months ended May 31, 2015, were associated with the acquisition of the Bayswater assets and the costs of drilling and completing wells that we operate. As of May 31, 2015, we had drilled, completed and brought into productive status 19 wells in our 2015 drilling program. In addition, we had drilled 28 gross (26 net) wells that had not been brought into productive status. Approximately 20 of the wells in progress are scheduled to commence production before August 31, 2015.

~~With respect to our ownership interest in wells operated by other companies, we participated in drilling and completion activities on 45 gross (4.7 net) wells.~~

Capital Requirements

Our primary need for cash will be to fund our drilling and acquisition programs for the remainder of the fiscal year ending August 31, 2015, and the fiscal year ending August 31, 2016. Our cash requirements have increased significantly since May 2013, when we implemented our horizontal drilling program. Standard-length horizontal wells we drilled early in the fiscal year are estimated to cost between $3.5 million and $3.8 million each. However, as commodity prices have dropped, we have negotiated lower costs from our service providers and revised our completion design and we are now budgeting that the remaining standard length lateral wells to be drilled this fiscal year will cost between $2.9 million and $3.5 million each. In order to maximize the efficient use of our capital, we have reduced the amount of non-operated working interests in wells operated by others, either by swapping interests when appropriate or by outright selling of interests.

Our updated fiscal 2015 plan anticipates drilling and completing 39 operated wells and exiting 2015 with 12 wells in various stages of completion. We expect that we will participate in 5 net non-operated wells. Our total fiscal 2015 budget remains at $270 million, with $190 million to $195 million allocated to drilling activities.

Our preliminary capital expenditure plan for 2016 includes spending $220 million to $240 on operated horizontal wells, $15 million to $25 million on non-operated wells, and $10 million to $15 million for additional leasehold and seismic activities.

As has been our historical practice, we regularly review capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service costs and drilling success. Our level of exploration, development, and acreage expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows, and development results, among other factors.

Our primary need for capital will be to fund our anticipated drilling and completion activities as well as any acquisitions we may complete during the remainder of our fiscal year ending August 31, 2016.

While our preliminary capital expenditure plan continues to anticipate the use of one drilling rig during the remainder of fiscal 2016, as has been our historical practice, we regularly review capital expenditures throughout the year and will adjust our program based on changes in commodity prices, service costs, drilling success, and capital availability. Our total anticipated fiscal 2016 capital program remains between $115 million and $135 million including leasing activities, but excluding any potential acquisitions that we may execute.

For the near term, we believe that we have sufficient liquidity to fund our needs through cash on hand, cash flow from operations, and additional borrowings available under our revolving credit facility. However, to meet all of our long-term goals, we may need to raise additional funds to drill new wells through the sale of our securities, from our revolving credit facility or from third parties willing to pay our share of drilling and completing 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.

Oil and Gas Commodity Contracts

We use derivative contracts to ~~hedge against~~mitigate a portion of our exposure to potentially adverse market changes in commodity prices and the ~~variability in~~associated impact on our expected future cash ~~flows created by short-term price fluctuations associated with the sale of future oil and gas production.~~flows. We ~~typically~~generally enter into contracts covering between 45% and 85% of the anticipated production from our proved developed producing reserves, as projected in our most recent semi-annual reserve report, for a period of 24 months. At ~~May 31,~~November 30, 2015, we had open positions covering 1.1 million barrels of oil and ~~3.7 million mcf~~2,692 MMcf of natural gas. We do not use derivative instruments for speculative purposes.

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Our commodity derivative instruments may include but are not limited to ~~"collars", "swaps",~~“collars,” “swaps,” and ~~"put"~~“put” positions. Our ~~hedging~~derivative strategy, including ~~how much anticipated production we hedge, whether we hedge oil and/~~the associated volumes, the commodity, and the relevant reference price or ~~natural gas, and at what~~ prices, ~~we hedge,~~ is based in part on our view of expected future market conditions and our analysis of well-level economic return potential. In addition, our use of ~~hedging~~derivative contracts is subject to stipulations set forth in our credit ~~facility as amended.~~facility.

During periods of significant price declines, for settled contracts structured as "collars", we will receive settlement payments from the contracts' counterparties for the difference between the contracted "floor" price and the average posted price for the contract period. For settled "swaps," we will receive the difference between the contracted swap price and the average posted price for the contract period. For settled "put" contracts, we will receive the difference between the put's strike price and the average posted price for the contract period. If we decide to liquidate an "in-the-money" position prior to settlement date, we will receive the approximate fair value of the contract at that time. These realized gains increase our reported net income for the period in which they are recognized.

Conversely, during periods of significant price increases, upon settlement we would be obligated to pay the counterparties the difference between the contract's "ceiling" and/or swap price and the average posted price for the contract period. If liquidated prior to settlement, we would pay the approximate fair market value to close the position at that time. Losses associated with puts that expire out-of-the-money are simply the original premium paid for the contract and are recognized upon expiration. These realized losses reduce our reported net income for the period in which they are recognized.

The fair values of our open, but not yet settled, derivative contracts are estimated by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors, as well as other relevant economic measures. We compare the valuations calculated by us to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or us, as appropriate.

The mark-to-market fair value of the open commodity derivative contracts will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. Higher underlying commodity price volatility will generally lead to higher volatility in our unrealized gains and losses and by association, the fair value of our commodity derivative contracts. These unrealized gains and losses will also impact our net income in the period recorded.

~~Hedge Activity Accounting~~

We do not designate our commodity contracts as accounting hedges. Accordingly, we use mark-to-market accounting to value the portfolio at the end of each reporting period. Mark-to-market accounting can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility in the past and are likely to experience it in the future. Mark-to-market accounting treatment results in volatility of our results as unrealized gains and losses from derivatives are reported. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate lower wellhead ~~revenues~~prices in the future while losses indicate higher future wellhead ~~revenues.~~prices.

During the three months ended November 30, 2015, we reported an unrealized commodity activity gain of $2.5 million. Unrealized gains and losses are non-cash items. We also reported a realized gain of $0.7 million, representing the cash settlement proceeds for contracts settled during the period, net of amortization of cash premiums paid for commodity contracts.

At ~~May 31,~~November 30, 2015, we estimated that the fair value of our various commodity derivative contracts was a net asset of ~~$8.9~~$7.3 million. We value these contracts using fair value methodology that considers various inputs including a) quoted forecast prices, b) time value, c) volatility factors, d) counterparty risk, and e) other relevant factors. The fair value of these contracts as estimated at ~~May 31,~~November 30, 2015 may differ significantly from the realized values at their respective settlement dates.

Our commodity derivative contracts as of November 30, 2015 are summarized below:

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	Volumes		Average Collar Prices ⁽¹⁾		Average Put Prices ⁽¹⁾
Month	Oil (Bbl)	Gas (MMBtu)	Average Oil (Bbl) Price	Average Gas (MMBtu) Price	Average Oil (Bbl) Price	Average Gas (MMBtu) Price
Dec 1 to Dec 31, 2015	50,000	172,000	N/A	$3.02 - $3.65	$51.00	N/A
Jan 1 to Dec 31, 2016	660,000	1,680,000	$45.00 - $65.00	$3.03 - $3.47	$48.57	N/A
Jan 1 to Dec 31, 2017	400,000	840,000	$45.00 - $70.00	$2.64 - $3.48	$52.50	N/A

⁽¹⁾ Price is at NYMEX WTI and NYMEX Henry Hub and CIG Rocky Mountain.

Results of Operations

Material changes of certain items in our statements of operations included in our financial statements for the periods presented are discussed below.

For the three months ended November 30, 2015, compared to the three months ended November 30, 2014

For the three months ended November 30, 2015, we reported net loss of $122.3 million compared to net income of $21.2 million during the three months ended November 30, 2014. Net loss per basic and diluted share were $(1.14) for the three months ended November 30, 2015 compared to earnings per share of $0.27 and $0.26 per basic and diluted share for the three months ended November 30, 2014. Other significant differences between the two periods include the rapid growth in reserves, producing wells and daily production totals, as well as the impact of changing prices on our revenues and our commodity hedge positions. The following discussion expands upon significant items of inflow and outflow that affected results of operations.

Oil and Gas Production and Revenues - For the three months ended November 30, 2015, we recorded total oil and gas revenues of $26.1 million compared to $42.5 million for the three months ended November 30, 2014, a decrease of $16.4 million or 39%.

As of November 30, 2015, we reported production from 95 net horizontal wells. The increase of 49 net horizontal wells increased our reserves and daily production totals as compared to the same period of the prior year. Net oil and gas production for the three months ended November 30, 2015 averaged 10,540 BOED, an increase of 27% over average production of 8,278 BOED in the three months ended November 30, 2014.

Our revenues are sensitive to changes in commodity prices. As shown in the following table, there has been a decrease of 52% in average realized prices between the periods presented. This decline in average sales prices more than offset the effects of increased production. The following table presents actual realized prices, without the effect of commodity derivative transactions. The impact of commodity derivative transactions is presented later in this discussion.

Key production information is summarized in the following table:



	Three Months Ended November 30,
	2015		2014		Change
Production:
Oil (MBbls¹)	543		467		16	%
Gas (MMcf²)	2,500		1,720		45	%

Total production in MBOE³	959		753		27	%

Revenues (in thousands):
Oil	$	19,921	$	34,386	-42	%
Gas	6,216		8,152		-24	%
	$	26,137	$	42,538	-39	%
Average sales price:
Oil	$	36.72	$	73.69	-50	%
Gas	$	2.49	$	4.74	-47	%
BOE	$	27.25	$	56.47	-52	%

¹"MBbl” refers to one thousand stock tank barrels, or 42,000 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.

²"MMcf” refers to one million cubic feet of natural gas.

³"MBOE” refers to one thousand barrels of oil equivalent, which combines MBbls of oil and MMcf of gas by converting each six MMcf of gas to one MBbl of oil.

Lease Operating Expenses (“LOE”) - Direct operating costs of producing oil and natural gas are reported as follows (in thousands):



	Three Months Ended November 30,
	2015		2014
Production costs	$	3,748	$	3,035
Workover	61		6
Total LOE	$	3,809	$	3,041

Per BOE:
Production costs	$	3.91	$	4.03
Workover	0.06		0.01
Total LOE	$	3.97	$	4.04

Lease operating and workover 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. During the first fiscal quarter of fiscal 2016, we experienced decreased production costs per BOE primarily as a result of increased production.

Production taxes - During the three months ended November 30, 2015, production taxes were $2.4 million, or $2.55 per BOE, compared to $4.2 million, or $5.55 per BOE, during the three months ended November 30, 2014. Production taxes tend to increase or decrease primarily based on the value of oil and gas sold. As a percent of revenues, production taxes were 9.3% and 9.8% for the three months ended November 30, 2015 and 2014, respectively.

Depletion, Depreciation, Accretion, and Amortization (“DDA”) - The following table summarizes the components of DDA:



	Three Months Ended November 30,
(in thousands)	2015		2014
Depletion of oil and gas properties	$	14,376	$	16,304
Depreciation, accretion, and amortization	298		150
Total DDA	$	14,674	$	16,454

DDA expense per BOE	$	15.30	$	21.84

For the three months ended November 30, 2015, depletion of oil and gas properties was $15.30 per BOE compared to $21.84 per BOE for the three months ended November 30, 2014. For the three months ended November 30, 2015, production of 959 MBOE represented 1.5% of estimated total proved reserves. For the three months ended November 30, 2014, production of 753 MBOE represented 2.3% of estimated total proved reserves. The decrease in the DDA rate was the result of a substantial increase in estimated recoverable reserves as of November 30, 2015 as compared to November 30, 2014.

Full cost ceiling impairment - During the three months ended November 30, 2015, we recognized a total impairment of $125.2 million, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling. See Note 2, "Property and Equipment," to the Financial Statements included as part of this report.

Transportation commitment charge - During the three months ended November 30, 2015, we recognized a charge of $1.5 million related to our crude oil transportation volume commitments. In addition to our volume commitment to a third party refiner, which expired on December 31, 2015, two pipeline related transportation agreements commenced in October 2015, and we were unable to meet all of obligations during the quarter. We estimate that we could incur an additional $1.0 million charge in December 2015. As of January 1, 2016, our current production exceeds our delivery obligations, subsequent to the expiration of the volume commitment to the third party refiner. See Note 15, “Other Commitments and Contingencies, Volume Commitments,” to the Financial Statements included as part of this report.

General and Administrative (“G&A”) - The following table summarizes G&A expenses incurred and capitalized during the periods presented:



	Three Months Ended November 30,
(in thousands)	2015			2014
G&A costs incurred	$	14,906		$	4,613
Capitalized costs	(916		)	(503		)
Total G&A	$	13,990		$	4,110

Non-Cash G&A	$	7,279		$	667
Cash G&A	$	6,711		$	3,443
Total G&A	$	13,990		$	4,110

Non-Cash G&A per BOE	$	7.59		$	0.89
Cash G&A per BOE	$	7.00		$	4.57
G&A Expense per BOE	$	14.59		$	5.46

G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. During the three months ended November 30, 2015, we increased our employee count from 36 to 61, while reducing the number of consultants, advisors, and contractors that had historically been used for certain tasks. Additionally, during the fiscal first quarter of 2016, we awarded bonuses, consisting of cash and restricted stock, to management, employees and directors. Most significantly, bonuses totaling approximately $4.8 million (including restricted stock valued at $4.0 million) were paid to our co-CEOs. They both have resigned as CEO as of December 31, 2015, but remain as Directors.

Our G&A expense for the three months ended November 30, 2015 includes stock-based compensation of $7.2 million compared to $0.7 million for the three months ended November 30, 2014. Stock-based compensation includes a calculated value for stock options or shares of common stock that we grant for compensatory purposes. It is a non-cash charge. For stock options, the fair value is estimated using the Black-Scholes-Merton option pricing model. For shares, the fair value is estimated using the closing stock price on the grant date. Amounts are pro-rated over the vesting terms of the award agreements, which are generally three to five years.

Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the three months ended November 30, 2014 to the three months ended November 30, 2015 reflects our increasing activities to acquire leases and develop our properties.

Commodity derivative gains - As more fully described in the paragraphs titled “Oil and Gas Commodity Contracts” located in “Liquidity and Capital Resources,” we use commodity contracts to mitigate the risks inherent in the price volatility of oil and natural gas. For the three months ended November 30, 2015, we realized a cash settlement gain of $0.7 million, net of amortization of cash premiums paid for commodity contracts. For the three months ended November 30, 2014, we realized a cash settlement gain of $1.4 million.

In addition, we recorded an unrealized gain of $2.5 million to recognize the mark-to-market change in fair value of our commodity contracts for the three months ended November 30, 2015. In comparison, in the three months ended November 30, 2014, we reported an unrealized gain of $16.7 million. Unrealized gains and losses are non-cash items.

Income taxes - We reported income tax benefit of $10.0 million for the three months ended November 30, 2015, calculated at an effective tax rate of 8%. During the comparable prior year period, we reported income tax expense of $11.7 million, calculated at an effective tax rate of 36%. As explained in more detail below, during the period ended November 30, 2015, the effective tax rate was substantially reduced by recognition of a full valuation allowance on the net deferred tax asset. During the period ended November 30, 2014, the effective tax rate differed from the federal and state statutory rate primarily due to the impact of deductions for percentage depletion.

For tax purposes, we have a net operating loss (“NOL”) carryover of $21.3 million, which is available to offset future taxable income. The NOL will begin to expire, if not used, in 2031. As a result of the NOL and other tax strategies, it appears that payment of any tax liability will be substantially deferred into future years.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. Based on the level of losses in the current period and the level of uncertainty with respect to future taxable income over the period in which the deferred tax assets are deductible, a valuation allowance has been provided as of November 30, 2015. During fiscal 2015, we reached the opposite conclusion; therefore, we did not record a valuation allowance against any of our deferred tax assets in that period.

Non-GAAP Financial ~~Measures~~Measure

In addition to financial measures presented on the basis of accounting principles generally accepted in the United States of America ("US GAAP"), we present ~~certain~~"adjusted EBITDA," which is a financial ~~measures which are~~measure that is not prescribed by US GAAP ("non-GAAP"). ~~A summary of these measures is described below.~~

~~Adjusted EBITDA~~

We use ~~"adjusted~~adjusted EBITDA~~" a non-GAAP financial measure~~ for internal managerial purposes when evaluating period-to-period comparisons. This measure is not a measure of financial performance under US GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, ~~nor~~and it should not be viewed as a liquidity measure or indicator of cash flows reported in accordance with US GAAP. ~~The non-GAAP financial measure that we use~~Our definition of adjusted EBITDA may not be comparable to measures with similar titles reported by other companies. Also, in the future, we may disclose different non-GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure.

We define adjusted EBITDA as net income adjusted to exclude the impact of ~~interest expense, interest income, income tax expense, DDA (depletion, depreciation and amortization), stock-based compensation, and~~ the ~~plus or minus change~~items set forth in ~~fair value of derivative assets or liabilities.~~the table below. We believe adjusted EBITDA is relevant because ~~it is a measure of cash flow available to fund our capital expenditures and service our debt and is a~~similar measures are widely used ~~industry metric which may provide comparability of~~in our ~~results with our peers.~~ industry.

The following table presents a reconciliation of adjusted EBITDA, a non-GAAP financial measure, to net income (loss), its nearest GAAP measure:

Three Months Ended
May 31,

Nine Months Ended
May 31,

(in thousands) 2015 2014 2015 2014
Adjusted EBITDA:
   Net (loss) income $ (2,481 ) $ 7,160 $ 23,322 $ 18,421
   Depletion, depreciation and amortization 16,397 7,796 48,357 21,106
   Full cost ceiling impairment 3,000 - 3,000 -
   Provision (benefit) for income tax (1,833 ) 3,116 13,118 8,841
   Stock-based compensation 1,401 702 3,330 1,569
   Commodity derivative hedge 8,298 179 (5,578 ) (652 )
   Interest income, net 83 (22 ) 55 (70 )
       Adjusted EBITDA $ 24,865 $ 18,931 $ 85,604 $ 49,215

~~Table of Contents~~

~~TRENDS AND OUTLOOK~~

Oil prices traded as high as $107/bbl in June 2014, and have since declined more than 40%. A continuing decline in oil and gas prices (i) will reduce our cash flow which, in turn, will reduce the funds available for exploring and replacing oil and gas reserves, (ii) will potentially reduce our current LOC borrowing base capacity and 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 returns, (iv) may cause us to allow 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 cause a ceiling test impairment. However, price declines reduce the competition for oil and gas properties and correspondingly reduce the prices paid for leases and prospects.



	Three Months Ended November 30,
	2015			2014
Adjusted EBITDA:
Net (loss) income	$	(122,328	)	$	21,151
Depreciation, depletion, accretion, and amortization	14,674			16,454
Full cost ceiling impairment	125,230			—
Income tax (benefit) provision	(10,007		)	11,744
Stock-based compensation	7,197			793
Mark to market of commodity derivative contracts:
Total gain on commodity derivatives contracts	(3,192		)	(18,140		)
Cash settlements on commodity derivative contracts	1,272			1,432
Cash premiums paid for commodity derivative contracts	(959		)	—
Adjusted EBITDA	$	11,887		$	33,434

Other 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, and (v) competition from larger companies. Our revenues will also be significantly impacted by our ability to maintain or increase oil or gas production through exploration and development activities.Critical Accounting Policies

Horizontal well development within the field is still relatively new and the geology is enabling operators to utilize higher density drilling within designated spacing units. We are currently spacing our well bores to allow for up to ~~24 wells per 640 acre~~ section and we are testing drilling patterns that could lead to an even higher number of wells per section. We are also testing longer lateral wells, utilizing different amounts of proppant per hydraulic fractionation stage, employing different completion fluids and comparing "plug-and-perf" completions to "sliding-sleeve" completions in order to determine the most cost efficient well designs for the formations we are developing.

The recent decline in commodity prices has led to a corresponding decline in service costs, which directly relate to our drilling and completion costs. On average, we have been able to reduce drilling and completion costs by approximately 25% over the first three quarters of fiscal 2015 due to a combination of optimizing well designs, moving to day-rate drilling, lower contract rates for drilling rigs, and lower completion costs. This focus on cost reduction has supported well-level economics in spite of the severe price drop in crude oil and natural gas. We believe at current drilling and completion cost levels and with current prevailing commodity prices, we can achieve reasonable well-level rates of return going forward.

Our production continues to be adversely impacted by high natural gas gathering line pressures, especially in the northern area of the Wattenberg Field. This problem has persisted since 2012 and has grown along with the expansion of horizontal drilling in the area. High line pressure restricts our ability to produce crude oil and natural gas. As line pressures increase, it becomes more difficult to inject gas produced by our wells into gathering pipelines. When line pressure is greater than the operating pressure of our wellhead equipment, the wellhead equipment is unable to inject gas into the pipeline, and our production is restricted or shut-in. Since our wells produce a mixture of crude oil and natural gas, restrictions in gas production also restrict oil production.

Although various factors can cause increased line pressure, a significant factor in our area of the Wattenberg Field is the success of horizontal wells that have been drilled over the last several years. As new horizontal wells come on-line with increased pressures and volumes, they produce more gas than the gathering system was designed to handle. Once a pipeline is at capacity, pressures increase and older wells with less natural pressure are not able to compete with the new wells.

We are continuing our efforts to mitigate the adverse impact of high line pressures. Where it is cost effective, we install wellhead compression to enhance our ability to inject gas into the gathering system. Additionally, along with our midstream service provider, we are evaluating and in some instances installing larger gathering pipelines to our operated pads.

~~Table of Contents~~

Over the longer term, midstream companies that operate the gas gathering pipelines have continued to make significant capital investments to increase system capacity. As publicly disclosed, DCP Midstream Partners ("DCP"), the principal third-party provider that we employ to gather production from our wells, brought online a 160 MMcf/d gas processing plant in La Salle, CO (the O'Connor plant), which is part of an eight-plant system owned by the DCP enterprise with approximately 600 MMcf/d capacity. DCP has also announced the building of the Lucerne II plant, northeast of Greeley in Weld County, with a maximum capacity of approximately 200 MMcf/d. The Lucerne II plant recently began operations and is expected to be fully operational during our fourth quarter. We believe this additional processing capacity will help lower line pressures in the northern area of the Wattenberg Field where we have several operated pads and anticipate further completion activity in the near future. However, we do not know if this new capacity will completely mitigate the problem and does not help alleviate increasing line pressures in the west and/or south portions of the field.

The success of horizontal drilling techniques in the D-J Basin has also significantly increased quantities of oil produced in the region. Local crude oil refineries do not have sufficient capacity to process all of the oil available and the imbalance of supply and demand is increasing the transportation of oil out of the D-J Basin via pipeline and rail. This imbalance has also impacted the prices paid by oil purchasers in the basin, leading to generally wider differentials between the wellhead prices we realize and the crude oil prices posted on NYMEX. However, as commodity prices have contracted and transportation options have increased, we anticipate price differentials may narrow in the coming quarters and we continue to explore various alternatives with other oil purchasers to ensure we realize the highest net prices available. In all cases, we believe we will continue to have sufficient take-away capacity for all of our oil production. Further details regarding posted prices and average realized prices are discussed in the section entitled "Market Conditions," presented in this Item 2.

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, expenses, liquidity or capital resources.

~~CRITICAL ACCOUNTING POLICIES~~

We prepare our financial statements and the accompanying notes in conformity with US GAAP, which requires management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection, and disclosure of each of the critical accounting policies.

~~During the nine months ended May 31, 2015, there was a~~There have been no significant decline in the price of oil and there are no indications that it will reverse in the near future. The declines are the most significant price volatility experienced during the last three years. Accordingly, the description of certainchanges to our critical accounting policies ~~was updated to reflect the potential impact of these changing commodity prices on our financial statements. The goal of this disclosure is to highlight some areas where increased price volatility~~ and ~~updated economic assumptions will interact with existing accounting policies. Please note that there have been no changes~~estimates or in the underlying accounting assumptions and estimates used from those disclosed Management’s Discussion and Analysis of Financial Condition and Results of Operations and in the consolidated financial statements and accompanying notes contained in our 2015 Form 10-K filed with the SEC on October 16, 2015. However, certain events during the first fiscal quarter increased the significance of our policies ~~since August 31, 2014, our fiscal year end.~~ with respect to the evaluation of goodwill and the recording of costs incurred under firm transportation commitments. These items are discussed in Note 1, Organization and Summary of Significant Accounting Policies, to the accompanying condensed financial statements included elsewhere in this report. Note 1 also provides information regarding recently adopted and issued accounting pronouncements.

~~Oil and Gas Reserves:~~ ~~Oil and gas reserves represent theoretical, estimated quantities~~We call your attention to the increased significance of crude oil and natural gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Numerous assumptions are used in the reserve estimation process. Various engineering and geologic criteria are interpreted to derive volumetric estimates, and financial assumptions are made with regard to realized pricing, costs to be incurred to develop and operate the properties, and future tax regimes

~~Table of Contents~~

In spite of the imprecise nature of reserves estimates, they are a critical component of our financial statements. The determination of the depletion component of our depletion, depreciation and amortization expenses ("DDA"), as well as the ceiling test ~~calculation, is highly dependent on estimates of proved oil~~as disclosed in Note 2, Property and ~~natural gas reserves. For example, if estimates of proved reserves decline, our DDA rate will increase, resulting~~Equipment, to the accompanying condensed financial statements included elsewhere in ~~a decrease~~this report. During the quarter ended November 30, 2015, we recorded an impairment in net income. A decline in estimates of proved reserves may result from a number of factors including lower prices, evaluation of additional operating history, mechanical problems on our wells and catastrophic events. Lower prices can also make it uneconomical to drill wells or produce from propertiesconjunction with ~~high operating costs.~~

~~Oil and Gas Properties, including Ceiling Test:~~ There are two alternative methods of accounting for enterprises involved in the oil and gas industry: the successful efforts method and the full cost method. We use the full cost method of accounting. Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves (including the costs of dry holes, abandoned leases, delay rentals and overhead costs directly related to acquisition, exploration, and development activities) are capitalized into a single full cost pool.

Under the successful efforts method, exploration costs, including the cost of exploratory wells that do not increase proved reserves, the cost of geological and geophysical activities, seismic costs, and lease rentals, are charged to expense as incurred. Depletion of oil and gas properties and the evaluation for impairment are generally calculated on a narrowly defined asset basis compared to an aggregated "pool" basis under the full cost method. The conveyance of oil and gas assets generally results in recognition of gain or loss. In comparison, the conveyance or abandonment of full cost properties does not generally result in the recognition of gain or loss. Under full cost accounting, recognition of gain or loss is only allowable when the transaction would significantly alter the relationship between capitalized costs and proved reserves.

Our calculation of DDA expense incorporates all the costs capitalized under full cost accounting plus the estimate of costs to be incurred to develop proved reserves. The sum of historical and future costs are allocated to our estimated quantities of proved oil and gas reserves and depleted using the units-of-production method. Changes in commodity prices, as well as associated changes in costs that are affected by commodity prices, can have a significant impact on the estimates used in our calculations.

~~Companies that use full cost accounting perform~~performing a ceiling test ~~each quarter. The full cost ceiling test is an impairment test~~as prescribed by SEC Regulation S-X Rule 4-10. The test compares capitalized costs in the full cost pool, less accumulated DDA and related deferred income taxes, to a calculated ceiling amount. The calculated ceiling amount is equal to the sum of the present value (using a 10% discount factor) of future net revenues, plus unproved property costs and pre-production costs not being amortized, plus the lower of cost or estimated fair value of unproved properties included in costs being amortized, less related income tax effects. If the net capitalized costs exceed the ceiling amount, the excess must be charged to expense in recognition of the impairment.4-05.

Under the ceiling test, the estimate of future revenues is calculated using a current price (as defined in the SEC rules to include data points over a trailing 12-month period). Thus, the full impact of a sudden price decline is not recognized immediately. As prices decline, the economic performance of certain properties in the reserve estimate may deteriorate to the point that they are removed from the proved reserve category, thus reducing the quantity and value of proved reserves. The use of a 12-month average will tend to spread the impact of the change on the financial statements over several reporting periods.

During the three months ended May 31, 2015, our ceiling test resulted in an impairment of $3 million, which was driven by the previously discussed declines in the price of oil and gas. A further decline in oil and gas prices, or an increase in oil and gas prices that is insufficient to overcome the impact of price declines in the year-ago periods on the ceiling test calculation, could result in additional ceiling test impairments in future periods.

~~Table of Contents~~

~~Oil and Gas Sales:~~ Our proportionate interests in transactions are recorded as revenue when products are delivered to the purchasers. This method can require estimates of volumes, ownership interests, and settlement prices. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement. Historically, such differences have not been material. During periods of increased price volatility, it will be more difficult to estimate final settlement prices, and retroactive price adjustments pertaining to prior periods could become significant.

~~Commodity Derivative Instruments:~~ Our use of commodity derivative instruments helps us mitigate the cash flow impact of short-term commodity price volatility. We typically enter into contracts covering a portion of our expected oil and gas production over 24 months. We record realized gains and losses for contracts that settle during the reporting periods. Contracts either settle at their scheduled maturity date or settle prior to their scheduled maturity date as a result of our decision to early liquidate an open position. Realized gains and losses represent cash transactions. Under our hedge strategy we typically receive cash payments when the posted price for the settlement period is less than the hedge price. Conversely, when the posted price for the settlement period is greater than the hedge price, we typically disburse a cash payment to the counterparty. Thus, realized gains and losses tend to offset increases or decreases in our revenue stream that are caused by changing prices.

In comparison, unrealized gains and losses are related to positions that have not yet settled and do not represent cash transactions. At each reporting date, we estimate the fair value of the open (not settled) commodity contract positions and record a gain or loss based upon the change in fair value since the previous reporting date. The fair values are an approximation of the contracts' values as if we sold them on the reporting date. Since these amounts represent a calculated value for a hypothetical transaction, the actual value realized at the cash settlement date may be significantly different.

With the current downward trend in commodity prices, we expect to report reduced oil and gas revenues and to report partially offsetting realized gains in our hedge transactions. During any reporting period in which the commodity prices decline, we expect to report unrealized gains on our open commodity derivative contracts. However, during any period in which the downward trend reverses, we expect to report unrealized losses. Looking forward, we expect current contracts to be settled or liquidated over the next 24 months. We expect to periodically enter into new hedges at then current prices. Newer hedges at lower prices will reduce the amount of potential price protection provided by the newer contracts.

~~Business Combinations:~~ The Company accounts for its acquisitions using the acquisition method under ASC 805, Business Combinations. Under the acquisition method, assets acquired and liabilities assumed are measured at their fair values, which requires the use of significant judgment since some of the acquired assets and liabilities do not have fair values that are readily determinable. Different techniques may be used to determining fair values, including market prices (when available), appraisals, comparisons to transactions for similar assets and liabilities, and present values of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.

Once the fair values of the assets acquired and the liabilities assumed are determined, the excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, the excess, if any, of the fair value of assets acquired and liabilities assumed over the purchase price of the acquired entity is recognized immediately in earnings as a gain from bargain purchase.

~~Table of Contents~~

~~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:~~

	•		~~volatility of oil and natural gas prices;~~
	•		~~operating hazards that result in losses;~~
	•		~~uncertainties in the estimates of proved reserves;~~
	•		~~effect of seasonal weather conditions and wildlife restrictions on our operations;~~
	•		~~our need to expand our oil and natural gas reserves;~~
	•		~~our ability to obtain adequate financing;~~
	•		~~availability and capacity of gathering systems and pipelines for our production;~~
	•		~~effect of local and regional factors on oil and natural gas prices;~~
	•		~~incurrence of ceiling test write-downs;~~
	•		~~our inability to control operations on properties we do not operate;~~
	•		~~our ability to market our production;~~
	•		~~the strength and financial resources of our competitors;~~
	•		~~identifying future acquisitions;~~
	•		~~uncertainty in global economic conditions;~~
	•		~~legal and/or regulatory compliance requirements;~~
	•		~~the amount of our indebtedness and ability to maintain compliance with debt covenants;~~
	•		~~our need for capital;~~
	•		~~key executives allocating a portion of their time to other business interests; and~~
	•		~~effectiveness of our disclosure controls and our internal controls over financial reporting.~~


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

~~Item 3.~~ ~~Quantitative and Qualitative Disclosures About Market Risks~~

Commodity Price Risk

~~Commodity Price Risk~~ - Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. The volatility of oil prices affects our results to a greater degree than the volatility of gas prices, as approximately ~~79%~~76% of our revenue during ~~the~~our first ~~nine~~three months of fiscal ~~2015~~2016 was from the sale of oil. A $10 per barrel change in our realized oil price would have resulted in a ~~$4.5~~$5.4 million change in oil revenues during our ~~third~~first fiscal quarter of 2016, while a $0.50 per ~~mcf~~Mcf change in our realized gas price would have resulted in a ~~$0.9~~$1.3 million change in our natural gas revenues in our ~~third~~first fiscal quarter.

~~During the last several months, the price of oil has declined significantly.~~ These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil, the global supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, the strength of the US dollar compared to other currencies, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources.

~~Table of Contents~~

We attempt to mitigate fluctuations in short-term cash flow resulting from changes in commodity prices by entering into derivative positions on a portion of our expected oil and gas production. WeTypically, we use derivative contracts to cover no less than 45% and no more than 85% of expected proved developed producing production as projected in our semi-annual reserve report, generally over a period of two years. We do not enter into derivative contracts for speculative or trading purposes. As of ~~May 31,~~November 30, 2015, we had open crude oil and natural gas derivatives in a net asset position with a fair value of $~~8.9~~$7.3 million. A hypothetical upward or downward shift of 10% in the NYMEX forward curve of crude oil and natural gas prices would change the fair value of our position by $.7$0.7 million.

Interest Rate Risk -

At ~~May 31,~~November 30, 2015, we had debt outstanding under our bank credit facility totaling $~~141.0~~$78 million. Interest on our bank credit facility accrues at a variable rate, based upon either the Prime Rate or the London InterBank Offered Rate ~~("LIBOR"~~(“LIBOR”) plus an applicable margin. At ~~May 31,~~November 30, 2015, we were incurring interest at a rate of 2.5%. We are exposed to interest rate risk on the bank credit facility if the variable reference rates increase. A decrease in the variable interest rates would not have a significant impact on us, as the bank credit facility has a minimum interest rate of 2.5%. If interest rates increase, our monthly interest payments would increase, and our available cash flow would decrease. We estimate that if market interest rates ~~increase~~increased by 1% to an annual ~~percentage~~ rate of 3.5%, our interest payments in our first fiscal quarter of 2016 would ~~increase~~have increased by ~~approximately $1.4~~ ~~million per year.~~$0.2 million.

Under current market conditions, we do not anticipate significant changes in prevailing interest rates for the next year and we have not undertaken any activities to mitigate potential interest rate risk. There was no material change in interest rate risk during the quarter ended ~~May 31,~~November 30, 2015.

Counterparty Risk –

As described in the discussion about Commodity Price Risk, we enter into commodity derivative agreements to mitigate short-term price volatility. These derivative financial instruments present certain counterparty risks. We are exposed to potential loss if a counterparty fails to perform according to the terms of the agreement. The failure of any of the counterparties to fulfill their obligations to us could adversely affect our results of operations and cash flows. We do not require collateral or other security to be furnished by counterparties. We seek to manage the counterparty risk associated with these contracts by limiting transactions to well capitalized, well established, and well known counterparties that have been approved by our senior officers. There can be no assurance, however, that our practice effectively mitigates counterparty risk.

Our exposure to counterparty risk has increased during the last ~~few months~~year as the amounts due to us from counterparties has increased.

~~Item 4. Controls and Procedures.~~


ITEM 4.	CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our ~~Co-Chief~~Chief Executive ~~Officers~~Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the ~~"Exchange Act"~~“Exchange Act”) as of the end of the period covered by this report on Form 10-Q (the ~~"evaluation date"~~“Evaluation Date”). Based on such evaluation, our ~~Co-Chief~~Chief Executive ~~Officers~~Officer and Chief Financial Officer concluded that, as of the ~~evaluation date,~~Evaluation Date, our disclosure controls and procedures were effective.

Changes in Internal Control ~~Over~~over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

5437

~~Table of Contents~~

PART II


Item 1.	Legal Proceedings

During the quarter, there were no material developments regarding legal matters, which were previously described under Item 1.3, Legal ~~Proceedings.~~Proceedings, of our 2015 Form 10-K. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.


Item 1A.	Risk Factors

On June 1, 2015, the Company filed a complaint in the District Court of Weld County, Colorado, against Briller, Inc., R.W.L. Enterprises and Robert W. Loveless (together, the "Defendants") arising from a dispute concerning the validity of certain leases covering properties in Weld County. On June 23, 2015, the Defendants removed the case to the Federal District Court of Colorado and filed an answer and counterclaims against the Company and two officers of the Company. The essence of the Defendants' counterclaims isWe face many risks. Factors that the Company unlawfully drilled wells through properties leased by the Defendants and extracted oil and gas from these properties causing physical damage and economic damages measured by the value of hydrocarbons to be produced of approximately $42 million. Although the Company believes Defendants' counterclaims are without merit, it is not possible at this time to predict the outcome of this matter.

~~Item 1A. Risk Factors.~~

~~A substantial or extended decline in oil and natural gas prices may~~could materially adversely affect our business, financial condition, operating results or ~~results of operations and our ability to meet our capital expenditure obligations and financial commitments.~~

The prices we will receive for our oil and natural gas will significantly affect our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. For example, over the past year, the NYMEX—WTI oil price ranged from a high of $107.95 per Bbl to a low of $43.39 per Bbl, while the NYMEX—Henry Hub natural gas price ranged from a high of $4.71 per MMBtu to a low of $2.50 per MMBtu. These markets will likely continue to be volatile in the future. The prices we will receive for our production,liquidity, and the ~~levels~~trading price of our ~~production, will depend on numerous factors beyond our control. These factors include the following:~~

~~worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;~~

~~the actions of the Organization of Petroleum Exporting Countries, or OPEC;~~

~~the price and quantity of imports of foreign oil and natural gas;~~

political conditions in or hostilities in oil-producing and natural gas-producing regions and related sanctions, including current conflicts in the Middle East and conditions in Africa, South America, Russia and Ukraine;

~~the level of global oil and domestic natural gas exploration and production;~~

~~the level of global oil and domestic natural gas inventories;~~

~~prevailing prices on local oil and natural gas price indexes in the areas in which we operate;~~

~~localized supply and demand fundamentals and gathering, processing and transportation availability;~~

~~weather conditions and natural disasters;~~

~~domestic and foreign governmental regulations;~~

~~authorization of exports from the United States of liquefied natural gas or oil;~~

~~speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;~~

~~price and availability of competitors' supplies of oil and natural gas;~~

~~technological advances affecting energy consumption; and~~

~~the price and availability of alternative fuels.~~

~~Table of Contents~~

Lower oil and natural gas prices will reduce our cash flows and our borrowing ability. Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms in the future, which may, in turn, limit our ability to develop our exploration and production plans. Lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and may cause the valuecommon stock are described under Item 1A, Risk Factors, of our ~~estimated proved reserves at future reporting dates~~2015 Form 10-K. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.


Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

Purchases of equity securities by the Company



Period	Total Number of Shares Purchased	Average Price Paid per Share
September 1, 2015 - September 30, 2015 ⁽¹⁾	3,074	$	10.01
October 1, 2015 - October 31, 2015 ⁽¹⁾	5,314	$	11.56
November 1, 2015 - November 30, 2015 ⁽¹⁾	5,462	$	11.45
Total	13,850

(1) Pursuant to ~~decline compared to our estimated proved reserves at our most recent reporting period. Specifically, a decline in the value~~statutory minimum withholding requirements, certain of our ~~reserves may reduce~~employees exercised their right to "withhold to cover" as a tax payment method for the ~~borrowing base available to us under the Facility,~~vesting and ~~should the value~~exercise of our reserves decline below our recorded costs as measured by the ceiling test, we would be required to record a non-cash impairment charge in our financial statements. Additionally, an extended decline in commodity prices could lead us to reduce our capital expenditure budget and scale back our drilling and development plans.certain shares. These elections were outside of any publicly announced repurchase plan.


Item 3.	Defaults Upon Senior Securities

None.


Item 4.	Mine Safety Disclosures

Not applicable


Item 5.	Other Information

None.

To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations and results of operations.

Item 6. Exhibits

~~a. Exhibits~~



Exhibit Number	Exhibit
31.1	Certification of the Principal Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 ~~for Ed Holloway~~

31.2

Certification of the Principal Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 ~~for William Scaff, Jr.~~

~~31.3~~

~~Certification~~Certifications of the Principal Executive Officer and Principal Financial Officer pursuant to ~~Section 302 of the Sarbanes-Oxley Act of 2002 for Frank L. Jennings.~~

	32	~~Certification~~18 USC 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ~~for Ed Holloway, William Scaff, Jr. and Frank L. Jennings.~~
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~~101 INSXBRL~~

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~~101 SCHXBRL~~

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~~101 CALXBRL~~

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~~101 DEFXBRL~~

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~~101 LABXBRL~~

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~~101 PREXBRL~~

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~~Table of Contents~~

SIGNATURES

Pursuant to the requirements of Section 13 or 15(a) of the Securities Exchange Act of 1934, the ~~registrant~~Registrant has duly caused this ~~report~~Report to be signed on its behalf by the undersigned, thereunto duly ~~authorized.~~authorized on the 7th day of January, 2016.



	SYNERGY RESOURCES CORPORATION


~~Date: July 10, 2015~~	~~By:~~	/s/ ~~Ed Holloway~~	Lynn A. Peterson
		~~Ed Holloway, Co-Chief~~Lynn A. Peterson, President and Chief Executive Officer (Principal Executive Officer)

~~Date: July 10, 2015~~	~~By:~~	~~/s/ William Scaff, Jr.~~
	/s/ James P. Henderson
	~~William Scaff, Jr., Co-Chief~~James P. Henderson, Executive Vice President, Chief Financial Officer, and Treasurer (Principal ~~Executive~~Financial Officer)

~~Date: July 10, 2015~~	~~By:~~	/s/ Frank L. Jennings
		Frank L. Jennings, Vice President and Chief ~~Financial~~Accounting Officer (Principal ~~Financial~~Accounting Officer)

~~Colorado~~			~~20-2835920~~

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



1625 Broadway, Suite 300, Denver, CO	80202
(Address of principal executive offices)	(Zip Code)



Large accelerated filer ☒ý	Accelerated filer ☐o

Non-accelerated filer o (Do not check if a smaller reporting company)	~~Non-accelerated filer ☐~~	Smaller reporting company ☐o

ASSETS	May 31, 2015		August 31, 2014
	(unaudited)
Current assets:
Cash and cash equivalents	$	190,205	$	34,753
Accounts receivable:
Oil and gas sales		14,781		16,974
Joint interest billing and other		18,487		15,398
Commodity derivative		4,268		365
Other current assets		1,311		750
Total current assets		229,052		68,240

Oil and gas properties, full cost method:
Proved properties, net		407,576		275,018
Unproved properties and properties under development, not being amortized		170,639		95,278
Other property and equipment, net		4,811		9,104
Property and equipment, net		583,026		379,400

Commodity derivative		4,615		54
Other assets		2,767		848

Total assets	$	819,460	$	448,542

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities:
Trade accounts payable	$	1,027	$	1,747
Well costs payable		26,491		71,849
Revenue payable		18,786		14,487
Production taxes payable		17,120		14,376
Other accrued expenses		457		817
Commodity derivative		-		302
Total current liabilities		63,881		103,578

Revolving credit facility		141,000		37,000
Commodity derivative		-		307
Deferred tax liability, net		34,670		21,437
Asset retirement obligations		7,772		4,730
Total liabilities		247,323		167,052
Commitments and contingencies (See Note 13)

Shareholders' equity:
Preferred stock - $0.01 par value, 10,000,000 shares authorized:
no shares issued and outstanding		-		-
Common stock - $0.001 par value, 200,000,000 shares authorized:
105,025,453 and 77,999,082 shares issued and outstanding, respectively		105		78
Additional paid-in capital		533,091		265,793
Retained earnings		38,941		15,619
Total shareholders' equity		572,137		281,490

Total liabilities and shareholders' equity	$	819,460	$	448,542



ASSETS	November 30, 2015			August 31, 2015
	(unaudited)
Current assets:
Cash and cash equivalents	$	80,723		$	133,908
Accounts receivable:
Oil and gas sales	10,408			13,601
Joint interest billing and other	11,029			15,325
Commodity derivative contracts	4,890			2,897
Other current assets	1,896			1,109
Total current assets	108,946			166,840

Property and equipment:
Oil and gas properties, full cost method:
Proved properties, net	415,582			452,393
Unproved properties, not subject to amortization	106,921			77,564
Oil and gas properties, net	522,503			529,957
Other property and equipment, net	5,093			4,783
Total property and equipment, net	527,596			534,740

Commodity derivative contracts	2,450			1,565
Goodwill	40,711			40,711
Other assets	2,423			2,593

Total assets	$	682,126		$	746,449

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Trade accounts payable	$	2,282		$	670
Well costs payable	41,746			33,071
Revenue payable	12,263			19,044
Production taxes payable	24,389			20,899
Other accrued expenses	3,198			27
Total current liabilities	83,878			73,711

Revolving credit facility	78,000			78,000
Deferred tax liability, net	—			10,007
Asset retirement obligations	12,444			12,334
Total liabilities	174,322			174,052

Commitments and contingencies (See Note 15)

Shareholders' equity:
Preferred stock - $0.01 par value, 10,000,000 shares authorized: no shares issued and outstanding	—			—
Common stock - $0.001 par value, 200,000,000 shares authorized: 109,547,330 and 105,099,342 shares issued and outstanding, respectively	110			105
Additional paid-in capital	596,361			538,631
Retained (deficit) earnings	(88,667		)	33,661
Total shareholders' equity	507,804			572,397

Total liabilities and shareholders' equity	$	682,126		$	746,449

☒

	ý	QUARTERLY REPORT ~~UNDER~~PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

☐

	o	TRANSITION REPORT ~~UNDER~~PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



			Page
Part I –- FINANCIAL INFORMATION

Item 1.	Financial Statements

	Condensed Balance Sheets as of ~~May 31,~~November 30, 2015 (unaudited) and August 31, ~~2014~~ 2015		2

	Condensed Statements of Operations for the three ~~and nine~~ months ended ~~May 31,~~November 30, 2015 and ~~May 31,~~November 30, 2014 (unaudited)		3

	Condensed Statements of Cash Flows for the ~~nine~~three months ended ~~May 31,~~November 30, 2015 and ~~May 31,~~November 30, 2014 (unaudited)		4

	Notes to Condensed Financial Statements (unaudited)		5

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		2923

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52

~~Item 4.~~	~~Controls and Procedures~~		5336

Item 4.	Controls and Procedures		37

Part II - OTHER INFORMATION

Item 1.	Legal Proceedings		54

~~Item 1A.~~	~~Risk Factors~~		5438

Item 6. 1A.	Risk Factors		~~Exhibits~~	5538

~~SIGNATURES~~ Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		5638

Item 3.	Defaults of Senior Securities		38

Item 4.	Mine Safety Disclosures		38

Item 5.	Other Information		38

Item 6.	Exhibits		39

SIGNATURES			49


	Three Months Ended May 31,						Nine Months Ended May 31,
	2015			2014			2015			2014

Oil and gas revenues	$	26,033		$	25,672		$	92,284		$	67,966

Expenses
Lease operating expenses		3,570			2,303			10,300			5,382
Production taxes		2,249			2,376			8,570			6,647
Depletion, depreciation
amortization and accretion		16,397			7,796			48,357			21,106
Full cost ceiling impairment		3,000			-			3,000			-
General and administrative		3,886			1,938			12,075			6,876
Total expenses		29,102			14,413			82,302			40,011

Operating income (loss)		(3,069	)		11,259			9,982			27,955

Other income (expense)
Commodity derivative realized gain (loss)		7,136			(826	)		20,935			(1,415	)
Commodity derivative unrealized (loss) gain		(8,298	)		(179	)		5,578			652
Interest expense		(116	)		-			(116	)		-
Interest income		33			22			61			70
Total other income (expense)		(1,245	)		(983	)		26,458			(693	)

Income (loss) before income taxes		(4,314	)		10,276			36,440			27,262

Income tax provision (benefit)		(1,833	)		3,116			13,118			8,841
Net income (loss)	$	(2,481	)	$	7,160		$	23,322		$	18,421

Net income (loss) per common share:
Basic	$	(0.02	)	$	0.09		$	0.26		$	0.24
Diluted	$	(0.02	)	$	0.09		$	0.25		$	0.24

Weighted-average shares outstanding:
Basic		104,234,519			77,176,420			91,105,035			75,689,903
Diluted		104,234,519			79,008,619			91,804,253			77,299,456

Major Customers	As of May 31, 2015	As of August 31, 2014
Company A	29%	37%
Company B	12%	⁽¹⁾

	As of			As of
	May 31, 2015			August 31, 2014
Oil and gas properties, full cost method:
Unproved properties, not subject to amortization:
Lease acquisition and other costs	$	139,012		$	41,531
Properties under development		31,627			53,747
Subtotal		170,639			95,278

Proved producing and non-producing properties		513,677			329,926
Total capitalized costs		684,316			425,204
Less, accumulated depletion		(103,101	)		(54,908	)
Less, full cost ceiling impairment		(3,000	)		-
Oil and gas properties, net		578,215			370,296

Land		4,478			3,898
Other property and equipment		867			5,961
Less, accumulated depreciation		(534	)		(755	)
Other property and equipment, net		4,811			9,104

Total property and equipment, net	$	583,026		$	379,400

Purchase Price	December 15, 2014
Consideration Given
Cash	$	74,221
Synergy Resources Corp. Common Stock (1)		48,434
Liabilities assumed, including asset retirement obligations		2,467
Total consideration given	$	125,122

Allocation of Purchase Price
Proved oil and gas properties (2)	$	51,400
Unproved oil and gas properties		73,722
Total fair value of oil and gas properties acquired	$	125,122

Purchase Price	November 12, 2013
Consideration Given
Cash	$	15,902
Synergy Resources Corp. Common Stock *		2,896

Total consideration given	$	18,798

Allocation of Purchase Price
Proved oil and gas properties	$	11,514
Unproved oil and gas properties	$	7,725
Total fair value of oil and gas properties acquired		19,239

Working capital	$	(83	)
Asset retirement obligation		(358	)

Fair value of net assets acquired	$	18,798

Working capital acquired was estimated as follows:
Accounts receivable		536
Accrued liabilities and expenses		(619	)

Total working capital	$	(83	)

* The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of November 12, 2013. (301,339 shares at $9.61 per share)

Purchase Price	November 13, 2013
Consideration Given
Cash	$	14,688
Synergy Resources Corp. Common Stock *		5,432

Total consideration given	$	20,120

Allocation of Purchase Price
Proved oil and gas properties	$	13,284
Unproved oil and gas properties	$	7,577
Total fair value of oil and gas properties acquired		20,861

Working capital	$	(507	)
Asset retirement obligation		(234	)

Fair value of net assets acquired	$	20,120

Working capital acquired was estimated as follows:
Accounts receivable		662
Accrued liabilities and expenses		(1,169	)

Total working capital	$	(507	)

	For The Nine Months Ended May 31,
	2015	2014
Inflation rate	3.9%	3.9 - 4.0%
Estimated asset life	25.0 - 39.0 years	20.0 - 40.0 years
Credit adjusted risk free interest rate	8.0%	8.0%

Asset retirement obligations, August 31, 2014	$	4,730
Liabilities incurred		744
Liabilities assumed		1,913
Accretion expense		385
Asset retirement obligations, May 31, 2015	$	7,772


Settlement Period		Derivative Instrument	Average Volumes (BBls/MMBtu per month)		Average Fixed Price		Floor Price		Ceiling Price		Derivative Instrument	Average Volumes (Bbls per month)	Floor Price		Ceiling Price
Crude Oil - NYMEX WTI
Jun 1, 2015 - Jun 30, 2015		Collar		2,500		-	$	80.00	$	95.75
Jun 1, 2015 - Dec 31, 2015		Put		40,000		-	$	50.00		-
Jun 1, 2015 - Oct 31, 2015		Put		5,200		-	$	50.00		-
Jun 1, 2015 - Dec 31, 2015		Put		10,000		-	$	55.00		-
Dec 1, 2015 - Dec 31, 2015											Purchased Put	40,000	$	50.00	—
Dec 1, 2015 - Dec 31, 2015											Purchased Put	10,000	$	55.00	—

Jan 1, 2016 - May 31, 2016		Collar		10,000		-	$	75.00	$	96.00
Jan 1, 2016 - May 31, 2016		Collar		5,000		-	$	80.00	$	100.75
Jun 1, 2016 - Aug 31, 2016		Collar		15,000		-	$	80.00	$	100.05
Jan 1, 2016 - Aug 31, 2016		Swap		5,000	$	88.55		-		-
Sep 1, 2016 - Dec 31, 2016		Swap		20,000	$	88.10		-		-
Jan 1, 2016 - Oct 31, 2016		Swap		6,400	$	78.96		-		-
Jan 1, 2016 - Dec 31, 2016											Purchased Put	25,000	$	50.00	—
Jan 1, 2016 - Dec 31, 2016											Purchased Put	10,000	$	45.00	—
Jan 1, 2016 - Dec 31, 2016		Put		25,000		-	$	50.00		-	Collar	20,000	$	45.00	$	65.00

Jan 1, 2017 - Apr 30, 2017		Put		20,000		-	$	50.00		-	Purchased Put	20,000	$	50.00	—
May 1, 2017 - Aug 31, 2017		Put		20,000		-	$	55.00		-	Purchased Put	20,000	$	55.00	—
Jan 1, 2017 - Dec 31, 2017											Collar	20,000	$	45.00	$	70.00

Settlement Period											Derivative Instrument	Average Volumes (MMBtu per month)	Floor Price		Ceiling Price
Natural Gas - NYMEX Henry Hub	Natural Gas - NYMEX Henry Hub
Jun 1, 2015 - Dec 31, 2015		Collar		72,000		-	$	4.15	$	4.49
Dec 1, 2015 - Dec 31, 2015											Collar	72,000	$	4.15	$	4.49

Jan 1, 2016 - May 31, 2016		Collar		60,000		-	$	4.05	$	4.54	Collar	60,000	$	4.05	$	4.54
Jun 1, 2016 - Aug 31, 2016		Collar		60,000		-	$	3.90	$	4.14	Collar	60,000	$	3.90	$	4.14

Natural Gas - CIG Rocky Mountain	Natural Gas - CIG Rocky Mountain
Jun 1, 2015 - Dec 31, 2015		Collar		100,000		-	$	2.20	$	3.05
Dec 1, 2015 - Dec 31, 2015											Collar	100,000	$	2.20	$	3.05

Jan 1, 2016 - Dec 31, 2016		Collar		100,000		-	$	2.65	$	3.10	Collar	100,000	$	2.65	$	3.10

Jan 1, 2017 - Apr 30, 2017		Collar		100,000		-	$	2.80	$	3.95	Collar	100,000	$	2.80	$	3.95
May 1 2017 - Aug 31, 2017		Collar		110,000		-	$	2.50	$	3.05	Collar	110,000	$	2.50	$	3.06

		As of May 31, 2015
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Derivative contracts	Current assets	$	4,487	$	(219	)	$	4,268
Derivative contracts	Noncurrent assets	$	4,994	$	(379	)	$	4,615
Derivative contracts	Current liabilities	$	219	$	(219	)	$	-
Derivative contracts	Noncurrent liabilities	$	379	$	(379	)	$	-



		As of November 30, 2015
Underlying	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Commodity derivative contracts	Current assets	$	5,088	$	(198	)	$	4,890
Commodity derivative contracts	Noncurrent assets	$	2,973	$	(523	)	$	2,450
Commodity derivative contracts	Current liabilities	$	198	$	(198	)	$	—
Commodity derivative contracts	Noncurrent liabilities	$	523	$	(523	)	$	—


		As of August 31, 2014
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Derivative contracts	Current assets	$	903	$	(538	)	$	365
Derivative contracts	Noncurrent assets	$	718	$	(664	)	$	54
Derivative contracts	Current liabilities	$	840	$	(538	)	$	302
Derivative contracts	Noncurrent liabilities	$	971	$	(664	)	$	307



		As of August 31, 2015
Underlying	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Commodity derivative contracts	Current assets	$	3,047	$	(150	)	$	2,897
Commodity derivative contracts	Noncurrent assets	$	1,774	$	(209	)	$	1,565
Commodity derivative contracts	Current liabilities	$	150	$	(150	)	$	—
Commodity derivative contracts	Noncurrent liabilities	$	209	$	(209	)	$	—

	Fair Value Measurements at May 31, 2015
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	-	$	8,883	$	-	$	8,883
Commodity derivative liability	$	-	$	-	$	-	$	-



	Fair Value Measurements at August 31, 2014								Fair Value Measurements at November 30, 2015
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	-	$	419	$	-	$	419	$	—	$	7,340	$	—	$	7,340
Commodity derivative liability	$	-	$	609	$	-	$	609	$	—	$	—	$	—	$	—

	As of May 31,		As of August 31,
	2015		2014
Preferred stock, shares authorized		10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01
Preferred stock, shares issued and outstanding	nil		nil
Common stock, shares authorized		200,000,000		200,000,000
Common stock, par value	$	0.001	$	0.001
Common stock, shares issued and outstanding		105,025,453		77,999,082



	As of November 30,		As of August 31,
	2015		2015
Preferred stock, shares authorized	10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01
Preferred stock, shares issued and outstanding	nil		nil
Common stock, shares authorized	200,000,000		200,000,000
Common stock, par value	$	0.001	$	0.001
Common stock, shares issued and outstanding	109,547,330		105,099,342

	For the nine months ended May 31, 2015
Number of common shares issued for mineral property leases		995,672
Number of common shares issued for acquisitions		4,648,136
Total common shares issued		5,643,808

Average price per common share	$	10.45
Aggregate value of shares issued (in thousands)	$	58,968



	Three Months Ended November 30, 2015
Number of common shares issued for acquisition	4,418,413

Price per common share	$	11.28
Aggregate value of shares issues (in thousands)	$	49,840

	Number of Warrants			Weighted-Average Exercise Price
Outstanding, August 31, 2014		2,562,473		$	6.00
Granted		-		$	-
Exercised		(2,562,473	)	$	6.00
Expired		-		$	-
Outstanding, May 31, 2015		-		$	-

	Number of Shares			Weighted-Average Exercise Price
Outstanding, August 31, 2014		2,167,000		$	5.94
Granted		2,302,500		$	11.64
Exercised		(258,000	)	$	3.81
Forfeited		(110,000	)	$	(4.97	)
Outstanding, May 31, 2015		4,101,500		$	9.30



	Number of Shares		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life	Aggregate Intrinsic Value (thousands)
Outstanding, August 31, 2015	4,176,500		$	9.29	8.6 years	$	8,187
Granted	932,500		11.05
Exercised	(188,000	)	6.56			981
Expired	(60,000	)	11.74
Forfeited	(15,000	)	5.76
Outstanding, November 30, 2015	4,846,000		$	9.70	8.7 years	$	8,874
Outstanding, Exercisable at November 30, 2015	1,391,450		$	7.17	7.3 years	$	5,960
Outstanding, Vested and expected to vest at November 30, 2015	4,729,461		$	9.65	8.7 years	$	8,872

	Outstanding Options		Vested Options
Number of shares		4,101,500		888,100
Weighted-average remaining contractual life	8.8 years		6.9 years
Weighted-average exercise price		$9.30		$5.34
Aggregate intrinsic value (in thousands)		$9,547		$5,480



	Outstanding Options				Exercisable Options
Range of Exercise Prices	Options	Weighted-Average Remaining Contractual Life	Weighted-Average Exercise Price per Share		Options	Weighted-Average Exercise Price per Share

Under $5.00	654,000	5.8 years	$	3.51	509,000	$	3.50
$5.00 - $6.99	480,000	7.2 years	6.46		345,000	6.53
$7.00 - $10.99	910,000	9.0 years	9.94		127,450	9.27
$11.00 - $13.46	2,802,000	9.5 years	11.62		410,000	11.62
Total	4,846,000	8.7 years	$	9.70	1,391,450	$	7.17



	Unvested Options at November 30, 2015
Unrecognized compensation, net of estimated forfeitures (in thousands)	$	16,736
Remaining vesting phase	3.9 years



	Number of Shares		Weighted-Average Grant-Date Fair Value
Non-vested, August 31, 2015	632,500		$	10.93
Granted	213,500		11.05
Vested	(33,666	)	10.72
Forfeited	—		$	—
Non-vested, November 30, 2015	812,334		$	10.96



	Unvested Awards at November 30, 2015
Unrecognized compensation, net of estimated forfeitures (in thousands)	$	7,246
Remaining vesting phase	3.6 years