SRC Energy Inc. - FORM 10-Q

Attached files

file	filename
EX-32 - EXHIBIT 32 - SRC Energy Inc.	exhibit32120151130.htm
EX-31.2 - EXHIBIT 31.2 - SRC Energy Inc.	exhibit31320151130.htm
EX-31.1 - EXHIBIT 31.1 - SRC Energy Inc.	exhibit31120151130.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended November 30, 2015



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

For the transition period from _______________________ to _______________________

Commission file number: 001-35245

SYNERGY RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)



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



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

Registrant's telephone number, including area code: (720) 616-4300

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such filing). Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer ý	Accelerated filer o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): Yes o No ý

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 109,973,188 outstanding shares of common stock as of January 4, 2016.

SYNERGY RESOURCES CORPORATION

Index



		Page
Part I - FINANCIAL INFORMATION

Item 1.	Financial Statements

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

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

	Condensed Statements of Cash Flows for the three months ended November 30, 2015 and 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	23

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36

Item 4.	Controls and Procedures	37

Part II - OTHER INFORMATION

Item 1.	Legal Proceedings	38

Item 1A.	Risk Factors	38

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38

Item 3.	Defaults of Senior Securities	38

Item 4.	Mine Safety Disclosures	38

Item 5.	Other Information	38

Item 6.	Exhibits	39

SIGNATURES		49

SYNERGY RESOURCES CORPORATION

CONDENSED BALANCE SHEETS

(in thousands, except share data)



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

The accompanying notes are an integral part of these condensed financial statements

SYNERGY RESOURCES CORPORATION

CONDENSED STATEMENTS OF OPERATIONS

(unaudited; in thousands, except share and per share data)



	Three Months Ended November 30,
	2015			2014

Oil and gas revenues	$	26,137		$	42,538

Expenses:
Lease operating expenses	3,809			3,041
Production taxes	2,443			4,178
Depreciation, depletion, accretion, and amortization	14,674			16,454
Full cost ceiling impairment	125,230			—
Transportation commitment charge	1,518			—
General and administrative	13,990			4,110
Total expenses	161,664			27,783

Operating (loss) income	(135,527		)	14,755

Other income:
Commodity derivatives realized gain	700			1,432
Commodity derivatives unrealized gain	2,492			16,708
Total other income	3,192			18,140

(Loss) Income before income taxes	(132,335		)	32,895

Income tax (benefit) provision	(10,007		)	11,744
Net (loss) income	$	(122,328	)	$	21,151

Net (loss) income per common share:
Basic	$	(1.14	)	$	0.27
Diluted	$	(1.14	)	$	0.26

Weighted-average shares outstanding:
Basic	107,105,253			79,008,719
Diluted	107,105,253			80,141,152

The accompanying notes are an integral part of these condensed financial statements

SYNERGY RESOURCES CORPORATION

CONDENSED STATEMENTS OF CASH FLOWS

(unaudited; in thousands)



	Three Months Ended November 30,
	2015			2014
Cash flows from operating activities:
Net (loss) income	$	(122,328	)	$	21,151
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, accretion, and amortization	14,674			16,454
Full cost ceiling impairment	125,230			—
Provision for deferred taxes	(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		)	—
Changes in operating assets and liabilities:
Accounts receivable
Oil and gas sales	4,269			(4,085		)
Joint interest billing and other	4,296			(9,566		)
Accounts payable
Trade	1,542			(1,393		)
Revenue	(6,781		)	10,764
Production taxes	3,490			4,607
Accrued expenses	3,171			1,001
Other	(787		)	(327		)
Total adjustments	143,415			13,284
Net cash provided by operating activities	21,087			34,435

Cash flows from investing activities:
Acquisition of oil and gas properties	(35,045		)	—
Well costs and other capital expenditures	(39,073		)	(66,137		)
Earnest money deposit	—			(6,250		)
Net cash used in investing activities	(74,118		)	(72,387		)

Cash flows from financing activities:
Proceeds from exercise of warrants	—			10,699
Shares withheld for payment of employee payroll taxes	(154		)	(389		)
Proceeds from revolving credit facility	—			40,000
Net cash (used in) provided by financing activities	(154		)	50,310

Net (decrease) increase in cash and equivalents	(53,185		)	12,358

Cash and equivalents at beginning of period	133,908			34,753

Cash and equivalents at end of period	$	80,723		$	47,111

Supplemental Cash Flow Information (See Note 16)

The accompanying notes are an integral part of these condensed financial statements

SYNERGY RESOURCES CORPORATION

NOTES TO CONDENSED FINANCIAL STATEMENTS

November 30, 2015

(unaudited)


1.	Organization and Summary of Significant Accounting Policies

Organization: Synergy Resources Corporation ("we", "us", "Synergy", or the “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 common stock is listed and traded on the NYSE MKT under the symbol “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”).

Interim Financial Information: The unaudited condensed interim financial statements included herein have been prepared by the Company 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, 2015 was derived from the Company's Annual Report on Form 10-K for the year ended August 31, 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, 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.

Major Customers: The Company sells production to a small number of customers, as is customary in the industry. As a result, during the three months ended November 30, 2015 and 2014, certain of the Company’s customers represented 10% or more of its oil and gas revenue (“major customers”). For the three months ended November 30, 2015, the Company had three major customers, which represented 60%, 15%, and 12% of its revenue during the period. For the three months ended November 30, 2014, the Company had two major customers, which represented 68% and 12% 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 warrant, the Company believes that its oil and gas production can be sold in the market in the event that it is not sold to the Company’s existing customers. However, in some circumstances, a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer.

Accounts receivable consist primarily of trade receivables from oil and gas sales and amounts due from other working interest owners 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:



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

The Company operates exclusively within the United States of America and, except for cash and short-term investments, all of the Company’s assets are employed in, and all of its revenues are derived from, the oil and gas industry.

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 may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required two-step impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the 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 contain considerable management judgments. Changes in these assumptions or future economic conditions could impact the Company's conclusion regarding an impairment of goodwill and potentially result in a non-cash impairment loss in a future period.

Transportation Commitment Charge: The Company has entered into several agreements that require us to deliver minimum amounts of crude oil to a third party marketer and/or other counterparties that transport crude oil via pipelines. See Note 15 for additional information. Pursuant to 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 expense as a transportation commitment charge in the Statement of Operations.

Recently Adopted Accounting Pronouncements:

In November 2015, the FASB issued Accounting Standards Update (“ASU”) 2015-17, “Balance Sheet Classification of Deferred Taxes,” which requires that 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 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 recognized in the reporting period in which the adjustment is identified. The standard is effective prospectively for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted. On September 1, 2015, we elected to early adopt the pronouncement. This amendment will be applied prospectively to measurement period adjustments 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.

In January 2015, the FASB issued ASU 2015-01, “Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary 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 this amendment did not have an effect on the Company's financial position or results of 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 ASU 2014-16, “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” (“ASU 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. We are currently evaluating the impact of the adoption of this standard on our consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 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, 2017 including interim periods within that period. Early adoption is not permitted. We are currently evaluating which transition approach to use and the impact of the adoption of this standard on 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 our reported financial position, results of operations, or cash flows.


2.	Property and Equipment

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



	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 reserves is calculated using the average of the published spot prices for 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 $42.54 per barrel and $2.77 per Mcf. The oil prices used at 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 August 31, 2015 price of $3.28. Using these prices, the Company's net capitalized costs for oil and natural gas properties exceeded the ceiling amount by $125.2 million at 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 ended November 30, 2015 and 2014 indicated that estimated fair values of such assets exceeded the carrying values. Therefore, no 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 the amounts shown in the table below, were capitalized in the full cost pool (in thousands):



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


3.	Acquisitions

During the three months ended November 30, 2015, the Company acquired certain oil and gas and other assets, as described below.

Kauffman Acquisition

On October 20, 2015, the Company completed the acquisition of certain assets from K.P. Kauffman Company, Inc. ("Kauffman") for a total purchase price of $85.2 million, net of customary closing adjustments. The purchase price was composed of $35.0 million in cash and $49.8 million in restricted common stock plus the assumption of certain liabilities.

The Kauffman acquisition encompassed approximately 4,300 net acres 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 acquisition were expensed as 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):



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 October 20, 2015 (4,418,413 shares at $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 12%, and assumptions regarding the timing and amount of future development and operating costs.

The results of 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 months ended November 30, 2015 and 2014 as if the Kauffman transaction had occurred on September 1, 2014, the first day of our 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 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”)

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



	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 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. 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

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



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

The Company maintains a revolving credit facility ("Revolver") with a bank syndicate. The Revolver is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit. As most recently amended on June 2, 2015, the terms of the Revolver provide for up to $500 million in borrowings, subject to a borrowing base limitation, as further described below. The maturity date of the Revolver is December 15, 2019.

Certain of the Company’s assets, including substantially all of its producing wells and developed oil and gas leases, have been designated as collateral under the Revolver. The borrowing commitment is subject to adjustment based upon a borrowing base calculation that includes the value of oil and gas reserves. The borrowing base limitation is subject to scheduled redeterminations on a semi-annual basis. In certain events, and at the discretion of the bank syndicate, an unscheduled redetermination may be required. During the quarter ended August 31, 2015, the Company's borrowing base was adjusted to $163 million. Accordingly, as of November 30, 2015, based on a borrowing base of $163 million and an outstanding principal balance of $78 million, the unused borrowing base available for future borrowing totaled approximately $85 million. The next semi-annual redetermination has been rescheduled for January 2016.

Interest under the Revolver is payable monthly and accrues at a variable rate, subject to a minimum rate of 2.5%. For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or the London Interbank Offered Rate (“LIBOR”) plus a margin. The interest rate margin, as well as other bank fees, varies with utilization of the Revolver. The average annual interest rate for borrowings during the three months ended November 30, 2015 was 2.5%.

The Revolver also contains covenants that, among other things, restrict the payment of dividends and limits the minimum and maximum use of derivative contracts. Specifically, the Revolver requires that for a rolling 24 month period no less than 45% and no more than 85% of the proved developed producing reserves projected in the Company’s most recent semi-annual reserve report be covered by Commodity Derivative Instruments as discussed in Note 7 below.

Furthermore, the Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. Under the requirements, as most recently amended, the Company, on a quarterly basis, must (a) not, at any time, permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0; and (b) maintain a minimum liquidity, defined as cash and cash equivalents plus the unused availability under the Revolver, of not less than $25 million. As of November 30, 2015, the most recent compliance date, the Company was in compliance with all loan covenants except the covenants related to its overall commodity derivative position as described above whereby the Company did not meet the minimum hedging requirement. The Company has obtained a waiver for this covenant.


7.	Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, as described below. The Company has utilized swaps, puts, or collars to reduce the effect of price changes on a portion of its future oil and gas production. A swap requires a payment to the counterparty if the settlement price exceeds the strike price and the same counterparty is required to make a payment if the settlement price is less than the strike price. A put requires the counterparty to make a payment if the settlement price is below the strike price. A collar requires a payment to the counterparty if the settlement price is above the ceiling price and requires the counterparty to make a payment if the settlement price is below the floor price. The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to cover additional production, restructure existing derivative contracts, or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with four counterparties and an exchange. Two of the counterparties are lenders in the Company’s credit facility. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from contract settlement of derivatives

are recorded in the statements of operations. The Company’s cash flow is only impacted when the actual settlements under commodity derivative contracts result in making or receiving a payment to or from the counterparty. Actual cash settlements can occur at either the scheduled maturity date of the contract or at an earlier date if the contract is liquidated prior to its scheduled maturity. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s Statements of Cash Flows.

The Company’s valuation estimate takes into consideration the counterparty’s creditworthiness, the Company’s creditworthiness, and the time value of money. The consideration of the factors results in an estimated fair value for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.

The Company’s commodity derivative contracts as of November 30, 2015 are summarized below:



Settlement Period	Derivative Instrument	Average Volumes (Bbls per month)	Floor Price		Ceiling Price
Crude Oil - NYMEX WTI
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 - 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	Collar	20,000	$	45.00	$	65.00

Jan 1, 2017 - Apr 30, 2017	Purchased Put	20,000	$	50.00	—
May 1, 2017 - Aug 31, 2017	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
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
Jun 1, 2016 - Aug 31, 2016	Collar	60,000	$	3.90	$	4.14

Natural Gas - CIG Rocky Mountain
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

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

Offsetting of Derivative Assets and Liabilities

As of November 30, 2015 and August 31, 2015, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its accompanying Balance Sheets.

The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands):



		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, 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	)	$	—

The amount of gain recognized in the statements of operations related to derivative financial instruments was as follows (in thousands):



	Three Months Ended November 30,
	2015		2014
Realized gain on commodity derivatives	$	700	$	1,432
Unrealized gain on commodity derivatives	2,492		16,708
Total gain	$	3,192	$	18,140

Credit Related Contingent Features

As of November 30, 2015, two of the four counterparties to the Company's derivative instruments were members of the Company’s credit facility syndicate. The Company’s obligations under the credit facility and its derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties. The agreement with the third counterparty, which is not a lender under the credit facility, is unsecured and does not require the posting of collateral. The agreement with the fourth counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility.


8.	Fair Value Measurements

ASC Topic 820, Fair Value Measurements and Disclosure, establishes a hierarchy for inputs used in measuring fair value for financial assets and liabilities that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:


•	Level 1: Quoted prices available in active markets for identical assets or liabilities;


•	Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;


•	Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models.

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The Company’s non-recurring fair value measurements include asset retirement obligations and purchase price allocations for the fair value of assets and liabilities acquired through business combinations. Please refer to Notes 3 and 5 for further discussion of business combinations and asset retirement obligations, respectively.

The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period, and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.

The acquisition of a group of assets in a business combination transaction requires fair value estimates for assets acquired and liabilities assumed. The fair value of assets and liabilities acquired through business combinations is calculated using a net discounted cash flow approach for the producing properties. The discounted cash flows are developed using the income approach and are based on management’s expectations for the future. Unobservable inputs include estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on the NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy). For unproved properties, fair value is determined using unobservable market comparables. For the asset retirement liability assumed, the fair value is determined using the same inputs as describe in the paragraph above. See Note 3 for additional information.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of November 30, 2015 and August 31, 2015 by level within the fair value hierarchy (in thousands):



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



	Fair Value Measurements at August 31, 2015
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	4,462	$	—	$	4,462
Commodity derivative liability	$	—	$	—	$	—	$	—

Commodity Derivative Instruments

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted commodity prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At November 30, 2015, derivative instruments utilized by the Company consist of puts and collars. The crude oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors, including public indices, the instruments themselves are primarily traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and credit facility borrowings. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s credit facility approximated fair value as it bears interest at variable rates over the term of the loan.


9.	Interest Expense

The components of interest expense are (in thousands):



	Three Months Ended November 30,
	2015			2014
Revolving bank credit facility	$	493		$	378
Amortization of debt issuance costs	252			137
Less, interest capitalized	(745		)	(515		)
Interest expense, net	$	—		$	—


10.	Shareholders’ Equity

The Company's classes of stock are summarized as follows:



	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

Preferred stock may be issued in series with such rights and preferences as may be determined by the Board of Directors. Since inception, the Company has not issued any preferred shares.

Shares of the Company’s common stock were issued during three months ended November 30, 2015 and 2014, as described further below.

Common stock issued for acquisition of mineral property interests

During the period presented, the Company issued shares of common stock in exchange for mineral property interests. The value of each transaction was determined using the market price of the Company’s common stock on the date of each transaction.



	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


11.	Earnings per Share

Basic earnings per share includes no dilution and is computed by dividing net income by the weighted-average number of shares outstanding during the period. Diluted earnings per share reflects the potential dilution of securities that could share in the earnings of the Company. The number of potential shares outstanding relating to stock options, non-vested restricted stock, 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 November 30,
	2015	2014
Weighted-average shares outstanding - basic	107,105,253	79,008,719
Potentially dilutive common shares from:
Stock options	—	793,270
Warrants	—	339,163
Weighted-average shares outstanding - diluted	107,105,253	80,141,152

The following potentially dilutive securities outstanding for the fiscal 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 November 30,
	2015	2014
Potentially dilutive common shares from:
Stock options	4,846,000	523,000
Restricted stock	812,334	—
Total	5,658,334	523,000


12.	Stock-Based Compensation

In addition to cash compensation, the Company may compensate certain service providers, including employees, directors, consultants, and other advisors, with equity-based compensation in the form of stock options, stock bonus shares, and warrants. The Company records an expense related to equity compensation by pro-rating the estimated grant date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the “vesting phase”). The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock. Indirect valuations are calculated using the Black-Scholes-Merton option pricing model. For the periods presented, all stock-based compensation expense was classified either as a component within general and administrative expense in the Company's statements of operations, or, for that portion which is directly attributable to individuals performing acquisition, exploration, and development activities, was capitalized to the full cost pool.

Stock-based compensation was recognized as follows (in thousands):



	Three Months Ended November 30,
	2015			2014
Stock options	$	1,560		$	500
Stock bonus shares	6,489			293
Total stock-based compensation	$	8,049		$	793
Less: stock-based compensation capitalized	(852		)	(126		)
Total stock-based compensation expense	$	7,197		$	667

Subsequent to November 30, 2015, the Company granted 706,104 bonus shares, of which 557,570 bonus shares vested immediately. Due to the immediate vesting condition, these 557,570 bonus shares were deemed to have a service inception date which precedes the grant date, and as such, $5.5 million of stock-based compensation was accrued during the three months ended November 30, 2015. Of the $5.5 million in stock-based compensation, $4.0 million was associated with bonuses granted to the departing co-CEOs.

Stock options under the stock option plans

During the three months ended November 30, 2015 and 2014, the Company granted the following stock options:



	Three Months Ended November 30,
	2015		2014
Number of options to purchase common shares	932,500		75,000
Weighted-average exercise price	$	11.05	$	12.87
Term	10 years		10 years
Vesting Period	5 years		5 years
Fair Value (in thousands)	$	5,459	$	639

The assumptions used in valuing stock options granted during each of the three months presented were as follows:



	Three Months Ended November 30,
	2015		2014
Expected term	6.5 years		6.5 years
Expected volatility	53	%	72	%
Risk free rate	1.75 - 2.00%		1.95	%
Expected dividend yield	0.0	%	0.0	%
Average forfeiture rate	0.1	%	0.3	%

The following table summarizes activity for stock options for the three months ended November 30, 2015:



	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

The following table summarizes information about issued and outstanding stock options as of November 30, 2015:



	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

The estimated unrecognized compensation cost from unvested stock options as of November 30, 2015, which will be recognized ratably over the remaining vesting phase, is as follows:



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

Restricted stock awards under the stock bonus plan

The Company grants shares of time-based restricted stock to directors, eligible employees and officers as a part of its equity incentive plan. Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each share of restricted stock represents one share of the Company’s common stock to be released from restrictions upon completion of the vesting period. The time-based restricted stock awards typically vest in equal increments over three to five years. Shares of restricted stock are valued at the closing price of the Company’s common stock on the grant date and are recognized over the vesting period of the award.

The following table summarizes activity for restricted stock awards for the three months ended November 30, 2015:



	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

The estimated unrecognized compensation cost from unvested restricted stock awards as of November 30, 2015, which will be recognized ratably over the remaining vesting phase, is as follows:



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


13.	Income Taxes

We evaluate and update our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. A tax expense or benefit unrelated to the current year income or loss is recognized in its entirety as a discrete item of tax in the period identified. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate, adjusted for the effect of discrete items.

The effective tax rate for the three months ended November 30, 2015 was 8% compared to 36% for the three months ended November 30, 2014. The effective tax rate for the three months ended November 30, 2015 is based upon a full year forecasted tax provision and differs from the statutory rate, primarily due to the recognition of a valuation allowance recorded against deferred tax assets. The effective tax rate for the three months ended November 30, 2014 differs from the statutory rate primarily due to state taxes and nondeductible officers' compensation, partially offset by percentage depletion. There were no significant discrete items recorded during the three months ended November 30, 2015 and 2014.

As of November 30, 2015, we had no liability for unrecognized tax benefits. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position. Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards, and would not result in significant interest expense or penalties. Most of the Company's tax returns filed since August 31, 2011 are still subject to examination by tax authorities. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions, and we are not currently under any state income tax examinations.

No significant uncertain tax positions were identified as of any date on or before November 30, 2015. The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of November 30, 2015, the Company has not recognized any interest or penalties related to uncertain tax benefits.

Each period, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Based upon our cumulative losses through November 30, 2015, we have provided a full valuation allowance reducing the net realizable benefits.


14.	Related Party Transactions

Whenever the Company engages in transactions with its officers, directors, or other related parties, the terms of the transaction are reviewed by the disinterested directors. All transactions must be on terms no less favorable to the Company than similar transactions with unrelated parties.

Lease Agreement: The Company leases its Platteville facilities under a lease agreement with HS Land & Cattle, LLC (“HSLC”). HSLC is controlled by Ed Holloway and William Scaff, Jr., Directors of the Company. The most recent lease, dated June 30, 2014, is currently on a month-to-month basis and requires payments of $15 thousand per month. Historically, the lease has been renewed annually. Under this agreement, the Company incurred the following expenses to HSLC for the periods presented (in thousands):



	Three Months Ended November 30,
	2015		2014
Rent expense	$	45	$	45

Mineral Leases Acquired from Director: Mr. Seward owns mineral interests in several Colorado and Nebraska counties. He agreed to lease his interests to the Company in exchange for restricted shares of common stock. During the three months ended November 30, 2015, the Company acquired leases valued at $248 thousand from Mr. Seward. The acquisition of these leases was accrued as of November 30, 2015; however, the associated restricted shares for these leases were issued in December 2015.

Revenue Distribution Processing: Effective January 1, 2012, the Company commenced processing revenue distribution payments to all persons that own a mineral interest in wells that it operates. Payments to mineral interest owners included payments to entities controlled by three of the Company’s directors, Ed Holloway, William Scaff Jr, and George Seward. The following table summarizes the royalty payments made to directors or their affiliates for the periods presented (in thousands):



	Three Months Ended November 30,
	2015		2014
Total royalty payments	$	54	$	53


15.	Other Commitments and Contingencies

Volume Commitments

During fiscal 2015, the Company entered into crude oil transportation agreements with three counterparties and a volume commitment to a third party refiner. Deliveries under two of the transportation agreements commenced during the quarter ended November 30, 2015. Deliveries under the third transportation agreement are not expected to commence until late in fiscal 2016. The third party refinery volume commitment expired on December 31, 2015.

Pursuant to these agreements, we must deliver specific amounts of crude oil either from our own production or from oil we acquire from third parties. If we are unable to fulfill all of our contractual obligations, we may be required to pay penalties or damages pursuant to these agreements. As of January 1, 2016, our commitments over the next five years are as follows:



Year ending August 31,
(in MBbls/year)
Remainder of 2016		1,651
2017		4,072
2018		4,072
2019		4,072
2020		4,072
Thereafter		1,855
Total		19,794

During the quarter ended November 30, 2015, the Company incurred a transportation deficiency charge of $1.5 million as we were unable to meet all of the obligations during the quarter, and we estimate we could incur an additional $1.0 million deficiency charge in the month of December 2015. As of January 1, 2016, our current production exceeds our delivery obligations, subsequent to the expiration of the volume commitment to a third party refiner.

Office leases

The Company leases its Platteville offices and other facilities from a related party, as described in Note 14. In addition, the Company maintains its principal offices in Denver. The Denver office lease requires monthly payments of approximately $30 thousand and terminates in October 2016.

Litigation

From time to time, the Company is a party to various commercial and regulatory claims, pending or threatened legal action, and other proceedings that arise in the ordinary course of business. It is the opinion of management that none of the current matters of contention are reasonably likely to have a material adverse impact on its business, financial position, results of operations, or cash flows.


16.	Supplemental Schedule of Information to the Statements of Cash Flows

The following table supplements the cash flow information presented in the financial statements for the periods presented (in thousands):



	Three Months Ended November 30,
Supplemental cash flow information:	2015			2014
Interest paid	$	514		$	321
Income taxes (refunded) paid	(150		)	110

Non-cash investing and financing activities:
Accrued well costs	$	41,746		$	69,511
Assets acquired in exchange for common stock	49,840			—
Asset retirement costs and obligations	459			269


17.	Subsequent Events

On December 15, 2015, the Company held its annual meeting of shareholders. The shareholders approved an amendment to the Company’s Articles of Incorporation to increase the number of authorized shares of common stock of the Company from 200,000,000 to 300,000,000. Additionally, the shareholders approved the Company's 2015 Equity Incentive Plan (the "2015

Plan"). With the approval of the 2015 Plan, the 2011 non-qualified stock option plan, the 2011 incentive stock option plan, and the 2011 stock bonus plan (collectively, the "2011 Plans") were terminated. Existing awards under the 2011 Plans will continue in accordance with their applicable terms and conditions. Under the 2015 Plan, the Company is authorized to grant stock options, stock appreciation rights, restricted stock, restricted stock units, stock bonuses and other forms of awards that may be granted or denominated in the Company’s common stock or units of the Company’s common stock, as well as, cash bonus awards. The Company will have 4,500,000 common shares authorized for grant under the 2015 Plan.

Effective December 31, 2015, Ed Holloway and William Scaff, Jr. resigned their positions as Co-Chief Executive Officers of the Company. They continue to serve as directors, and management has been authorized to hire Mr. Holloway and Mr. Scaff as consultants with each being paid $70 thousand per month during the five-month period ending May 31, 2016. Effective January 1, 2016, Lynn A. Peterson assumed the duties of the Chief Executive Officer.


ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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, indicate forward-looking statements. Forward-looking statements included in this report include statements relating to future capital expenditures and projects, the adequacy and nature of future sources of financing, possible future impairment charges, midstream capacity issues, future differentials, and future production relative to volume commitments.

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:


•	extended or further decline in oil and natural gas prices;


•	operating hazards that adversely affect our ability to conduct business;


•	uncertainties in the estimates of proved reserves;


•	effect of seasonal weather conditions and wildlife restrictions on our operations;


•	our ability to fund, develop, produce and acquire additional oil and natural gas reserves that are economically recoverable;


•	our ability to obtain adequate financing;


•	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;


•	availability and capacity of gathering systems and pipelines for our production;


•	the strength and financial resources of our competitors;


•	our ability to successfully identify, execute or effectively integrate future acquisitions;


•	effect of federal, state and local laws and regulations;


•	effects of new environmental legislation or regulatory initiatives, including those related to hydraulic fracturing;


•	our ability to market our production;


•	the effects of local moratoria or bans on our business;


•	effect of environmental liabilities;


•	effect of the adoption and implementation of new statutory and regulatory requirements for derivative transactions;


•	changes in U.S. tax laws;


•	our ability to satisfy our contractual obligations and commitments;


•	the amount of our indebtedness and ability to maintain compliance with debt covenants;


•	effectiveness of our disclosure controls and our internal controls over financial reporting;


•	the geographic concentration of our principal properties;


•	our ability to protect critical data and technology systems;


•	the availability of water for use in our operations; and


•	the risks and uncertainties described and referenced in "Risk Factors."

Introduction

The following discussion and analysis was prepared to supplement information contained in the accompanying unaudited condensed financial statements and is intended to explain certain items regarding the Company's financial condition as of November 30, 2015, and its results of operations for the three months ended November 30, 2015 and 2014. It should be read in conjunction with the accompanying unaudited condensed financial statements and related notes thereto contained in this report as well as the audited financial statements included in our Form 10-K for the fiscal year ended August 31, 2015.

Overview

Synergy Resources Corporation ("we," "us," "Synergy," or the "Company") is a growth-oriented independent oil and natural gas company engaged in the acquisition, development, and production of crude oil and natural gas in and around the D-J Basin, which we believe to be one of the premier, liquids-rich oil and gas resource plays in the United States. The D-J Basin generally extends from the Denver metropolitan area throughout northeast Colorado into Wyoming, Nebraska, and Kansas. It contains hydrocarbon-bearing deposits in several formations, including the Niobrara, Codell, Greenhorn, Shannon, Sussex, J-Sand and D-Sand. The area has produced oil and gas for over fifty years and benefits from established infrastructure including midstream and refining capacity, long reserve life, and multiple service providers.

Our drilling and completion activities are focused in the Wattenberg Field, an area that covers the western flank of the D-J Basin, predominantly in Weld County, Colorado. Currently we are focused on the horizontal development of the Codell and Niobrara formations, which are characterized by relatively high liquids content. We operate the majority of the horizontal wells we have working interests in, and we strive to maintain a high net revenue interest in all of our operations.

Substantially all of our producing wells are either in or adjacent to the Wattenberg Field. We operate over 74% of our proved producing reserves and over 98% of our planned fiscal 2016 drilling and completion expenditures are focused on the Wattenberg Field. This gives us both operational focus and development flexibility to maximize returns on our leasehold position.

Core Operations

Since commencing active operations in September 2008, we have undergone significant growth. From inception through November 30, 2015, we have completed, acquired or participated in 594 gross (401 net) successful oil and gas wells. Our early development efforts were focused on drilling vertical wells into the Niobrara, Codell, and J-Sand formations. In May 2013, we shifted our efforts to horizontal well development within the Wattenberg Field.

The following table provides details about our ownership interests with respect to vertical and horizontal producing wells as of November 30, 2015:

Vertical Wells

Operated Wells

Non-Operated Wells

Totals

Gross

Net

Gross

Net

Gross

Net

332

285

403

306

Horizontal Wells

Operated Wells

Non-Operated Wells

Totals

Gross

Net

Gross

Net

Gross

Net

113

191

In addition to the producing wells summarized in the preceding table, as of November 30, 2015, we were the operator of 25 wells in progress, and we were participating as a non-operating working interest owner in 7 wells in progress.

During the first three months of fiscal 2016, crude oil prices have declined by approximately 20%. Price declines, especially of this magnitude, can impact many aspects of our operations. For a more complete analysis of the potential impacts from declining commodity prices, please see our discussions in "Drilling and Completion Operations," "Market Conditions," "Trends and Outlook," and "Oil and Gas Commodity Contracts."

Strategy

Our primary objective is to enhance shareholder value by increasing our net asset value, net reserves and cash flow through development, exploitation, exploration, and acquisitions of oil and gas properties. We intend to follow a balanced risk strategy by allocating capital expenditures to a combination of lower risk development and exploitation activities and higher potential exploration prospects. Key elements of our business strategy include the following:


•	Concentrate on our existing core area in and around the D-J Basin, where we have significant operating experience. All of our current wells are located within the D-J Basin, and our undeveloped acreage is located either in or adjacent to the D-J Basin. Focusing our operations in this area leverages our management, technical and operational experience in the basin.

•

Develop and exploit existing oil and natural gas properties. Since inception, our principal growth strategy has been to develop and exploit our acquired and leased properties to add proved reserves. In the Wattenberg Field, we target three benches of the Niobrara formation as well as the Codell formation for horizontal drilling and production. Our plans focus on horizontal development as we believe horizontal drilling is the most efficient way to recover the potential hydrocarbons. We consider the Wattenberg Field to be relatively low-risk because information gained from the large number of existing wells can be applied to potential future wells. There is enough similarity between wells in the Wattenberg Field that the exploitation process is generally repeatable.

•

Improve hydrocarbon recovery through increased well density. We utilize the best available industry practices in our effort to determine the optimal recovery area for each well. When we began our operated horizontal well development program in the Wattenberg Field, we assumed spacing of 16 wells per 640 acre section. With increased experience and industry knowledge, we are now testing up to 24 horizontal wells per section.


•	Complete selective acquisitions. We seek to acquire developed and undeveloped oil and gas properties, primarily in the D-J Basin and certain adjacent areas. We generally seek acquisitions that will provide us with opportunities for reserve additions and increased cash flow through production enhancement and additional development and exploratory prospect generation.


•	Retain control over the operation of a substantial portion of our production. As operator of a majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled or existing wells to be re-completed. This allows us to modify our capital spending as our financial resources and underlying lease terms allow and market conditions permit.

•

Maintain financial flexibility while focusing on operational cost control. We strive to be a cost-efficient operator in the D-J Basin. Our relatively low utilization of debt enhances our financial flexibility, and our high degree of operational control, as well as our focus on operating efficiencies and short return on investment cycle times, is central to our operating strategy. Additionally, we seek to maintain low lease operating, drilling and completion costs. We intend to finance our operations through a mixture of cash from operations, debt and equity capital as market conditions allow.

•

Use the latest technology to maximize returns. Beginning in fiscal 2013, we shifted our emphasis away from drilling vertical wells towards drilling horizontal wells. In doing so, we have significantly increased our production and the value of our asset base. While horizontal drilling requires higher up-front costs, these wells have generated relatively higher returns on our capital deployed. Increasing the number of wells drilled within a given drilling section and applying technical advances in drilling and completion designs is leading to enhanced productivity. Production results from various well designs are analyzed, and the conclusions from each analysis are factored into future well designs that take into account spacing between hydraulic fracturing stages, potential communication between wellbores, lateral length, timing and economics. Similarly, we evaluate the use of different completion fluids.

Significant Developments

Acquisition Activity

Acquisition of Mineral Assets from K.P. Kauffman on October 20, 2015

On October 20, 2015, we completed the acquisition of interests in producing wells and non-producing leaseholds in the Wattenberg Field from K.P. Kauffman Company, Inc. The assets include leasehold rights for approximately 4,300 net acres in the

core Wattenberg Field and non-operated working interests in 25 gross (approximately 5 net) horizontal wells in the Niobrara and Codell formations. Net production associated with the purchased assets was approximately 1,200 BOED. The purchase price for the assets was $85.2 million, comprised of $35.0 million in cash and approximately 4.4 million restricted shares of our common stock, subject to closing adjustments. The transaction has an effective date of September 1, 2015.

Impairment of full cost pool

Every quarter, we perform a ceiling test as prescribed by SEC regulations for entities following the full cost method of accounting. This test determines a limit on the book value of oil and gas properties using a formula to estimate future net cash flows from oil and gas reserves. This formula is dependent on several factors and assumes future oil and natural gas prices to be equal to an unweighted arithmetic average of oil and natural gas prices from each of the 12 months prior to the reporting period. During our first fiscal quarter of 2016, this calculation indicated that the ceiling amount had declined, largely as a result of the decline in oil and natural gas prices, such that the ceiling was less than the net book value of oil and gas properties. As a result, we recorded a ceiling test impairment totaling $125.2 million for the three months ended November 30, 2015. This full cost ceiling impairment is recognized as a charge to earnings and may not be reversed in future periods, even if oil and natural gas prices subsequently increase. For more information, see "Trends and Outlook" for discussion relating to future potential impairments.

Drilling and Completion Operations

Our drilling and completion schedule has a material impact on our production forecast and a corresponding impact on our expected future cash flows. As commodity prices have fallen, we have been able to reduce per well drilling and completion costs. We actively monitor prices and costs to determine if we can achieve a reasonable well-level rate of return. Our operational flexibility allows us to adjust our drilling and completion schedule as necessary. If management believes the well-level internal rate of return will be at or below our weighted-average cost of capital, we may choose to further delay completions and/or forego drilling altogether.

Subsequent to the quarter end, we elected to terminate our existing drilling rig contract, approximately one month prior to the contract’s expiration date, and entered into a 180 day contract for a new build rig. We believe the lower day rate and expected increased efficiencies of the new rig should more than offset the expected $0.5 million early termination fee incurred. The new rig is expected to be mobilized onto our Vista pad in mid-January 2016.

During the three months ended November 30, 2015, we drilled 10 horizontal wells targeting the Niobrara or Codell formations. During the three months ended November 30, 2015, we completed 5 horizontal wells. As of November 30, 2015, there are 25 horizontal wells in various stages of completion.

Other Operations

We continue to be opportunistic with respect to acquisition efforts. We continue to enter into land and working interest swaps to increase our overall leasehold control. During the three months ended November 30, 2015, we consummated several asset and acreage swaps, resulting in a higher working interest in several of our operated pads as well as a higher working interest in yet-to-be-developed leaseholds.

Production

Our production decreased from 10,925 BOED for the three months ended August 31, 2015 to 10,540 BOED for the three months ended November 30, 2015. The additional production volumes from recently completed wells and the K.P. Kauffman acquisition did not offset the natural decline of our existing 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 NYMEX prices for oil and natural gas for each of the last five fiscal years.



	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 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 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.

Trends and Outlook

Oil traded at $49.20 per Bbl on Monday, August 31, 2015, the last day of our 2015 fiscal year, but declined more than 20% through November 2015. This decline has resulted in a reduction of operating cash flow and contributed to a ceiling test impairment charge of $125.2 million for the three months ended 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 example, had the ceiling test computation used the lower price deck of $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 would be recorded.

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 Revolver 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.

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 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 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 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 severe price drop in crude oil and natural gas 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.

From time to time, our production has been adversely impacted by high natural gas gathering line pressures, especially in the northern area of the Wattenberg Field. Where it is cost effective, we install wellhead compression to enhance our ability to inject gas into the gathering system and in some instances install larger gathering lines to help mitigate the impacts. Additionally, midstream companies that operate the gas gathering pipelines in the area continue to make significant capital investments to 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 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. This has reversed the prior imbalance of oil production exceeding the combination of local refinery demand and the capacity of pipelines to move the oil to other markets. Depending on transportation commitments, local refinery demand, and our production volumes, we may be able to reduce the 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 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.

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. During the first fiscal quarter of 2016, the NYMEX-WTI oil price ranged from a high of $49.20 per Bbl on Monday, August 31, 2015, the last day of our 2015 fiscal year, to a low of $39.27 per Bbl near the end of November 2015, while the NYMEX-Henry Hub natural gas price ranged from a high of $2.76 per MMBtu in the middle of September to a low of $2.03 per 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.

At November 30, 2015, we had cash and cash equivalents of $80.7 million and an outstanding balance of $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 three months ended 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

Net cash provided by operating activities was $21.1 million and $34.4 million for the three months ended November 30, 2015 and 2014, respectively. The decline in cash from operating activities reflects the decline in commodity prices which was partially offset by the increase in 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 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. The value of the collateral will generally be derived 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 November 30, 2015, our borrowing base was $163 million, and we had $78.0 million outstanding under the facility. The maturity date of the 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 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.

With respect to 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 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 accrual basis, capital expenditures totaled $134.7 million and $64.2 million for the three months ended November 30, 2015 and 2014, respectively. A reconciliation of the differences between cash payments and the accrual basis amounts is summarized in the following table (in thousands):



	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 Requirements

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 mitigate a portion of our exposure to potentially adverse market changes in commodity prices and the associated impact on our expected future cash flows. We 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 November 30, 2015, we had open positions covering 1.1 million barrels of oil and 2,692 MMcf of natural gas. We do not use derivative instruments for speculative purposes.

Our commodity derivative instruments may include but are not limited to “collars,” “swaps,” and “put” positions. Our derivative strategy, including the associated volumes, the commodity, and the relevant reference price or prices, 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 derivative contracts is subject to stipulations set forth in our credit facility.

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 prices in the future while losses indicate higher future wellhead 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 November 30, 2015, we estimated that the fair value of our various commodity derivative contracts was a net asset of $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 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:



	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 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 "adjusted EBITDA," which is a financial measure that is not prescribed by US GAAP ("non-GAAP").

We use adjusted EBITDA 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, and it should not be viewed as a liquidity measure or indicator of cash flows reported in accordance with US GAAP. 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 the items set forth in the table below. We believe adjusted EBITDA is relevant because similar measures are widely used in our 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 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

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.

There have been no significant changes to our critical accounting policies and 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 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.

We call your attention to the increased significance of the ceiling test as disclosed in Note 2, Property and Equipment, to the accompanying condensed financial statements included elsewhere in this report. During the quarter ended November 30, 2015, we recorded an impairment in conjunction with performing a ceiling test as prescribed by SEC Regulation S-X Rule 4-05.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

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 76% of our revenue during our first three months of fiscal 2016 was from the sale of oil. A $10 per barrel change in our realized oil price would have resulted in a $5.4 million change in oil revenues during our first fiscal quarter of 2016, while a $0.50 per Mcf change in our realized gas price would have resulted in a $1.3 million change in our natural gas revenues in our first fiscal quarter.

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.

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. Typically, 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 November 30, 2015, we had open crude oil and natural gas derivatives in a net asset position with a fair value of $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 $0.7 million.

Interest Rate Risk

At November 30, 2015, we had debt outstanding under our bank credit facility totaling $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”) plus an applicable margin. At 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 increased by 1% to an annual rate of 3.5%, our interest payments in our first fiscal quarter of 2016 would have increased by $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 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 year as the amounts due to us from counterparties has increased.


ITEM 4.	CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive 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”) as of the end of the period covered by this report on Form 10-Q (the “Evaluation Date”). Based on such evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the Evaluation Date, our disclosure controls and procedures were effective.

Changes in Internal Control 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.

PART II


Item 1.	Legal Proceedings

During the quarter, there were no material developments regarding legal matters, which were previously described under Item 3, Legal 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

We face many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity, and the trading price of our common stock are described under Item 1A, Risk Factors, 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 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 statutory minimum withholding requirements, certain of our employees exercised their right to "withhold to cover" as a tax payment method for the vesting and exercise of 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.

Item 6. 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
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
32	Certifications of the Principal Executive Officer and Principal Financial Officer pursuant to 18 USC 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

SIGNATURES

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



	SYNERGY RESOURCES CORPORATION

	/s/ Lynn A. Peterson
	Lynn A. Peterson, President and Chief Executive Officer (Principal Executive Officer)

	/s/ James P. Henderson
	James P. Henderson, Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)

	/s/ Frank L. Jennings
	Frank L. Jennings, Vice President and Chief Accounting Officer (Principal Accounting Officer)

SRC Energy Inc. - FORM 10-Q - January 7, 2016

Attached files

SRC Energy Inc. Reports