SRCI SRC Energy Inc

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PART I

EXPLANATORY NOTE REGARDING THIS TRANSITION REPORT

    

On February 25, 2016, we changed our fiscal year from the period beginning on September 1 and ending on August 31 to the period beginning on January 1 and ending on December 31. As a result, this report on Form 10-K (the "10-K") is a transition report and includes financial information for the transition period from September 1, 2015 through December 31, 2015. Subsequent to this report, our reports on Form 10-K will cover the calendar year, January 1 to December 31, which will be our fiscal year. Unless otherwise noted, all references to "years" in this report refer to the twelve-month fiscal year, which prior to September 1, 2015 ended on August 31, and beginning after December 31, 2015 ends on the December 31 of each year.

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.

Important 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;

•	the 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;

•	the 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 that we do not operate;

•	the 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;

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

•	the effects of, including cost to comply with, 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;

•	the effect of environmental liabilities;

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

•	changes in U.S. tax laws;

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•	our ability to satisfy our contractual obligations and commitments;

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

•	the 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."

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GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS

We have included below the definitions for various units of measurement and industry terms used in this Transition Report on Form 10-K.

Units of Measurement

The following presents a list of units of measurement used throughout the document:

Bbl - One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or NGL.

Bcf - One billion cubic feet of natural gas volume.

BOE - One barrel of crude oil equivalent, which combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil.

BOED - BOE per day.

Btu - British thermal unit.

MBOE - One thousand BOE.

MMBbls - One million barrels of crude oil.

Mcf - One thousand cubic feet of natural gas volume.

MMBtu - One million British thermal units.

MMcf - One million cubic feet of natural gas volume.

MMcf/d - MMcf per day.

Glossary of Industry Terms

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report:

Completion  - Refers to the work performed and the installation of permanent equipment for the production of crude oil and natural gas from a recently drilled well.

Developed acreage  - Acreage assignable to productive wells.

Development well  - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differentials -  The difference between the crude oil and natural gas index spot price and the corresponding cash spot price in a specified location.

Dry gas  - Natural gas is considered dry when its composition is over 90% pure methane.

Dry well or dry hole   - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well.

EURs - Estimated ultimate recovery.

Exploratory well   - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

Extensions and discoveries - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.

Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest.

Gross acres  or  wells  - Refers to the total acres or wells in which we have a working interest.

Henry Hub - Henry Hub index. Natural gas distribution point where prices are set for natural gas futures contracts traded on the NYMEX.

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Horizontal drilling   - A drilling technique that permits the operator to drill a horizontal wellbore from the bottom of a vertical section of a well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques allow and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.

Horizontal well   - A well that has been drilled using the horizontal drilling technique. The term "horizontal wells" include wells where the productive length of the wellbore is drilled more or less horizontal to the earth's surface, to intersect the target formation on a parallel basis.

Hydraulically fracture  or  Hydraulic fracturing  - a procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability, thereby allowing the release of trapped hydrocarbons.

Joint interest billing  - Process of billing/invoicing the costs related to well drilling, completions and production operations among working interest partners.

Natural gas liquid(s)  or  NGL(s)  - Hydrocarbons which can be extracted from "wet" natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane, and other condensates.

Net acres  or  wells  - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest.

Net revenue interest - Refers to all working interests less all royalties.

Net production   - Crude oil and natural gas production that we own, less royalties and production due to others.

Non-operated  - A project in which another entity has responsibility over the daily operation of the project.

NYMEX   - New York Mercantile Exchange.

OPEC - the Organization of Petroleum Exporting Countries.

Operator  - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease.

Overriding royalty -  An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest.

Possible reserves -  This term is defined in SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates.

Present value of future net revenues  or  (PV-10) -  PV-10 is a Non-GAAP financial measure calculated before the imposition of corporate income taxes. It is derived from the standardized measure of discounted future net cash flows relating to proved oil and gas reserves prepared in accordance with the provisions of Accounting Standards Codification Topic 932, Extractive Activities - Oil and Gas.  The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and the periods in which they are expected to be developed and produced based on specified economic conditions.  The estimated future production is based upon benchmark prices that reflect the unweighted arithmetic average of the first-day-of-the-month price for oil and gas during the relevant period. The resulting estimated future cash inflows are then reduced by estimated future costs to develop and produce reserves based on current cost levels.  No deduction is made for the depletion of historical costs or for indirect costs, such as general corporate overhead.  Present values are computed by discounting future net revenues by 10% per year.

Probable reserves -  This term is defined in SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

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Productive well  - A well that is not a dry well or dry hole, as defined above, and includes wells that are mechanically capable of production.

Proved developed non-producing reserves   or PDNPs - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.

Proved developed producing reserves  or  PDPs   - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.

Proved developed reserves  - The combination of proved developed producing and proved developed non-producing reserves.

Proved reserves  - This term means "proved oil and gas reserves" as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of crude oil and condensate, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Proved undeveloped reserves  or  PUDs   - Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Recomplete  or  Recompletion  - The modification of an existing well for the purpose of producing crude oil and natural gas from a different producing formation.

Reserves  - Estimated remaining quantities of crude oil, natural gas, NGLs and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil, natural gas and NGLs or related substances to market, and all permits and financing required to implement the project.

Royalty  - An interest in a crude oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Section -  A square tract of land one mile by one mile, containing 640 acres.

Spud -  To begin drilling; the act of beginning a hole.

Standardized measure of discounted future net cash flows  or  standardized measure   - Future net cash flows discounted at a rate of 10%. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense.

Undeveloped acreage  - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether such acreage contains proved reserves.

Vertical well - Directional wells that are drilled at an angle toward a target area where the productive length of the wellbore intersects the target formation on a perpendicular basis.

Wet gas or wet natural gas  - Natural gas that contains a larger quantity of hydrocarbon liquids than dry natural gas, such as NGLs, condensate and crude oil.

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Working interest  - An interest in a crude oil and natural gas lease that gives the owner of the interest the right to drill and produce crude oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production operations.

Workover  - Major remedial operations on a producing well to restore, maintain or improve the well's production.

WTI - West Texas Intermediate. A specific grade of crude oil used as a benchmark in oil pricing. It is the underlying commodity of NYMEX's oil futures contracts.

ITEM 1.	BUSINESS

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 Denver-Julesburg Basin (“D-J Basin”) of Colorado, 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 crude oil and NGL content. We operate the majority of the horizontal wells in which we have working interests, and we strive to maintain a high net revenue interest in all of our operations.

Core Operations         

Since commencing active operations in September 2008, we have undergone significant growth. From inception through December 31, 2015 , we have completed, acquired or participated in 609 gross ( 409 net) productive oil and gas wells. As of December 31, 2015 , we are the operator of 418 gross ( 369 net) producing wells and participate as non-operators in 191 producing wells. In addition, there were 18 gross ( 14 net) wells in various stages of drilling or completion as of December 31, 2015.

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. Since shifting to horizontal development, we have drilled or participated in the drilling of 206 gross ( 103 net) horizontal wells. As of December 31, 2015 , we are the operator of 86 gross ( 84 net) Codell or Niobrara horizontal wells.

For the four months ended December 31, 2015 and 2014, our average net daily production was 10,822 BOED and 8,432 BOED, respectively. By comparison, during the years ended August 31, 2015 , 2014 and 2013 , our average production rate was 8,750 BOED, 4,290 BOED and 2,117 BOED, respectively. By the end of December 31, 2015 , over 80% of our daily operated production was from horizontal wells as compared to less than 10% as of August 31, 2013.

Key Developments

    

During the four months ended December 31, 2015 , we continued to execute our plans for growth through development of our existing oil and gas properties and strategic acquisitions of producing properties. During the period, oil prices declined 25% and gas prices declined 13% , which impacted both our revenues for the period and our costs to produce oil and gas. Revenue for the four months ended December 31, 2015 was $34.1 million , and net loss was $122.9 million (including a ceiling test impairment of $125.2 million ), or $(1.14) per diluted share, compared to revenue of $52.9 million and net income of $26.8 million , or $0.33 per diluted share, for the four months ended December 31, 2014 . See further discussion of our financial and operational results for the four months ended December 31, 2015 in Part II, Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations and in our financial statements included as part of this report.

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Significant business developments for the four months ended December 31, 2015 and subsequent periods are described below:

Acquisition Activity

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

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 assets included leasehold rights for 4,300 net acres in the Wattenberg Field and non-operated working interests in 25 gross (approximately 6 net) horizontal wells in the Niobrara and Codell formations. Net production associated with the purchased assets was approximately 1,200 BOED at the time of purchase. The transaction had an effective date of September 1, 2015.

Financing

Equity offerings

On January 27, 2016, the Company closed on the sale of 16,100,000 shares of common stock pursuant to an underwriting agreement with Credit Suisse Securities (USA) LLC, acting severally on behalf of itself and the other underwriters.  The price to the Company was $5.545 per share and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company were $89.1 million .  Proceeds from the offering were expected to be used for general corporate purposes, including continuing to develop our acreage position in the Wattenberg Field in Colorado, repaying amounts borrowed under our revolving credit facility (the "Revolver"), funding a portion of our capital expenditure program for the remainder of 2016, or other uses.

On April 14, 2016, the Company closed on the sale of an additional 22,425,000 shares of common stock pursuant to an underwriting agreement with the same underwriters.  The price to the Company was $7.3535 per share and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company were $164.8 million .  The proceeds from this offering are also expected to be used for general corporate purposes, including to fund development activities and/or potential future acquisitions.

Revolving Credit Facility

We continue to maintain a borrowing arrangement (sometimes referred to herein as the "Revolver") with our bank syndicate to provide us with liquidity, which could be used to develop oil and gas properties, acquire new oil and gas properties, and for working capital and other general corporate purposes. As of December 31, 2015 , the Revolver provided for maximum borrowings of $500 million , subject to adjustments based upon a borrowing base calculation, which is re-determined semi-annually using updated reserve reports. As of December 31, 2015 , the Revolver provided for a borrowing base of $163 million , of which $85 million was available to us for future borrowings. The Revolver is collateralized by certain of our assets, including producing properties, and bears a minimum interest rate on borrowings of 2.5% , with the effective rate varying with utilization. The Revolver expires on December 15, 2019 .

On January 28, 2016, the Revolver was amended in connection with a previously postponed semi-annual borrowing base redetermination. The borrowing base was reduced from $163 million to $145 million , and the Revolver was further amended to (i) delete the minimum interest rate floor, (ii) delete the minimum liquidity covenant, (iii) add a current ratio covenant of 1.0 to 1.0, and (iv) delete the minimum hedging requirement. In January 2016, the Company reduced its outstanding borrowings under the Revolver from $78 million to nil . As of March 31, 2016, the entire $145 million borrowing base was available to us for future borrowings.

See further discussion in Note 6 to our financial statements.

Properties

As of December 31, 2015 , our estimated net proved oil and gas reserves, as prepared by our independent reserve engineering firm Ryder Scott Company, L.P. ("Ryder Scott"), were 26.4  MMBbls of oil and condensate and 238.7 Bcf of natural gas. As of December 31, 2015 , we had approximately 441,000   gross and 349,000  net acres under lease, substantially all of which are located in the greater D-J Basin. We further delineate our acreage into specific areas, including the areas we refer to as the “core" Wattenberg Field (approximately 55,000 gross and 41,000 net acre s) and the “North East Extension Area” of the Wattenberg

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Field (approximate ly 99,000 gross and 51,000  net acres) . In addition, we hold approximately 191,000 gross ( 188,000 net) acres in southwest Nebraska, a conventional oil-prone prospect, and approximately 87,000 gross ( 63,000 net) acres in far eas tern Colorado.

Within our leasehold in the North East Extension Area, we completed our first horizontal well targeting the Greenhorn formation which was drilled during the year ended August 31, 2015 and subsequently completed. The well is producing hydrocarbons but not in paying quantities, and further expenditures will not be incurred until commodity prices return to a higher level. Our eastern Colorado mineral assets are located in Yuma and Washington Counties, in an area that has a history of dry gas production from the Niobrara formation, where there is little to no activity in the current commodity price environment.

We currently operate over 75% of our proved producing reserves and over 90% of our drilling and completion expenditures during the four months ended December 31, 2015 were focused on the Wattenberg Field. Over 98% of our drilling and completion expenditures for the 2016 calendar year are anticipated to be focused on the Wattenberg Field. A high degree of operational and capital control gives us both operational focus and development flexibility to maximize returns on our leasehold position.

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Business 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. With current economic conditions, we intend to follow a balanced risk strategy by allocating capital expenditures to lower risk development and exploitation activities. 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 properties to add reserves.  In the Wattenberg Field, we target three benches of the Niobrara formation as well as the Codell formation for horizontal drilling and production. We believe horizontal drilling is the most efficient way to recover the potential hydrocarbons and 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 core Wattenberg Field.  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 and to maintain a relatively low utilization of debt which enhances our financial flexibility. 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.

•

Use the latest technology to maximize returns.   While horizontal drilling requires higher up-front costs, these wells generate relatively higher returns on our capital deployed. Our primary focus is drilling wells that have 7,000' to 10,000' of lateral as opposed to the 4,000' laterals that were initially drilled in the Wattenberg Field. Increasing the number of wells drilled within a given drilling section, drilling longer laterals, and applying technical advances in drilling and completion designs is leading to increased 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.

      

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Competitive Strengths

 

We believe that we are positioned to successfully execute our business strategy because of the following competitive strengths:

•

Core acreage position in the Wattenberg Field. Wells in our core properties in the Wattenberg Field generally exhibit high liquids content, and those properties are generally prospective for Niobrara A, B, and C bench and Codell development. We believe that these factors will lead to attractive EURs per well, per unit capital and operating costs and rates of return. Increased well density within the Codell and Niobrara formations as well as our acquisition efforts and organic leasing efforts within the core Wattenberg Field have added to our multi-year drilling inventory. We also believe that our core acreage could be prospective for Greenhorn, Sussex, and J-Sand development.

•

Financial flexibility. Our capital structure and high degree of operational control continues to provide us with significant financial flexibility. We have historically utilized very little debt in our capital structure. In addition to being a potential future source of liquidity, our low debt level has enabled us to make capital decisions with limited restrictions imposed by debt covenants, lender oversight and/or mandatory repayment schedules. Additionally, as the operator of 100% of our anticipated future net drilling locations per our December 31, 2015 reserve report, we control the timing and selection of drilling locations as well as completion schedules. This allows us to modify our capital spending program depending on financial resources, leasehold requirements, and market conditions.

•	Management experience.   Our key management team possesses an average of over thirty years o f experience in oil and gas exploration and production in multiple resource plays, including the Wattenberg Field.

 

•	Balanced oil and natural gas reserves and production.   At December 31, 2015 , approximately 64% of total gross revenues from proved reserves were oil and condensate, and 36% were natural gas and natural gas liquids, measured on a Btu equivalent basis. We believe that this balanced commodity mix will provide diversification of sources of cash flow.

•	Cost-efficient operator. We have continued to demonstrate our ability to drill wells in a cost efficient way and to successfully integrate acquired assets without incurring significant increases in overhead.

•	High success rate. We have concentrated our drilling in areas that we perceive as relatively low risk and, as a result, have had a very high success rate in our drilling program throughout the Wattenberg Field.

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Drilling Operations

During the periods presented below, we drilled or participated in the drilling of a number of wells that reached productive status in each respective period. During the four months ended December 31, 2015 , we drilled 9 horizontal wells that are classified as exploratory and 4 that are classified as development. Although the 9 wells were drilled in an area that contained productive vertical wells, the area had not been proved on a horizontal basis. Therefore, these new wells met the definition of exploratory wells.

	Four Months Ended December 31,												Year Ended August 31,
	2015						2014						2015						2014						2013
	Gross			Net			Gross			Net			Gross			Net			Gross			Net			Gross			Net
Development Wells:
Productive:
Oil	4			4			8			1			8			1			47			22			48			32
Gas	—			—			1			—			1			—			2			1			—			—
Nonproductive	—			—			—			—			—			—			—			—			—			—
Exploratory Wells:
Productive:
Oil	9			9			34			8			67			40			11			10			—			—
Gas	—			—			—			—			—			—			—			—			—			—
Nonproductive	1			—			—			—			—			—			1			—			—			—

All of the oil wells in the table above are located in, or adjacent to, the Wattenberg Field of the D-J Basin. The three gas wells in the table above are located in Yuma County, Colorado. As of December 31, 2015 , there were 18 gross ( 14 net) wells in progress that were not included in the above well counts.

Production Data

          

The following table shows our net production of oil and gas, average sales prices, and average production costs for the periods presented:

	Four Months Ended December 31,								Years Ended August 31,
	2015				2014				2015				2014				2013
Production :
Oil (MBbls)	742				639				1,970				941				421
Gas (MMcf)	3,468				2,340				7,344				3,747				2,108
MBOE	1,320				1,029				3,194				1,566				773
BOED	10,822				8,432				8,750				4,290				2,117
Average sales price:
Oil ($/Bbl)	$	34.65			$	66.72			$	50.75			$	89.98			$	85.95
Gas ($/Mcf)	$	2.43			$	4.41			$	3.39			$	5.21			$	4.75
BOE	$	25.86			$	51.45			$	39.09			$	66.56			$	59.83
Average lease operating expenses per BOE	$	4.41			$	4.61			$	4.70			$	5.10			$	4.42

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Major Customers

Historically, we sold our crude oil production to local refineries and, to a lesser degree, third-party marketers. During 2015 , we secured contracts with additional oil purchasers who intend to transport oil via pipelines. Under the contracts, we have delivery commitments covering a portion of our anticipated future production over the next five years. Our natural gas and natural gas liquids are sold under contracts with two midstream gas gathering and processing companies. We believe that both gas processing and crude oil takeaway capacity are sufficient to meet our anticipated production growth. See further discussion in Note 16 to our financial statements.

Oil and Gas Properties, Wells, Operations and Acreage

We believe that the title to our oil and gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. Our properties are typically subject, in one degree or another, to one or more of the following:

•	royalties and other burdens and obligations, expressed or implied, under oil and gas leases;

•	overriding royalties and other burdens created by us or our predecessors in title;

•	a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farm-out agreements, production sales contracts, and other agreements that may affect the properties or title thereto;

•	back-ins and reversionary interests existing as a result of pooling under state orders;

•	liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors, and contractual liens under operating agreements;

•	pooling, unitization and communitization agreements, declarations, and orders; and

•	easements, restrictions, rights-of-way, and other matters that commonly affect property.

To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and obligations affecting our properties are customary in the industry for properties of the kind that we own.

The following table shows, as of March 31, 2016 , by state, our producing wells, developed acreage, and undeveloped acreage, excluding service (injection and disposal) wells:

		Productive Wells						Developed Acreage						Undeveloped Acreage 1
State		Gross			Net			Gross			Net			Gross			Net
Colorado		609			409			31,100			25,400			188,800			118,200
Nebraska		—			—			—			—			191,400			187,500
Wyoming		—			—			—			—			1,100			500
Kansas		—			—			—			—			800			800
Total		609			409			31,100			25,400			382,100			307,000

         ¹     Undeveloped acreage includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial quantities of oil and natural gas regardless of whether the leasehold interest is classified as containing proved undeveloped reserves.

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    The following table shows, as of March 31, 2016 , the status of our gross acreage:

State		Held by Production			Not Held by Production
Colorado		31,100			188,800
Nebraska		—			191,400
Wyoming		—			1,100
Kansas		—			800
Total		31,100			382,100

Leases that are held by production generally remain in force so long as oil or gas is produced from the well on the particular lease.  Leased acres which are not held by production may require annual rental payments to maintain the lease until the expiration of the lease or the time oil or gas is produced from one or more wells drilled on the leased acreage.  At the time oil or gas is produced from wells drilled on the leased acreage, the lease is considered to be held by production.

 

The following table shows the calendar years during which our leases not currently held by production will expire unless a productive oil or gas well is drilled on the lease.

Leased Acres (Gross)		Expiration of Lease
42,400		2016
51,400		2017
67,200		2018
252,200		After 2018

The overriding royalty interests that we own are not material to our business.

Oil and Gas Reserves

 

Our estimated proved reserve quantities increased by 17% from August 31, 2015 to December 31, 2015 .  Our December 31, 2015 , reserve report indicated that we had estimated proved reserves of 26.4 million barrels of oil and 238.7 billion cubic feet of gas. The increase in estimated proved reserve quantities is due to high-grading our inventory of wells to be drilled, plans to drill an increased number of mid- and extended-length horizontal wells, and the K.P. Kauffman acquisition. The estimated PV-10 value of our reserves at that date was $438.1 million . PV-10 is a non-GAAP measure that reflects the present value, discounted at 10%, of estimated future net revenues from our proved reserves. We present a reconciliation of PV-10 value to the standardized measure of discounted future net cash flows in Item 7 under "Non-GAAP Financial Measures." The PV-10 value as of December 31, 2015 stayed relatively flat compared to August 31, 2015, decreasing by $0.1 million . The decrease in price between August 31, 2015 and December 31, 2015 was largely offset by decreased operating costs and decreased development costs due to reduced completions costs and efficiencies realized from items such as utilizing technology that eliminates the intermediate string of casing, reducing drill time and costs.

Ryder Scott Company, L.P. (“Ryder Scott”) prepared the estimates of our proved reserves, future production, and income attributable to our leasehold interests as of December 31, 2015 .  Ryder Scott is an independent petroleum engineering firm that has been providing petroleum consulting services worldwide for over seventy years.  The estimates of proved reserves, future production, and income attributable to certain leasehold and royalty interests are based on technical analyses conducted by teams of geoscientists and engineers employed at Ryder Scott.  The office of Ryder Scott that prepared our reserves estimates is registered in the State of Texas (License #F-1580).  Ryder Scott prepared our reserve estimate based upon a review of property interests being appraised, historical production, lease operating expenses, price differentials, authorizations for expenditure, and geological and geophysical data.

 

The report of Ryder Scott dated March 28, 2016, which contains further discussions of the reserve estimates and evaluations prepared by Ryder Scott, as well as the qualifications of Ryder Scott’s technical personnel responsible for overseeing such estimates and evaluations, is attached as Exhibit 99. 1 to the Current Report on Form 8-K filed on April 11, 2016.

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Our reserves technical team, which consists of our lead Reservoir Engineer, VP of Exploration, VP of Drilling, and VP of Completions, oversaw the preparation of the reserve estimates by Ryder Scott to ensure accuracy and completeness of the data prior to and after submission.  Our technical team has an average of over thirty years of experience in oil and gas exploration and development.

 

Our proved reserves include only those amounts which we reasonably expect to recover in the future from known oil and gas reservoirs under existing economic and operating conditions, at current prices and costs, under existing regulatory practices and with existing technology.  Accordingly, any changes in prices, operating and development costs, regulations, technology or other factors could significantly increase or decrease estimates of proved reserves.

 

Estimates of volumes of proved reserves at year end are presented in barrels for oil and Mcf for natural gas at the official temperature and pressure bases of the areas in which the gas reserves are located.

 

The proved reserves attributable to producing wells and/or reservoirs were estimated by performance methods.  These performance methods include decline curve analysis, which utilized extrapolations of historical production and pressure data available through December 31, 2015 in those cases where this data was considered to be definitive.  The data used in this analysis was obtained from public sources and was considered sufficient for calculating producing reserves. The undeveloped reserves were estimated by the analogy method.  The analogy method uses pertinent well data obtained from public sources that was available through December 31, 2015.

 

Below are estimates of our net proved reserves at December 31, 2015 , all of which are located in Colorado:

	Oil (MBbls)			Gas (MMcf)			MBOE
Proved:
Developed	8,410			56,751			17,868
Undeveloped	17,969			181,919			48,289
Total	26,379			238,670			66,157

The following tabulations present the PV-10 value of our estimated reserves as of December 31, 2015 , August 31, 2015 , 2014 , and 2013 (in thousands):

	Proved - December 31, 2015
	Developed												Total
	Producing				Non-producing				Undeveloped				Proved
Future cash inflow	$	494,858			$	—			$	1,215,752			$	1,710,610
Future production costs	(172,183		)		—				(289,914		)		(462,097		)
Future development costs	(31,310		)		—				(309,139		)		(340,449		)
Future pre-tax net cash flows	$	291,365			$	—			$	616,699			$	908,064
PV-10 (Non-U.S. GAAP)	$	199,462			$	—			$	238,681			$	438,143

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	Proved - August 31, 2015
	Developed												Total
	Producing				Non-producing				Undeveloped				Proved
Future cash inflow	$	554,366			$	—			$	1,492,249			$	2,046,615
Future production costs	(211,911		)		—				(441,098		)		(653,009		)
Future development costs	(29,486		)		—				(481,234		)		(510,720		)
Future pre-tax net cash flows	$	312,969			$	—			$	569,917			$	882,886
PV-10 (Non-U.S. GAAP)	$	227,063			$	—			$	211,218			$	438,281

	Proved - August 31, 2014
	Developed												Total
	Producing				Non-producing				Undeveloped				Proved
Future cash inflow	$	511,252			$	234,452			$	1,094,283			$	1,839,987
Future production costs	(127,900		)		(48,990		)		(218,129		)		(395,019		)
Future development costs	(13,245		)		(29,403		)		(369,869		)		(412,517		)
Future pre-tax net cash flows	$	370,107			$	156,059			$	506,285			$	1,032,451
PV-10 (Non-U.S. GAAP)	250,749				76,593				206,356				$	533,698

	Proved - August 31, 2013
	Developed												Total
	Producing				Non-producing				Undeveloped				Proved
Future cash inflow	$	206,065			$	286,207			$	256,758			$	749,030
Future production costs	(46,410		)		(52,605		)		(47,337		)		(146,352		)
Future development costs	—				(26,086		)		(82,204		)		(108,290		)
Future pre-tax net cash flows	$	159,655			$	207,516			$	127,217			$	494,388
PV-10 (Non-U.S. GAAP)	$	92,888			$	104,392			$	38,836			$	236,116

The combined effect of our drilling, acquisition, and participation activities, offset by declining commodity prices, during the four months ended December 31, 2015 generated a decrease in projected future cash inflow from proved reserves of $336.0 million compared to August 31, 2015 . However, future pre-tax net cash flow increased $25.2 million from August 31, 2015 to December 31, 2015 as per-unit costs declined commensurate with per-unit future cash inflow.  During the same period, our PV-10 from proved reserves decreased by $0.1 million .  During the four months ended December 31, 2015 , we incurred capital expenditures of approximately $92.5 million related to the acquisition and development of proved reserves. The prices for the oil and gas reserves as of December 31, 2015 are based on the twelve-month arithmetic average for the first of month prices from January 1, 2015 through December 31, 2015 . The following table presents the prices used to prepare the reserve estimates, based upon the unweighted arithmetic average of the first day of the month price for each month within the twelve-month period prior to the end of the respective reporting period presented as adjusted for our differentials:

	Oil (Bbl)				Gas (Mcf)
August 31, 2013 (Average)	$	86.40			$	4.40
August 31, 2014 (Average)	$	89.48			$	5.03
August 31, 2015 (Average)	$	53.27			$	3.28
December 31, 2015 (Average)	$	41.33			$	2.60

Our drilling, acquisition, and participation activities, partially offset by declining commodity prices, during the year ended August 31, 2015 generated an increase in projected future cash inflow from proved reserves of $206.6 million compared

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to August 31, 2014. However, future pre-tax net cash flow decreased $149.6 million from August 31, 2014 to August 31, 2015 as per-unit costs did not decline commensurate with per-unit future cash inflow.  During that same period, our PV-10 from proved reserves decreased by $95.4 million.  During the year ended August 31, 2015, we incurred capital expenditures of approximately $203.2 million related to the acquisition and development of proved reserves.

Our drilling, acquisition, and participation activities during the year ended August 31, 2014 generated increases in projected future cash inflow from proved reserves of $1.1 billion and future pre-tax net cash flow of $538.1 million from August 31, 2013 .  During that same period, our PV-10 from proved reserves increased by $297.6 million .  During the year ended August 31, 2014 , we incurred capital expenditures of approximately $185.1 million related to the acquisition and development of proved reserves.

Our drilling, acquisition, and participation activities during the year ended August 31, 2013 generated increases in projected future cash inflow from proved reserves of $211.6 million and future pre-tax net cash flow of $143.4 million from August 31, 2012 .  During that same period, our PV-10 from proved reserves increased by $87.2 million .  During the year ended August 31, 2013 , we incurred capital expenditures of approximately $104.3 million related to the acquisition and development of proved reserves.

In general, the volume of production from our oil and gas properties declines as reserves are depleted.  Unless we acquire additional properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced.  Accordingly, volumes generated from our future activities are highly dependent upon our success in acquiring or finding additional reserves and the costs incurred in doing so.

Proved Undeveloped Reserves	Net Reserves (MBOE)
Beginning September 1, 2013	4,859
Converted to proved developed	(587	)
Extensions	13,436
Acquisitions	1,522
Revisions	(19	)
Ending August 31, 2014	19,211
Converted to proved developed	(414	)
Extensions	17,633
Acquisitions	3,780
Divestitures	(1,278	)
Revisions	2,689
Ending August 31, 2015	41,621
Converted to proved developed	(1,869	)
Extensions	17,161
Acquisitions	11,960
Divestitures	(4,360	)
Revisions	(16,224	)
Ending December 31, 2015	48,289

At December 31, 2015 , our proved undeveloped reserves were 48,289 MBOE. In an effort to delineate more of our acreage, much of our capital program was dedicated to drilling exploratory wells rather than developing our proved undeveloped well locations. As a result, we drilled 9 net exploratory wells and 4 net development wells during the four months ended December 31, 2015 . This generated proved developed reserves from those exploratory wells, as well as new proved undeveloped reserves due to direct offset locations. In addition, our reserve estimates reflect the positive impact of additional offset operator activities within the Wattenberg Field. As a result, we recognized an increase in proved undeveloped reserves from extensions of 17,161 MBOE. The 4 net development wells converted 1,869 MBOE, or 4% , of our proved undeveloped reserves into proved developed reserves, requiring $17.7 million of drilling and completion capital expenditures. All proved undeveloped reserves as of December 31, 2015 are expected to be converted to proved producing within four years.

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Our operational focus since 2013 has been to delineate our leasehold rather than continue to develop our proven areas. This has resulted in increases to our proved undeveloped reserves as we delineate new exploratory areas, but slower conversion of existing proved undeveloped reserves to producing status. Furthermore, the result of this exploratory drilling, in conjunction with our efforts to determine the proper density of wellbores, has resulted in undeveloped lands moving directly to the proven developed category. In the four months ended December 31, 2015 , this effect increased with the downturn in commodity prices as we scaled back our drilling and completion operations in the reduced price environment. Based on our current drilling plans for the next three years, we expect to allocate more funds to developmental drilling in areas of established production where ongoing and planned infrastructure buildout continues. In addition to the undeveloped locations added as a result of recent drilling and acquisitions, we limited our undeveloped locations related to horizontal wells to be drilled within a three year horizon due to the current uncertainty in the oil and gas environment. This reduced proved undeveloped reserves by 25,066 MBOE and is included in revisions . None of the proved undeveloped reserves have been in this category for more than five years, and all are scheduled to be drilled within five years of their initial booking.

In addition, our proved undeveloped reserves on undrilled locations were revised upwards by 8,842 MBOE during the four months ended December 31, 2015 as a result of improved well performance as compared to original estimates. This improved performance was attributable to advances in drilling and completion designs, better takeaway capacity and longer well history, allowing for more accurate projections.

At August 31, 2015, our proved undeveloped reserves were 41,621 MBOE. In an effort to delineate more of our acreage, much of our capital program during the year ended August 31, 2015 was dedicated to drilling exploratory wells rather than developing our proved undeveloped well locations. As a result, we drilled 40 net exploratory wells and one net development well during the year ended August 31, 2015. This generated proved developed reserves from those exploratory wells, as well as new proved undeveloped reserves due to direct offset locations. In addition, our reserve estimates reflect the positive impact of additional offset operator activities within the Wattenberg Field. As a result, we recognized an increase in proved undeveloped reserves from extensions of 17,633 MBOE. The one net development well converted 414 MBOE, or 2%, of our proved undeveloped reserves into proved developed reserves, requiring $5.0 million of drilling and completion capital expenditures.

At August 31, 2014 , our proved undeveloped reserves were 19,211 MBOE. During the year ended August 31, 2014, 587 MBOE or 12% of our proved undeveloped reserves were converted into proved developed reserves, requiring $14.9 million of drilling and completion capital expenditures. Executing our capital program during the year ended August 31, 2014 resulted in the addition of 13,436 MBOE in proved undeveloped reserves.

Delivery Commitments

See "Volume Commitments" in Note 16 to our financial statements, included elsewhere in this report.

Government Regulation

 

Our operations are subject to various federal, state, and local laws and regulations that change from time to time. Many of these regulations are intended to prevent pollution and protect environmental quality, including regulations related to permit requirements for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling, completing and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the drilling and completion process, groundwater testing, air emissions, noise, lighting and traffic abatement, and the plugging and abandonment of wells. Other regulations are intended to prevent the waste of oil and gas and to protect the rights among owners in a common reservoir. These include regulation of the size of drilling and spacing units or proration units, the number or density of wells that may be drilled in an area, the unitization or pooling of oil and natural gas wells, and regulations that generally prohibit the venting or flaring of natural gas and that impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. In addition, our operations are subject to regulations governing the pipeline gathering and transportation of oil and natural gas, as well as various federal, state, and local tax laws and regulations.

Failure to comply with applicable laws and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe that we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance.

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Regulation of production

Federal, state, and local agencies have promulgated extensive rules and regulations applicable to our oil and natural gas exploration, production, and related operations.  Most states require drilling permits, drilling and operating bonds, and the filing of various reports and impose other requirements relating to the exploration and production of oil and natural gas.  Many states also have statutes or regulations addressing conservation matters including provisions governing the size of drilling and spacing units or proration units, the density of wells, and the unitization or pooling of oil and natural gas properties.  Some states like Colorado allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on the voluntary pooling of lands and leases. In areas with voluntary pooling, it may be more difficult to develop a project if the operator owns less than 100% of the leasehold. The statutes and regulations of some states limit the rate at which oil and gas is produced from properties, prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability of production. This may limit the amount of oil and gas that we can produce from our wells and may limit the number of wells or locations at which we can drill.  The federal and state regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability.  Because these rules and regulations are amended or reinterpreted frequently, we are unable to predict the future cost or impact of complying with these laws.

The Colorado Oil and Gas Conservation Commission (“COGCC”) is the primary regulator of exploration and production of oil and gas resources in the principal area in which we operate.  The COGCC regulates oil and gas operators through rules, policies, written guidance, orders, permits, and inspections. Among other criteria, the COGCC enforces specifications regarding drilling, development, production, abandonment, enhanced recovery, safety, aesthetics, noise, waste, flowlines, and wildlife.  In recent years, the COGCC has amended its existing regulatory requirements and adopted new requirements with increased frequency. For example, in August 2013, the COGCC implemented new setback rules for oil and natural gas wells and production facilities near occupied buildings. The COGCC increased its setback distance to a uniform 500 feet statewide setback from occupied buildings and imposed new notice, meeting, and mitigation requirements for nearby homes and communities. In January 2013, the COGCC approved new rules that require operators to sample groundwater for hydrocarbons and other indicator compounds both before and after drilling. In December 2013, the COGCC issued new and more restrictive rules regarding spill reporting and remediation. In December 2014, the COGCC issued amendments clarifying and modifying a number of existing rules, including those governing drilling, plugging, mechanical integrity testing, blow out prevention, and waste management. In January 2015, the COGCC amended its enforcement and penalty rules to increase the maximum penalty for regulatory violations. In March 2015, the COGCC adopted new requirements for operations within floodplains. In June 2015, the COGCC announced that it would begin a new rulemaking to implement two recommendations by a task force appointed by Colorado Governor John Hickenlooper. COGCC is currently considering new rules concerning local government collaboration with oil and gas operators regarding locations for large scale oil and gas facilities in urban mitigation areas and the sharing by operators with municipalities of information regarding current and planned drilling operations. The COGCC has also announced that it expects to amend its noise control regulations during the first quarter of 2016.

Regulation of sales and transportation of natural gas

Historically, the transportation and sales for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978, and the Federal Energy Regulatory Commission (“FERC”) regulations. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated the price for all “first sales” of natural gas. Thus, all of our sales of gas may be made at market prices, subject to applicable contract provisions. Sales of natural gas are affected by the availability, terms, and cost of pipeline transportation. Since 1985, the FERC has implemented regulations intended to make natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis. We cannot predict what further action the FERC will take on these matters. Some of the FERC's more recent proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers, and marketers with which we compete.

 Our natural gas sales are generally made at the prevailing market price at the time of sale. Therefore, even though we sell significant volumes to major purchasers, we believe that other purchasers would be willing to buy our natural gas at comparable market prices.

On August 8, 2005, the Energy Policy Act of 2005 (the “2005 EPA”) was signed into law. This comprehensive act contains many provisions that will encourage oil and gas exploration and development in the U.S. The 2005 EPA directs the FERC, Bureau of Ocean Energy Management (“BOEM”), and other federal agencies to issue regulations that will further the goals set out in the 2005 EPA. The 2005 EPA amends the NGA to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC.

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On January 20, 2006, the FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme, or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. It, therefore, reflects a significant expansion of the FERC's enforcement authority. To date, we do not believe that we have been, nor do we anticipate that we will be, affected any differently than other producers of natural gas.

In 2007, the FERC issued a final rule on annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, and natural gas marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. The monitoring and reporting required by these rules have increased our administrative costs. To date, we do not believe that we have been, nor do we anticipate that we will be, affected any differently than other producers of natural gas.

Regulation of sales and transportation of oil

Our sales of crude oil are affected by the availability, terms, and cost of transportation. Interstate transportation of oil by pipeline is regulated by the FERC pursuant to the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products (collectively referred to as “petroleum pipelines”) be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with the FERC.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective, interstate and intrastate rates are equally applicable to all comparable shippers, we do not believe that the regulation of oil transportation rates will affect our operations in any way that is materially different than those of our competitors who are similarly situated.

In May 2015, the U.S. Department of Transportation (“DOT”) issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on “offerors” of crude oil, including sampling, testing, and certification requirements. In March 2016, DOT also proposed to significantly expand its regulations pertaining to gas and hazardous liquid pipelines.

Regulation of derivatives and reporting of government payments

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was passed by Congress and signed into law in July 2010. The Dodd-Frank Act is designed to provide, among other things, a comprehensive framework for the regulation of the over-the-counter derivatives market with the intent to provide greater transparency and reduction of risk between counterparties. The Dodd-Frank Act subjects swap dealers and major swap participants to capital and margin requirements and requires many derivative transactions to be cleared on exchanges. The Dodd-Frank Act provides for a potential exemption from certain of these requirements for commercial end-users. In addition, in August 2012, the SEC issued a final rule under Section 1504 of the Dodd-Frank Act, Disclosure of Payment by Resource Extraction Issuers, which would have required resource extraction issuers, such as us, to file annual reports that provide information about the type and total amount of payments made for each project related to the commercial development of oil, natural gas, or minerals to each foreign government and the federal government. In July 2013, the U.S. District Court for the District of Columbia vacated the rule, and the SEC has announced it will not appeal the court's decision. However, the SEC has proposed a revised version of this rule.

 

Environmental Regulations

 

 As with the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state, and local laws and regulations designed to protect and preserve natural resources and the environment.  Long-term and recent

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trends in environmental legislation and regulation are generally toward stricter standards, and this trend is likely to continue.  These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; mandate requirements and standards for operations; impose substantial liabilities and remedial obligations for pollution; and require the reclamation of certain lands.

 

 The permits required for many of our operations are subject to revocation, modification, and renewal by issuing authorities.  Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions, or both.  In March 2015, the COGCC implemented regulatory and statutory amendments that significantly increase the potential penalties for violating the Colorado Oil and Gas Conservation Act or its implementing regulations, orders, or permits. These amendments increase the maximum penalty per violation per day from $1,000 to $15,000; eliminate the $10,000 maximum penalty for violations without significant consequences; require the COGCC to assess a penalty for each day of violation; and authorize the COGCC to prohibit the issuance of new permits and suspend certificates of clearance for egregious violations. In the opinion of our management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements.  Nevertheless, changes in existing environmental laws and regulations or in their interpretation could have a significant impact on us, as well as the oil and natural gas industry in general.

 

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict and joint and several liability on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites.  Persons responsible for the release or threatened release of hazardous substances under CERCLA may be subject to liability for the costs of cleaning up those substances and for damages to natural resources. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.   Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations impose clean-up liability relating to petroleum and petroleum related products.  The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance.  Although RCRA classifies certain oil field wastes as non-hazardous "solid wastes,” such exploration and production wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements.

Certain of our operations are subject to the federal Clean Air Act (“CAA”) and similar state and local requirements. The CAA may require certain pollution control requirements with respect to air emissions from our operations. The Environmental Protection Agency (“EPA”) and states continue to develop regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air-emission-related issues. Greenhouse gas recordkeeping and reporting requirements under the CAA took effect in 2011 and impose increased administrative and control costs. Federal New Source Performance Standards regarding oil and gas operations (“NSPS OOOO”) took effect in 2012, with more amendments effective in 2013 and 2014, all of which have likewise added administrative and operational costs. In August 2015, the EPA proposed a package of new regulations under the CAA to reduce methane emissions from new and modified sources in the oil and gas sector. Concurrent with the proposed methane rules, the EPA also proposed a new rule for aggregating adjacent operational units into a single source for review and permitting and recommended guidelines for reducing volatile organic compound emissions from existing equipment. Colorado adopted new regulations to meet the requirements of NSPS OOOO and promulgated significant new rules in February 2014 relating specifically to crude oil and natural gas operations that are more stringent than NSPS OOOO and directly regulate methane emissions from affected facilities.

In October 2015, the EPA lowered the national ambient air quality standard (“NAAQS”) for ozone under the CAA from 75 parts per billion to 70 parts per billion. Any resulting expansion of the ozone nonattainment areas in Colorado could cause oil and natural gas operations in such areas to become subject to more stringent emissions controls, emission offset requirements, and increased permitting delays and costs. In addition, the EPA has proposed to "bump up" Colorado from "marginal" to "moderate" ozone non-attainment status for the Denver Metro North Front Range Ozone Nonattainment Area as a result of the area failing to attain the 2008 ozone NAAQS by the applicable attainment date of July 20, 2015. This bump-up in attainment status will trigger additional obligations for the State under the CAA and will result in a state rulemaking to address the new "moderate" status. This rulemaking may result in more stringent standards or additional control requirements applicable to our operations. On March 10, 2016, EPA announced that it will begin a formal process under CAA § 111(d) to require companies operating existing oil and gas sources to provide information to assist EPA in developing comprehensive regulations to reduce methane emissions. EPA will send Information Collection Requests (ICRs) to operators to gather information on existing sources of methane emissions, technologies to reduce those emissions, and the costs of those technologies in the production, gathering, processing, and transmission and storage segments of the oil and gas sector.

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The federal Clean Water Act (“CWA”) and analogous state laws impose requirements regarding the discharge of pollutants into waters of the U.S. and the state, including spills and leaks of hydrocarbons and produced water. The CWA also requires approval for the construction of facilities in wetlands and other waters of the U.S., and it imposes requirements on storm water run-off. In April 2015, the EPA proposed new CWA regulations that would prevent onshore unconventional oil and gas wells from discharging wastewater pollutants to public treatment facilities. In June 2015, the EPA and the U.S. Army Corps of Engineers adopted a new regulatory definition of “waters of the U.S.,” which governs which waters and wetlands are subject to the CWA. This final rule has been stayed pending the resolution of ongoing litigation. Depending upon if and how the new definition is implemented, it could significantly expand the jurisdictional reach of the CWA in many states, including Colorado.

The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Some of our operations may be located in areas that are or may be designated as habitats for threatened or endangered species. In such areas, we may be prohibited from conducting operations at certain locations or during certain periods, and we may be required to develop plans for avoiding potential adverse effects. In addition, certain species are subject to varying degrees of protection under state laws.

Federal laws including the CWA require certain owners or operators of facilities that store or otherwise handle oil and produced water to prepare and implement spill prevention, control, countermeasure ("SPCC") and response plans addressing the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (“OPA”) subjects owners and operators of facilities to strict and joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills, including the government’s response costs. Spills subject to the OPA may result in varying civil and criminal penalties and liabilities.

In 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic conditions. Based on these findings, the EPA has adopted regulations under the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”), construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already major sources of emissions of regulated pollutants. Our operations and those of our customers could become subject to these Title V and PSD permitting reviews and be required to install “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities if such facilities emitted volumes of GHGs in excess of threshold permitting levels. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified GHG emission sources in the United States, including certain onshore oil and natural gas production sources, which include certain of our operations. While Congress has not enacted significant legislation relating to GHG emissions, it may do so in the future and, moreover, several state and regional initiatives have been enacted aimed at monitoring and/or reducing GHG emissions through cap and trade programs.

In August 2015, the EPA proposed new regulations that set methane emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities as part of an effort to reduce methane emissions from the oil and natural gas sector by up to 45 percent from 2012 levels by 2025. EPA is expected to finalize this proposal in 2016.

The adoption of new laws, regulations, or other requirements limiting or imposing other obligations on GHG emissions from our equipment and operations, and the implementation of requirements that have already been adopted, could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, substantial limitations on GHG emissions in other sectors, such as the power sector under EPA’s August 2015 Clean Power Plan, could adversely affect demand for the oil and natural gas that we produce. Further GHG regulation may result from the December 2015 agreement reached at the United Nations climate change conference in Paris. Pursuant to the agreement, the United States made an initial pledge to a 26-28% reduction in its GHG emission by 2025 against a 2005 baseline and committed to periodically update its pledge in five yearly intervals starting in 2020. GHG emissions in the earth’s atmosphere have also been shown to produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events, any of which could have an adverse effect on our operations.

Hydraulic Fracturing

We operate primarily in the Wattenberg Field of the D-J Basin where the rock formations are typically tight, and it is a common practice to utilize hydraulic fracturing to allow for or increase hydrocarbon production.  Hydraulic fracturing involves the process of injecting substances such as water, sand and additives (some proprietary) under pressure into a targeted subsurface formation to create pores and fractures, thus creating a passageway for the release of oil and gas.  Hydraulic fracturing is a technique that we commonly employ and expect to employ extensively in future wells that we drill and complete.

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We outsource all hydraulic fracturing services to service providers with significant experience, and which we deem to be competent and responsible.  Our service providers supply all personnel, equipment, and materials needed to perform each stimulation, including the chemical mixtures that are injected into our wells.  We require our service companies to carry insurance covering incidents that could occur in connection with their activities.  In addition to the drilling permit that we are required to obtain and the notice of intent that we provide the appropriate regulatory authorities, our service providers are responsible for obtaining any regulatory permits necessary for them to perform their services in the relevant geographic location.  We have not had any incidents, citations, or lawsuits relating to any environmental issues resulting from hydraulic fracturing, and we are not presently aware of any such matters.

In recent years, environmental opposition to hydraulic fracturing has increased, and various governmental and regulatory authorities have adopted or are considering new requirements for this process. To the extent that these requirements increase our costs or restrict our development activities, our business and prospects may be adversely affected.

The EPA has asserted that the Safe Drinking Water Act (“SDWA”) applies to hydraulic fracturing involving diesel fuel, and in February 2014, it issued final guidance on this subject. The guidance defines the term “diesel fuel,” describes the permitting requirements that apply under SDWA for the underground injection of diesel fuel in hydraulic fracturing, and makes recommendations for permit writers. Although the guidance applies only in those states, excluding Colorado, where the EPA directly implements the Underground Injection Control Class II program, it could encourage state regulatory authorities to adopt permitting and other requirements for hydraulic fracturing. In addition, from time to time, Congress has considered legislation that would provide for broader federal regulation of hydraulic fracturing under the SDWA. If such legislation were enacted, hydraulic fracturing operations could be required to meet additional federal permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and provide for additional public disclosure of the chemicals used in the fracturing process.

The EPA is also conducting a nationwide study into the effects of hydraulic fracturing on drinking water. In June 2015, the EPA released a draft study report for peer review and comment. The draft report did not find evidence of widespread systemic impacts to drinking water, but did find a relatively small number of site-specific impacts. The EPA noted that these results could indicate that such effects are rare or that other limiting factors exist. A final report is expected in 2016.

Federal agencies have also adopted or are considering additional regulation of hydraulic fracturing. On March 26, 2016, the U.S. Occupational Safety and Health Administration (“OSHA”) issued a final rule, with effective dates of 2018 and 2021 for the hydraulic fracturing industry, which imposes stricter standards for worker exposure to silica, including worker exposure to sand in hydraulic fracturing. In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act (“TSCA”) to obtain data on chemical substances and mixtures used in hydraulic fracturing. In March 2015, the Bureau of Land Management (“BLM”) issued a new rule regulating hydraulic fracturing activities involving federal and tribal lands and minerals, including requirements for chemical disclosure, wellbore integrity and handling of flowback and produced water.

 In Colorado, the primary regulator is the COGCC, which has adopted regulations regarding chemical disclosure, pressure monitoring, prior agency notice, emission reduction practices, and offset well setbacks with respect to hydraulic fracturing operations and may in the future adopt additional requirements for this purpose. As part of these requirements, operators must report all chemicals used in hydraulically fracturing a well to a publicly searchable registry website developed and maintained by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission.  

Apart from these ongoing federal and state initiatives, local governments are adopting new requirements and restrictions on hydraulic fracturing and other oil and gas operations. Some local governments in Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same objective. Beyond that, during the past few years, a total of five Colorado cities have passed voter initiatives temporarily or permanently prohibiting hydraulic fracturing. None of these cities currently have significant oil and gas development, and the oil and gas industry and the State have challenged four of these initiatives in court. Although one case remains pending, the trial courts in the other three cases have invalidated the initiatives on the ground that state law preempts local governments from banning hydraulic fracturing. In September 2015, the Colorado Supreme Court announced that it would review two of these cases for the purpose of deciding whether local hydraulic fracturing bans are preempted. The Colorado Supreme Court heard oral arguments in December 2015, and a decision is expected in 2016.

During 2014, opponents of hydraulic fracturing also sought statewide ballot initiatives that would have restricted oil and gas development in Colorado by, among other things, significantly increasing the setback between oil and gas wells and occupied buildings. These initiatives were withdrawn from the November 2014 ballot in return for the creation of a task force to craft recommendations for minimizing land use conflicts over the location of oil and gas facilities. In February 2015, the task force

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submitted six recommendations to the Governor, including recommendations that the COGCC adopt new rules providing for local government involvement in the siting of certain large scale oil and gas facilities and the sharing with municipalities of information on current and planned drilling operations. Depending upon the success of these recommendations, the Colorado Supreme Court’s preemption decision, and other considerations, opponents of hydraulic fracturing could pursue state legislation or additional local or statewide ballot initiatives to restrict hydraulic fracturing or oil and gas development generally.

Competition and Marketing

We are faced with strong competition from many other companies and individuals engaged in the oil and gas business, many of which are very large, well-established energy companies with substantial capabilities and established earnings records.  We may be at a competitive disadvantage in acquiring oil and gas prospects since we must compete with these individuals and companies, many of which have greater financial resources and larger technical staffs.  It is nearly impossible to estimate the number of competitors; however, it is known that there are a large number of companies and individuals in the oil and gas business.

Exploration for and production of oil and gas are affected by the availability of pipe, casing and other tubular goods, and certain other oil field equipment including drilling rigs and tools.  We depend upon independent drilling contractors to furnish rigs, equipment, and tools to drill our wells.  Higher prices for oil and gas may result in competition among operators for drilling equipment, tubular goods, and drilling crews, which may affect our ability expeditiously to drill, complete, recomplete, and work-over wells.

The market for oil and gas is dependent upon a number of factors beyond our control, which at times cannot be accurately predicted.  These factors include the proximity of wells to, and the capacity of, natural gas pipelines, the extent of competitive domestic production and imports of oil and gas, the availability of other sources of energy, fluctuations in seasonal supply and demand, and governmental regulation.  In addition, there is always the possibility that new legislation may be enacted, which would impose price controls or additional excise taxes upon crude oil or natural gas, or both.  Oversupplies of natural gas can be expected to recur from time to time and may result in the gas producing wells being shut-in.  Imports of natural gas may adversely affect the market for domestic natural gas.

The market price for crude oil is significantly affected by policies adopted by the member nations of OPEC.  Members of OPEC establish prices and production quotas among themselves for petroleum products from time to time with the intent of controlling the current global supply and consequently price levels.  We are unable to predict the effect, if any, that OPEC or other countries will have on the amount of, or the prices received for, crude oil and natural gas.

Gas prices, which were once effectively determined by government regulations, are now largely influenced by competition.  Competitors in this market include producers, gas pipelines, and their affiliated marketing companies, independent marketers, and providers of alternate energy supplies, such as residual fuel oil.  Changes in government regulations relating to the production, transportation, and marketing of natural gas have also resulted in significant changes in the historical marketing patterns of the industry.

Generally, these changes have resulted in the abandonment by many pipelines of long-term contracts for the purchase of natural gas, the development by gas producers of their own marketing programs to take advantage of new regulations requiring pipelines to transport gas for regulated fees, and an increasing tendency to rely on short-term contracts priced at spot market prices.

General

Our offices are located at 1625 Broadway Suite 300, Denver, CO 80202.  Our office telephone number is (720) 616-4300, and our fax number is (720) 616-4301.

Our Platteville offices includes field offices and an equipment yard and are rented to us pursuant to a lease with HS Land & Cattle, LLC, a firm controlled by Ed Holloway and William E. Scaff, Jr., Directors of the Company. The most recent lease, dated June 20, 2014, is currently on a month-to-month basis and requires monthly payments of $15,000 per month. Historically, the lease has been renewed annually.

As of December 31, 2015 , we had 62 full-time employees.

Available Information

    

We make available on our website, www.syrginfo.com, under “Investor Relations, SEC Filings,” free of charge, our annual and transition reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to

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those reports as soon as reasonably practicable after we electronically file or furnish them to the U.S. Securities and Exchange Commission (“SEC”). You may also read or copy any document we file at the SEC's public reference room in Washington, D.C., located at 100 F Street, N.E., Room 1580, Washington D.C. 20549, or may obtain copies of such documents at the SEC's website at www.sec.gov. Please call the SEC at (800) SEC-0330 for further information on the public reference room.

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ITEM 1A.	RISK FACTORS

Investors should be aware that any purchase of our securities involves certain risks, including those described below, which could adversely affect the value of our common stock. We do not make, nor have we authorized any other person to make, any representation about the future market value of our common stock. In addition to the other information contained in this transition report, the following factors should be considered carefully in evaluating an investment in our securities.

Risks Relating to Our Business and the Industry

An extended or further decline in oil and natural gas prices may adversely affect our business, financial condition, or results of operations and our ability to meet our financial commitments. Additionally, the value of our proved reserves calculated using SEC pricing may be higher than the estimated or fair market value of our proved reserves using more recent prices.

The prices we receive for our oil and natural gas significantly affects many aspects of our business, including our revenue, profitability, access to capital, quantity, and present value of proved reserves and future rate of growth. Oil and natural gas are commodities, and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. In the recent past, benchmark oil prices have fallen from highs of over $100 per Bbl to lows below $30 per Bbl, and natural gas prices have experienced declines of comparable magnitude. During the four months ended December 31, 2015, the average benchmark price was $42.82 per barrel for oil and $2.26 per Mcf for gas. Oil and natural gas prices will likely continue to be volatile in the future and will depend on numerous factors beyond our control. These factors include the following:

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

•	the actions of OPEC;

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

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

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

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

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

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

•	weather conditions and natural disasters;

•	domestic and foreign governmental regulations;

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

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

•	price and availability of competitors’ supplies of oil and natural gas;

•	technological advances affecting energy consumption; and

•	the price and availability of alternative fuels.

    

Lower oil and natural gas prices will reduce our cash flows and our borrowing ability. Our business has historically relied on the availability of additional capital, including proceeds from the sale of equity and convertible securities, to execute our business strategy. Further, our future growth strategy requires substantial additional capital, the availability of which will depend in significant part on current and expected commodity prices. If we are unable to raise capital on acceptable terms in the future, we may be unable to pursue our future acquisition, drilling, and development plans. While our current revolving credit facility provides for commitments of up to $500 million, actual borrowings may not exceed our borrowing base in effect at any time, which is subject to re-determination on a semi-annual basis. Our borrowing base is based in substantial part on the value of our oil and natural gas reserves which are, in turn, impacted by prevailing oil and natural gas prices. Accordingly, declining oil and natural gas prices have a direct impact on the amount that we can borrow under our revolving credit facility, which could affect our cash flows and ability to execute on our business plans. In January 2016, the borrowing base under our revolving credit facility was reduced from $163 million to $145 million. As of March 31, 2016 , $145 million is unused and available for future borrowing. The next semi-annual redetermination is scheduled to occur on May 1, 2016 . We may experience further decreases in our borrowing base if oil and natural gas prices stay at current levels or continue to decline. If our borrowing base declines significantly, we would have to either raise additional capital or adjust our drilling plan.

    

In addition, lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and may cause the value of our estimated proved reserves at future reporting dates to decline. Our estimated proved reserves as of August 31, 2015 , and related PV-10 and standardized measure values, were calculated under SEC rules using twelve-

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month trailing average benchmark prices of $53.27 per barrel of oil (West Texas Intermediate Cushing ("WTI") and $3.28 per MMBtu (Henry Hub). The twelve-month trailing average benchmark prices used in calculating proved reserves, PV-10 and standardized measure as of December 31, 2015 were $41.33 per barrel of oil (WTI) and $2.60 per MMBtu (Henry Hub). These lower prices adversely affected the estimated quantity and value of our proved reserves.

Furthermore, sustained periods with oil and natural gas prices at recent or lower levels and the resultant effect such prices will have on our drilling economics and our ability to raise capital would likely require us to re-evaluate and postpone or eliminate our development drilling, which would likely result in the further reduction of some of our proved undeveloped reserves and PV-10 and standardized measure values, and would make it more difficult for us to achieve expected levels of production. At current commodity prices, it will be difficult to generate acceptable rates of return from drilling activities unless we are able to achieve additional cost savings and/or efficiencies.

To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. To the extent that oil and natural gas prices remain at current levels or decline further, we will not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition would be negatively impacted. In addition, hedging arrangements can expose us to risk of financial loss in some circumstances, including when production is less than expected, a counterparty to a hedging contract fails to perform under the contract, or there is a change in the expected differential between the underlying price in the hedging contract and the actual prices received.

Accordingly, any substantial or extended decline in the prices that we receive for our production would have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations, and our results of operations.

Operating hazards may adversely affect our ability to conduct business.

Our operations are subject to risks inherent in the oil and natural gas industry, such as:

•	unexpected drilling conditions including blowouts, cratering, and explosions;

•	uncontrollable flows of oil, natural gas, or well fluids;

•	equipment failures, fires, or accidents;

•	pollution, releases of hazardous materials, and other environmental risks; and

•	shortages in experienced labor or shortages or delays in the delivery of equipment.

These risks could result in substantial losses to us from injury and loss of life, damage to and destruction of property and equipment, pollution and other environmental damage, and suspension of operations. We do not maintain insurance for all of these risks, nor in amounts that cover all of the losses to which we may be subject, and the insurance that we have may not continue to be available on acceptable terms. Moreover, some risks that we face are not insurable. Also, we could in some circumstances have liability for actions taken by third parties over which we have no or limited control, including operators of properties in which we have an interest. The occurrence of an uninsured or underinsured loss could result in significant costs that could have a material adverse effect on our financial condition and liquidity. In addition, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation, and development operations to be curtailed while those activities are being completed.

Our actual production, revenues, and expenditures related to our reserves are likely to differ from our estimates of proved reserves. We may experience production that is less than estimated, and drilling costs that are greater than estimated, in our reserve report. These differences may be material.

Although the estimates of our oil and natural gas reserves and future net cash flows attributable to those reserves were prepared by Ryder Scott, our independent petroleum and geological engineers, we are ultimately responsible for the disclosure of those estimates. Reserve engineering is a complex and subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:

•	historical production from the area compared with production from similar producing wells;

•	the assumed effects of regulations by governmental agencies;

•	assumptions concerning future oil and natural gas prices; and

•	assumptions concerning future operating costs, severance and excise taxes, development costs, and work-over and remedial costs.

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Because all reserve estimates are to some degree subjective, each of the following items may differ from those assumed in estimating proved reserves:

•	the quantities of oil and natural gas that are ultimately recovered;

•	the production and operating costs incurred;

•	the amount and timing of future development expenditures; and

•	future oil and natural gas sales prices.

Historically, there has been a difference between our actual production and the production estimated in a prior year’s reserve report. We cannot assure you that these differences will not be material in the future.

Approximately 73% of our estimated proved reserves at December 31, 2015 are undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our estimates of proved undeveloped reserves reflect our plans to make significant capital expenditures to convert those reserves into proved developed reserves, including approximately $309.1 million in estimated capital expenditures during the four years ending December 31, 2019. The estimated development costs may not be accurate, development may not occur as scheduled, and results may not be as estimated. If we choose not to develop proved undeveloped reserves, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, proved undeveloped reserves generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of initial booking, and we may, therefore, be required to downgrade to probable or possible any proved undeveloped reserves that are not developed or expected to be developed within this five-year time frame.

You should not assume that the standardized measure of discounted cash flows is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the standardized measure of discounted cash flows from proved reserves at December 31, 2015 is based on twelve-month average prices and costs as of the date of the estimate. These prices and costs will change and may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by oil and natural gas purchasers or in governmental regulations or taxation may also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor we use when calculating standardized measure of discounted cash flows for reporting requirements in compliance with accounting requirements is not necessarily the most appropriate discount factor. The effective interest rate at various times and the risks associated with our operations or the oil and natural gas industry in general will affect the accuracy of our estimates of our oil and gas reserves. Each of the foregoing considerations also impacts the PV-10 values of our reserves.

Seasonal weather conditions, wildlife restrictions, and other constraints could adversely affect our ability to conduct operations.

Our operations could be adversely affected by weather conditions and wildlife restrictions. In the Rocky Mountains, certain activities cannot be conducted as effectively during the winter months. Winter and severe weather conditions limit and may temporarily halt operations. These constraints and resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operational and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

Similarly, some of our properties are located in relatively populous areas in the Wattenberg Field, and our operations in those areas may be subject to additional expenses and limitations. For example, we may incur additional expenses in those areas to mitigate noise and odor issues relating to our operations, and we may find it more difficult to obtain drilling permits and other governmental approvals. In addition, the risk of litigation related to our operations may be higher in those areas. Any of these factors could have a material impact on our operations in the Wattenberg Field and could have a material adverse effect on our business, financial condition, and results of operations.

Furthermore, a critical habitat designation for certain wildlife under the U.S. Endangered Species Act or similar state laws could result in material restrictions to public or private land use and could delay or prohibit land access or development. The listing of certain species as threatened or endangered could have a material adverse effect on our operations in areas where such listed species are found.

Our future success depends upon our ability to find, develop, produce, and acquire additional oil and natural gas reserves that are economically recoverable. Drilling activities may be unsuccessful or may be less successful than anticipated.

In order to maintain or increase our reserves, we must locate and develop or acquire new oil and natural gas reserves to replace those being depleted by production. We must do this even during periods of low oil and natural gas prices when it is

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difficult to raise the capital necessary to finance our exploration, development, and acquisition activities. Without successful exploration, development, or acquisition activities, our reserves and revenues will decline rapidly. We may not be able to find and develop or acquire additional reserves at an acceptable cost or have access to necessary financing for these activities, either of which would have a material adverse effect on our financial condition.

Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs, drilling results, and the accuracy of our assumptions and estimates regarding potential well communication issues and other matters affecting the spacing of our wells. Because of these uncertainties, we do not know if the numerous potential drilling locations that we have identified will ever be drilled or if we will be able to produce oil and natural gas from these or any other potential drilling locations. Many factors may cause us to curtail, delay, or cancel scheduled drilling projects, including factors relating to our receipt of drilling permits and other governmental approvals, shortages or delays in obtaining necessary equipment or services, equipment failures or accidents, adverse weather, environmental hazards, and title problems. As such, our actual drilling activities may differ materially from those presently identified, which could adversely affect our business and reserves.

Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient quantities to cover drilling, operating, and other costs. In addition, even a commercial well may have production that is less, or costs that are greater, than we projected. The cost of drilling, completing, and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. There can be no assurance that proved or unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such proved or unproved property or wells.

We may not be able to obtain adequate financing when the need arises to execute our long-term operating strategy.

Our ability to execute our long-term operating strategy is highly dependent on our having access to capital when the need arises. We historically have addressed our liquidity needs through credit facilities, issuances of equity and convertible securities, sales of assets, joint ventures, and cash provided by operating activities. We will examine the following alternative sources of capital in light of economic conditions in existence at the relevant time:

•	borrowings from banks or other lenders;

•	the sale of non-core assets;

•	the issuance of debt securities;

•	the sale of common stock, preferred stock, or other equity securities;

•	joint venture financing; and

•	production payments.

The availability of these sources of capital when the need arises will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices, our credit ratings, interest rates, market perceptions of us or the oil and gas industry, our market value, and our operating performance. We may be unable to execute our long-term operating strategy if we cannot obtain capital from these sources when the need arises, which would adversely affect our production, cash flows, and capital expenditure plans.

Oil and natural gas prices may be affected by local and regional factors.

The prices to be received for our production will be determined to a significant extent by factors affecting the local and regional supply of and demand for oil and natural gas, including the adequacy of the pipeline and processing infrastructure in the region to process and transport our production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional natural gas production and the actual (frequently lower) price that we receive for our production. Our average differential for the four months ended December 31, 2015 was $(8.17) per barrel for oil and $0.17 per Mcf for gas. These differentials are difficult to predict and may widen or narrow in the future based on market forces. The unpredictability of future differentials makes it more difficult for us to effectively hedge our production. Our hedging arrangements are generally based on benchmark prices and therefore do not protect us from adverse changes in the differential applicable to our production.

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Lower oil and natural gas prices and other adverse market conditions may cause us to record ceiling test write-downs or other impairments, which could negatively impact our results of operations.

We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for, and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a “full cost ceiling” which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If, at the end of any fiscal period, we determine that the net capitalized costs of oil and natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders’ equity. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date.

We review the net capitalized costs of our properties quarterly, using a single price based on the beginning-of-the-month average of oil and natural gas prices for the preceding 12 months. We also assess investments in unproved properties periodically to determine whether impairment has occurred. The risk that we will be required to further write down the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase.

The ceiling test calculation as of December 31, 2015 used average realized prices of $41.33 per barrel and $2.60 per Mcf. The oil prices used at December 31, 2015 were approximately 22% lower than the August 31, 2015 price of $53.27 per barrel, and the gas prices were approximately 21% lower than the August 31, 2015 price of $3.28 per Mcf. We compare our net capitalized costs for oil and natural gas properties to the ceiling amount at various points during the year. At May 31, 2015 and August 31, 2015, our net capitalized costs for oil and natural gas properties exceeded the ceiling amount by $3.0 million and $13.0 million, respectively, resulting in a total ceiling test write-down of $16.0 million for the year ended August 31, 2015. At November 30, 2015, our prior fiscal first quarter, our net capitalized costs for oil and natural gas properties exceeded the ceiling amount by $125.2 million, resulting in immediate recognition of a ceiling test impairment of $125.2 million for the four months ended December 31, 2015. We also compared our net capitalized costs for oil and natural gas properties to the ceiling amount at November 30, 2014, February 28, 2015, and December 31, 2015, noting that the ceiling amount was greater than our net capitalized costs for oil and natural gas properties. Oil prices continued to decline since December 31, 2015. As of March 31, 2016, the posted price of oil was lower than the December 31, 2015 posted oil price. As a result, we anticipate that we will experience further ceiling test write-downs for the quarter ending March 31, 2016, and we may experience further ceiling test write-downs in the future. Any future ceiling test cushion, and the risk we may incur further write-downs or impairments, will be subject to fluctuation as a result of acquisition or divestiture activity. In addition, declining commodity prices or other adverse market conditions, such as declines in the market price of our common stock, could result in goodwill impairments or reductions in proved reserve estimates that would adversely affect our results of operation or financial condition.

We cannot control the activities on properties that we do not operate, and we are unable to ensure the proper operation and profitability of these non-operated properties.

We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of drilling and development activities on our partially owned properties operated by others, therefore, will depend upon a number of factors outside of our control, including the operator’s:

•	timing and amount of capital expenditures;

•	expertise and diligence in adequately performing operations and complying with applicable agreements;

•	financial resources;

•	inclusion of other participants in drilling wells; and

•	use of technology.

As a result of any of the above or an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected. In addition, our lack of control over non-operated properties makes it more difficult for us to forecast future capital expenditures and production.

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We are dependent on third party pipeline, trucking, and rail systems to transport our production and gathering and processing systems to prepare our production. These systems have limited capacity and, at times, have experienced service disruptions. Curtailments, disruptions, or lack of availability in these systems interfere with our ability to market the oil and natural gas that we produce, and could materially and adversely affect our cash flow and results of operations.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of gathering, processing, pipeline, trucking, and rail systems. The amount of oil and natural gas that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, accidents, excessive pressure, physical damage to the gathering or transportation system, lack of contracted capacity on such systems, inclement weather, labor or regulatory issues, or other interruptions. A portion of our production may be interrupted, or shut in, from time to time as a result of these factors. Curtailments and disruptions in these systems may last from a few days to several months or longer. These risks are greater for us than for some of our competitors because our operations are focused on areas where there has been a substantial amount of development activity in recent years and resulting increases in production, and this has increased the likelihood that there will be periods of time in which there is insufficient midstream capacity to accommodate the increased production. For example, the gas gathering systems serving the Wattenberg Field have in recent years experienced high line pressures, and at times, this has reduced capacity and caused gas production to either be shut in or flared. In addition, we might voluntarily curtail production in response to market conditions. Any significant curtailment in gathering, processing or pipeline system capacity, significant delay in the construction of necessary facilities, or lack of availability of transport, would interfere with our ability to market the oil and natural gas that we produce, and could materially and adversely affect our cash flow and results of operations and the expected results of our drilling program.

We may be unable to satisfy our contractual obligations, including obligations to deliver oil from our own production or other sources.

We have entered into agreements that require us to deliver minimum amounts of crude oil to three counterparties that transport crude oil via pipelines. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil we acquire, over the next five years. Since October 2015, we have been obligated to deliver a combined volume of 6,157 Bbls of oil per day to two of these counterparties. We have also committed to deliver 5,000 Bbls of oil per day to the third counterparty for five years beginning in the latter half of the 2016 calendar year. 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. We incurred such a charge, in the amount of $2.8 million , during the four months ended December 31, 2015. We have also entered into a six-month rig commitment which began in January 2016 that provides for a penalty upon early termination by us. Any future penalties or damages of the type described above could adversely impact our cash flows, profit margins, net income, and reserve values.

We face strong competition from larger oil and natural gas companies that may negatively affect our ability to carry on operations.

We operate in the highly competitive areas of oil and natural gas exploration, development, and production. Factors that affect our ability to compete successfully in the marketplace include:

•	the availability of funds for, and information relating to, properties;

•	the standards established by us for the minimum projected return on investment; and

•	the transportation of natural gas and crude oil.

Our competitors include major integrated oil companies, substantial independent energy companies, affiliates of major interstate and intrastate pipelines, and national and local natural gas gatherers, many of which possess greater financial and other resources than we do. If we are unable to successfully compete against our competitors, our business, prospects, financial condition, and results of operations may be adversely affected.

We may be unable to successfully identify, execute, or effectively integrate future acquisitions, which may negatively affect our results of operations.

Acquisitions of oil and gas businesses and properties have been an important element of our business, and we will continue to pursue acquisitions in the future. Although we regularly engage in discussions with, and submit proposals to, acquisition candidates, suitable acquisitions may not be available in the future on reasonable terms. If we do identify an appropriate acquisition candidate, we may be unable to successfully negotiate the terms of an acquisition, finance the acquisition, or if the acquisition occurs, effectively integrate the acquired business into our existing business. Negotiations of potential acquisitions and the

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integration of acquired business operations may require a disproportionate amount of management’s attention and our resources. Even if we complete additional acquisitions, any new businesses may not generate revenues comparable to our existing business, the anticipated cost efficiencies or synergies may not be realized, and these businesses may not be integrated successfully or operated profitably. The success of any acquisition will depend on a number of factors, including our ability to estimate accurately the recoverable volumes of reserves associated with the acquired assets, rates of future production and future net revenues attainable from the reserves and possible environmental liabilities. Our inability to successfully identify, execute, or effectively integrate future acquisitions may negatively affect our results of operations.

Even though we perform due diligence reviews (including a review of title and other records) of the major properties that we seek to acquire that we believe is consistent with industry practices, these reviews are inherently incomplete. It is generally not feasible for us to perform an in-depth review of every individual property and all records involved in each acquisition. Moreover, even an in-depth review of records and properties may not necessarily reveal existing or potential liabilities or other problems or permit us to become familiar enough with the properties to assess fully their deficiencies and potential. We may assume known and unknown environmental and other risks and liabilities in connection with the acquired businesses and properties. The discovery of any material liabilities associated with our acquisitions could materially and adversely affect our business, financial condition, and results of operations.

In addition, acquisitions of businesses may require additional debt or equity financing, resulting in additional leverage or dilution of ownership. Our credit facility contains, and future debt agreements may contain, covenants that limit our ability to complete acquisitions.

We may incur substantial costs to comply with the various federal, state, and local laws and regulations that affect our oil and natural gas operations.

We are affected significantly by a substantial number of governmental regulations that increase costs related to the drilling, completion, production, and abandonment of wells, the transportation and processing of oil and natural gas, the management and disposal of waste, and other aspects of our operations. It is possible that the number and extent of these regulations, and the costs to comply with them, will increase significantly in the future. In Colorado, for example, significant governmental regulations have been adopted in recent years to address well siting, well construction, hydraulic fracturing, water quality, public safety, air emissions, aesthetics, waste management, spill reporting, land reclamation, wildlife protection, and data collection. These government regulatory requirements may result in substantial costs that are not possible to pass through to our customers and could impact the profitability of our operations.

Our oil and natural gas operations are subject to stringent federal, state, and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to health and safety, land use, environmental protection, or the oil and natural gas industry generally. Legislation affecting the industry is under constant review for amendment or expansion, frequently increasing our regulatory burden. Compliance with such laws and regulations often increases our cost of doing business and, in turn, decreases our profitability. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the incurrence of investigatory or remedial obligations, or the issuance of cease and desist orders.

The environmental laws and regulations to which we are subject may, among other things:

•	require us to apply for and receive a permit before drilling commences or certain associated facilities are developed;

•	restrict the types, quantities, and concentrations of substances that can be released into the environment in connection with drilling, hydraulic fracturing, and production activities;

•	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other "waters of the United States," threatened and endangered species habitat, and other protected areas;

•	require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and

•	impose substantial liabilities for pollution resulting from our operations.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal, or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our earnings, results of operations, competitive position, or financial condition. Changes to the requirements for drilling, completing, operating, and abandoning wells and related facilities could have similar adverse effects on us.

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New environmental legislation or regulatory initiatives, including those related to hydraulic fracturing, could result in increased costs and additional operating restrictions or delays.

We are subject to extensive federal, state, and local laws and regulations concerning health, safety, and environmental protection. Government authorities frequently add to those requirements, and both oil and gas development generally and hydraulic fracturing specifically are receiving increased regulatory attention. Our operations utilize hydraulic fracturing, an important and commonly used process in the completion of oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the injection of water, proppant, and chemicals under pressure into rock formations to stimulate hydrocarbon production.

In 2012, the Environmental Protection Agency ("EPA") issued final rules that establish new air emission controls for natural gas processing operations, as well as for oil and natural gas production. Among other things, the latter rules cover the completion and operation of hydraulically fractured gas wells and associated equipment. After several parties challenged the new air regulations in court, the EPA reconsidered certain requirements and amended the rules in 2013 and 2014. In August 2015, the EPA proposed new regulations that set methane and VOC emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities as part of an effort to reduce methane emissions from the oil and natural gas sector by up to 45 percent from 2012 levels by 2025. EPA is expected to finalize this proposal in 2016. At this point, we cannot accurately predict the final regulatory requirements or the cost to comply with them. In addition, on March 10, 2016, EPA announced that it will begin a formal process under CAA § 111(d) to require companies operating existing oil and gas sources to provide information to assist EPA in developing comprehensive regulations to reduce methane emissions. EPA will send Information Collection Requests (ICRs) to operators to gather information on existing sources of methane emissions, technologies to reduce those emissions, and the costs of those technologies in the production, gathering, processing, and transmission and storage segments of the oil and gas sector. In addition, in October 2015, the EPA lowered the national ambient air quality standard ("NAAQS") for ozone under the CAA from 75 parts per billion to 70 parts per billion. Any resulting expansion of the ozone nonattainment areas in Colorado could cause our oil and natural gas operations in such areas to become subject to more stringent emissions controls, emission offset requirements and increased permitting delays and costs. In addition, the EPA has proposed to "bump up" Colorado from "marginal" to "moderate" ozone non-attainment status for the Denver Metro North Front Range Ozone Nonattainment Area as a result of the area failing to attain the 2008 ozone NAAQS by the applicable attainment date of July 20, 2015. This bump-up in attainment status will trigger additional obligations for the State under the CAA and will result in a state rulemaking to address the new "moderate" status. This rulemaking may result in more stringent standards or additional control requirements applicable to our operations.

 

 Several governmental reviews are underway assessing the impact of hydraulic fracturing on the environment and human health and safety, including potential adverse effects on drinking water supplies as well as migration of methane and other hydrocarbons. As a result, the federal government is studying the environmental risks associated with hydraulic fracturing and evaluating whether to adopt additional regulatory requirements. For example, the EPA has commenced a multi-year study of the potential impacts of hydraulic fracturing on drinking water resources, and the draft results were released for public and peer review in June 2015. In addition, in February 2014, the EPA issued final guidance for underground injection permits that regulate hydraulic fracturing using diesel fuel, where the EPA has permitting authority under the SDWA. This guidance eventually could encourage other regulatory authorities to adopt permitting and other restrictions on the use of hydraulic fracturing. In May 2014, the EPA issued an advance notice of proposed rulemaking under the TSCA to obtain data on chemical substances and mixtures used in hydraulic fracturing. In October 2015, EPA also granted, in part, a petition filed by several national environmental advocacy groups to add the oil and gas extraction industry to the list of industries required to report releases of certain "toxic chemicals" under the Toxics Release Inventory ("TRI") program under EPCRA. EPA determined that natural gas processing facilities may be appropriate for addition to the scope of TRI and will conduct a rulemaking process to propose such action. In April 2015, the EPA proposed regulations under the CWA to impose pretreatment standards on wastewater discharges associated with hydraulic fracturing activities. Aside from the EPA, the BLM has issued new rules, which are currently stayed pending further litigation, for hydraulic fracturing activities involving federal and tribal lands and minerals that, in general, would cover disclosure of fracturing fluid components, wellbore integrity, and handling of flowback and produced water. On March 26, 2016, OSHA issued a final rule, with effective dates of 2018 and 2021 for the hydraulic fracturing industry, which imposes stricter standards for worker exposure to silica, including worker exposure to sand in hydraulic fracturing. In addition, OSHA and the National Institute of Occupational Safety and Health have issued hazard alerts to the hydraulic fracturing industry regarding risks to workers from silica exposure and other hazards, which include recommendations to reduce those risks and proposals for additional study of the industry. In December 2015, the U.S. Department of Labor and the U.S. Department of Justice released a Memorandum of Understanding ("MOU"), announcing an interagency effort to increase enforcement of worker endangerment violations under environmental statutes (such as the Clean Water Act, the Clean Air Act, and the Resource Conservation and Recovery Act) and Title 18 criminal statutes that carry harsher penalties that the Occupational Safety and Health Act of 1970. Consistent with this MOU, where appropriate, DOJ will seek felony charges (such as false statements, conspiracy, and obstruction of justice) when prosecuting worker endangerment violations.

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In the United States Congress, bills have been introduced from time to time that would amend the SDWA to eliminate an existing exemption for certain hydraulic fracturing activities from the definition of "underground injection," thereby requiring the oil and natural gas industry to obtain SDWA permits for fracturing not involving diesel fuels, and to require disclosure of the chemicals used in the process. If adopted, such legislation could establish an additional level of regulation and permitting at the federal level, but some form of chemical disclosure is already required by most oil and gas producing states. At this time, it is not clear what action, if any, the United States Congress will take on hydraulic fracturing.

Apart from these ongoing federal initiatives, state governments where we operate have moved to impose stricter requirements on hydraulic fracturing and other aspects of oil and gas production. Colorado, for example, comprehensively updated its oil and gas regulations in 2008 and adopted significant additional amendments in 2011, 2013, 2014 and 2015. Among other things, the updated and amended regulations require operators to reduce methane emissions associated with hydraulic fracturing, compile and report additional information regarding wellbore integrity, satisfy more stringent reclamation and remediation standards, avoid certain wildlife habitat, publicly disclose the chemical ingredients used in hydraulic fracturing, increase the minimum distance between occupied structures and oil and gas wells, undertake additional mitigation for nearby residents, implement additional groundwater testing, and take additional actions to prevent blowouts and avoid subsurface well communication. Colorado has also adopted new regulations for air emissions from oil and gas operations as well as new legislation and implementing regulations increasing the monetary penalties for regulatory violations and lowering the threshold for reporting spills. Additionally, local governments are adopting new requirements on hydraulic fracturing and other oil and gas operations, including local county and city governments in Colorado.

Colorado currently is conducting a rulemaking addressing local government collaboration with oil and gas operators concerning locations for "Large Scale Oil and Gas Facilities" in Urban Mitigation Areas. The proposed rules would require oil and gas operators that are registered with the state also to register with municipalities in which they operate and, if requested by the municipality, provide certain information about current and planned drilling operations in the municipality.

           In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas. The public comment period closed January 8, 2016. In addition, in August 2015, the EPA proposed new regulations to reduce methane emissions from oil and gas operations, including hydraulically fractured wells, in an effort to reduce methane emissions from the oil and gas sector by up to forty-five percent by 2025.

The trend toward stricter standards and greater enforcement in environmental legislation and regulation is likely to continue. For example, concern has recently arisen in several states over increasing numbers of earthquakes that may be associated with underground injection wells used for the disposal of oil and gas wastewater. Such concerns could eventually limit the use of such wells in certain areas and increase the cost of disposal in others. Similarly, concerns have recently been expressed over the flaring of natural gas associated with crude oil production in certain areas. These concerns and regulations could limit or increase the cost of crude oil production in certain areas. Other environmental issues and concerns may periodically arise in the future and lead to new and additional legislative and regulatory initiatives.

The adoption of future federal, state, or local laws or implementing regulations or orders imposing new environmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete oil and natural gas wells, increase our costs of compliance and doing business, delay or prevent the development of certain resources (including especially shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products and services. We cannot assure you that any such outcome would not be material, and any such outcome could have a material and adverse impact on our cash flows and results of operations.

Any local moratoria or bans on our activities could have a negative impact on our business, financial condition, and results of operations.

Some local governments are adopting new requirements and restrictions on hydraulic fracturing and other oil and gas operations. Some local governments in Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same objective. Beyond that, during the past few years, a total of five Colorado cities have passed voter initiatives temporarily or permanently prohibiting hydraulic fracturing. The oil and gas industry and the State of Colorado have challenged four of these initiatives in court, and the trial courts in three of the cases have invalidated the initiatives. In September 2015, the Colorado Supreme Court announced that it would review two of these cases for the purpose of deciding whether local hydraulic fracturing bans are preempted. The Court heard oral argument in December 2015, and a decision is expected in 2016.

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In addition, during 2014, opponents of hydraulic fracturing sought statewide ballot initiatives that would have restricted oil and gas development in Colorado. These initiatives were withdrawn in return for the creation of a task force to craft recommendations for minimizing land use conflicts over the location of oil and gas facilities. Although the task force has completed its work, in December 2015, interest groups filed a package of 11 potential ballot initiatives focused on restricting oil and gas development. Among other things, these initiatives, if successful, could require mandatory setbacks of up to 4,000 feet, more local control over drilling, and prohibitions on drilling. If we are required to cease operating in any of the areas in which we now operate as the result of bans or moratoria on drilling or related oilfield services activities, it could have a material effect on our business, financial condition, and results of operations.

Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

In 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic conditions. Based on these findings, the EPA has adopted regulations under the CAA that, among other things, establish Prevention of Significant Deterioration ("PSD"), construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already major sources of emissions of regulated pollutants. Our operations and those of our customers could become subject to these Title V and PSD permitting reviews and be required to install "best available control technology" to limit emissions of GHGs from any new or significantly modified facilities if such facilities emitted volumes of GHGs in excess of threshold permitting levels. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified GHG emission sources in the United States, including certain onshore oil and natural gas production sources, which include certain of our operations. While Congress has not enacted significant legislation relating to GHG emissions, it may do so in the future, and moreover, several state and regional initiatives have been enacted aimed at monitoring and/or reducing GHG emissions through cap and trade programs.

The adoption of new laws, regulations, or other requirements limiting or imposing other obligations on GHG emissions from our equipment and operations, and the implementation of requirements that have already been adopted, could require us to incur costs to reduce emissions of GHGs associated with our operations, including those regulating methane emissions from the oil and gas industry. See the risk factor above entitled "New environmental legislation or regulatory initiatives, including those related to hydraulic fracturing, could result in increased costs and additional operating restrictions or delays" for further information regarding methane emissions regulations. In addition, substantial limitations on GHG emissions in other sectors, such as the power sector under EPA's August 2015 Clean Power Plan, could adversely affect demand for the oil and natural gas that we produce. Further, GHG regulation may result from the December 2015 agreement reached at the United Nations climate change conference in Paris. Pursuant to the agreement, the United States made an initial pledge to a 26-28% reduction in its GHG emissions by 2025 against a 2005 baseline and committed to periodically update its pledge in five yearly intervals starting in 2020. GHG emissions in the earth's atmosphere have also been shown to produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events, any of which could have an adverse effect on our operations.

Environmental liabilities could have a material adverse effect on our financial condition and operations.

Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs, and other environmental damages. We could also be liable for environmental damages caused by previous property owners. As a result, we could incur substantial liabilities to third parties or governmental entities, which could have a material adverse effect on our financial condition and results of operations. We maintain insurance coverage for our operations, but this insurance may not extend to the full potential liability to which we may be subject and further may not cover all potential environmental damages. Accordingly, we may be subject to liability or may lose the ability to continue exploration or production activities upon substantial portions of our properties if certain environmental damages occur.

For example, over the years, we have owned or leased numerous properties for oil and natural gas activities upon which petroleum hydrocarbons or other materials may have been released by us or by predecessor property owners or lessees who were not under our control. Under applicable environmental laws and regulations, including CERCLA, RCRA, and state laws, we could be held liable for the removal or remediation of previously released materials or property contamination at such locations, or at third-party locations to which we have sent waste, regardless of whether we were responsible for the release or whether the operations at the time of the release were standard industry practice.

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Similarly, the OPA imposes a variety of regulations on “responsible parties” related to the prevention of oil spills. The implementation of new, or the modification of existing, environmental laws or regulations, including regulations promulgated pursuant to the OPA, could have a material adverse impact on us.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

The Dodd-Frank Act authorizes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. Regulations under the Dodd-Frank Act may, among other things, require us to comply with margin requirements in connection with our derivative activities. If we are required to post cash collateral in connection with some or all of our derivative positions, this would make it difficult or impossible to pursue our current hedging strategy. The regulations may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The regulations may also reduce the number of potential counterparties in the market, which could make hedging more expensive.

If we reduce our use of derivatives as a result of the Dodd-Frank Act and its implementing regulations, our results of operations may be more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on our financial position, results of operations, and cash flows. In addition, derivative instruments create a risk of financial loss in some circumstances, including when production is less than the volume covered by the instruments.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations, and cash flows.

From time to time, legislative proposals are made that would, if enacted, result in significant changes to U.S. tax laws. These proposed changes have included, among others, eliminating the immediate deduction for intangible drilling and development costs, eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development, repealing the percentage depletion allowance for oil and natural gas properties and extending the amortization period for certain geological and geophysical expenditures. Such proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development, could adversely affect our business, financial condition, results of operations, and cash flows.

Potential indebtedness may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt.

As of December 31, 2015 , the aggregate amount of our outstanding indebtedness was $78 million . Our indebtedness could have important consequences for investors, including the following:

•	the covenants contained in our credit facility limit our ability to borrow money in the future for acquisitions, capital expenditures, or to meet our operating expenses or other general corporate obligations and may limit our flexibility in operating our business;

•	the amount of our interest expense may increase because amounts borrowed under our credit facility bear interest at variable rates, payable either quarterly or at the end of a specified interest period; if interest rates increase, this could result in higher interest expense;

•	we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage;

•	we may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially extended or further declines in oil and natural gas prices; and

•	our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

The lenders under our credit facility have the ability to unilaterally lower the borrowing base. In January 2016, our borrowing base was reduced from $163 million to $145 million. As of March 31, 2016 , $145 million is unused and available for future borrowing. The next semi-annual redetermination is scheduled to occur on May 1, 2016 . We may experience further decreases in our borrowing base if oil and natural gas prices stay at current levels or continue to decline. If the lenders reduce the borrowing base below the then-outstanding balance, we will be required to repay the difference between the outstanding balance and the reduced borrowing base, and we may not have or be able to obtain the funds necessary to do so.

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Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory, and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow from operations will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we do not have enough cash to service our debt, we may be required to refinance all or part of our existing debt, sell assets, borrow more money, or raise equity. We may not be able to refinance our debt, sell assets, borrow more money, or raise equity on terms acceptable to us, if at all.

A significant amount of cash may be required to service our indebtedness. Our ability to generate cash depends on many factors beyond our control, and any failure to meet our debt obligations could harm our business, financial condition, and results of operations.

Our ability to make payments on and to refinance indebtedness that we may incur and to fund planned capital expenditures will depend on our ability to generate sufficient cash flow from operations in the future. To a significant extent, this is subject to general economic, financial, competitive, legislative and regulatory conditions, and other factors that are beyond our control, including the prices that we receive for our oil and natural gas production.

We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our credit facility in an amount sufficient to enable us to pay principal and interest on our indebtedness or to fund our other liquidity needs. For example, decreases in oil and gas prices in the recent past, and any further decreases in oil and gas prices, will adversely affect our ability to generate cash flow from operations. If our cash flow and existing capital resources are insufficient to fund our debt obligations, we may be forced to reduce our planned capital expenditures, sell assets, seek additional equity or debt capital, or restructure our debt, and any of these actions, if completed, could adversely affect our business and/or our shareholders. We cannot assure you that any of these remedies could, if necessary, be effected on commercially reasonable terms, in a timely manner or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and could impair our liquidity.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions, and engage in other business activities that may be in our best interests.

Our credit facility contains, and future debt agreements may contain, covenants that restrict or limit our ability to:

•	pay dividends or distributions on our capital stock or issue preferred stock;

•	repurchase, redeem, or retire our capital stock or subordinated debt;

•	make certain loans and investments;

•	sell assets;

•	enter into certain transactions with affiliates;

•	create or assume certain liens on our assets;

•	enter into sale and leaseback transactions;

•	merge or enter into other business combination transactions; or

•	engage in certain other corporate activities.

Our ability to comply with these ratios and tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and tests in the future. These restrictions could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the restrictive covenants under our credit facility. Future debt agreements may have similar, or more restrictive, provisions.

A breach of any of the covenants in our debt agreements or our inability to comply with the required ratios or tests could result in a default under the agreement. A default, if not cured or waived, could result in all indebtedness outstanding under the agreement becoming immediately due and payable. If that should occur, we may not be able to pay all such debt or borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. If we were unable to repay those amounts, the lenders could accelerate the maturity of the debt or proceed against any collateral granted to them to secure such defaulted debt.

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We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.

We frequently own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other parties own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in commodity prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, will not be able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.

Our disclosure controls and procedures may not prevent or detect potential acts of fraud.

Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in reports we file or submit under the Exchange Act is accumulated and communicated to management, and recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms.

Our management, including our Chief Executive Officer and Chief Financial Officer, believes that any disclosure controls and procedures or internal controls and procedures, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, they cannot provide absolute assurance that all control issues and instances of fraud, if any, within our company have been prevented or detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by an unauthorized override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and we cannot assure you that any design will succeed in achieving its stated goals under all potential future conditions. Accordingly, because of the inherent limitations in a cost effective control system, misstatements due to error or fraud may occur and not be detected.

Failure to maintain an effective system of internal control over financial reporting may have an adverse effect on our stock price.

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, and the rules and regulations promulgated by the SEC to implement Section 404, we are required to furnish a report by our management in this transition report on Form 10-K regarding the effectiveness of our internal control over financial reporting. The report includes, among other things, an assessment of the effectiveness of our internal control over financial reporting as of the end of our fiscal year, including a statement as to whether or not our internal control over financial reporting is effective. This assessment must include disclosure of any material weaknesses in our internal control over financial reporting identified by management. If we are unable to assert that our internal control over financial reporting is effective now or in any future period, or if our auditors are unable to express an opinion on the effectiveness of our internal controls, investors could lose confidence in the accuracy and completeness of our financial reports, which could have an adverse effect on our stock price.

Substantially all of our producing properties are located in the D-J Basin in Colorado, making us vulnerable to risks associated with operating in one major geographic area.

Our operations have been focused on the D-J Basin in Colorado, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of oil and natural gas produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production, or interruption of transportation and processing services, and any resulting delays or interruptions of production from existing or planned new wells.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. We sell production to a small number of customers, as is customary in the industry. For the four months ended December 31, 2015, we had three major customers, which represented 57% , 15% , and 12% of our revenue during the period.

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This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil and natural gas hedging arrangements expose us to credit risk in the event of nonperformance by counterparties.

Failure to adequately protect critical data and technology systems could materially affect our operations.

Information technology solution failures, network disruptions, and breaches of data security could disrupt our operations by causing delays or cancellation of customer orders, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee, or other information, or damage to our reputation. A system failure or data security breach may have a material adverse effect on our financial condition, results of operations, or cash flows.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have a material adverse effect on our financial condition, results of operations, and cash flows.

Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. When drought conditions occur, governmental authorities may restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations from local sources, we may be unable to produce oil, natural gas, and NGLs economically, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could materially and adversely affect our business. The risk of lease expiration typically increases at times when commodity prices are depressed, as the pace of our exploration and development activity tends to slow during such periods.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

Part of our strategy involves drilling using the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. As of December 31, 2015, we operated 86 gross horizontal producing wells, with an additional 18 horizontal wells waiting on completion, and therefore are subject to increased risks associated with horizontal drilling as compared to companies that have greater experience in horizontal drilling activities. Risks that we face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore, and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during completion operations, and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage. In addition, our horizontal drilling activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or commodity prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result

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of any of these developments, we could incur material write-downs of our oil and natural gas properties, and the value of our undeveloped acreage could decline in the future.

Risks Relating to our Common Stock

We do not intend to pay dividends on our common stock, and our ability to pay dividends on our common stock is restricted.

Since inception, we have not paid any cash dividends on common stock. Cash dividends are restricted under the terms of our credit facility, and we presently intend to continue the policy of using retained earnings for expansion of our business. Any future dividends also may be restricted by future agreements.

The price of our stock price has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices.

The market price of our common stock is highly volatile, and we expect it to continue to be volatile for the foreseeable future. Adverse events, including, among others:

•	changes in production volumes, worldwide demand and prices for crude oil and natural gas;

•	changes in market prices of crude oil and natural gas;

•	changes in securities analysts’ estimates of our financial performance;

•	fluctuations in stock market prices and volumes, particularly among securities of energy companies;

•	changes in market valuations of similar companies;

•	changes in interest rates;

•	announcements regarding adverse timing or lack of success in discovering, acquiring, developing and producing crude oil and natural gas resources;

•	announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures, or capital commitments;

•	decreases in the amount of capital available to us;

•	operating results that fall below market expectations or variations in our quarterly operating results;

•	loss of a major customer;

•	loss of a relationship with a partner;

•	the identification of and severity of environmental events and governmental and other third-party responses to the events; or

•	additions or departures of key personnel,

could trigger significant declines in the price of our common stock. For example, the market price of our common stock has been adversely affected by the recent declines in commodity prices. In addition, external events, such as news concerning economic conditions, counterparties to our natural gas or oil derivatives arrangements, changes in government regulations impacting the oil and natural gas exploration and production industries, or the movement of capital into or out of our industry, also are likely to affect the price of our common stock, regardless of our operating performance. Furthermore, general market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could affect the price of our common stock. Recently, the stock markets have experienced price and volume volatility that has affected many companies' stock prices. Stock prices for many companies have experienced wide fluctuations that have often been unrelated to the operating performance of those companies. These fluctuations may affect the market price of our common stock.

Additional financings may subject our existing stockholders to significant dilution.

To the extent that we raise additional funds or complete acquisitions by issuing equity securities, our stockholders may experience significant dilution. In addition, debt financing, if available, may involve restrictive covenants. We may seek to access the public or private capital markets whenever conditions are favorable, even if we do not have an immediate need for additional capital at that time. Our access to the financial markets and the pricing and terms that we receive in those markets could be adversely impacted by various factors, including changes in general market conditions and commodity price changes.

Equity compensation plans may cause a future dilution of our common stock.

To the extent options to purchase common stock under our equity incentive plans are exercised, or shares of restricted stock or other equity awards are issued based on satisfaction of vesting requirements, holders of our common stock will experience dilution.

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As of December 31, 2015 , there were 10,065,067 shares reserved for issuance under our equity compensation plans, of which 915,867 restricted shares have been granted and are subject to issuance in the future based on the satisfaction of certain vesting criteria established pursuant to the respective awards and 5,056,000 of which are issuable upon the exercise of outstanding options to purchase common stock. Our outstanding options have a weighted average exercise price of $9.71 per share.

Non-U.S. holders of our common stock, in certain situations, could be subject to U.S. federal income tax upon sale, exchange or disposition of our common stock.

        It is likely that we are, and will remain for the foreseeable future, a U.S. real property holding corporation for U.S. federal income tax purposes because our assets consist primarily of "United States real property interests" as defined in the applicable Treasury regulations. As a result, under the Foreign Investment in Real Property Tax Act, or FIRPTA, certain non-U.S. investors may be subject to U.S. federal income tax on gain from the disposition of shares of our common stock, in which case they would also be required to file U.S. tax returns with respect to such gain, and may be subject to a withholding tax. In general, whether these FIRPTA provisions apply depends on the amount of our common stock that such non-U.S. investors hold and whether, at the time they dispose of their shares, our common stock is regularly traded on an established securities market within the meaning of the applicable Treasury regulations. So long as our common stock continues to be regularly traded on an established securities market, only a non-U.S. investor who has owned, actually or constructively, more than 5% of our common stock at any time during the shorter of (i) the five-year period ending on the date of disposition and (ii) the non-U.S. investor's holding period for its shares may be subject to U.S. federal income tax on the disposition of our common stock under FIRPTA.

ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.

ITEM 2.     PROPERTIES

See Item 1 of this report.

ITEM 3.	LEGAL PROCEEDINGS

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

ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed on the NYSE MKT under the symbol “SYRG”.

Shown below is the range of high and low sales prices for our common stock as reported by the NYSE MKT for the past two years. 

Period Ended		High		Low
Three Months Ended November 30, 2014		$13.75		$8.05
Three Months Ended February 28, 2015		$13.50		$8.14
Three Months Ended May 31, 2015		$12.98		$10.40
Three Months Ended August 31, 2015		$12.82		$9.04
Four Months Ended December 31, 2015		$12.12		$8.31

Period Ended		High		Low
Three Months Ended November 30, 2013		$11.40		$8.86
Three Months Ended February 28, 2014		$10.69		$8.11
Three Months Ended May 31, 2014		$12.96		$9.70
Three Months Ended August 31, 2014		$14.11		$10.13

As of March 31, 2016 , the closing price of our common stock on the NYSE MKT was $7.77 .

As of March 31, 2016 , we had 126,245,686 outstanding shares of common stock and 140 shareholders of record.

Since inception, we have not paid any cash dividends on common stock.  Cash dividends are restricted under the terms of our credit facility and we presently intend to continue the policy of using retained earnings for expansion of our business.

Issuer Purchases of Equity Securities

Period		Total Number of Shares (or Units) Purchased			Average Price Paid per Share (or Unit)				Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs			Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs)
December 1, 2015 - December 31, 2015 (1)		335,349			$	10.60			—			—

(1) Pursuant to statutory minimum withholding requirements, certain of our executives 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 a publicly announced repurchase plan.

Comparison of Cumulative Return

The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2015 , with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the companies with a Standard Industrial Code ("SIC") of 1311. The SIC Code 1311 consists of a weighted average composite of publicly traded crude petroleum and natural gas companies. The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on August 31, 2010 and in the S&P 500 Index and all companies with the SIC Code 1311 on the same date. The results shown in the graph below are not necessarily indicative of future performance.

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		August 31,																		December 31, 2015
		2010			2011			2012			2013			2014			2015
Synergy Resources Corporation		100.00			138.22			124.44			416.00			598.22			477.33			378.67
S&P 500		100.00			118.50			139.83			165.99			207.89			208.88			218.06
SIC Code 1311		100.00			127.29			119.94			142.03			177.48			96.99			80.11

The stock price performance included in this graph is not necessarily indicative of future stock price performance.

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ITEM 6.	SELECTED FINANCIAL DATA

The selected financial data presented in this item has been derived from our audited financial statements that are either included in this report or in reports previously filed with the SEC.  The information in this item should be read in conjunction with the financial statements and accompanying notes and other financial data included in this report.

	Four Months Ended December 31, 2015				Year Ended August 31,
					2015				2014				2013				2012				2011
Results of Operations (in thousands):
Revenues	$	34,138			$	124,843			$	104,219			$	46,223			$	24,969			$	10,002
Net income (loss)	(122,932		)		18,042				28,853				9,581				12,124				(11,600		)
Net income (loss) per common share:
Basic	$	(1.14	)		$	0.19			$	0.38			$	0.17			$	0.26			$	(0.45	)
Diluted	$	(1.14	)		$	0.19			$	0.37			$	0.16			$	0.25			$	(0.45	)
Certain Balance Sheet Information (in thousands):
Total Assets	$	672,616			$	746,449			$	448,542			$	291,236			$	120,731			$	63,698
Working (Deficit) Capital	24,992				93,129				(35,338		)		50,608				10,875				685
Total Liabilities	166,106				174,052				167,052				88,016				19,619				14,590
Equity	506,510				572,397				281,490				203,220				101,112				49,108
Certain Operating Statistics:
Production:
Oil (MBbls)	742				1,970				941				421				236				90
Gas (MMcf)	3,468				7,344				3,747				2,108				1,109				451
MBOE	1,320				3,194				1,566				773				421				165
BOED	10,822				8,750				4,290				2,117				1,149				452
Average sales price per BOE	$	25.86			$	39.09			$	66.56			$	59.83			$	59.38			$	59.24
LOE per BOE	$	4.41			$	4.70			$	5.10			$	4.42			$	2.89			$	2.94
DD&A per BOE	$	14.22			$	20.62			$	21.05			$	17.26			$	14.29			$	16.62

On February 25, 2016, we changed our fiscal year from the period beginning on September 1 and ending on August 31 to the period beginning on January 1 and ending on December 31. As a result, the selected financial data above includes financial information for the transition period from September 1, 2015 through December 31, 2015. This financial information may not be directly comparable to the prior periods as it covers a shorter time frame. Subsequent to this report, our reports on Form 10-K will cover the calendar year, January 1 to December 31, which will be our fiscal year.

See Note 19 to the Financial Statements included as part of this report for our quarterly financial data. See Note 1 and Note 3 to the Financial Statements included as part of this report for information concerning significant accounting policies and acquisitions, respectively.

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ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following discussion and analysis was prepared to supplement information contained in the accompanying financial statements and is intended to explain certain items regarding the Company's financial condition as of December 31, 2015 , and its results of operations for the four months ended December 31, 2015 and 2014 (unaudited) and for the years ended August 31, 2015 , 2014 and 2013 .  It should be read in conjunction with the “Selected Financial Data” and the accompanying audited financial statements and related notes thereto contained in this Transition Report on Form 10-K.

This section and other parts of this Transition Report on Form 10-K contain forward-looking statements that involve risks and uncertainties.  See the “Cautionary Statement Concerning Forward-Looking Statements” at the beginning of this Transition Report on Form 10-K.  Forward-looking statements are not guarantees of future performance, and our actual results may differ significantly from the results discussed in the forward-looking statements.  Factors that might cause such differences include, but are not limited to, those discussed in “Risk Factors”.  We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.

Overview

We are 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 that 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 75% of our proved producing reserves, and over 98% of our planned 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. Our early development efforts were focused on drilling vertical wells into the Niobrara, Codell, and J-Sand formations. From inception through December 31, 2015 , we have completed, acquired, or participated in 609 gross ( 409 net) successful oil and gas wells. We are the operator of 418 gross ( 369 net) produ cing wells and participate with other operators in 191 producing wells.

In May 2013, we shifted our efforts to horizontal well development within the Wattenberg Field. Since shifting to horizontal development, we have drilled or participated in the drilling of 206 gross ( 103 net) horizontal wells. As of December 31, 2015 , we were the operator of 86 gross ( 84 net) Codell or Niobrara horizontal wells. In addition to the wells that had reached productive status, there are 18 gross ( 14 net) wells in various stages of drilling or completion as of December 31, 2015 .

The following table provides details about our ownership interests with respect to vertical and horizontal producing wells:

Vertical Wells

Operated Wells

Non-Operated Wells

Totals

Gross

Net

Gross

Net

Gross

Net

332

285

71

21

403

306

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Horizontal Wells

Operated Wells

Non-Operated Wells

Totals

Gross

Net

Gross

Net

Gross

Net

86

84

120

19

206

103

In addition to the producing wells summarized in the preceding table, as of December 31, 2015 , we were the operator of 18 gross ( 14 net) wells in progress, and we were participating as a non-operating working interest owner in 7 wells in progress.

For the four months ended December 31, 2015 , our average net daily production was 10,822 BOED. By comparison, during the twelve months ended August 31, 2015 , 2014 and 2013 , our average production rate was 8,750 BOED, 4,290 BOED, and 2,117 BOED, respectively. By December 31, 2015 , over 80% of our daily production was from horizontal wells as compared to less than 10% as of August 31, 2013.

  

During the four months ended December 31, 2015 , crude oil prices declined by approximately 25% , and gas prices declined by approximately 13% . Price declines, especially of this magnitude, can impact many aspects of our operations. For additional discussion concerning the potential impacts of declining commodity prices, please see “Drilling and Completion Operations,” “Market Conditions,” “Oil and Gas Commodity Contracts,” and “Trends and Outlook.”

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 4,300 net acres in the Wattenberg Field and non-operated working interests in 25 gross (approximately 6 net) horizontal wells in the Niobrara and Codell formations. Net production associated with the purchased assets was approximately 1,200 BOED at the time of purchase. The purchase price for the assets was $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, subject to closing adjustments. The transaction had an effective date of September 1, 2015.

Financing and Other

Equity offerings

On January 27, 2016, the Company closed on the sale of 16,100,000 shares of common stock pursuant to an underwriting agreement with Credit Suisse Securities (USA) LLC, acting severally on behalf of itself and the other underwriters.  The price to the Company was $5.545 per share and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company were $89.1 million .  Proceeds from the offering are expected to be used for general corporate purposes, including continuing to develop our acreage position in the Wattenberg Field in Colorado, repaying amounts borrowed under the Revolver, funding a portion of our capital expenditure program for the remainder of 2016, or other uses.

On April 14, 2016, the Company closed on the sale of an additional 22,425,000 shares of common stock pursuant to an underwriting agreement with the same underwriters.  The price to the Company was $7.3535 per share and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company were $164.8 million .  The proceeds of this offering are also expected to be used for general corporate purposes, including to fund development activities and/or potential future acquisitions.

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Revolving Credit Facility

We continue to maintain a borrowing arrangement with our bank syndicate to provide us with liquidity, which could be used to develop oil and gas properties, acquire new oil and gas properties, and for working capital and other general corporate purposes. As of December 31, 2015 , this revolving credit facility (sometimes referred to as the "Revolver") provides for maximum borrowings of $500 million , subject to adjustments based upon a borrowing base calculation, which is re-determined semi-annually using updated reserve reports. As of December 31, 2015 , the Revolver provided for a borrowing base of $163 million , of which $85 million was available to us for future borrowings. The Revolver is collateralized by certain of our assets, including producing properties, and bears a minimum interest rate on borrowings of 2.5% , with the effective rate varying with utilization. The Revolver expires on December 15, 2019 .

On January 28, 2016, the Revolver was amended in connection with the previously postponed semi-annual borrowing base redetermination. The borrowing base was reduced from $163 million to $145 million , and the Revolver was further amended to (i) delete the minimum interest rate floor, (ii) delete the minimum liquidity covenant, (iii) add a current ratio covenant of 1.0 to 1.0, and (iv) delete the minimum hedging requirement. In January 2016, the Company reduced its outstanding borrowings under the Revolver from $78 million to nil . As of March 31, 2016, the entire $145 million borrowing base was available to us for future borrowings.

See further discussion in Note 6 to our financial statements.

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 derived from each of the 12 months prior to the reporting period. During the four months ended December 31, 2015 , 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 during the four months ended December 31, 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.

Properties

As of December 31, 2015 , our estimated net proved oil and gas reserves, as prepared by Ryder Scott, were 26.4 MMBbls of oil and condensate and 238.7 Bcf of natural gas. As of December 31, 2015 , we had approximately 441,000   gross and 349,000 net acres under lease, substantially all of which are located in the greater D-J Basin. We further delineate our acreage into specific areas, including the areas that we refer to as the “core" Wattenberg Field (approximately 55,000 gross and 41,000 net acre s) and the “North East Extension Area” of the Wattenberg Field (approximate ly 99,000 gross and 51,000  net acres ). In addition, we hold approximately 191,000 gross ( 188,000 net) acres in southwest Nebraska, a conventional oil-prone prospect, and approximately 87,000 gross ( 63,000 net) acres in far eastern Colorado.

Within our leasehold in the North East Extension Area, we completed our first horizontal well targeting the Greenhorn formation which was drilled during the year ended August 31, 2015 and subsequently completed. The well is producing hydrocarbons but not in paying quantities, and further expenditures will not be incurred until commodity prices return to a higher level. Our eastern Colorado mineral assets are located in Yuma and Washington Counties, in an area that has a history of dry gas production from the Niobrara formation, where there is little to no activity in the current commodity price environment.

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 believe that at current drilling and completion cost levels and with currently prevailing commodity prices, we can achieve reasonable well-level rates of return when drilling mid or long laterals. Should commodity prices weaken further, our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent. If management believes that the well-level internal rate of return will be at or below our weighted-average cost of capital, we may choose to delay completions and/or forego drilling altogether.

During the four months ended December 31, 2015 , we drilled 12 horizontal wells and completed 13 Codell or Niobrara

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horizontal wells. As of December 31, 2015 , there are 18 horizontal wells in various stages of completion. For the 2016 calendar year, the Company expects to drill 55 gross (52 net) horizontal wells of mostly mid and long laterals, targeting the Codell and Niobrara zones.

Other Operations

We continue to be opportunistic with respect to acquisition efforts. In an effort to extend the length of laterals in our wells, we continue to enter into land and working interest swaps to increase our overall leasehold interest. During the four months ended December 31, 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

For the four months ended December 31, 2015 , our average net daily production increased to 10,822 BOED as compared to 8,750 BOED for the year ended August 31, 2015 . By comparison, our production increased from 4,290 BOED for the year ended August 31, 2014 to 8,750 BOED for the year ended August 31, 2015 . The additional production volumes from recently completed wells more than offset the natural decline of our existing wells. The increase was achieved despite continuing mid-stream constraints, high line pressures in the northern portion of the Wattenberg Field, and the temporary suspension of production from shut-in wells due to offset operator completion activities.

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 years.

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013				2012				2011
Average NYMEX prices
Oil (per Bbl)	$	42.82			$	77.66			$	60.65			$	100.39			$	94.58			$	94.88			$	91.79
Natural gas (per Mcf)	$	2.26			$	3.83			$	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.

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
Oil (NYMEX WTI)
Average NYMEX Price	$	42.82			$	77.66			$	60.65			$	100.39			$	94.58
Realized Price	$	34.65			$	66.72			$	50.75			$	89.98			$	85.95
Differential	$	(8.17	)		$	(10.94	)		$	(9.90	)		$	(10.41	)		$	(8.63	)
Gas (NYMEX Henry Hub)
Average NYMEX Price	$	2.26			$	3.83			$	3.12			$	4.38			$	3.55
Realized Price	$	2.43			$	4.41			$	3.39			$	5.21			$	4.75
Differential	$	0.17			$	0.58			$	0.27			$	0.83			$	1.20

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

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to the natural gas liquids produced with the gas.

There has been a significant decline in the price of oil since the summer of 2014.  As reflected in published data, the price for WTI oil settled at $49.20 per Bbl on Monday, August 31, 2015 .  Ultimately, the price of oil settled at $37.13 per Bbl on December 31, 2015 , down 25% from August 31, 2015. Our revenues, results of operations, profitability and future growth, and the carrying value of our oil and natural gas properties, depend primarily on the prices that we receive for our oil and natural gas production.

A further decline in oil and natural gas prices will adversely affect our financial condition and results of operations.  Furthermore, low oil and natural gas prices can result in an impairment of the value of our properties and the calculation of the “ceiling test” required under the accounting principles for companies following the “full cost” method of accounting.  Our ceiling tests resulted in a total impairment charge of $125.2 million for the four months ended December 31, 2015 , and additional impairments may occur in the future.

Trends and Outlook

Oil traded at $49.20 per Bbl on Monday, August 31, 2015 , but has since declined approximately 25% as of December 31, 2015. 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 could 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 and transportation 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.

Horizontal well development in the Wattenberg Field is still relatively new and the geology is enabling operators to utilize higher density drilling within designated spacing units. When we began our operated horizontal well development program in the Wattenberg Field, we allowed for up to 16 wells per 640 acre section, but we are now testing up to 24 horizontal wells per section.

The recent decline in commodity prices has led to a corresponding decline in service costs, which directly relate to our drilling and completion costs. We have been able to reduce drilling and completion costs during the four months ended December 31, 2015 and the year ended August 31, 2015 due to a combination of optimizing well designs, moving to day-rate drilling, lower contract rates for drilling rigs, less average days to drill, and lower completion costs. This focus on cost reduction has supported well-level economics in spite of the severe price drop in crude oil and natural gas. We 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 that we will achieve the same percentage reduction of costs during 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 that these gathering systems would be owned and operated by independent third party companies, but that we would commit specific wellhead production to these systems. We believe that 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.

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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 that we have historically realized on our oil production. We anticipate that 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 7.

    

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 that 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, available borrowings under our credit facility are reduced, or we experience other unfavorable events, our liquidity could be adversely impacted.  Our liquidity would also be affected if we increase our capital expenditures or complete one or more acquisitions. 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 or existing wells to be recompleted. 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 while currently not overly burdening us with restrictive financial covenants and 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 four months ended December 31, 2015, the NYMEX-WTI oil price ranged from a high of $49.20 per Bbl on Monday, August 31, 2015 to a low of $34.55 per Bbl on Monday, December 21, 2015 , while the NYMEX-Henry Hub natural gas price ranged from a high of $2.76 per MMBtu on September 14, 2015 to a low of $1.76 per MMBtu on December 17, 2015 . 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.

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At December 31, 2015 , we had cash and cash equivalents of $66.5 million and an outstanding balance of $78.0 million under our revolving credit facility. Our sources and (uses) of funds for the four months ended December 31, 2015 and 2014 and the twelve months ended August 31, 2015 , 2014 , and 2013 are summarized below (in thousands):

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
					(unaudited)
Cash provided by operations	$	20,072			$	41,329			$	125,087			$	74,905			$	32,120
Acquisitions and development of oil and gas properties and equipment	(84,937		)		(158,181		)		(275,808		)		(155,602		)		(80,469		)
Short-term investments	—				—				—				60,018				(60,000		)
Cash provided by other investing activities	—				—				6,239				704				—
Cash (used in) provided by equity financing activities	(2,544		)		14,965				204,953				35,265				74,528
Net borrowings on Revolver	—				106,704				38,684				—				34,000
Net (decrease) increase in cash and equivalents	$	(67,409	)		$	4,817			$	99,155			$	15,290			$	179

Net cash provided by operating activities was $20.1 million and $41.3 million for the four months ended December 31, 2015 and 2014 (unaudited), respectively, and $125.1 million and $74.9 million for the years ended August 31, 2015 and 2014 , respectively. The decline in cash from operating activities over the four-month periods reflects the decline in commodity prices, partially offset by the increase in production. The significant improvement in cash from operating activities over the annual periods reflects the operating contribution from new wells that were drilled and producing wells that were acquired.

During the four months ended December 31, 2015 , we did not receive cash proceeds from any significant financing activities.

During the year ended August 31, 2015 , we received cash proceeds from the following financing activities:

•	$15.4 million from the exercise of Series C warrants. As of August 31, 2015 , all Series C warrants had been exercised.

•

Approximately $190.8 million (after underwriting discounts, commissions and expenses) from our public offering of 18,613,952 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to the public of $10.75 per share in February 2015. These proceeds were used to pay down outstanding indebtedness under our revolving credit facility and for other corporate purposes, including working capital.

•	Net proceeds of $38.7 million drawn under our revolving credit facility.

Subsequent to December 31, 2015, we received cash proceeds from and used cash in the following financing activities:

•

On January 27, 2016, we received cash proceeds of approximately $89.1 million (after underwriting discounts, commissions and expenses) from our public offering of 16,100,000 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to us of $5.545 per share. These proceeds have been or are expected to be used for general corporate purposes, which may include continuing to develop our acreage position in the Wattenberg Field in Colorado, repaying amounts borrowed under the Revolver, funding a portion of our capital expenditure program for the remainder of 2016, or other uses. As discussed below, proceeds were initially used to repay amounts borrowed under the Revolver.

•	In January 2016, the Company repaid its outstanding borrowings under the Revolver of $78 million .

•

On April 14, 2016, we received cash proceeds of approximately $164.8 million (after underwriting discounts, commissions and expenses) from our public offering of 22,425,000 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to us of $7.3535 per share. These proceeds are also expected to be used for general corporate purposes, including to fund development activities and/or potential future acquisitions.

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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 Seventh Amendment to the credit facility on January 28, 2016.  The arrangement provides for a maximum loan commitment of $500 million; however, the maximum amount we can borrow 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 December 31, 2015 , our borrowing base was $163 million , and we had $78 million outstanding under the facility. The maturity date of the facility is December 15, 2019 . In January 2016, the Company reduced its outstanding borrowings under the Revolver from $78 million to nil . On January 28, 2016, the borrowing base was reduced from $163 million to $145 million . As of March 31, 2016, the total of the $145 million was available to us for future borrowings. The next semi-annual redetermination is scheduled for May 1, 2016 .

As of December 31, 2015 , interest on our revolving line of credit accrues at a variable rate, which will equal or exceed the minimum rate of 2.5% . The interest rate pricing grid contains a graduated escalation in applicable margin for increased utilization. As discussed below, the minimum interest rate was removed under the Seventh Amendment.

On January 28, 2016, the Revolver was amended to (i) delete the minimum interest rate floor, (ii) delete the minimum liquidity covenant, (iii) add a current ratio covenant of 1.0 to 1.0, and (iv) delete the minimum hedging requirement.

Reconciliation of Cash Payments to Capital Expenditures

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 $136.1 million and $191.9 million for the four months ended December 31, 2015 and 2014 (unaudited), respectively, and $304.9 million , $214.0 million , and $118.1 million for the years ended August 31, 2015 , 2014 , and 2013, respectively. A reconciliation of the differences between cash payments and the accrual basis amounts is summarized in the following table (in thousands):

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
					(unaudited)
Cash payments for acquisitions	$	35,045			$	74,050			$	74,221			$	30,590			$	29,012
Cash payments for capital expenditures	49,892				84,131				201,587				125,012				51,457
Accrued costs, beginning of period	(33,071		)		(71,849		)		(71,849		)		(25,491		)		(5,733		)
Accrued costs, end of period	31,414				52,747				33,071				71,849				25,491
Non-cash acquisitions, common stock	50,265				50,330				60,221				11,184				16,684
Other	2,575				2,475				7,622				905				1,233
Accrual basis capital expenditures	$	136,120			$	191,884			$	304,873			$	214,049			$	118,144

Capital Expenditures

The majority of capital expenditures during the four months ended December 31, 2015 were associated with the acquisition of the K.P. Kauffman assets and the costs of drilling and completing wells that we operate.  During the four months ended December 31, 2015, we brought 13 wells into productive status and spudded 10 wells. In addition, we had drilled 18 gross ( 14 net) wells that had not been brought into productive status as of December 31, 2015. All but 8 of the wells in progress are scheduled to commence production before December 31, 2016.

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With respect to our ownership interest in wells operated by other companies, we did not participate in drilling and completion activities any such wells during the four months ended December 31, 2015.

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 that we may complete during the remainder of our new fiscal year ending December 31, 2016.

Our preliminary capital expenditure plan continues to anticipate the use of one drilling rig during the remainder of new fiscal year ending December 31, 2016 except for a short period which we anticipate adding a second rig to drill adjoining pads to minimize the impact on the local municipality. We also regularly review capital expenditures, as has been our historical practice, throughout the year and will adjust our program based on changes in commodity prices, service costs, drilling success, and capital availability. Our total anticipated capital program for the year ended December 31, 2016 is estimated at a range between $130 million and $150 million, including approximately $30 million for discretionary seismic and land leasing, 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 protect against the variability in cash flows created by short-term price fluctuations associated with the sale of future oil and gas production.  At March 31, 2016 , we had open positions covering 0.9 million barrels of oil and 2,040  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 volume amounts, whether we utilize oil and/or natural gas instruments, and at what commodity prices the instruments are associated with, 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.

A “put” option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, purchase put options, which require us to pay premiums at the time we purchase the contracts. These premiums represent the fair value of the purchased put as of the date of purchase. The ownership of put options is consistent with our derivative strategy inasmuch as the value of the puts will increase as commodity prices decline, helping to offset the cash flow impact of a decline in realized prices for the underlying commodity. However, if the underlying commodity increases in value, there is a risk that the put option will expire worthless and the net premiums paid would be recognized as a loss.

Conversely, a “call” option gives the owner the right, but not the obligation, to purchase the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, sell call options in conjunction with the purchase of put options to create “collars”. We regularly utilize “no premium” (a.k.a. zero cost) collars constructed by selling call options while simultaneously buying put options, in which the premiums paid for the puts is offset by the premiums received for the calls. Collars are consistent with our derivative strategy inasmuch as the they establish a known range of prices to be received for the associated volume equivalents, that being bound at the upper end by the call’s strike price (the “ceiling”) and at the lower end by the put’s strike price (the “floor”).

Additionally, at times, we may enter into swaps. Swaps are derivative contracts which obligate two counterparties to effectively trade the underlying commodity at a set price over a specified term. Swaps are consistent with our derivative strategy inasmuch as they establish a known future price to be received for the associated equivalent volumes.

During periods of significant price declines, for settled contracts structured as “collars,” we will receive settlement payments from the contracts’ counterparties for the difference between the contracted “floor” price and the average posted price for the contract period. For settled “swaps,” we will receive the difference between the contracted swap price and the average

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posted price for the contract period, if lower. For settled “put” contracts, we will receive the difference between the put’s strike price and the average posted price for the contract period. If we decide to liquidate an “in-the-money” position prior to settlement date, we will receive the approximate fair value of the contract at that time. These realized gains increase our cash flows for the period in which they are recognized.

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

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

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

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

During the four months ended December 31, 2015 , we reported an unrealized commodity activity gain of $4.9 million .  Unrealized gains and losses are non-cash items.  We also reported a realized gain of $1.6 million , representing the cash settlement of commodity contracts settled during the period, net of previously incurred premiums attributable to the settled commodity contracts.

At December 31, 2015 , we estimated that the fair value of our various commodity derivative contracts was a net asset of $9.6 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 December 31, 2015 may differ significantly from the realized values at their respective settlement dates.

Our commodity derivative contracts as of March 31, 2016 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
Apr 1 to Dec 31, 2016		495,000		1,200,000		$45.00 - 65.00		$2.98 - 3.40		$48.57		N/A
Jan 1 to Aug 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. All references to the four month period ended December 31, 2014 are unaudited.

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For the four months ended December 31, 2015 compared to the four months ended December 31, 2014

For the four months ended December 31, 2015 , we reported net loss of $122.9 million compared to net income of $26.8 million during the four months ended December 31, 2014 . Net loss per basic and diluted share were $1.14 and $1.14 , respectively, for the four months ended December 31, 2015 compared to net income per share per basic and diluted share of $0.34 and $0.33 , respectively, for the four months ended December 31, 2014 . Revenues decreased $18.8 million during the four months ended December 31, 2015 compared to the four months ended December 31, 2014 due to the rapid decline of commodity prices as discussed above. As of December 31, 2015 , we had 609 gross producing wells, compared to 561 gross producing wells as of December 31, 2014 . However, although our production increased during the comparable periods, our revenues during the 2015 period decreased 36% as a result of declining oil and gas prices. The impact of changing prices on our commodity derivative positions also drove significant differences in our results of operations between the two periods.

Oil and Gas Production and Revenues - For the four months ended December 31, 2015 , we recorded total oil and gas revenues of $34.1 million compared to $52.9 million for the four months ended December 31, 2014 , a decrease of $18.8 million or 36% . The following table summarizes key production and revenue statistics:

	Four Months Ended December 31,
	2015				2014				Change
Production:
Oil (MBbls)	742				639				16	%
Gas (MMcf)	3,468				2,340				48	%
MBOE	1,320				1,029				28	%
BOED	10,822				8,432				28	%
Revenues (in thousands):
Oil	$	25,724			$	42,615			(40	)%
Gas	8,414				10,316				(18	)%
	$	34,138			$	52,931			(36	)%
Average sales price:
Oil	$	34.65			$	66.72			(48	)%
Gas	$	2.43			$	4.41			(45	)%
BOE	$	25.86			$	51.45			(50	)%

Net oil and gas production for the four months ended December 31, 2015 averaged 10,822 BOED, an increase of 28% over average production of 8,432 BOED in the four months ended December 31, 2014 . From December 31, 2014 to December 31, 2015, we added 55 net horizontal wells, including 6 (net) horizontal wells acquired in the K.P. Kauffman transaction, increasing our reserves, producing wells, and daily production totals. The decline in average sales prices by approximately 50% more than offset the effects of increased production, resulting in an overall reduction of revenues.

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

	Four Months Ended December 31,
	2015				2014
Production costs	$	5,790			$	4,742
Workover	22				3
Total LOE	$	5,812			$	4,745
Per BOE:
Production costs	$	4.39			$	4.61
Workover	0.02				—
Total LOE	$	4.41			$	4.61

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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 our four months ended December 31, 2015, we experienced decreased production costs per BOE primarily as a result of increased production.

Production taxes - During the four months ended December 31, 2015 , production taxes were $3.1 million , or $2.35 per BOE, compared to $5.1 million , or $4.91 per BOE, during the prior year comparable period. Taxes tend to increase or decrease primarily based on the value of oil and gas sold. As a percent of revenues, taxes were 9.1% and 9.5% for the four months ended December 31, 2015 and 2014, respectively.

Depletion, Depreciation, and Accretion (“DD&A”) - The following table summarizes the components of DD&A:

	Four Months Ended December 31,
(in thousands)	2015				2014
Depletion of oil and gas properties	$	18,371			$	22,357
Depreciation and accretion	405				217
Total DD&A	$	18,776			$	22,574
DD&A expense per BOE	$	14.22			$	21.94

For the four months ended December 31, 2015 , depletion of oil and gas properties was $14.22 per BOE compared to $21.94 per BOE for the four months ended December 31, 2014 . The decrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. This ratio was significantly reduced due to the impairment of our full cost pool as described below and the increase in our total proved reserves. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning-of-quarter estimated total reserves determine the depletion rate.

Full cost ceiling impairment - During the four months ended December 31, 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 “Oil and Gas Properties, including Ceiling Test,” included in the discussion of Critical Accounting Policies below.

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

	Four Months Ended December 31,
(in thousands)	2015				2014
G&A costs incurred	$	18,966			$	6,392
Capitalized costs	(1,091		)		(714		)
Total G&A	$	17,875			$	5,678
Non-Cash G&A	$	8,513			$	685
Cash G&A	9,362				4,993
Total G&A	$	17,875			$	5,678
Non-Cash G&A per BOE	$	6.45			$	0.67
Cash G&A per BOE	7.09				4.85
G&A Expense per BOE	$	13.54			$	5.52

G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. During the  four months ended December 31, 2015 , we increased our employee count from 36 as of August 31, 2015 to 62 , while reducing the number of consultants, advisors, and contractors that had historically been used for certain tasks. Additionally, during the four months ended December 31, 2015 , we awarded bonuses, consisting of cash and restricted stock, to management, employees, and directors. Most significantly, bonuses totaling approximately $4.8

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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  four months ended December 31, 2015  includes stock-based compensation of  $8.4 million  compared to  $0.7 million  for the  four months ended December 31, 2014 . Stock-based compensation includes a calculated value for stock options or shares of common stock that we grant for compensatory purposes. It is a non-cash charge. 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  four months ended December 31, 2014  to the  four months ended December 31, 2015  reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.

Commodity derivative gains (losses) - As more fully described in the paragraphs titled “Oil and Gas Commodity Contracts” located in “Liquidity and Capital Resources,” we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the four months ended December 31, 2015 , we realized a cash settlement gain of $1.6 million , net of previously incurred premiums attributable to the settled commodity contracts. For the prior comparable period, we realized a cash settlement gain of $3.7 million .

In addition, for the four months ended December 31, 2015 , we recorded an unrealized gain of $4.9 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the four months ended December 31, 2014 , we reported an unrealized gain of $24.0 million . Unrealized gains are non-cash items.

Income taxes - We reported income tax benefit of $10.0 million for the four months ended December 31, 2015 , calculated at an effective tax rate of 8% . During the comparable prior year period, we reported income tax expense of $15.8 million , calculated at an effective tax rate of 37% . As explained in more detail below, during the four months ended December 31, 2015 , the effective tax rate was substantially reduced by the recognition of a full valuation allowance on the net deferred tax asset which resulted primarily from the recording of a $125.2 million ceiling test impairment. During four months ended December 31, 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 $44.2 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 December 31, 2015. As of August 31, 2015 and for periods prior, we reached the opposite conclusion; therefore, we did not record a valuation allowance against any of our deferred tax assets in those periods.

For the year ended August 31, 2015, compared to the year ended August 31, 2014

For the year ended August 31, 2015 , we reported net income of $18.0 million compared to net income of $28.9 million during the year ended August 31, 2014 . Net income per basic and diluted share were $0.19 and $0.19 , respectively, for the year ended August 31, 2015 compared to earnings per share of $0.38 and $0.37 per basic and diluted share for the year ended August 31, 2014. Revenues increased $20.6 million during the year ended August 31, 2015 compared to the year ended August 31, 2014 due to rapid growth in production as discussed below. As of August 31, 2015 , we had 582 gross producing wells, compared to 404 gross producing wells as of August 31, 2014 . However, although our production more than doubled during the comparable periods, our revenues during the year ended August 31, 2015 increased only 20% as a result of declining oil and gas prices. The impact of changing prices on our commodity derivative positions also drove significant differences in our results of operations between the two periods.

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Oil and Gas Production and Revenues - For the year ended August 31, 2015 we recorded total oil and gas revenues of $124.8 million compared to $104.2 million for the year ended August 31, 2014 , an increase of $20.6 million or 20% . The following table summarizes key production and revenue statistics:

	Year Ended August 31,
	2015				2014				Change
Production:
Oil (MBbls)	1,970				941				109	%
Gas (MMcf)	7,344				3,747				96	%
MBOE	3,194				1,566				104	%
BOED	8,750				4,290				104	%
Revenues (in thousands):
Oil	$	99,969			$	84,693			18	%
Gas	24,874				19,526				27	%
	$	124,843			$	104,219			20	%
Average sales price:
Oil	$	50.75			$	89.98			-44	%
Gas	3.39				5.21				-35	%
BOE	$	39.09			$	66.56			-41	%

Net oil and gas production for the year ended August 31, 2015 averaged 8,750 BOED, an increase of 104% over average production of 4,290 BOED in the year ended August 31, 2014 . Year over year, we added 48 net horizontal wells, including 3 (net) horizontal wells acquired in the Bayswater transaction, increasing our reserves, producing wells, and daily production totals. The decline in average sales prices by approximately 41% mostly offset the effects of increased production, resulting in an overall 20% increase of revenues.

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

	Year Ended August 31,
	2015				2014
Production costs	$	13,879			$	7,794
Workover	1,138				197
Total LOE	$	15,017			$	7,991
Per BOE:
Production costs	$	4.35			$	4.98
Workover	0.35				0.12
Total LOE	$	4.70			$	5.10

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 year ended August 31, 2015, we experienced decreased production costs per BOE primarily as a result of increased production. Partially offsetting this decline in costs was increased costs resulting from intermittent midstream restrictions that reduced the efficiency and capacity of the gas gathering system.

Production taxes - During the year ended August 31, 2015 , production taxes were $11.3 million , or $3.55 per BOE, compared to $9.7 million , or $6.17 per BOE, during the prior year. Taxes tend to increase or decrease primarily based on the value of oil and gas sold. As a percent of revenues, taxes were 9.1% and 9.3% for the years ended August 31, 2015 and 2014 , respectively.

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DD&A - The following table summarizes the components of DD&A:

	Year Ended August 31,
(in thousands)	2015				2014
Depletion of oil and gas properties	$	65,158			$	32,132
Depreciation and accretion	711				826
Total DD&A	$	65,869			$	32,958
DD&A expense per BOE	$	20.62			$	21.05

For the year ended August 31, 2015 , depletion of oil and gas properties was $20.62 per BOE compared to $21.05 per BOE for the year ended August 31, 2014 . The decrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning-of-quarter estimated total reserves determine the depletion rate. Since DD&A expense represents depletion of historical costs, our implemented reductions in well costs were not fully reflected in the rate.

Full cost ceiling impairment - During the year ended August 31, 2015 , we recognized a total impairment of $16.0 million , representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling. See “Oil and Gas Properties, including Ceiling Test,” included in the discussion of Critical Accounting Policies below.

G&A - The following table summarizes G&A expenses incurred and capitalized during the periods presented:

	Year Ended August 31,
(in thousands)	2015				2014
G&A costs incurred	$	21,044			$	11,369
Capitalized costs	(2,049		)		(1,230		)
Total G&A	$	18,995			$	10,139
G&A Expense per BOE	$	5.95			$	6.48

G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. In an effort to minimize overhead costs, we employed a total staff of 36 employees as of August 31, 2015 and used consultants, advisors, and contractors to perform certain tasks when it is cost effective.

Although G&A costs increased as we grew the business, we strove to maintain an efficient overhead structure.  For the year ended August 31, 2015 , G&A was $5.95 per BOE compared to $6.48  per BOE for the year ended August 31, 2014 .

Our G&A expense for the year ended August 31, 2015 includes stock-based compensation of $7.7 million compared to $3.0 million for the year ended August 31, 2014 .

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 development of properties. Those costs were reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from 2014 to 2015 reflected our increasing activities to acquire leases and develop the properties.

Commodity derivative gains (losses) - As more fully described in the paragraphs titled “Oil and Gas Commodity Contracts” located in “Liquidity and Capital Resources,” we used commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the year ended August 31, 2015 , we realized a cash settlement gain of $30.5 million , including gains of $10.0 million from the settlement of contracts at their scheduled maturity dates and gains of $20.5 million from the early liquidation of “in-the-money” contracts. For the prior year, we realized a cash settlement loss of $2.1 million.

In addition, for the year ended August 31, 2015 , we recorded an unrealized gain of $1.8 million to recognize the mark-to-market change in fair value of our commodity contracts for the year ended August 31, 2015 . In comparison, in the year ended August 31, 2014 , we reported an unrealized gain of $2.5 million . Unrealized gains are non-cash items.

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Income taxes - We reported income tax expense of $11.7 million for the year ended August 31, 2015 , calculated at an effective tax rate of 39% . During the comparable prior year period, we reported income tax expense of $15.0 million , calculated at an effective tax rate of 34% . For both periods, it appeared that the tax liability will be substantially deferred into future years. During both periods, the effective tax rate differed from the federal and state statutory rate primarily by the impact of deductions for percentage depletion.

For tax purposes, we had a net operating loss (“NOL”) carryover of $23.1 million, which is available to offset future taxable income. The NOL will begin to expire, if not used, in 2031.

Each year, management evaluates all the positive and negative evidence regarding our tax position and reaches a conclusion on the most likely outcome.  As of August 31, 2015 and 2014 , we concluded that it was more likely than not that we would be able to realize a benefit from the net operating loss carryforward and, therefore, included it in our inventory of deferred tax assets.

For the year ended August 31, 2014, compared to the year ended August 31, 2013

For the year ended August 31, 2014, we reported net income of $28.9 million compared to net income of $9.6 million for the twelve months ended August 31, 2013. Earnings per basic and diluted share were $0.38 per basic and $0.37 per diluted share for the year ended August 31, 2014 compared to $0.17 per basic and $0.16 per diluted share during the same period one year prior. Rapid growth in production and the impact of changing prices on our commodity derivative positions drove this increase. The significant variances between the two years were primarily caused by increased revenues and expenses associated with production from 31 new horizontal wells and the acquisition of producing properties included in the Trilogy and Apollo transactions. The following discussion expands upon significant items that affected results of operations.

Oil and Gas Production and Revenues - For the year ended August 31, 2014, we recorded total oil and gas revenues of $104.2 million compared to $46.2 million for the year ended August 31, 2013, an increase of $58.0 million or 125%. The following table summarizes key production and revenue statistics:

	Year Ended August 31,
	2014				2013				Change
Production:
Oil (MBbls)	941				421				124	%
Gas (MMcf)	3,747				2,108				78	%
MBOE	1,566				773				103	%
BOED	4,290				2,117				103	%
Revenues (in thousands):
Oil	$	84,693			$	36,206			134	%
Gas	19,526				10,017				95	%
	$	104,219			$	46,223			125	%
Average sales price:
Oil	$	89.98			$	85.95			5	%
Gas	5.21				4.75				10	%
BOE	$	66.56			$	59.83			11	%

Net oil and gas production averaged 4,290 BOED for the year ended August 31, 2014, compared to 2,117 BOED for 2013, a year-over-year increase of 103%.  As of August 31, 2014, we owned interests in 404 producing wells.  The significant increase in production from the prior year reflects our increased well count and shift to horizontal wells. Our rate of growth was even more pronounced at the end of the year ended August 31, 2014. During the three months ended August 31, 2014, we completed 15 new horizontal wells. Production for the three months ended August 31, 2014 averaged 5,894 BOED. The increase in average realized sales prices by approximately 11% compounded with the increased production resulting in an overall 125% increase of revenues.

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LOE - Direct operating costs of producing oil and natural gas and taxes on production and properties are reported as lease operating expenses as follows (in thousands):

	Year Ended August 31,
	2014				2013
Production costs	$	7,794			$	3,198
Workover	197				219
Total LOE	$	7,991			$	3,417
Per BOE:
Production costs	$	4.98			$	4.14
Workover	0.12				0.28
Total LOE	$	5.10			$	4.42

From the year ended August 31, 2013 to the year ended August 31, 2014, we experienced an increase in production cost per BOE in connection with additional costs to bolster output from some of our older wells as well as additional costs to operate horizontal wells. Additional wellhead compression was added at some well locations and older equipment was replaced or refurbished. During the year ended August 31, 2014, we incurred additional costs related to the integration of newly acquired producing properties. In particular, the acquisition of a disposal well in one of the acquisitions added to our average cost per BOE, as the disposal well had a slightly different cost profile than our other wells. As expected, horizontal wells are more costly to operate than vertical wells, especially during the early stages of production. Finally, costs incurred to comply with new environmental regulations were significant.

Production taxes - During the year ended August 31, 2014, production taxes were $9.7 million , or $6.17 per BOE, compared to $4.2 million or $5.48 per BOE during the year ended August 31, 2013. Taxes made up the largest single component of direct costs and tend to increase or decrease primarily based on the value of oil and gas sold. As a percentage of revenues, taxes averaged  9.3% in 2014 and 9.2% in 2013.

DD&A - The following table summarizes the components of DD&A:

	Year ended August 31,
(in thousands)	2014				2013
Depletion of oil and gas properties	$	32,132			$	13,046
Depreciation and accretion	826				290
Total DD&A	$	32,958			$	13,336
DD&A expense per BOE	$	21.05			$	17.26

For the year ended August 31, 2014, depletion of oil and gas properties was $21.05 per BOE compared to $17.26 for the year ended August 31, 2013. The increase in the DD&A rate was the result of an increase in both the ratio of reserves produced and the total costs capitalized in the full cost pool. Capitalized costs of evaluated oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning of quarter estimated total reserves determine the depletion rate.  For the year ended August 31, 2014, production represented 4.6% of our reserve base compared to 5.2% for the year ended August 31, 2013. A contributing factor to the change in the ratio was the inclusion of additional horizontal wells in the calculation.

In addition to a change in the ratio of production to proved reserves EUR, our DD&A rate was affected by the increasing costs of mineral leases, included as proven properties, and the costs associated with the acquisition of producing properties. Leasing costs in the D-J Basin increased with the success of horizontal development.  For acquisition of producing properties, substantially all of the costs were allocated to proved reserves and included in the full cost pool.  The allocation of the purchase price related to the November 2013 Trilogy and Apollo acquisitions was at a higher cost per BOE than our historical cost of acquiring leaseholds and developing our properties.  Therefore, the increase in the ratio of costs subject to depletion to the reserves acquired was greater than our internally developed properties. 

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G&A - The following table summarizes G&A expenses incurred and capitalized during the periods presented:

	Year Ended August 31,
(in thousands)	2014				2013
G&A costs incurred	$	11,369			$	6,325
Capitalized costs	(1,230		)		(637		)
Total G&A	$	10,139			$	5,688
G&A Expense per BOE	$	6.48			$	7.36

G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. For the year ended August 31, 2014, G&A was $6.48 per BOE compared to $7.36 for the year ended August 31, 2013, primarily as a result of the increase in BOE produced during the year ended August 31, 2014. Our G&A expense for the year ended August 31, 2014 includes stock-based compensation of $3.0 million, compared to $1.4 million for the year ended August 31, 2013.

The increase in capitalized costs from the year ended August 31, 2013 to August 31, 2014 reflected our increasing activities to acquire leases and develop the properties.

Other Income (Expense) - Neither interest expense nor interest income had a significant impact on our results of operations for either the year ended August 31, 2014 or 2013. The interest costs that we incurred under our credit facility were eligible for capitalization into the full cost pool. We capitalized interest costs that are related to the cost of assets during the period of time before they are placed into service.

Commodity derivative gains (losses) - In the year ended August 31, 2014, we realized a cash settlement loss of $2.1 million related to contracts that settled during the period. For the year ended August 31, 2013, we realized a cash settlement loss of $0.4 million.

In addition, we recorded an unrealized gain of $2.5 million to recognize the mark-to-market change in fair value of our futures contracts for the year ended August 31, 2014. In comparison, in the year ended August 31, 2013 we reported an unrealized loss of $2.6 million.

Income Taxes - We reported income tax expense of $15.0 million for the year ended August 31, 2014, calculated at an effective tax rate of 34%. During the comparable prior year, we reported income tax expense of $6.9 million, calculated at an effective tax rate of 42%. For both periods, it appeared that the tax liability will be substantially deferred into future years. During the year ended August 31, 2014, the effective tax rate was reduced from the federal and state statutory rate by the impact of deductions for percentage depletion.

As of August 31, 2014 and 2013, we concluded that it was more likely than not that we would be able to realize a benefit from the net operating loss carryforward and, therefore, included it in our inventory of deferred tax assets.

Contractual Commitments

The following table summarizes our contractual obligations as of December 31, 2015 (in thousands):

	Less than One Year				One to Three Years				Three to Five Years				More Than Five Years				Total
Rig Contract (1)	$	2,790			$	—			$	—			$	—			$	2,790
Volume commitments (2)	13,548				45,272				42,388				6,390				107,598
Revolving credit facility (3)	1,950				3,900				80,763				—				86,613
Operating Leases	373				23				—				—				396
Total	$	18,661			$	49,195			$	123,151			$	6,390			$	197,397

1	Represents an estimate of the commitment related to the use of one rig.  Actual amounts will vary as a result of a number of variables, including target formations, measured depth, and other technical details.

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2

We have entered into agreements that require us to deliver minimum amounts of crude oil to certain third parties through 2021. Production can be sourced via third party contract, in-kind agreements, or self-sustained production. We will incur a charge of approximately $5.56 per Bbl if a minimum quantity of crude oil is not delivered to the pipeline-related counterparties. Additionally, we may be subject to potential damages should we fail to deliver committed volumes to a third party refiner. Amounts reflect the estimated deficiency payments under our pipeline-related commitments assuming no deliveries are made. Potential damages and other charges related to nonperformance under these contracts are not included in the amounts above. See further discussion in Note 16 to our financial statements.

3	Includes interest payments assuming a constant interest rate of 2.5%; subsequent to December 31, 2015, the principal balance of $78 million was repaid.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future material effect on our financial condition, changes in financial condition, revenues or expense, results of operations, liquidity, or capital resources.

Non-GAAP Financial Measures

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

Adjusted EBITDA

We use "adjusted EBITDA," a non-GAAP financial measure, for internal managerial purposes when evaluating period-to-period comparisons. This measure is not a measure of financial performance under US GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, 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 (loss) income adjusted to exclude the impact of the items set forth in the table below. We believe that adjusted EBITDA is relevant because similar measures are widely used in our industry.

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

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
Adjusted EBITDA:
Net (loss) income	$	(122,932	)		$	26,799			$	18,042			$	28,853			$	9,581
Depletion, depreciation, and accretion	18,776				22,574				65,869				32,958				13,336
Full cost ceiling impairment	125,230				—				16,000				—				—
Income tax (benefit) provision	(10,007		)		15,802				11,677				15,014				6,870
Stock-based compensation	8,431				960				7,691				2,968				1,362
Mark to market of commodity derivative contracts:
Total (gain) loss on commodity derivatives contracts	(6,482		)		(27,701		)		(32,256		)		(321		)		3,044
Cash settlements on commodity derivative contracts	1,954				3,683				31,721				(2,138		)		(395		)
Cash premiums paid for commodity derivative contracts	(956		)		—				(4,117		)		—				—
Interest expense (income)	(40		)		(16		)		159				(82		)		50
Adjusted EBITDA	$	13,974			$	42,101			$	114,786			$	77,252			$	33,848

PV-10

PV-10 is a non-GAAP financial measure. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with US GAAP, but rather should be considered in addition to the standardized measure.

PV-10 is derived from the standardized measure, which is the most directly comparable GAAP financial measure. PV-10 is calculated using the same inputs and assumptions as the standardized measure, with the exception that it omits the impact of future income taxes. It is considered to be a pre-tax measurement.

The following table provides a reconciliation of the standardized measure to PV-10 at December 31, 2015 and August 31, 2015 , 2014 , and 2013 (in thousands):

	As of December 31, 2015				As of August 31,
					2015				2014				2013
Standardized measure of discounted future net cash flows:	$	390,953			$	365,829			$	402,699			$	181,732
Add: 10 percent annual discount, net of income taxes	408,939				372,658				376,827				199,111
Add: future undiscounted income taxes	108,172				144,399				252,925				113,545
Future pre-tax net cash flows	$	908,064			$	882,886			$	1,032,451			$	494,388
Less: 10 percent annual discount, pre-tax	(469,921		)		(444,605		)		(498,753		)		(258,272		)
PV-10	$	438,143			$	438,281			$	533,698			$	236,116

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

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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.

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

In spite of the imprecise nature of reserves estimates, they are a critical component of our financial statements. The determination of the depletion component of our depletion, depreciation, and accretion expenses ("DD&A"), as well as the ceiling test calculation, is highly dependent on estimates of proved oil and natural gas reserves. For example, if estimates of proved reserves decline, our DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves may result from a number of factors including lower prices, evaluation of additional operating history, mechanical problems on our wells, and catastrophic events. Lower prices can also make it uneconomical to drill wells or produce from properties with high operating costs.

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

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

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

Companies that use full cost accounting perform a ceiling test each quarter. The full cost ceiling test is the impairment test prescribed by SEC Regulation S-X Rule 4-10. The test compares capitalized costs in the full cost pool, less accumulated DD&A and related deferred income taxes, to a calculated ceiling amount. The calculated ceiling amount is equal to the sum of the present value of estimated future net revenues, plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproven properties included in costs being amortized, less the income tax effects related to differences between the book and tax basis of the properties. The present value of estimated future net revenues is computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves; the result of which is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued on the balance sheet are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. In accordance with SEC Staff Accounting Bulletin Topic 12D, the income tax effect is calculated by using the present value of estimated future net revenue as pre-tax income, deducting the aforementioned tax effects, and applying the statutory tax rate. If the net capitalized costs exceed the ceiling amount, the excess must be charged to expense in recognition of the impairment.

Under the ceiling test, the estimate of future revenues is calculated using a current price (as defined in the SEC rules to include data points over a trailing 12-month period). Thus, the full impact of a sudden price decline is not recognized immediately. As prices decline, the economic performance of certain properties in the reserve estimate may deteriorate to the point that they

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are removed from the proved reserve category, thus reducing the quantity and value of proved reserves. The use of a 12-month average will tend to spread the impact of the change on the financial statements over several reporting periods.

During the four months ended December 31, 2015 , our ceiling test resulted in a cumulative impairment of $125.2 million , which was driven by the previously discussed declines in the price of oil and gas. A further decline in oil and gas prices, or an increase in oil and gas prices that is insufficient to overcome the impact of price declines in the year-ago periods on the ceiling test calculation, could result in additional ceiling test impairments in future periods.

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

Asset Retirement Obligations ("ARO"): We are subject to legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service. Calculation of an ARO requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors. The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using our credit adjusted risk free rate. Estimates are periodically reviewed and adjusted to reflect changes.

The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made.  This is typically when a well is completed or an asset is placed in service.  When the ARO is initially recorded, we capitalize the cost (asset retirement cost or “ARC”) by increasing the carrying value of the related asset.  ARCs related to wells are capitalized to the full cost pool and subject to depletion.  Over time, the liability increases for the change in its present value (accretion of ARO), while the capitalized cost decreases over the useful life of the asset, recognized as depletion.

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

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

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

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

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

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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 interim goodwill tests as of November 30, 2015 and December 31, 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.

Income Taxes: Deferred income taxes are recorded for timing differences between items of income or expense reported in the financial statements and those reported for income tax purposes using the asset/liability method of accounting for income taxes. Deferred income taxes and tax benefits are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and for tax loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. We provide for deferred taxes for the estimated future tax effects attributable to temporary differences and carryforwards when realization is more likely than not. If we conclude that it is more likely than not that some portion, or all, of the net deferred tax asset will not be realized, the balance of net deferred tax assets is reduced by a valuation allowance.

We consider many factors in our evaluation of deferred tax assets, including the following sources of taxable income that may be available under the tax law to realize a portion or all of a tax benefit for deductible timing differences and carryforwards:

• Future reversals of existing taxable temporary differences,

• Taxable income in prior carry back years, if permitted,

• Tax planning strategies, and

• Future taxable income exclusive of reversing temporary differences and carryforwards.

Recently Adopted and Issued Accounting Pronouncements

See Note 1, Organization and Summary of Significant Accounting Policies , to the accompanying financial statements included elsewhere in this report for information regarding recently adopted and issued accounting pronouncements.

ITEM 7A.	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 75% of our revenue during four months ended December 31, 2015 was from the sale of oil. A $10 per barrel change in our realized oil price would have resulted in a $7.4 million change in revenues for the four months ended December 31, 2015 , while a $0.50 per Mcf change in our realized gas price would have resulted in a $1.7 million change in our natural gas revenues for the four months ended December 31, 2015 .

During the four months ended December 31, 2015 , the price of oil and natural gas declined significantly.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the levels of demand and supply for oil (in global or local markets), 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

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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.  We use derivative contracts to cover up to 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 December 31, 2015 , we had open crude oil derivatives in a net asset position with a fair value of $9.6 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 $0.6 million . 

Interest Rate Risk - At December 31, 2015 , we had debt outstanding under our bank credit facility totaling $78 million .  Interest on our 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 December 31, 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.  Historically, a decrease in the variable interest rates would not have a significant impact on us, as the bank credit facility had a minimum interest rate of 2.5%. As of January 28, 2016, the minimum interest rate was removed from the credit facility.  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% or decreased by 1% to an annual rate of 1.5%, our interest payments in the four months ended December 31, 2015 would have changed by approximately $0.3 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 four months ended December 31, 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 period as the amounts due to us from counterparties has increased.

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and supplementary data are filed with this Transition Report in a separate section following Part IV, as shown in the index on page F-1 of this Transition Report.

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.	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-K (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)

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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.

Management's Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our management, including Lynn A. Peterson, our Chief Executive Officer, and James P. Henderson, our Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2015 based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, or the “COSO Framework.”  Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2015.

Attestation Report of Registered Public Accounting Firm

        The attestation report required under this Item 9A is set forth under the caption "Report of Independent Registered Public Accounting Firm," which is included with the financial statements and supplemental data required by Item 8.

ITEM 9B.	OTHER INFORMATION

None.

PART III

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Executive Officers and Directors

Our executive officers and directors are listed below. Our directors are generally elected at our annual shareholders’ meeting and hold office until the next annual shareholders’ meeting or until their successors are elected and qualified.  Our executive officers are appointed by the Board and serve at its discretion.

 

Name		Age		Position
Lynn A. Peterson		63		President, Chief Executive Officer, and Director
James P. Henderson		50		Executive Vice President, Chief Financial Officer, and Treasurer
Frank L. Jennings		65		Chief Accounting Officer
Craig D. Rasmuson		48		Chief Operating Officer
Edward Holloway		64		Director
William E. Scaff, Jr.		59		Director
Rick A. Wilber		69		Director
Raymond E. McElhaney		59		Director
Bill M. Conrad		59		Director (through March 1, 2016)
R.W. Noffsinger, III		41		Director
George Seward		65		Director (through February 1, 2016)
Jack N. Aydin		75		Director
Daniel E. Kelly		57		Director

Lynn A. Peterson – Mr. Peterson joined Synergy in May 2015 and currently serves the Chairman of the board of directors, President, and the Chief Executive Officer. He was a co-founder of Kodiak Oil & Gas Corporation (“Kodiak”) and served Kodiak as a director (2001-2014), President and Chief Executive Officer (2002-2014), and Chairman of the Board (2011-2014) until its acquisition by Whiting Petroleum Corporation in December 2014. Mr. Peterson served as a director of Whiting Petroleum

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Corporation from December 2014 to June 2015. Mr. Peterson has over 30 years of industry experience. Mr. Peterson was an independent oilman from 1986 to 2001 and served as Treasurer of Deca Energy from 1981 to 1986. He graduated from the University of Northern Colorado with a Bachelor of Science in Accounting.

James P. Henderson – Mr. Henderson joined Synergy in August 2015 and currently serves as an Executive Vice President and Chief Financial Officer. He was the Chief Financial Officer of Kodiak from 2007 to 2014 until its acquisition by Whiting Petroleum Corporation in December 2014. Mr. Henderson has over 25 years of industry experience and holds a Bachelor’s degree in Accounting from Texas Tech University and a Master of Business Administration degree from Regis University.

    

Craig D. Rasmuson  – Mr. Rasmuson joined Synergy in September 2008 and currently serves as our Chief Operating Officer. Prior to joining Synergy, Mr. Rasmuson worked with DCP Midstream from May 2006 to January 2008 as its Right-of-Way Agent and for PDC Energy from January 2008 to September 2008 as its Field Landman. Mr. Rasmuson has worked in the DJ Basin since 2006.

Frank L. Jennings  – Mr. Jennings began his service as our Chief Financial Officer on a part-time basis in June 2007.  In March 2011, he joined us on a full-time basis. He became our Chief Accounting Officer in August 2015.  From 2001 until 2011, Mr. Jennings was an independent consultant providing financial accounting services, primarily to smaller public companies.  From 2006 until 2011, he also served as the Chief Financial Officer of Gold Resource Corporation (NYSE MKT: GORO).  From 2000 to 2005, he served as the Chief Financial Officer and a director of Global Casinos, Inc., and from 1994 to 2001 he served as Chief Financial Officer of American Educational Products, Inc. (NASDAQ: AMEP), before it was purchased by Nasco International.  After his graduation from Austin College with a degree in economics and from Indiana University with an MBA in finance, he joined the Houston office of Coopers & Lybrand.  He also spent four years as the manager of internal audit for The Walt Disney Company.

Edward Holloway  – Mr. Holloway has been a director of the Company since September 2008. Mr. Holloway was also an officer of Synergy between September 2008 and December 2015 and an officer and director of our predecessor between June 2008 and September 2008.  Mr. Holloway co-founded Cache Exploration Inc., an oil and gas exploration and development company.  In 1987, Mr. Holloway sold the assets of Cache Exploration to LYCO Energy Corporation.  He rebuilt Cache Exploration and sold the company to Southwest Production a decade later.  In 1997, Mr. Holloway co-founded (along with Mr. Scaff), and since that date has co-managed, Petroleum Management, LLC (“PM LLC”), a company engaged in the distribution of gasoline and related operations.  In 2001, Mr. Holloway co-founded (along with Mr. Scaff), and since that date has co-managed, Petroleum Exploration and Management, LLC (“PEM LLC”), a company which owns overriding royalties and mineral interests.  Mr. Holloway holds a degree in Business Finance from the University of Northern Colorado and is a past president of the Colorado Oil and Gas Association.

William E. Scaff, Jr.  – Mr. Scaff has been a director of the Company since September 2008. Mr. Scaff was also an officer of Synergy between September 2008 and December 2015 and an officer and director of our predecessor between June 2008 and September 2008.  Between 1980 and 1990, Mr. Scaff oversaw financial and credit transactions for Dresser Industries, a Fortune 50 oilfield equipment company.  Immediately after serving as a regional manager with TOTAL Petroleum between 1990 and 1997, Mr. Scaff co-founded (along with Mr. Holloway), and since that date co-managed, PM LLC.  In 2001, Mr. Scaff co-founded (along with Mr. Holloway), and since that date has co-managed, PEM LLC.  Mr. Scaff holds a degree in Finance from the University of Colorado.

Rick A. Wilber  – Mr. Wilber has been one of our directors since September 2008.  Since 1984, Mr. Wilber has been a private investor in, and a consultant to, numerous development stage companies.  In 1974, Mr. Wilber was co-founder of Champs Sporting Goods, a retail sporting goods chain, and served as its President from 1974-1984.  He has been a director of Ultimate Software Group Inc. since October 2002 and serves as a member of its audit and compensation committees.  Mr. Wilber was a director of Ultimate Software Group between October 1997 and May 2000.  He served as a director of Royce Laboratories, Inc., a pharmaceutical concern, from 1990 until it was sold to Watson Pharmaceuticals, Inc. in April 1997 and was a member of its compensation committee. Mr. Wilber graduated from the United States Military Academy at West Point.

Raymond E. McElhaney  – Mr. McElhaney has been one of our directors since May 2005.  Since January 2013, he has been the President of Longhorn Investments, LLC, a private financial company. From 1990 until December 2012, he was the President of MCM Capital Management Inc., a privately held financial management company.  Mr. McElhaney is a seasoned executive with numerous appointments, directorships and consulting roles with both private and public companies in a variety of industries and business sectors.  Mr. McElhaney has a strong background in oil and gas exploration and management and was a former officer and director of Wyoming Oil and Minerals and a director of United States Exploration, Inc., both publicly traded companies. Mr. McElhaney was a managing partner of Waco Pipeline, a natural gas gathering system. Over the course of his career, Mr. McElhaney has advised companies on M&A and equity transactions, commercial finance transactions, stock offerings,

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spinoffs and joint venture arrangements. Mr. McElhaney received his Bachelor of Science Degree in Business Administration from the University of Northern Colorado in 1978.

Bill M. Conrad  – Mr. Conrad was one of our directors from May 2005 until the effective date of his resignation on March 1, 2016. In addition, prior to the acquisition of our predecessor, he was our Vice President and Secretary.  Mr. Conrad has been involved in several aspects of the oil and gas industry over the past 30 years.  From February 2002 until June 2005, Mr. Conrad served as president and a director of Wyoming Oil & Minerals, Inc., and from 2000 until April 2003, he served as vice president and a director of New Frontier Energy, Inc.  Since June 2006, Mr. Conrad has served as a director of Gold Resource Corporation (NYSE MKT: GORO), a publicly traded corporation engaged in the mining industry and PetroShare Corp (OTCQB: PRHR).  In 1990, Mr. Conrad co-founded MCM Capital Management Inc. and served as its vice president until December 2012.

R.W. “Bud” Noffsinger, III  –  Mr. Noffsinger has been a director since September 2009.  Mr. Noffsinger has been the President/CEO of RWN3 LLC, a company involved with quantitative modeling and private equity investment, since February 2009.  Previously, Mr. Noffsinger was the Regional President (2005 to 2009) and Chief Credit Officer (2008 to 2009) of First Western Trust Bank.  Prior to his association with First Western, Mr. Noffsinger was a manager of Centennial Bank of the West (now Guaranty Bank and Trust).  Mr. Noffsinger has expertise as a financial service executive in the areas of development, commercial real estate, agriculture, and natural resources.  Since 2008, Mr. Noffsinger has served as a Director of NCMC, Inc., a 501(c)(3) organization.  Mr. Noffsinger is the Vice-Chair of NCMC, Inc. and serves on the Executive Committee and the Finance Committee.  Mr. Noffsinger is currently a member of the University of Northern Colorado Monfort College of Business Advisory Board and is a former member of the University of Wyoming College of Business Advisory Board.  Mr. Noffsinger is a graduate of the University of Wyoming and holds a Bachelor of Science degree in Economics with an emphasis on natural resources and environmental economics.

George Seward –  Mr. Seward was appointed as one of our directors in July 2010. Mr. Seward co-founded Prima Energy in 1980 and served as its Secretary until 2004, when Prima was sold to Petro-Canada. Since March 2006, Mr. Seward has been the President of Pocito Oil and Gas, a production company with operations in northeastern Colorado, southwestern Nebraska and Barber County, Kansas.  Mr. Seward has also operated a diversified farming operation in southwestern Nebraska and northeastern Colorado, since 1982. Mr. Seward resigned as a director effective February 1, 2016.

Jack N. Aydin   – Mr. Aydin was appointed as one of our directors on July 2, 2014.  Mr. Aydin was employed as an analyst by KeyBanc Capital Markets from 1973 through July 1, 2014, most recently serving as Senior Managing Director since April 2002.  With KeyBanc, Mr. Aydin concentrated his analyst coverage on integrated oil companies and the exploration and production sector and, for the latter part of his tenure, focused in particular on small to mid-cap exploration and production companies.  Mr. Aydin is a member of the National Association of Petroleum Investment Analysts, the Oil Analysts Group of New York, and the New York Society of Security Analysts.  Mr. Aydin holds an M.B.A. degree in finance and economics, as well as a Bachelor of Science degree in Business Administration, from Fairleigh Dickinson University in New Jersey, and a Bachelor of Science degree in Philosophy from St. Ephraim College in Mosul, Iraq.

Daniel E. Kelly - Mr.  Kelly was appointed as one of our directors on February 1, 2016. Mr. Kelly retired from Noble Energy, Inc. in March 2015, where he served as Vice President of Regional Strategy and Planning from June 2014 to March 2015. In that role, he focused on governmental and industry relations and community engagement in the DJ Basin, and served on Governor Hickenlooper’s task force on oil and gas development issues. He served as Noble’s Vice President of Operations for the DJ Basin from June 2008 to May 2014, and as a Business Unit Manager in the DJ Basin for Noble from January 2006 to May 2008. Prior to that, he served in various engineering, operational and management roles for Noble and other oil and gas companies beginning in 1982. He holds a B.S. in Petroleum Engineering from the Colorado School of Mines.

We believe Messrs. Holloway, Scaff, Peterson, McElhaney, Conrad, Seward, and Kelly are (or in the case of Messrs. Conrad and Seward, were) qualified to act as directors due to their experience in the oil and gas industry.  We believe Messrs. Wilber, Noffsinger and Aydin are qualified to act as directors as result of their experience in financial matters.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires the Company’s officers and directors, and persons who own more than 10% of a registered class of the Company’s equity securities, to file reports of ownership and changes in ownership with the SEC. Officers, directors and holders of more than 10% of the common stock are required by SEC rules to furnish the Company with copies of all Section 16(a) reports they file. If requested, the Company assists its officers and directors in complying with the reporting requirements of Section 16(a) of the Exchange Act.

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Based solely on a review of the reports furnished to the Company or on written representations from reporting persons that all reportable transactions were reported, the Company believes that, during the year ended August 31, 2015, the Company’s officers and directors and owners of more than 10% of the Company’s common stock timely filed all reports they were required to file under Section 16(a) of the Exchange Act.

Code of Ethics

In connection with its oversight of our operations and governance, the Board has adopted, among other things, a Code of Business Conduct and Ethics to provide guidance to directors, officers and employees with regard to certain ethical and compliance issues and charters of the Audit Committee and the Compensation Committee of the Board. Each of these documents can be viewed on our website at  www.syrginfo.com  under the heading “Investor Relations” and the subheading “Corporate Governance.” We will disclose on our website any amendment or waiver of the Code of Business Conduct and Ethics in the manner required by SEC and NYSE MKT rules. Copies of the foregoing documents and disclosures are available without charge to any person who requests them. Requests should be directed to Synergy Resources Corporation, Attn: Secretary, 1625 Broadway, Suite 300, Denver, Colorado 80202.

Nominating Committee

The Nominating Committee currently consists of Messrs. Wilber, McElhaney, Noffsinger, and Aydin, with Mr. Wilber acting as Chairman. The Nominating Committee’s primary functions are to identify, evaluate and recommend to the Board qualified candidates for election or appointment to the Board. The Nominating Committee does not have a written charter. The Board has determined that each member of the committee is independent under applicable NYSE MKT rules. During the year ended August 31, 2015, the Nominating Committee held no m eetings.

The Company does not have a formal policy regarding the consideration of director candidates recommended by shareholders; however, the Nominating Committee will consider candidates recommended by shareholders on the same basis as candidates proposed by other persons.  The Board believes that its process for assessing director candidates is appropriate at this time. Under Colorado law, any shareholder can nominate an individual as a director candidate at the annual shareholders’ meeting.  To submit a candidate for the Board, a shareholder should send the name, address and telephone number of the candidate, together with any relevant background or biographical information, to the Company’s Chief Executive Officer at 1625 Broadway, Suite 300, Denver, Colorado 80202.  The Board has not established any specific qualifications or skills a nominee must meet to serve as a director.  

The Nominating Committee does not have a formal policy with respect to the consideration of diversity when assessing directors and directorial candidates, but considers diversity as part of its overall assessment of the Board’s functioning and needs. The committee may retain a search firm to assist it in identifying potential candidates, but it has not done so to date.

Audit Committee

The Audit Committee currently consists of Messrs. Aydin, McElhaney and Noffsinger, with Mr. Noffsinger acting as Chairman. The primary function of the Audit Committee is to assist the Board in its oversight of our financial reporting process. Among other things, the committee is responsible for reviewing and selecting our independent registered public accounting firm and reviewing our accounting practices. The Board has determined that Mr. Noffsinger qualifies as an “audit committee financial expert” as defined in Item 407(d)(5) of SEC Regulation S-K and that each member of the committee is independent under applicable NYSE MKT and SEC rules.

Compensation Committee

The Compensation Committee currently consists of Messrs. Aydin, McElhaney, and Wilber, with Mr. Aydin acting as Chairman. The Compensation Committee’s primary function is to evaluate and approve the Company’s compensation plans and programs for officers, including our chief executive officer. The Company’s Board of Directors has adopted a written charter for the Compensation Committee, a copy of which can be found on the Company’s website at: www.syrginfo.com. The Board has determined that each member of the committee is independent under applicable NYSE MKT rules.

Compensation Committee Interlocks and Insider Participation 

We had no compensation committee interlocks with any other company during the Transition Period.

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ITEM 11.	EXECUTIVE COMPENSATION

Compensation Committee Report

The Compensation Committee of the Board of Directors of the Company has reviewed and discussed the following Compensation Discussion and Analysis with management and, based on its review and discussions, recommends its inclusion in this report.

COMPENSATION COMMITTEE MEMBERS:

Jack N. Aydin

Raymond E. McElhaney

Rick A. Wilber

Compensation Discussion and Analysis

Overview

Introduction

This Compensation Discussion and Analysis ("CD&A") outlines our executive compensation program for our named executive officers ("NEOs" or "Named Executive Officers") for the period from September 1, 2015 to December 31, 2015 (the “Transition Period”). In addition, the CD&A also contains some disclosure for our 2015 Fiscal Year (ending August 31, 2015), as well as some disclosure for calendar year 2016. We believe this additional disclosure helps to place in context the compensation of our NEOs for the Transition Period, particularly in light of the unique nature of the Transition Period and the significant changes we made to our executive compensation programs for calendar 2016 in response to the outcome of our recent "say-on-pay" proposal. This CD&A includes information on our compensation philosophy, how compensation decisions are made, the overall objectives of the Company’s compensation program, a description of the various components of compensation that are provided, and additional information pertinent to understanding the NEO’s compensation program. For a complete discussion on the compensation paid to the Named Executive Officers during Fiscal Year 2015 (ending August 31, 2015), please see the CD&A section of the Proxy Statement for the 2015 Annual Meeting of Shareholders (filed on November 9, 2015).

Our NEOs for the Transition Period were:

•	Edward Holloway, former Co-Chief Executive Officer (resigned effective December 31, 2015);

•	William E. Scaff, Jr., former Co-Chief Executive Officer and Treasurer (resigned effective December 31, 2015);

•	Lynn A. Peterson, President, and (effective January 1, 2016) Chairman and Chief Executive Officer;

•	James P. Henderson, Chief Financial Officer;

•	Frank L. Jennings, Chief Accounting Officer (has notified us that he would not be renewing his contract effective May 31, 2016); and

•	Craig D. Rasmuson, Chief Operating Officer.

2015 Stockholder Say-on-Pay Vote

We provide our stockholders with the opportunity to cast a non-binding advisory vote on the compensation of our NEOs. In December 2015, at our annual meeting of shareholders, based upon total shares voted, our stockholders did not approve our Named Executive Officers’ compensation, with approximately 49% voting in favor and approximately 50% voting against (with approximately 1% abstaining). The Compensation Committee takes the views of our stockholders seriously and their dissatisfaction with our existing executive compensation programs, as well as the issues that have been raised by certain proxy advisory firms with respect to historic pay agreements between the Company and its former executives that we believe are primarily responsible for the negative voting outcome. In response to the opinions of our stockholders and the issues raised with our historic pay agreements, the Company has undertaken a complete redesign of its executive compensation programs for calendar year 2016. The new compensation program is intended to address our stockholders’ concerns and the issues raised with our historic pay agreements, and was developed with the help of Compensation & Benefit Solutions, LLC ("CBS" or the "Compensation Consultant"), an independent executive compensation consulting firm hired directly by the Compensation Committee in late 2015 to assist the Compensation Committee in evaluating and redefining the Company’s future executive compensation policies and procedures. Based on the advice of CBS, the Company, through the Compensation Committee, implemented a 2016 compensation program more directly linked to Company performance and shareholder returns. Please see “Components of Compensation-

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Executive Officers” section below for details regarding the design and certain determinations made for our 2016 executive compensation program.

Executive Summary

Overview

The Compensation Committee has overall responsibility for the compensation program for our NEOs. The Compensation Committee reviews, adopts, and oversees our compensation strategy, policies, plans, and programs.

In evaluating executive officer pay, the Compensation Committee may retain the services of an independent compensation consultant or research firm and consider recommendations from our Chief Executive Officer and persons serving in managerial positions over a particular executive officer with respect to goals and compensation of the executive officer. Our Compensation Committee assesses the information it receives in accordance with its business judgment. All decisions with respect to executive compensation, other than compensation for our Chief Executive Officer, are first approved by our Compensation Committee and then submitted, together with the Compensation Committee’s recommendations, to our Board for final approval.

We choose to pay the various elements of compensation discussed in this CD&A in order to attract, retain, and motivate our high performing and well respected executive talent, reward annual performance, and to provide incentives for the achievement of intermediate and long-term strategic goals.

Leadership Changes

We experienced significant leadership changes during the Transition Period, which drove certain out of the ordinary compensation actions. On December 14, 2015, the board of directors accepted the resignations of Messrs. Holloway and Scaff, effective December 31, 2015. Pursuant to their resignations, the employment agreements with Messrs. Holloway and Scaff were terminated effective December 31, 2015. As part of the arrangement, Messrs. Holloway and Scaff entered into consulting agreements with the Company which provide that the former Co-CEOs would provide advice to Mr. Peterson on an as requested basis in the areas of acquisitions and special projects, or as otherwise requested by Mr. Peterson. In exchange for their services, the Company agreed to pay each $70,000 per month during the five-month period ending May 31, 2016, and each received title to the Company vehicle which was assigned to them at the time of resignation. In addition, in recognition of past services, Messrs. Holloway and Scaff were each awarded a $375,000 discretionary bonus, as well as 200,000 shares of common stock of the Company. Lastly, upon their resignations, all unvested equity awards held by Messrs. Holloway and Scaff were accelerated. Messrs. Holloway and Scaff will not be eligible to receive any additional compensation for any continued service on the board of directors following their resignations.

Additionally, on March 30, 2016, Mr. Jennings notified the Company that after his employment agreement expires on May 31, 2016, he will not continue his employment with the Company, including his position as the Chief Accounting Officer of the Company.

2015 Market and Industry Context

In the past year, the oil and gas industry has witnessed extraordinary volatility. Exploration and production focused companies in particular have experienced some of the worst of this volatility. Following a decline in oil and gas prices in 2014 of approximately 40% and 35%, respectively, oil and gas prices remained under pressure in 2015, largely related to foreign market pressures and strong domestic production. However, the Company believes that it remains well positioned even in such an uncertain market. The Company has grown its production at over a 100% compounded annual rate since 2011, while maintaining an efficient cost structure and low leverage profile. The Company’s focus remains the Wattenberg Field, and we continue to attract key talented individuals with deep and relevant experience operating in the field. The Company retains a high degree of operational and financial flexibility, generally allowing it to increase or decrease its activities at its own discretion.

Operational and Financial Highlights

The following are operational and financial highlights for the four months ended December 31, 2015:

•	Revenues decreased 36% to $34.1 million for the four months ended December 31, 2015, compared to $52.9 million for the same period of 2014;

•	Adjusted EBITDA for the four months ended December 31, 2015 was down 67% compared to the corresponding period of the prior year;

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•	As of December 31, 2015, the Company's cash and equivalents totaled $66.5 million , and it had $85 million available on its credit facility, as compared to $133.9 million and $85 million, respectively, at August 31, 2015;

•	For the four months ended December 31, 2015, net oil and natural gas production increased 28% to 1,320 MBOE, as compared to 1,029 MBOE in the same year ago period;

•

December 31, 2015 estimated proved reserves increased 17% to 26.4 million barrels of oil and 238.7 billion cubic feet of gas, or combined total 66.2 million BOE, compared to 56.7 million BOE as of August 31, 2015. The PV-10 value of the reserves is $438.1 million as of December 31, 2015, compared to $438.3 million at August 31, 2015. The commodity prices used to evaluate the reserves as of December 31, 2015 dropped 22% per barrel of oil and 21% per Mcf of gas from the prices used at August 31, 2015;

•	Total shareholder return ("TSR"), a measure of long-term shareholder performance, was (32)% over the past calendar year, 58% over the past three calendar years, and 199% over the past five calendar years, on average, placing the Company fifth among the peer group for three-year TSR and first among the peer group for five-year TSR during the period.

•	In May 2015, we hired Lynn A. Peterson as our new President (subsequently appointed Chairman and Chief Executive Officer effective January 1, 2016), and in August 2015, we hired James P. Henderson as our new Chief Financial Officer.

Link of Pay to Performance

The Company firmly believes in the "pay for performance" philosophy and as such, TSR is an important metric to the Board and management. The charts below display the three- and five-year TSR of Synergy (58% and 199%, respectively) as compared to the same metric for our 2016 peer group and to the S&P MidCap 400 Energy Index. These charts display the Company’s significant TSR performance in a period where much of the industry has seen a loss in shareholder value due to the impacts of external market factors. The TSR charts below reflect trading prices through December 31, 2015.

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Key Transition Period Compensation Actions

Based in part on the Company's strong performance during an otherwise tumultuous period for our industry, we took the following key compensation actions in the Transition Period:

•	Maintained executive salaries at current levels pending the conclusion of the Compensation Committee’s competitive compensation analysis;

•	Limited discretionary bonuses pending the adoption of a formal performance-based short-term incentive compensation program;

•	Granted stock options to our Chief Financial Officer pursuant to our onboarding compensation agreement with Mr. Henderson;

•	Granted restricted stock awards to our new Chief Executive Officer, Chief Financial Officer, Chief Operating Officer, and Chief Accounting Officer in recognition of superior performance and contributions during the Transition Period; and

•	Finalized payment arrangements for our outgoing Co-CEOs, including terminating their employment agreements and executing ongoing consulting agreements for future services in order to provide our new CEO with additional advice and experience regarding the Company’s operations, areas in which it operates, and potential acquisition opportunities.

Compensation Objectives

The Compensation Committee oversees the executive compensation program. Synergy’s executive compensation program is designed to align the interests of our NEOs with those of our shareholders in a way that allows us to attract, motivate and retain talented executives who will drive Company growth and create long-term shareholder value.

The Compensation Committee has established the following set of objectives for the executive compensation program:

•	The executive compensation program should provide fair and market-competitive compensation based upon the employee’s position, experience and individual performance while maintaining fiscal responsibility for shareholders;

•	A significant portion of the NEOs’ total compensation should be variable and should take into consideration the growth and profitability of the Company; and

•	Synergy’s compensation program also seeks to reward executive officers for increasing the Company’s stock price over the long-term by providing compensation opportunities for NEOs in the form of long-term equity awards, the amounts of which are subject to performance modifications in the event of inferior or superior performance by the Company.

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As such, the Compensation Committee retained the services of CBS to assist in the design of a compensation program that is more directly linked to shareholder return. As a result of the analysis, the Company has adopted an executive pay program that is detailed further below.

Compensation Philosophy

Following are the principal tenets of our executive officer compensation philosophy for 2016 and beyond.

We Pay for Performance

Based on this philosophy, a significant portion of our NEO’s compensation will be in the form of performance-based short-term cash incentives and shareholder return-based long-term equity incentives. Each of these incentives plays a role in aligning pay with the Company's performance and in aligning the long-term financial interests of our named executive officers with those of our stockholders. Each of these incentives is earned, or value from them is achieved, based on the performance of the Company and the executive.

We Pay Market Competitive Compensation

In order to pay market competitive compensation, the Compensation Committee considers compensation data from Synergy’s peer companies, and such data is an important reference point in the Compensation Committee’s decision making. While market data is an important reference point for the Compensation Committee, decisions regarding NEO compensation are made by analyzing a number of factors, of which market data is a single component. With respect to compensation decisions for 2016, the independent Compensation Consultant and the Compensation Committee searched for public companies in Synergy’s industry which are similar in size based on revenue, assets, net income, market capitalization and total enterprise value. Additional factors, such as geographical operations, complexity of operations, and other more subjective factors were also considered in the peer company selection process.

The following table includes the peer companies that will comprise the 2016 Compensation Peer Group which will be utilized by the Compensation Committee as part of prospective compensation decisions.

Abraxas Petroleum Corp.	Oasis Petroleum Inc.
Callon Petroleum Company	PDC Energy, Inc.
Carrizo Oil & Gas Inc.	Panhandle Oil and Gas Inc.
Diamondback Energy, Inc.	Parsley Energy
Eclipse Resources Corp	Rice Energy Inc.
Gulfport Energy Corp.	RSP Permian, Inc.
Halcon Resources Corporation	SM Energy Company
Laredo Petroleum, Inc.	Triangle Petroleum Corporation
Magnum Hunter Resources Corp.	WPX Energy, Inc.
Matador Resources Company	Whiting Petroleum Corp.
Northern Oil and Gas, Inc.

While Magnum Hunter Resources Corp. was part of the peer group for the Transition Period, the Compensation Committee ultimately decided to remove it from the peer group for all compensation evaluations going forward on account of the company’s ongoing bankruptcy proceedings.

Our Executive Compensation Programs Should Remain Flexible

To date, the rapidly growing nature of our business has demanded that we retain flexibility in assessing our NEOs' performance and in determining the appropriate rewards for that performance. Previously, this flexibility was embodied by a compensation structure that incorporated discretionary annual bonuses and ad-hoc long-term equity incentive awards. However, the Company has elected to transition into more structured incentive compensation programs as we continue to grow and implement more objective, pre-established performance goals and a more structured long-term incentive grant program that we believe will help drive sustainable, long-term performance. To this end, we have eliminated discretionary bonuses and ad-hoc long-term incentive equity grants for our NEOs, in favor of performance-based short-term and long-term incentive awards primarily based on objective, determinable criteria. Additionally, in order to maintain flexibility to ensure that executive compensation packages

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are continuously aligned with shareholder interests, the Compensation Committee has retained negative discretion to reduce any short-term or long-term incentive awards where the Compensation Committee feels that performance does not warrant payouts at the formulaically determined levels.

Tax and Accounting Consequences Should not Drive our Executive Compensation Programs

The Compensation Committee’s current focus is primarily to incentivize and reward performance that increases shareholder value and that supports the growth of the Company. Accordingly, our compensation programs are not largely driven by tax and accounting considerations. However, where appropriate, the Committee may consider the tax and accounting ramifications of the Company’s plans, arrangements and agreements. Specifically, Section 162(m) of the Internal Revenue Code of 1986, as amended, limits the amount of compensation in excess of $1,000,000 that the Company may deduct in any one year with respect to its chief executive officer and three other most highly compensated executive officers (excluding the chief financial officer) whose compensation must be included in this proxy statement because they are the most highly compensated executive officers. There are exceptions to the $1,000,000 limitation for performance-based compensation meeting certain requirements. The Company believes that it has satisfied all of the requirements for the performance-based short-term incentive and performance-based long-term incentive awards to qualify as "performance-based" within the meaning of Section 162(m), so that it is fully deductible by the Company without regard to the $1,000,000 limit.

Compensation Setting Process

Role of the Compensation Committee and Management in Setting Compensation

The Board has authorized the Compensation Committee to have primary oversight over the compensation of our NEOs. Our Chief Executive Officer (and previously, our Co-CEOs) also plays an important role in the executive compensation process, in overseeing the performance and dynamics of the executive team and generally keeping the Compensation Committee informed of business objectives and the performance of the NEOs other than himself. The Compensation Committee independently reviews and evaluates the performance of the executive team in light of the recommendations made by the Chief Executive Officer. As such, all final approvals regarding the NEOs’ compensation remain with the Compensation Committee. Finally, the Compensation Committee may retain an independent consulting firm and/or legal counsel experienced in executive and overall compensation practices and policies to assist the Compensation Committee in calibrating the form and amount of executive compensation.

Role of the Compensation Consultant

While the Company did not rely on the Compensation Consultant in making fiscal 2015 compensation decisions, the Company engaged the Compensation Consultant to assist with a thorough review of the Company’s executive compensation practices, and to design and implement a pay-for-performance oriented compensation program for the Company’s NEOs and other executive officers. The information provided by the Compensation Consultant was utilized by the Compensation Committee in adjusting compensation packages for the Transition Period as well as setting the compensation programs for 2016.

For 2016 compensation, CBS assisted us in the process of designing a new compensation program, which included:

•	Base salaries for the executives which are at market competitive levels and consistent with Synergy’s compensation philosophy;

•	A formal short-term incentive plan with clearly defined financial and individual metrics, award opportunities, and direct linkage between earned compensation and Company performance;

•	A revised long-term incentive plan comprised of equity awards which are primarily performance-based, to better align executive compensation with Synergy’s long-term goals and objectives;

•	Elimination of compensation decisions based either solely on subjective performance assessments, or solely based on certain historical Company metrics, such as well-completions; and

•	Retention of negative discretion by the Compensation Committee for both short-term and long-term incentive awards in order to ensure payouts are aligned with actual Company performance.

Review of Executive Officer Compensation

Our review of executive officer compensation encompasses both the structure of our executive compensation program and the targeted amount of compensation. When making compensation decisions, the Compensation Committee considered multiple sources of internal and external data. However, because comparative compensation information is just one of the several analytical tools that we used in setting executive compensation, the Compensation Committee utilizes its judgment in determining the nature and extent of its use of comparative companies. When exercising its discretion, the Compensation Committee may

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consider factors such as the nature of the officer’s duties and responsibilities as compared to the corresponding position in the peer companies, the experience and value the executive brings to the role, the executive’s performance results, the success demonstrated in meeting financial and other business objectives, the relationship of compensation earned compared to Company performance, and the impact on the internal equity of our pay structure within our Company.

Timing of Compensation Decisions

The Compensation Committee reviews NEO compensation at different times throughout each year. Going forward, the Company has determined to implement an annualized compensation setting process (aside from certain circumstances that might require intermediate activity). For example, the Company intends to review base salaries and target incentive awards at the beginning of each calendar year, with performance criteria established prior to the end of the first quarter of the Company’s new fiscal year. Following completion of the fiscal year (or performance period, as applicable), the Company will determine the short-term incentive cash payouts for the NEOs. Additionally, following completion of the applicable performance period for long-term equity incentive awards, the Company will determine what portion, if any, of such awards will be deemed earned and vested. In addition, the Compensation Committee will review compensation on an as needed basis, including when new employees are hired, existing employees are promoted, or when other factors it deems relevant merit a compensation review.

Components of Compensation-Named Executive Officers

The Company’s executive compensation program has three components: base salary, annual cash-based short-term incentive awards, and long-term equity compensation. In addition to the cash and equity components of compensation, the NEOs also participate in the Company’s health and retirement benefits programs.

Base Salaries

Base salary is designed to compensate our NEOs at a fixed level of compensation that provides some financial certainty and security for our NEOs, and also serves as a retention tool throughout the executive’s career. In determining base salaries, our Compensation Committee considers many things, including each executive’s role and responsibilities with the Company, unique skills, base salary at the executive's existing employer, future potential with the Company, salary levels for similar positions in our market and internal pay equity.

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The Company took the following actions with respect to NEO base salaries for the year ended August 31, 2015, and they remained in effect for the Transition Period:

EXECUTIVE	DATE	SALARY ACTION	REASON FOR ACTION
Mr. Holloway	November 1, 2014	Base salary was increased to $999,900 per employment contract year (June 1 - May 31), beginning June 1, 2015.	Base salary was increased due to continued outstanding performance, long tenure with the Company, exceptional positioning of the Company despite prevailing market forces, a history of creating high levels of shareholder return, and payment of a 2014 bonus over a twelve month period.
Mr. Scaff, Jr.	November 1, 2014	Base salary was increased to $999,900 per employment contract year (June 1 - May 31), beginning June 1, 2015.	Base salary was increased due to continued outstanding performance, long tenure with the Company, exceptional positioning of the Company despite prevailing market forces, a history of creating high levels of shareholder return, and payment of a 2014 bonus over a twelve month period.
Mr. Peterson	May 27, 2015	Base salary was set at $600,000 per year upon hiring.	Mr. Peterson joined the Company on May 27, 2015. His base salary was set giving consideration to his skill set and fit within the Company, his current and future potential within the Company, and market conditions, while providing adequate incentive to induce him to work at the Company.
Mr. Henderson	August 24, 2015	Base salary was set at $375,000 per year upon hiring.	Mr. Henderson joined the Company on August 24, 2015. His base salary was set giving consideration to his skill set and fit within the Company, his current and future potential within the Company, and market conditions, while providing adequate incentive to induce him to work at the Company.
Mr. Rasmuson	February 1, 2015	Base salary was increased to $325,000 per year	Base salary was increased due to continued outstanding performance, long tenure with the Company, exceptional positioning of the Company despite prevailing market forces, and a history of creating high levels of shareholder return.
Mr. Jennings	March 7, 2015	Base salary was increased to $275,000 per year	Base salary was increased due to continued outstanding performance, long tenure with the Company, exceptional positioning of the Company despite prevailing market forces, and a history of creating high levels of shareholder return.

Following the completion of the compensation analysis conducted by CBS, the Company increased Mr. Petereson's base salary slightly, from $600,000 to $610,000 per year, effective April 1, 2016.

Short-Term Incentive ("STI") Compensation

Annual cash-based STI awards are designed to incentivize our NEOs, through a variable compensation program based on the Company’s as well as the individual’s performance. Previously, our annual STI program was managed at the discretion of the Compensation Committee based on its review of both Company and the individual performance of each NEO during the fiscal year. Going forward, STI compensation awards will be set and determined according to mostly objective performance metrics. As stated above, based on the analysis provided by CBS, the Company decided to adopt an objective, performance-based STI program for 2016 and future years.

Transition Period STI Compensation

In December 2015, based on the data and analysis provided by the Compensation Consultant, the Compensation Committee awarded discretionary annual bonuses of $375,000 to each of Messrs. Holloway, Scaff, and Peterson for the Transition Period in recognition of past services and superior performance, including helping guide the Company through the leadership transition.

2016 STI Compensation Program

Beginning with the 2016 STI awards, award targets will be set as a percentage of each NEO’s base salary, with threshold and maximum opportunities available depending upon performance against the pre-established performance criteria.

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Target STI awards for the NEOs will be set as follows:

Title	Target STI as % of Base Salary
CEO & Chairman	100%
CFO	85%
COO	50%

Threshold performance will result in payouts equal to 50% of target, while maximum performance will result in payouts equal to 200% of target. Performance in between payout levels will result in pro-rated payouts. Performance below the threshold level will result in no payouts. Additionally, the Compensation Committee will retain negative discretion to downward adjust any payouts if, in the Compensation Committee’s sole discretion, it is believed that Company performance does not warrant a payout at the determined level.

Each STI award to be earned will be based on the following metrics and weightings:

Performance Metrics	Metric Weight %
Production	20%
Adjusted EBITDA	25%
Proved Reserves	20%
Individual Objectives	25%
Safety	10%

Long-Term Incentive ("LTI") Compensation

Previously, our LTI program consisted of periodic grants of time vested stock options, with an exercise price equal to the fair market value of our common stock on the date of grant, as well as grants of time vested restricted stock. Time-vested equity awards were designed to focus our NEOs on our long-term goals and enhancement of stockholder value, and provide rewards for achievement of these goals through equity awards that increase based on increases in the Company’s stock value. Decisions made regarding the timing and size of grants took into account our performance and that of the employee, the overall financial health of the Company, as well as competitive market practices and the size of the grants made in prior years. The weighting of these factors varied and was subjective. As stated above, based on the analysis provided by CBS, the Company decided to adopt a performance-based LTI program for all awards beginning in 2016, the details of which are described further below.

Transition Period LTI Awards

Prior to the implementation of the newly designed LTI program, the Company made selected equity grants to fulfill commitments made as part of the onboarding of our new NEOs, as well as contributions of the new NEOs during the Transition Period. Consistent with prior practices, these awards were made in the form of stock options and restricted shares of our common stock.

In December 2015, we made the following LTI compensation grants to our NEOs:

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The Board granted Mr. Peterson 100,000 restricted stock units (RSUs) of the Company, with the RSUs scheduled to vest in three equal installments beginning on December 31, 2015 if Mr. Peterson remains employed with the Company through this period. These RSUs were granted for past services during the Transition Period and in recognition of superior performance, including guiding the Company through the leadership transition as well as an incentive for future performance and retention.

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The Board granted Mr. Henderson 150,000 stock options to purchase shares of the Company’s common stock, with an exercise price of $10.01 per share, with the options scheduled to vest in five equal annual installments. The first installment vested on December 15, 2015 and the remaining installments will vest beginning on August 24, 2016 and each year thereafter if Mr. Henderson remains employed with the Company through this period. These options were granted as part of the arrangement made with Mr. Henderson upon his hire as disclosed on August 28, 2015.

•	The Compensation Committee granted Mr. Henderson 25,000 RSUs of the Company, with the underlying shares scheduled to vest equally over a three-year period beginning on December 28, 2015 if Mr. Henderson remains

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employed with the Company through this period. These RSUs were granted for past services during the Transition Period and in recognition of superior performance, including guiding the Company through the leadership transition as well as an incentive for future performance and retention.

•

The Board ratified a grant to Mr. Henderson of 75,000 RSUs of the Company, with the RSUs scheduled to vest in five equal annual installments. The first installment vested on December 15, 2015 and the remaining installments will vest beginning on August 24, 2016 and each year thereafter if Mr. Henderson remains employed with the Company through this period. These awards were granted as part of the arrangement made with Mr. Henderson upon his hire as disclosed on August 28, 2015.

•

The Compensation Committee granted Mr. Rasmuson 40,500 RSUs of the Company, with the RSUs scheduled to vest equally over a three-year period beginning on December 28, 2015 if Mr. Rasmuson remains employed with the Company through this period. These RSUs were granted for past services during the Transition Period and in recognition of superior performance, including guiding the Company through the leadership transition as well as an incentive for future performance and retention.

•

The Compensation Committee granted Mr. Jennings 15,000 RSUs of the Company, with the RSUs scheduled to vest equally over a three-year period beginning on December 28, 2015 if Mr. Jennings remains employed with the Company through this period. These RSUs were granted for past services during the Transition Period and in recognition of superior performance, including guiding the Company through the leadership transition. Mr. Jennings announced his intention not to renew his contract with the Company effective May 31, 2016, and as such, these RSUs will vest at that time.

2016 LTI Compensation Program

The Company believes that performance-based equity awards that are directly tied to shareholder return should be a significant portion of the LTI program going forward. However, the Company also recognizes the retentive value of time-based awards, and believes that a well-rounded LTI compensation program is both linked to shareholder return, while also providing the NEOs with a level of financial security so as to avoid incentivizing excessive risk taking. As such, the Company has designed and implemented a new structure for all equity awards granted in 2016.

Under the new structure, each NEO will be eligible for a target award value based on a percent of base salary.

Target LTI awards for the NEOs will be determined as follows:

Title	Target LTI as % of Base Salary
CEO & Chairman	375%
CFO	200%
COO	125%

Thirty percent of the target annual award value will be granted in the form of time-based restricted stock units ("RSUs") which will vest in equal installments on each of the first three anniversaries of the grant date if the NEO remains employed with the Company through the applicable service period. The remaining 70% of the target annual equity award will be comprised of performance-based RSUs ("PSUs") which will be subject to a three-year performance period. The PSUs will vest, if at all, based on the Company’s TSR relative to a selected peer group of companies (i.e., Relative TSR) over the performance period. The peer group of companies used for determining the PSU payouts is not necessarily the same as the peer group utilized as part of the compensation determination process, although it is the Company’s intent that the PSU peer group will be comprised of companies that make up the compensation peer group.

With regards to the PSUs, performance at threshold levels will result in 50% of the target number of shares vesting, while performance at maximum levels will result in 200% of the target number of shares vesting. Further, should TSR for the Company be negative at the end of the performance period, vesting of awards will be limited to the target number of shares, irrespective of how the Company’s TSR compares to the TSR of the selected peer group companies. Finally, the Compensation Committee will retain negative discretion to downward adjust the amount of an award that will vest should the Committee, in its sole discretion, believe that Company performance does not warrant vesting at the determined levels.

Benefits

In addition to cash and equity compensation programs, NEOs participate in the health insurance programs available to the Company’s employees. All NEOs are eligible to participate in the Company’s 401(k) plan on the same basis as all other employees. The Company's contributions to the 401(k) plan consist of a discretionary matching contribution equal

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to  100% of compensation deferrals not to exceed 3% of eligible compensation plus 50% of compensation deferrals in excess of 3% of eligible compensation not to exceed more than 5% of eligible compensation. We do not have a defined benefit pension plan, profit sharing, or other retirement plan.

Executive Share Ownership Requirements

In 2016, the board of directors adopted Share Ownership Requirements for the Company’s NEOs and Vice Presidents. Required ownership ranges from 1 times to 6 times base salary. Qualified holdings include stock owned directly, as well as unvested time-based restricted stock. The value of the shares held to determine if the ownership guidelines are met is measured on April 1 each year, as the average of the month end closing price for the 12 months preceding the date of calculation. Applicable executives will have a five year phase-in period in which to meet the ownership requirements. Below are the specific guidelines for the Company’s NEOs:

Position	Required Ownership as a Multiple of Base Salary
CEO	6x
Other NEOs	3x
Vice Presidents	1x

Anti-Hedging, Anti-Pledging Policy

The Company adopted a policy to expressly prohibit directors and officers from pledging Company securities as collateral or engaging in any hedging or monetization transaction related to the Company securities.

Compensation Risks

We believe that risks arising from our compensation policies and practices for our employees are not reasonably likely to have a material adverse effect on the Company. In addition, the Compensation Committee believes that the mix and design of the elements of executive compensation do not encourage management to assume excessive risks.

The Compensation Committee reviewed the elements of executive compensation to determine whether any portion of the executive compensation package encouraged excessive risk taking and concluded:

•

Significant weighting toward incentive compensation provides a heavy incentive for the executive officers to produce value for shareholders. At the same time, providing market-based, sizeable cash base salaries for the executive officers helps avoid unreasonable risk-taking by the executive team by ensuring that they are not entirely dependent on achieving incentive compensation in order to attain a significant but market-based cash compensation levels;

•	Goals are appropriately set to avoid targets that, if not achieved, result in an unreasonably large percentage loss of compensation;

•	Incorporating a time-based vesting component for a portion of the annual long-term incentive awards to provide the NEOs with a measure of security to avoid incentivizing excessive risk-taking solely in order to drive the value of their incentive award payouts; and

•	The Compensation Committee should retain negative discretion for both STI and LTI awards in order to ensure payouts are aligned with actual Company performance.

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Executive Compensation Tables

Summary Compensation Table

The following table shows the compensation paid or accrued to our NEOs for the Transition Period ("TP") and three most recently completed fiscal years of the Company.

Name and Principal Position	Fiscal Year	Salary ($)				Bonus ($) 5			Non-Equity Incentive Plan Compensation 6			Stock Awards 7			Option Awards 8			All Other Compensation 9			Total
Edward Holloway 10	TP	$	319,612			$	375,000		—			$	2,000,000		—			$	1,000		$	2,695,612
Former Co-Chief Executive Officer	2015	$	1,197,000		4	$	350,000		$	600,000		—			—			$	10,400		$	2,157,404
	2014	$	450,000			$	320,000		$	400,000		$	819,600		—			$	10,000		$	1,999,600
	2013	$	330,000			$	200,000		—			—			—			$	10,000		$	540,000
William E. Scaff, Jr. 10	TP	$	319,613			$	375,000		—			$	2,000,000		—			$	1,000		$	2,695,613
Former Co-Chief Executive Officer, Treasurer	2015	$	1,197,000		4	$	350,000		$	600,000		—			—			$	10,400		$	2,157,404
	2014	$	450,000			$	320,000		$	400,000		$	819,600		—			$	10,000		$	1,999,600
	2013	$	330,000			$	200,000		—			—			—			$	10,000		$	540,000
Lynn A. Peterson 1	TP	$	200,000			$	375,000		—			$	1,001,000		—			$	8,975		$	1,584,975
President, Chairman and Chief Executive Officer	2015	$	150,000			$	250,000		—			$	2,865,000		$	9,699,023		—			$	12,964,023
James P. Henderson 2	TP	$	125,000			$	126,000		—			$	220,500		$	779,323		$	9,080		$	1,259,903
Chief Financial Officer	2015	$	8,654			—			—			$	727,500		—			—			$	736,154
Craig D. Rasmuson 3	TP	$	104,167			$	206,250		—			$	357,210		—			$	6,000		$	673,627
Chief Operating Officer	2015	$	264,584			$	250,000		—			$	489,200		—			$	10,400		$	1,014,184
	2014	$	203,623			$	50,000		—			$	518,400		$	653,473		$	10,000		$	1,435,496
Frank L. Jennings 11	TP	$	91,668			$	100,000		—			$	132,300		—			$	6,755		$	330,723
Chief Accounting Officer	2015	$	262,506			$	200,000		—			$	228,800		—			$	10,400		$	701,706
Former Chief Financial Officer	2014	$	215,000			$	90,000		—			$	648,000		—			$	10,000		$	963,000
	2013	$	180,000			—			—			—			—			$	7,000		$	187,000

1	Mr. Peterson was appointed as President on May 27, 2015, and Chairman and Chief Executive Officer effective January 1, 2016.

²     Mr. Henderson was appointed as the Chief Financial Officer on August 24, 2015.

³     Mr. Rasmuson was appointed as Chief Operating Officer on January 22, 2014.

4

On October 24, 2014 the Compensation Committee adjusted the base salaries of Mr. Holloway and Mr. Scaff with the intention of providing them with base salary for their employment contract year of June 1, 2014 through May 31, 2015 of $990,900, as well as for each employment contract year thereafter. Due to an interpretive error, the adjustment was applied incorrectly for the employment contract year beginning June 1, 2015 - May 31, 2016, resulting in base salary for the period June 1, 2015 through August 31, 2015 exceeding the pro-rata portion of the $990,900 annual base salary that should have been paid during such period. In order to correct the error, the base salaries of each of Mr. Holloway and Mr. Scaff were reduced through December 31, 2015 so that their base salaries for the June 1, 2015 - May 31, 2016 employment contract year would have equaled the intended amount of $990,900.

5	"Bonus" column includes discretionary annual bonuses as well as the signing bonus paid to Mr. Peterson upon his appointment as President.

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^6    " Non-Equity Incentive Plan Compensation" includes well completion bonuses paid to Mr. Holloway and Mr. Scaff.

7	Represents the grant date fair value of stock issued for services computed in accordance with ASC 718 on the date of grant. Please see Note 12 to the Company’s financial statements for information regarding the principles used to calculate the grant date fair values set forth above.

8	Represents the grant date fair value of options granted computed in accordance with ASC 718 on the date of grant. Please see Note 12 to the Company’s financial statements for information regarding the principles used to calculate the grant date fair values set forth above.

9	"All Other Compensation" includes compensation received that we could not properly report in any other column of the table. These amounts represent the Company matching contribution to the Company’s 401(k) Plan.

10	Messrs. Holloway and Scaff resigned from their positions as Co-Chief Executive Officers effective December 31, 2015.

11	Mr. Jennings has notified the Company that after his employment agreement expires on May 31, 2016, he will not continue his employment with the Company, including his position as the Chief Accounting Officer.

Grants of Plan-Based Awards

The following table provides information for each of our NEOs regarding annual and LTI award opportunities granted in the Transition Period:

		Estimated Possible Payouts Under Non‑Equity Incentive Plan Awards							Estimated Future Payouts Under Equity Incentive Plan Awards						All Other Stock Awards: Number of Shares of Stock or Units (#)			All Other Option Awards: Number of Securities Underlying Options (#)			Exercise or Base Price of Option Awards ($/Sh)		Grant Date Fair Value of Stock and Option Awards ($) 3
Name	Grant Date	Threshold ($)		Target ($)		Maximum ($)			Threshold (#)		Target (#)		Maximum (#)
Mr. Holloway	12/14/2015	—		—		—			—		—		—		200,000		1	—			—		$	2,000,000
Mr. Scaff, Jr.	12/14/2015	—		—		—			—		—		—		200,000		1	—			—		$	2,000,000
Mr. Peterson	12/15/2015	—		—		—			—		—		—		100,000		1	—			—		$	1,001,000
Mr. Henderson	8/24/2015	—		—		—			—		—		—		75,000		2	—			—		$	727,500
	12/15/2015	—		—		—			—		—		—		—			150,000		1	10.01		$	779,323
	12/28/2015	—		—		—			—		—		—		25,000		1	—			—		$	220,500
Mr. Rasmuson	12/28/2015	—		—		—			—		—		—		40,500		1	—			—		$	357,210
Mr. Jennings	12/28/2015	—		—		—			—		—		—		15,000		1	—			—		$	132,300

1	The amounts shown reflect RSUs grants made to Mr. Peterson, Mr. Henderson, Mr. Rasmuson, and Mr. Jennings in December 2015. See "Compensation Discussion and Analysis" above for additional information about these equity awards.

2	The awards reported for Mr. Henderson reflect onboarding grants of stock bonus shares and stock options awarded to Mr. Henderson in December 2015 pursuant to the commencement of his employment and appointment as Chief Financial Officer. See "Compensation Discussion and Analysis" above for additional information about these equity awards.

3	Represents the grant date fair value of options, RSUs, and stock bonus shares granted, computed in accordance with ASC 718 on the date of grant. Please see Note 12 to the Company’s financial statements for information regarding the principles used to calculate the grant date fair values set forth above.

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Outstanding Equity Awards at Fiscal Year End

The following table sets forth information regarding options, unvested restricted stock units, and unvested stock bonus shares held by our NEOs as of December 31, 2015. Market values for outstanding stock awards are presented as of December 31, 2015 based on the closing price of our common stock on the NYSE MKT on December 31, 2015 of $8.52.

	Option Awards									Stock Awards
Name	Grant Date	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable		Option Exercise Price ($)			Option Expiration Date		Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested ($) 1			Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Unit or Other Rights That Have Not Vested ($)
Mr. Peterson	5/27/2015	350,000	1,400,000	2	$	11.46		5/27/2025		—		—			—		—
	5/27/2015	—	—		—			—		200,000	3	$	1,704,000		—		—
	12/28/2015	—	—		—			—		66,666	4	$	567,994		—		—
Mr. Henderson	8/24/2015	—	—		—			—		60,000	5	$	511,200		—		—
	12/15/2015	30,000	120,000	6	$	10.01		12/15/2015		—		—
	12/28/2015	—	—		—			—		16,667	4	$	142,003		—		—
Mr. Rasmuson	12/31/2008	30,000	—		$	3.00		12/31/2018		—		—			—		—
	9/27/2010	20,000	—		$	2.40		9/27/2020		—		—			—		—
	9/22/2011	60,000	20,000	7	$	2.80		9/22/2021		—		—			—		—
	9/22/2012	75,000	25,000	8	$	3.67		9/22/2022		—		—			—		—
	9/22/2013	40,000	60,000	9	$	9.63		9/22/2023		—		—			—		—
	2/1/2014	—	—		—			—		40,000	10	$	340,800		—		—
	2/1/2015	—	—		—			—		40,000	11	$	340,800		—		—
	12/28/2015	—	—		—			—		27,000	4	$	230,040		—		—
Mr. Jennings	3/7/2011	150,000	—		$	4.40		3/7/2021		—		—			—		—
	3/7/2014	—	—		—			—		20,000	12	$	170,400		—		—
	3/7/2015	—	—		—			—		20,000	13	$	170,400		—		—
	12/28/2015	—	—		—			—		10,000	4	$	85,200		—		—

1	These amounts were calculated based on $8.52 per share, which was the closing price of the Company’s common stock on December 31, 2015.

2	The remainder of these nonqualified stock options will vest in increments of 350,000 shares upon the first four anniversaries of the grant date, subject generally to continued employment by the recipient during the four‑year period following the grant date.

3	The remainder of these stock bonus shares will vest in increments of 50,000 shares upon the first four anniversaries of the grant date, subject generally to continued employment by the recipient during the four‑year period following the grant date.

4	The remainder of these restricted stock units will vest in two equal increments on the first and second anniversaries of the grant date, subject generally to continued employment by the recipient during the two‑year period following the grant date.

5	The remainder of these stock bonus shares will vest in increments of 15,000 shares upon the first four anniversaries of the grant date, subject generally to continued employment by the recipient during the four‑year period following the grant date.

6	The remainder of these nonqualified stock options will vest in four equal installments beginning on August 24, 2015 and then on each of the three anniversaries of August 24 thereafter.

7	The remainder of these nonqualified stock options will vest on the fifth anniversary of the grant date, subject generally to continued employment by the recipient during the five‑year period following the grant date.

8	The remainder of these nonqualified stock options will vest on the fourth anniversary of the grant date, subject generally to continued employment by the recipient during the four‑year period following the grant date.

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9	The remainder of these nonqualified stock options will vest in increments of 20,000 shares upon the third, fourth, and fifth anniversaries of the grant date, subject generally to continued employment by the recipient during the five‑year period following the grant date.

10	The remainder of these stock bonus shares will vest in two equal increments on the second and third anniversaries of the grant date, subject generally to continued employment by the recipient during the three‑year period following the grant date.

11	The remainder of these stock bonus shares will vest in two equal increments on the first and second anniversaries of the grant date, subject generally to continued employment by the recipient during the two-year period following the grant date.

12	The remainder of these stock bonus shares will vest in full on the second anniversary of the grant date, subject generally to continued employment by the recipient during the three‑year period following the grant date.

13	The remainder of these stock bonus shares will vest in full on the first anniversary of the grant date, subject generally to continued employment by the recipient during the one‑year period following the grant date.

Option Exercises and Stock Vested

The following table shows information concerning the stock options exercised and stock awards vested during the four months ended December 31, 2015 by the persons named below:

	Option Awards					Stock Awards
	Number of Shares Acquired on Exercise (#)		Value Realized on Exercise ($) 1			Number of Shares Acquired on Vesting (#)		Value Realized on Vesting ($) 1
Mr. Holloway	—		—			222,500		2,208,225
Mr. Scaff, Jr.	—		—			222,500		2,208,225
Mr. Peterson	—		—			33,334		294,006
Mr. Henderson	—		—			23,333		223,647
Mr. Rasmuson	—		—			13,500		119,070
Mr. Jennings	—		—			5,000		44,100

1	For option awards, the value realized is the difference between the fair market value of our common stock at the time of exercise and the exercise price. For stock awards, the value realized is based on the closing price of our common stock on the vesting date.

Potential Payments Upon Termination or Change in Control

Employment Agreements

We currently maintain executive employment agreements with all of our NEOs except for Messrs. Holloway and Scaff, whose employment agreements have been terminated effective December 31, 2015, and Mr. Henderson. The employment agreement for each NEO sets forth their job title and responsibilities, compensation, restrictive covenants, and the consequences of certain terminations of employment, including upon a change of control. As part of the engagement of the Compensation Consultants, the Company has reviewed and evaluated all employment agreements currently in place with its NEOs to ensure market competitiveness and that the provisions therein generally align with market best practices.

Ed Holloway, Co-Chief Executive Officer. On December 14, 2015, the board of directors accepted the resignation of Mr. Holloway, effective December 31, 2015. The Company entered into a consulting agreement with Mr. Holloway for the purposes of providing advice to Mr. Peterson, on an as requested basis, in the areas of acquisitions and special projects or as otherwise requested by Mr. Peterson. In exchange for such consulting services, the Company has agreed to pay Mr. Holloway $70,000 per month during the five-month period ending May 31, 2016, and Mr. Holloway received the title to the Company vehicle which was assigned to him at the time of resignation.

William E. Scaff, Jr., Co-Chief Executive Officer and Treasurer. On December 14, 2015, the board of directors accepted the resignation of Mr. Scaff, effective December 31, 2015. The Company entered into a consulting agreement with Mr. Scaff for the purposes of providing advice to Mr. Peterson, on an as requested basis, in the areas of acquisitions and special projects or as

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otherwise requested by Mr. Peterson. In exchange for such consulting services, the Company has agreed to pay Mr. Scaff $70,000 per month during the five-month period ending May 31, 2016, and Mr. Scaff received the title to the Company vehicle which was assigned to him at the time of resignation.

Lynn A. Peterson, President. Mr. Peterson’s employment agreement commenced on May 27, 2015 and expires on May 31, 2020. Upon Mr. Peterson’s death or disability, he (or his legal representative) is entitled to receive all compensation that would otherwise be payable to Mr. Peterson through the last day of the month in which his death occurs or in which his employment is terminated due to disability, and any unvested equity grants and stock options will become immediately exercisable. In the event of his termination for "cause," Mr. Peterson is entitled to be paid through the date of his termination of employment. If the Company terminates Mr. Peterson for cause or for disability and an arbitrator determines that the termination was improper, Mr. Peterson is entitled to the compensation which he would have received had the employment agreement not been terminated. In the event the Company terminates Mr. Peterson’s employment other than for cause or due to his death or disability and not in connection with or within 12 months following a change in control (as defined below), the Company will pay to Mr. Peterson a lump sum amount equal to two times Mr. Peterson’s annual salary (as in effect at the time of termination) plus Mr. Peterson’s most recent bonus (the "Termination Payment"), and all of Mr. Peterson’s unpaid or unvested equity grants and stock options will be immediately vested. In the event of a "constructive termination" other than in connection with or within 12 months following a change in control, Mr. Peterson may terminate his employment upon not less than 30 days’ notice, will be entitled to receive the Termination Payment, and all of his unpaid or unvested restricted stock awards and option awards will be immediately vested. In the event of a change of control, if the Company terminates Mr. Peterson’s employment without the occurrence of a "cause" event on or before the first anniversary of the change of control and not due to Mr. Peterson’s death or disability, the Company will pay to Mr. Peterson a lump sum amount equal to three times Mr. Peterson’s annual salary (as in effect at the time of termination) plus Mr. Peterson’s most recent bonus. All of Mr. Peterson’s unpaid or unvested equity grants and stock options shall be immediately vested upon a change of control (whether or not followed by his termination of employment), and the expiration date of any options which would expire within 6 months after the constructive termination will be extended to the date that is the earlier to occur of 12 months after the date of the constructive termination or the tenth anniversary of the date of grant. In addition, upon a change of control and Mr. Peterson’s termination of employment, he will receive the value of 18 months of COBRA premiums in a cash lump sum. The termination payments provided in the employment agreement are subject to modification as necessary to comply with Section 409A of the Code. The termination payments described above (other than those payable in connection with a change of control) are subject to Mr. Peterson’s execution of a release agreement reasonably acceptable to the Company and are not payable in the event of a material breach of the employment agreement by Mr. Peterson. Mr. Peterson’s employment agreement contains confidentiality obligations applicable during the term of his employment and thereafter. The employment agreement also contains a non-competition provision which is applicable during the term of the employment agreement and for one year thereafter and restricts Mr. Peterson from being employed by or owning an interest in any company which competes with the Company and from owning an interest in any property located within 50 miles of any property owned or under consideration by the Company, subject to certain exceptions. During his term of employment, the Company agrees to nominate Mr. Peterson for election to the Board.

Upon the resignations of the Messrs. Holloway and Scaff, Mr. Peterson was appointed as the Chairman and Chief Executive Officer of the Company, effective January 1, 2016.

Craig Rasmuson, Chief Operating Officer. Mr. Rasmuson’s employment agreement commenced on February 1, 2014 and expires on February 1, 2017. Upon Mr. Rasmuson’s death or disability, he (or his legal representative) is entitled to receive all compensation that would otherwise be payable to Mr. Rasmuson through the last day of the month in which his death occurs or in which his employment is terminated due to disability, and any unvested equity grants and stock options will become immediately exercisable. In the event of his termination for "cause," Mr. Rasmuson is entitled to be paid through the date of his termination of employment. If the Company terminates Mr. Rasmuson for cause or for disability and an arbitrator determines that the termination was improper, Mr. Rasmuson is entitled to the compensation which he would have received had the employment agreement not been terminated. In the event of a "constructive termination" other than a "change of control," Mr. Rasmuson may terminate his employment upon not less than 30 days’ notice. In the event of a constructive termination following a change of control, Mr. Rasmuson may terminate his employment upon not less than 30 days’ notice and is entitled to receive a lump sum amount equal to the greater of 12 months’ salary (as in effect at the time of termination) or the amount of all salary and benefits which would otherwise be payable pursuant to his employment agreement. All unvested options and bonus shares held by Mr. Rasmuson will become fully vested upon a constructive termination (whether or not followed by his termination of employment). If Mr. Rasmuson retires during the term of the employment agreement after attaining the age of 70, any unvested equity grants and stock options will become immediately exercisable and may be exercised for a period of one year. Mr. Rasmuson’ employment agreement contains confidentiality obligations applicable during the term of his employment and thereafter. The employment agreement also contains a non- competition provision which is applicable during the term of the employment agreement and for one year thereafter and restricts Mr. Rasmuson from being employed by or owning an interest in any company which competes with the Company and from owning an interest in any property located within 50 miles of any property owned or under consideration

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by the Company, subject to certain exceptions.

Frank L. Jennings, Chief Accounting Officer. Mr. Jennings’ employment agreement commenced on March 7, 2014 and expires on May 31, 2016. Upon Mr. Jennings’ death or disability, he (or his legal representative) is entitled to receive all compensation that would otherwise be payable to Mr. Jennings through the last day of the month in which his death occurs or in which his employment is terminated due to disability, and any unvested equity grants and stock options will become immediately exercisable. In the event of his termination for "cause," Mr. Jennings is entitled to be paid through the date of his termination of employment. If the Company terminates Mr. Jennings for cause or for disability and an arbitrator determines that the termination was improper, Mr. Jennings is entitled to the compensation which he would have received had the employment agreement not been terminated. In the event of a "constructive termination" other than a "change of control," Mr. Jennings may terminate his employment upon not less than 30 days’ notice. In the event of a constructive termination following a change of control, Mr. Jennings may terminate his employment upon not less than 30 days’ notice and is entitled to receive a lump sum amount equal to the greater of 12 months’ salary (as in effect at the time of termination) or the amount of all salary and benefits that would otherwise be payable pursuant to his employment agreement. All unvested options and bonus shares held by Mr. Jennings will become fully vested upon a constructive termination (whether or not followed by his termination of employment). If Mr. Jennings retires during the term of the employment agreement after attaining the age of 70, any unvested equity grants and stock options will become immediately exercisable and may be exercised for a period of one year. Mr. Jennings’ employment agreement contains confidentiality obligations applicable during the term of his employment and thereafter. The employment agreement also contains a non-competition provision that is applicable during the term of the employment agreement and for one year thereafter and restricts Mr. Jennings from being employed by or owning an interest in any company which competes with the Company and from owning an interest in any property located within 50 miles of any property owned or under consideration by the Company, subject to certain exceptions.

On March 30, 2016, Mr. Jennings notified the Company that after his employment agreement expires on May 31, 2016, he will not continue his employment with the Company, including his position as the Chief Accounting Officer of the Company.

Estimated Termination and Change in Control Benefits

The following table quantifies the benefits that would have been received by our NEOs had they experienced a termination of employment under various circumstances as of December 31, 2015 under the terms of their employment agreements in effect on such date:

Name		Payment Type		Termination Upon Death or Disability ($)			Termination for Cause ($)			Certain Terminations in Violation of Agreement 1 ($)			Certain Terminations upon or after a Change of Control 2  ($)
Mr. Peterson		Cash Payment		—			—			1,575,000			2,175,000
		Equity 3		2,271,994			—			2,271,994			2,271,994
		COBRA		—			—			—			11,934
		TOTAL		2,271,994			—			3,846,994			4,458,928
Mr. Henderson 4		Cash Payment		—			—			—			—
		Equity 3		653,203			—			—			653,203
		TOTAL		653,203			—			—			653,203
Mr. Rasmuson		Cash Payment		—			—			352,083			352,083
		Equity 3		1,147,290			—			1,032,270			1,147,290
		TOTAL		1,147,290			—			1,384,353			1,499,373
Mr. Jennings		Cash Payment		—			—			114,583			275,000
		Equity 3		426,000			—			340,800			426,000
		TOTAL		426,000			—			455,383			701,000

1	Termination in Violation of Agreement refers to a termination event in which the Company terminates a NEO in breach of the "for cause" or disability termination provisions of the employment agreement. Except where otherwise noted, amounts shown reflect base salary for the remainder of the employment term and do not include discretionary bonuses.

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2	Termination upon or after a Change of Control refers to a constructive termination occurring simultaneously with or following a Change of Control for the periods described in the employment agreements.

3	Equity amounts based on the closing price of our common stock on the NYSE MKT on December 31, 2015 of $8.52

4	Mr. Henderson is not party to an employment agreement with the Company.

Director Compensation

On October 29, 2014, the Company's Directors approved the following compensation arrangements for the Company's directors:

•	Commencing December 1, 2014, each non-employee Board member will be paid an annual retainer of $160,000 payable in quarterly installments, in either cash or shares of the Company's common stock, at the election of the director.

•	Members of the Compensation Committee, Nominating Committee and Acquisition Committee are paid an additional annual retainer of $4,000 for their participation on each committee. Compensation for participation on the Audit Committee is $8,000 annually per member. Committee Chairmen for all board committees receive an additional $2,000 annually.

In late 2015, the Company decided to transition to a director compensation structure that would include equity incentive compensation, in the form of time-vesting restricted stock or restricted stock units, as a significant portion of overall compensation, and a reduced annual retainer. Based on a market review and analysis, on December 14, 2015, the Company’s directors approved the following revised compensation arrangements for the Company’s non-employee directors (excluding Messrs. Holloway and Scaff):

•	Commencing January 1, 2016, each non-employee director will be paid an annual retainer of $60,000, payable in quarterly installments in either cash or shares of the Company's common stock, at the election of the director.

•	The Chairman of the Audit Committee will receive an additional $17,000 per year, payable in quarterly installments. Members of the Audit Committee will receive an additional $10,000 per year, payable in quarterly installments.

•	The Chairman of the Compensation Committee will receive an additional $15,000 per year, payable in quarterly installments. Members of the Compensation Committee will receive an additional $5,000 per year, payable in quarterly installments.

•	The Chairman of the Nominating/Corporate Governance Committee will receive an additional $10,000 per year, payable in quarterly installments. Members of the Nominating/Corporate Governance Committee will receive an additional $5,000 per year, payable in quarterly installments.

•	Each non-employee director will receive an annual stock award equal to $150,000. The number of shares will be determined based on the average closing price of the Company’s common stock for the twenty trading days prior to January 1 of the applicable year of grant. The shares issued will vest in four equal quarterly installments, with the first tranche vesting upon the grant date.

The following table shows the compensation paid or accrued to our Directors during the Transition Period. Non-employee directors have the option to receive their fees in either cash or stock:

		Fees Earned or Paid in Cash
Name		Annual Retainer				Committee Retainers				Committee Chairman Retainer				Total
Rick Wilber   1		$	128,333			$	—			$	—			$	128,333
Raymond McElhaney 2		128,333				—				—				128,333
Bill Conrad 2		128,333				—				—				128,333
R.W. Noffsinger 2		128,333				—				—				128,333
George Seward   3		128,333				—				—				128,333
Jack Aydin   4		128,333				—				—				128,333
Total		$	769,998			$	—			$	—			$	769,998

1	Amount includes the issuance of 12,587 shares of common stock with a fair value, computed in accordance with ASC 718, of $128,333 during the Transition Period.

2	Amount includes the issuance of 7,500 shares of common stock with a fair value, computed in accordance

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with ASC 718, of $75,000 during the Transition Period.

3	Amount includes the issuance of 8,654 shares of common stock with a fair value, computed in accordance with ASC 718, of $88,333 during the Transition Period.

4	Amount includes the issuance of 11,433 shares of common stock with a fair value, computed in accordance with ASC 718, of $115,000 during the Transition Period.

Director Share Ownership Requirements

In 2016, the board of directors adopted Share Ownership Requirements for the Company’s non-employee directors. Required ownership for Non-Employee directors is three times annual board compensation. Qualified holdings for non-employee directors are the same types of holdings (stock owned directly and unvested time-based restricted stock) as the qualified holdings for the Company’s executives.

Additionally, the value of the shares held is also measured on January 1 each year as the average of the month end closing price for the 12 months preceding the date of calculation. Non-employee directors will have a five year phase-in period in which to meet the ownership requirements.

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Equity Compensation Plan Information

The following table summarizes information related to our equity compensation plans under which our equity securities are authorized for issuance as of December 31, 2015 .

 

Plan Category		Number of Securities to be Issued Upon Exercise of Outstanding Options and Rights (#)			Weighted-Average Exercise Price of Outstanding Options and Rights				Number of Securities  Remaining Available for Future Issuance Under Equity Compensation  Plans (#)
Equity compensation plans approved by security holders
2015 Equity Incentive Plan		332,533		1	$	9.88			4,093,200		1
2011 Non-Qualified Stock Option Plan		4,013,500			$	9.40			—
2011 Incentive Stock Option Plan		858,500			$	11.10			—
2011 Stock Bonus Plan		767,334			N/A				—
Equity compensation plans not approved by security holders		—			—				—
Total		5,971,867							4,093,200

¹ Includes 148,533 unvested restricted share awards.

Security Ownership of Certain Beneficial Owners and Management

The following table and footnotes show information as of March 31, 2016 regarding the beneficial ownership of our common stock by:

•	Each shareholder known by us to be the beneficial owner of more than 5% of the outstanding shares of our common stock;

•	Each member of the Board and each of our named executive officers; and

•	All members of the Board and our executive officers as a group.

Unless otherwise indicated in the footnotes to this table and subject to community property laws where applicable, we believe that each of the shareholders named in this table has sole voting and investment power with respect to the shares indicated

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as beneficially owned. Unless otherwise indicated, the address for each person set forth in the table is 1625 Broadway, Suite 300, Denver, Colorado 80202.

In calculating the number of shares beneficially owned by each person and the percentage owned by each person, we have assumed that all shares issuable upon exercise of options or the vesting of stock awards within 60 days of March 31, 2016 are beneficially owned by that person. The total number of shares outstanding used in calculating the percentage owned includes these shares.

Name of Beneficial Owner		Number of Common Shares Beneficially Owned				Percentage of Outstanding Common Shares Beneficially Owned
Named Executive Officers:
Lynn A. Peterson		833,333		1		0.7	%
James P. Henderson		53,333		2		—	%
Craig D. Rasmuson		284,507		3		0.2	%
Frank L. Jennings		244,089		4		0.2	%
Non-Employee Directors:
Edward Holloway		3,116,389				2.5	%
William E. Scaff, Jr.		3,091,389				2.4	%
Rick Wilber		754,519		5		0.6	%
Raymond McElhaney		296,071		5		0.2	%
R.W. Noffsinger		192,121		5		0.2	%
Jack Aydin		33,382		5		—	%
Daniel E. Kelly		6,538		5		—	%
All directors and named executive officers as a group (11 individuals)		8,905,671		6		7.0	%

1	Shares beneficially owned include 50,000 shares of common stock subject to stock bonus shares vesting within 60 days of March 31, 2016 and 700,000 shares of common stock subject to options exercisable within 60 days of March 31, 2016 .

2	Shares beneficially owned include 30,000 shares of common stock subject to options exercisable within 60 days of March 31, 2016 .

3	Shares beneficially owned include 225,000 shares of common stock subject to options exercisable within 60 days of March 31, 2016 .

4	Shares beneficially owned include 150,000 shares of common stock subject to options exercisable within 60 days of March 31, 2016 .

5	Shares beneficially owned include 3,923 shares of common stock subject to restricted stock units vesting within 60 days of March 31, 2016 .

6	Shares beneficially owned include 69,615 shares of common stock subject to stock bonus shares and restricted stock units vesting within 60 days of March 31, 2016 and 1,105,000 shares of common stock subject to options issued to named executive officers that are exercisable or issuable within 60 days of March 31, 2016 .

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR INDEPENDENCE

Certain Relationships and Related Person Transactions

The Board has established a practice pursuant to which it reviews, and approves and ratifies when deemed appropriate, transactions with related parties including directors and executive officers of the Company and entities in which such persons have a significant financial interest.  Pursuant to this practice, any transaction between the Company and the related person(s) must be approved by a majority of the Company’s disinterested directors.  In determining whether to approve or ratify a transaction, the disinterested directors will consider the relevant facts and circumstances of the transaction, which may include factors such

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as the relationship of the related person with the Company, the business purpose and reasonableness of the transaction, whether the transaction is comparable to a transaction that could be available to the Company on an arms-length basis and the impact of the transaction on the Company’s business and operations.

The Company leases its Platteville, Colorado office and an equipment storage yard under a lease agreement with HS Land & Cattle, LLC (“HSLC”). HSLC is controlled by Ed Holloway and William Scaff, Jr., members of the Company's board of directors.  The lease term expired on July 1, 2015 and is currently continuing on a month-to-month basis, at a monthly lease payment of $15,000.

The Company has a program to acquire undeveloped mineral interests in several Colorado and Nebraska counties.  George Seward, a member of the Company’s board of directors as of December 31, 2015, led that program.  In the aggregate, the Company has leased approximately 240,000 net mineral acres in the area.  The Company agreed to compensate the persons, including Mr. Seward, who assisted in the acquisition effort.  The compensation is paid in the form of restricted shares of the Company’s common stock.  Mr. Seward resigned from the board of directors effective February 1, 2016.

Amounts received by Mr. Seward are summarized in the following table:

	Four Months Ended December 31, 2015				Year Ended August 31,
					2015				2014				2013
Restricted shares of common stock	—				—				15,883				31,454
Value of restricted common stock (in thousands)	$	—			$	—			$	106			$	105

In addition, some of the mineral interests were leased from Mr. Seward.   The following table summarizes the net acres leased from Mr. Seward, the number of restricted common shares issued to him, and the value of those shares on the date of the transaction:

  

	Four Months Ended December 31, 2015				Year Ended August 31,
					2015				2014				2013
Mineral acres leased	6,498				—				4,844				2,263
Shares of restricted common stock	22,515				—				40,435				22,202
Value of common stock (in thousands)	$	248			$	—			$	313			$	91

The Company processes revenue distribution payments to entities that own mineral interests in wells which the Company operates, including payments to four of the Company’s directors or their affiliates, Lynn A. Peterson, Ed Holloway, William Scaff, Jr., and George Seward. The royalty payments made to directors or their affiliates totaled $62,000 for the four months ended December 31, 2015.

Director Independence

The Board has determined that each of Messrs. Wilber, McElhaney, Conrad, No ffsinger, Aydin, and Kelly is independent under NYSE MKT rules.

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ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

Fees Paid to Principal Accountants

For the four months ended December 31, 2015 and for each of the years ended August 31, 2015 and 2014, fees paid or accrued to EKS&H LLLP were:

	Four Months Ended December 31, 2015			Year Ended August 31,
				2015				2014
Audit Fees	225,000			$	345,000			$	275,000
Audit-Related Fees	92,000			65,000				42,000
Tax Fees	20,485			91,000				66,000
All Other Fees	26,815			46,000				50,000
Total Fees	364,300			$	547,000			$	433,000

Audit fees represent amounts billed for professional services rendered for the audit of our annual financial statements, our system of internal control over financial reporting and the reviews of the financial statements included in our Form 10-Q and Form 10-K reports.  Audit-related fees include amounts billed for the review of our registration statements on Form S-3 and Form S-8 and the audits of the historical financial statements of companies acquired. Tax fees consist of the aggregate fees billed for professional services rendered for tax compliance, tax advice, and tax planning for the Company. All other fees represent due diligence activities performed on our behalf.

Audit Committee Pre-Approval Policy

The Audit Committee has policies and procedures regarding the pre-approval of audit and non-audit services performed by an outside accountant. The committee is required to pre-approve all engagement letters and fees for all auditing services (including providing comfort letters in connection with securities underwritings) and permissible non-audit services, subject to any exception under Section 10A of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the rules promulgated thereunder. Pre-approval authority may be delegated in certain circumstances. All of the services described in "Fees Paid to Principal Accountants" were approved by the Audit Committee pursuant to its pre-approval policies as in effect as of the relevant time.

Report of the Audit Committee

Management is responsible for the Company’s internal controls and preparation of the financial statements in accordance with generally accepted accounting principles. The Company’s independent registered public accounting firm is responsible for performing an independent audit of the Company’s financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”) and issuing a report thereon. The Audit Committee’s responsibilities include monitoring and overseeing these processes.

The Audit Committee reviewed and discussed the Company’s audited financial statements for the four months ended December 31, 2015 (the “Audited Financial Statements”) with the Company’s management and EKS&H LLLP. The Audit Committee also discussed with EKS&H LLLP the matters required to be discussed by Statement of Auditing Standards No. 61 (Codification of Statements of Auditing Standards AU § 380) as adopted by the PCAOB in Rule 3200T, as amended. The Audit Committee has received the written disclosures and the letter from EKS&H LLLP required by PCAOB Rule 3526 and has discussed with EKS&H LLLP its independence from the Company. The Audit Committee has discussed with management and EKS&H LLLP such other matters and received such assurances from them as the Audit Committee deemed appropriate.

Based on the foregoing review and discussions and relying thereon, the Audit Committee has recommended that the Board include the Audited Financial Statements in the Company’s Transition Report on Form 10-K for the four months ended December 31, 2015.

AUDIT COMMITTEE MEMBERS:

Raymond E. McElhaney

R.W. Noffsinger, III

Jack N. Aydin

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PART IV

ITEM 15     EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Financial Statements

See page F-1 for a description of the financial statements filed with this report.

Exhibits

Exhibit Number	Exhibit
1.1	Underwriting Agreement dated January 21, 2016 between the Company and Credit Suisse Securities (USA) LLC, as representative of the several underwriters named therein (incorporated by reference to Exhibit 1.1 to the Current Report on Form 8-K of the Company filed on January 27, 2015
1.2	Underwriting Agreement dated April 11, 2016 between the Company and Credit Suisse Securities (USA) LLC, as representative of the several underwriters named therein (incorporated by reference to Exhibit 1.1 to the Current Report on Form 8-K of the Company filed on April 14, 2015
3.1	Amended and Restated Articles of Incorporation of Synergy Resources Corporation (the “Company”) (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K of the Company filed on December 17, 2015)
3.2	Bylaws of the Company, as amended by the First Amendment to the Bylaws dated January 21, 2016*
10.1	Amended and Restated Credit Agreement, dated as of November 28, 2012 (the “Credit Agreement”), by and among the Company, Community Banks of Colorado, as administrative agent and the lenders party thereto as amended by the First Amendment to Credit Agreement dated as of February 12, 2013 and the Second Amendment to Credit Agreement dated June 28, 2013 (incorporated by reference to Exhibit 10.21 to the Annual Report on Form 10-K of the Company filed on October 30, 2014)
10.1.1	Third Amendment to Credit Agreement, dated as of December 20, 2013, by and among the Company, Community Banks of Colorado as administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.22 to the Current Report on Form 8-K of the Company filed on December 26, 2013)
10.1.2	Fourth Amendment to Credit Agreement, dated as of June 3, 2014, by and among the Company, Community Banks of Colorado, as administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.23 to the Current Report on Form 8-K of the Company filed on June 10, 2014)
10.1.3	Fifth Amendment to Credit Agreement, dated as of December 15, 2014, by and among the Company, SunTrust Bank as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.32 to the Quarterly Report on Form 10-Q of the Company filed on January 9, 2015)
10.1.4	Sixth Amendment to Credit Agreement, dated as of June 2, 2015, by and among the Company, SunTrust Bank, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.35 to the Current Report on Form 8-K of the Company filed on June 8, 2015)
10.1.5	Seventh Amendment to Credit Agreement, dated as of January 28, 2016, by and among the Company, SunTrust Bank, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of the Company filed on February 2, 2016)
10.2	Employment agreement dated as of May 27, 2015 between the Company and Lynn A. Peterson (incorporated by reference to Exhibit 10.34 to the Current Report on Form 8-K of the Company filed on June 2, 2015)+
10.3	Employment agreement dated as of June 4, 2014 between the Company and Frank L. Jennings (incorporated by reference to Exhibit 10.24 to the Current Report on Form 8-K of the Company filed on June 10, 2014)+
10.4	Employment agreement dated as of June 4, 2014 between the Company and Craig Rasmuson (incorporated by reference to Exhibit 10.25 to the Current Report on Form 8-K of the Company filed on June 10, 2014)+
10.5	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.8 to the Annual Report on Form 10-K of the Company filed on October 16, 2015)
10.6	2015 Equity Incentive Plan (incorporated by reference to Exhibit 10.18 to the Current Report on Form 8-K of the Company filed on December 17, 2015)+
10.7	Lease dated as of July 1, 2014 between the Company and HS Land & Cattle, LLC (incorporated by reference to Exhibit 10.12 to the Annual Report on Form 10-K of the Company filed on October 16, 2015)
10.8	Agreement Regarding Conflicting Interest Transactions among the Company, Ed Holloway, William E. Scaff, Jr., Petroleum Management, LLC, Petroleum Exploration and Management, LLC, and HS Land & Cattle, LLC (incorporated by reference to Exhibit 10.4 to the Annual Report on Form 10-K/A of the Company filed on June 3, 2011)

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10.9	Consulting agreement dated as of December 31, 2015 between the Company and Ed Holloway (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of the Company filed on January 11, 2016)+
10.10	Consulting agreement dated as of December 31, 2015 between the Company and William E. Scaff, Jr.(incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of the Company filed on January 11, 2016)+
10.11	Purchase and Sale Agreement dated October 29, 2014 between Bayswater Exploration and Production, LLC, et al, as Sellers, and the Company, as Buyer, dated October 29, 2014 (incorporated by reference to Exhibit 10.33 to the Quarterly Report on Form 10-Q of the Company filed on January 9, 2015)
10.12	Exploration Agreement dated as of March 1, 2013 between the Company and Vecta Oil & Gas Ltd. (incorporated by reference to Exhibit 10.18 to the Quarterly Report on Form 10-Q filed on April 9, 2013)
21.1	Subsidiaries of the Company - None
23.1	Consent of EKS&H LLLP*
23.2	Consent of Ryder Scott Company, L.P. *
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 amended*
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 amended*
32.1	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**
99.1	Report of Ryder Scott Company, L.P. (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed on April 11, 2016)
99.2	Unaudited statements of operating revenues and direct operating expenses of properties acquired by Company from K.P. Kauffman Company, Inc. for the nine months ended September 30, 2015 and 2014, and the related notes to the statements of operating revenues and direct operating expenses*
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*

* Filed herewith

** Furnished herewith

+ Management contract or compensatory plan or arrangement

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SYNERGY RESOURCES CORPORATION

INDEX TO FINANCIAL STATEMENTS

Index to Financial Statements	F-1
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets	F-3
Statements of Operations	F-4
Statements of Changes in Shareholders’ Equity	F-5
Statements of Cash Flows	F-6
Notes to Financial Statements	F-7

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

Synergy Resources Corporation

Denver, Colorado

We have audited the accompanying balance sheets of Synergy Resources Corporation (the "Company") as of December 31, 2015, August 31, 2015 and 2014, and the related statements of operations, changes in shareholders’ equity, and cash flows for the four months ended December 31, 2015, and for each of the three years in the period ended August 31, 2015. We also have audited the Company’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Synergy Resources Corporation as of December 31, 2015, August 31, 2015 and 2014, and the results of its operations and its cash flows for the four months ended December 31, 2015, and for each of the three years in the period ended August 31, 2015, in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, Synergy Resources Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) , issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note 1 to the financial statements, in 2016, the Company changed its fiscal year end from August 31 to December 31.

/s/ EKS&H LLLP

April 22, 2016

Denver, Colorado

F-2

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SYNERGY RESOURCES CORPORATION

BALANCE SHEETS

(in thousands, except share data) 

ASSETS	December 31, 2015				August 31, 2015				August 31, 2014
Current assets:
Cash and cash equivalents	$	66,499			$	133,908			$	34,753
Accounts receivable:
Oil and gas sales	12,527				13,601				16,974
Joint interest billing and other	12,156				15,325				15,398
Commodity derivative contracts	6,572				2,897				365
Other current assets	1,944				1,109				750
Total current assets	99,698				166,840				68,240
Property and equipment:
Oil and gas properties, full cost method:
Proved properties, net	422,778				452,393				275,018
Unproved properties, not subject to depletion	98,945				77,564				95,278
Oil and gas properties, net	521,723				529,957				370,296
Other property and equipment, net	5,124				4,783				9,104
Total property and equipment, net	526,847				534,740				379,400
Commodity derivative contracts	2,996				1,565				54
Goodwill	40,711				40,711				—
Other assets	2,364				2,593				848
Total assets	$	672,616			$	746,449			$	448,542
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Trade accounts payable	$	4,350			$	670			$	1,747
Well costs payable	31,414				33,071				71,849
Revenue payable	13,603				19,044				14,487
Production taxes payable	24,530				20,899				14,376
Other accrued expenses	809				27				817
Commodity derivative contracts	—				—				302
Total current liabilities	74,706				73,711				103,578
Revolving credit facility	78,000				78,000				37,000
Commodity derivative contracts	—				—				307
Deferred tax liability, net	—				10,007				21,437
Asset retirement obligations	13,400				12,334				4,730
Total liabilities	166,106				174,052				167,052
Commitments and contingencies (See Note 16)
Shareholders' equity:
Preferred stock - $0.01 par value; 10,000,000 shares authorized; no shares issued and outstanding	—				—				—
Common stock - $0.001 par value; 300,000,000, 200,000,000, and 200,000,000 shares authorized, respectively; 110,033,601, 105,099,342, and 77,999,082 shares issued and outstanding, respectively	110				105				78
Additional paid-in capital	595,671				538,631				265,793
Retained (deficit) earnings	(89,271		)		33,661				15,619
Total shareholders' equity	506,510				572,397				281,490
Total liabilities and shareholders' equity	$	672,616			$	746,449			$	448,542

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SYNERGY RESOURCES CORPORATION

STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
					(unaudited)
Oil and gas revenues	$	34,138			$	52,931			$	124,843			$	104,219			$	46,223
Expenses:
Lease operating expenses	5,812				4,745				15,017				7,991				3,417
Production taxes	3,104				5,050				11,340				9,667				4,237
Depreciation, depletion, and accretion	18,776				22,574				65,869				32,958				13,336
Full cost ceiling impairment	125,230				—				16,000				—				—
Transportation commitment charge	2,802				—				—				—				—
General and administrative	17,875				5,678				18,995				10,139				5,688
Total expenses	173,599				38,047				127,221				60,755				26,678
Operating (loss) income	(139,461		)		14,884				(2,378		)		43,464				19,545
Other income (expense):
Commodity derivative gain (loss)	6,482				27,701				32,256				321				(3,044		)
Interest expense, net	—				—				(245		)		—				(97		)
Interest income	40				16				86				82				47
Total other income (expense)	6,522				27,717				32,097				403				(3,094		)
(Loss) Income before income taxes	(132,939		)		42,601				29,719				43,867				16,451
Income tax (benefit) provision	(10,007		)		15,802				11,677				15,014				6,870
Net (loss) income	$	(122,932	)		$	26,799			$	18,042			$	28,853			$	9,581
Net (loss) income per common share:
Basic	$	(1.14	)		$	0.34			$	0.19			$	0.38			$	0.17
Diluted	$	(1.14	)		$	0.33			$	0.19			$	0.37			$	0.16
Weighted-average shares outstanding:
Basic	107,789,554				79,971,698				94,628,665				76,214,737				57,089,362
Diluted	107,789,554				80,693,410				95,319,269				77,808,054				59,088,761

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SYNERGY RESOURCES CORPORATION

STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

(in thousands, except share data)

	Number of Common Shares			Par Value Common Stock				Additional Paid - In Capital				Accumulated Earnings (Deficit)				Total Shareholders' Equity
Balance, August 31, 2012	51,409,340			$	52			$	123,876			$	(22,815	)		$	101,113
Shares issued for cash at $6.25 per share pursuant to the June 13, 2013 stock offering memorandum, net of offering costs of $4.4 million	13,225,000			13				78,230				—				78,243
Shares issued for Orr Energy acquisition	3,128,422			3				13,515				—				13,518
Shares issued in exchange for mineral assets	687,122			1				3,165				—				3,166
Shares issued for exercise of warrants	1,052,698			1				3,274				—				3,275
Shares issued for exercise of stock options	1,030,057			1				(1		)		—				—
Stock-based compensation	55,084			—				1,314				—				1,314
Payment of tax withholdings using withheld shares	—			—				(6,990		)		—				(6,990		)
Net income	—			—				—				9,581				9,581
Balance, August 31, 2013	70,587,723			$	71			$	216,383			$	(13,234	)		$	203,220
Shares issued for Trilogy and Apollo acquisitions	872,483			1				8,327				—				8,328
Shares issued in exchange for mineral assets	357,901			—				2,856				—				2,856
Shares issued for exercise of warrants	6,063,801			6				35,628				—				35,634
Shares issued under stock bonus plan	89,875			—				1,201				—				1,201
Shares issued for exercise of stock options	27,299			—				—				—				—
Stock-based compensation for options	—			—				1,767				—				1,767
Payment of tax withholdings using withheld shares	—			—				(369		)		—				(369		)
Net income	—			—				—				28,853				28,853
Balance, August 31, 2014	77,999,082			$	78			$	265,793			$	15,619			$	281,490
Shares issued for cash at $10.75 per share pursuant to the February 2, 2015 stock offering memorandum, net of offering costs of $9.3 million	18,613,952			19				190,826				—				190,845
Shares issued for Bayswater acquisition	4,648,136			5				48,429				—				48,434
Shares issued in exchange for mineral assets	995,672			1				11,786				—				11,787
Shares issued for exercise of warrants	2,562,473			2				15,368				—				15,370
Shares issued under stock bonus plan	161,755			—				2,950				—				2,950
Shares issued for exercise of stock options	118,272			—				—				—				—
Stock-based compensation for options	—			—				4,741				—				4,741
Payment of tax withholdings using withheld shares	—			—				(1,262		)		—				(1,262		)
Net income	—			—				—				18,042				18,042
Balance, August 31, 2015	105,099,342			$	105			$	538,631			$	33,661			$	572,397
Shares issued for K.P. Kauffman acquisition	4,418,413			4				49,835				—				49,839
Shares issued in exchange for mineral assets	37,051			—				426								426
Shares issued under stock bonus and equity incentive plans	422,035			1				7,162				—				7,163
Shares issued for exercise of stock options	56,760			—				—				—				—
Stock-based compensation for options	—			—				2,161				—				2,161
Payment of tax withholdings using withheld shares	—			—				(2,544		)		—				(2,544		)
Net loss	—			—				—				(122,932		)		(122,932		)
Balance, December 31, 2015	110,033,601			$	110			$	595,671			$	(89,271	)		$	506,510

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SYNERGY RESOURCES CORPORATION 

STATEMENTS OF CASH FLOWS

(in thousands)

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
					(unaudited)
Cash flows from operating activities:
Net (loss) income	$	(122,932	)		$	26,799			$	18,042			$	28,853			$	9,581
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation, and accretion	18,776				22,574				65,869				32,958				13,336
Full cost ceiling impairment	125,230				—				16,000				—				—
Provision for deferred taxes	(10,007		)		15,802				11,679				15,014				6,870
Stock-based compensation	8,431				960				7,691				2,968				1,362
Mark to market of commodity derivative contracts:
Total (gain) loss on commodity derivatives contracts	(6,482		)		(27,701		)		(32,256		)		(321		)		3,044
Cash settlements on commodity derivative contracts	1,954				3,683				31,721				(2,138		)		(395		)
Cash premiums paid for commodity derivative contracts	(956		)		—				(4,117		)		—				—
Changes in operating assets and liabilities:
Accounts receivable:
Oil and gas sales	2,150				(3,327		)		3,373				(9,613		)		(3,756		)
Joint interest billing and other	3,546				(12,507		)		73				(10,698		)		(1,432		)
Accounts payable:
Trade	3,610				(543		)		(1,077		)		798				(550		)
Revenue	(5,441		)		10,214				4,557				8,406				1,921
Production taxes	3,631				4,957				5,121				8,099				2,472
Accrued expenses	344				800				(1,230		)		448				(141		)
Other	(1,782		)		(382		)		(359		)		131				(192		)
Total adjustments	143,004				14,530				107,045				46,052				22,539
Net cash provided by operating activities	20,072				41,329				125,087				74,905				32,120
Cash flows from investing activities:
Acquisition of oil and gas properties	(35,045		)		(74,050		)		(74,221		)		(30,590		)		(29,012		)
Well costs and other capital expenditures	(49,892		)		(84,131		)		(201,587		)		(125,012		)		(51,457		)
Short-term investments	—				—				—				60,018				(60,000		)
Net proceeds from sales of oil and gas properties	—				—				6,239				704				—
Net cash used in investing activities	(84,937		)		(158,181		)		(269,569		)		(94,880		)		(140,469		)
Cash flows from financing activities:
Proceeds from sale of stock	—				—				200,100				—				82,656
Offering costs	—				—				(9,255		)		—				(4,413		)
Proceeds from exercise of warrants	—				15,370				15,370				35,634				3,275
Shares withheld for payment of employee payroll taxes	(2,544		)		(405		)		(1,262		)		(369		)		(6,990		)
Proceeds from revolving credit facility	—				186,000				186,000				—				34,000
Principal repayments on revolving credit facility	—				(77,000		)		(145,000		)		—				—
Financing fee	—				(2,296		)		(2,316		)		—				—
Net cash (used in) provided by financing activities	(2,544		)		121,669				243,637				35,265				108,528
Net (decrease) increase in cash and equivalents	(67,409		)		4,817				99,155				15,290				179
Cash and equivalents at beginning of period	133,908				34,753				34,753				19,463				19,284
Cash and equivalents at end of period	$	66,499			$	39,570			$	133,908			$	34,753			$	19,463

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NOTES TO FINANCIAL STATEMENTS

December 31, 2015 and August 31, 2015, 2014 and 2013

1.	Organization and Summary of Significant Accounting Policies

Organization :  Synergy Resources Corporation (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 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.

At the directive of the Securities and Exchange Commission to use “plain English” in public filings, the Company will use such terms as “we,” “our,” “us” or “the Company” in place of Synergy Resources Corporation. When such terms are used in this manner throughout this document, they are in reference only to the corporation, Synergy Resources Corporation, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.

The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). Certain prior-period amounts have been reclassified to conform to the current-year presentation.

Change of Year-End:  On February 25, 2016, the Company's board of directors approved a change in fiscal year end from August 31 to December 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month fiscal year, which prior to September 1, 2015 ended on August 31, and beginning with December 31, 2015 ends on the December 31 of each year. This Form 10-K covers the transition period of September 1, 2015 through December 31, 2015.

Use of Estimates:      The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and gas reserves and goodwill, business combinations, derivatives, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions are revised periodically, and the effects of revisions are reflected in the financial statements in the period that it is determined to be necessary. Actual results could differ from these estimates.

Cash and Cash Equivalents:   The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents.

Short-Term Investments: As part of its cash management strategies, the Company invests in short-term interest bearing deposits such as certificates of deposits with maturities of less than one year.

 

Oil and Gas Properties:     The Company uses the full cost method of accounting for costs related to its oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool. These costs include land acquisition costs, geological and geophysical expense, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition, exploration, and development activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves.

Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves. For depletion purposes, the volume of proved petroleum reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Under the full cost method of accounting, a ceiling test is performed each quarter.  The full cost ceiling test is the impairment test prescribed by SEC regulations.  The ceiling test determines a limit on the net book value of oil and gas properties. The ceiling is calculated as the sum of the present value of estimated future net revenues from proved oil and gas reserves, plus the cost of

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properties not being amortized, plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized, less the income tax effects related to differences between the book and tax basis of the properties.  The present value of estimated future net revenues is computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves; the result of which is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued on the balance are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. If the capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion and prior impairments, and the related deferred income taxes exceed the ceiling limit, the excess is charged to expense. Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount. During the four months ended December 31, 2015, the Company recognized a ceiling test impairment of $125.2 million .

The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the preceding 12-month period, unless prices are defined by contractual arrangements.  Prices are adjusted for basis or location differentials and are held constant for the productive life of each well.

Oil and Gas Reserves: Oil and gas reserves represent theoretical, estimated quantities of crude oil and natural gas which geological and engineering data estimate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

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

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

Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities.  Under the full cost method of accounting, these expenses are capitalized in the full cost pool. See Note 2 for additional information.

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

Other Property and Equipment: Support equipment (including such items as vehicles, well servicing equipment, and office furniture and equipment) is stated at historical cost. Expenditures for support equipment relating to new assets or improvements are capitalized, provided the expenditure extends the useful life of an asset or extends the asset’s functionality. Support equipment is depreciated under the straight-line method using estimated useful lives ranging from five to seven years. No depreciation is taken on assets classified as construction in progress until the asset is placed into service. Gains and losses are recorded upon retirement, sale, or disposal of assets. Maintenance and repair costs are recognized as period costs when incurred. The Company evaluates its support equipment for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. 

Asset Retirement Obligations: The Company’s activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service.  Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors.  The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit adjusted risk-free rate.  Estimates are periodically reviewed and adjusted to reflect changes.

The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made.  This is typically when a well is completed or an asset is placed in service.  When the ARO is initially recorded, the Company capitalizes the cost (asset retirement cost or “ARC”) by increasing the carrying value of the related asset.  ARCs related

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to wells are capitalized to the full cost pool and subject to depletion.  Over time, the liability increases for the change in its present value (accretion of ARO), while the net capitalized cost decreases over the useful life of the asset, as depletion expense is recognized.  In addition, ARCs are included in the ceiling test calculation when assessing the full cost pool for impairment.

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

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 a goodwill test as of November 30, 2015 and December 31, 2015, neither of which resulted 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.

Oil and Gas Sales: The Company derives revenue primarily from the sale of crude oil and natural gas produced on its properties.  Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest. Revenues are reported on a net revenue interest basis, which excludes revenues that are attributable to other parties' working or royalty interests.  Revenue is recorded and receivables are accrued in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser.  Payment is generally received between thirty and ninety days after the date of production.  Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.

Major Customers:     The Company sells production to a small number of customers, as is customary in the industry. Customers representing 10% or more of its oil and gas revenue (“major customers”) for each of the periods presented are shown in the following table:

	Four Months Ended December 31,				Year Ended August 31,
	2015		2014		2015		2014		2013
			(unaudited)
Company A	57%		68%		65%		54%		50%
Company B	15%		11%		11%		13%		15%
Company C	12%		*		*		*		*
Company D	*		10%		*		*		*

* less than 10%

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

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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 December 31, 2015		As of August 31,
			2015		2014
Company A	13%		30%		37%
Company B	13%		*		*
Company C	13%		*		*

* less than 10%

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.

Lease Operating Expenses:   Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred.  Lease operating expenses (also referred to as production or lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities, property taxes, and insurance applicable to proved properties and wells and related equipment and facilities.

 

Stock-Based Compensation:   The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date. For stock options, fair value is calculated using the Black-Scholes-Merton option pricing model.  For stock bonus and restricted stock awards, fair value is the closing stock price for the Company's common stock on the grant date. The compensation is recognized over the vesting period of the grant.  See Note 12 for additional information.

 

Income Tax:   Income taxes are computed using the asset and liability method.  Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, their respective tax bases as well as the effect of net operating losses, tax credits, and tax credit carryforwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.

 

No significant uncertain tax positions were identified as of any date on or before December 31, 2015 .  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of December 31, 2015 , the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 14 for further information.

Financial Instruments : Financial instruments, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board (“FASB”), prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or collars to reduce the effect of price changes on a portion of its future oil and gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the statement of operations. The Company values its derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors, as well as other relevant economic measures. The Company compares the valuations calculated by it to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount

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rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 7 .

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 16 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 associated with business combinations. 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 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.

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

        

In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting” (“ASU 2016-09”), which intends to improve the accounting for share-based payment transactions. The ASU changes several aspects of the accounting for share-based payment award transactions, including: (1) Accounting and Cash Flow Classification for Excess

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Tax Benefits and Deficiencies, (2) Forfeitures, and (3) Tax Withholding Requirements and Cash Flow Classification. ASU 2016-09 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the impact of the adoption of this standard on our financial statements.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)” (“ASU 2016-02”), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous US GAAP. ASU 2016-02 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the impact of the adoption of this standard on our financial statements.

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. The adoption of this standard is not expected to have a significant impact on our 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, with early adoption permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating which transition approach to use and the impact of the adoption of this standard on our 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.

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2 .	Property and Equipment

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

	As of December 31, 2015				As of August 31,
					2015				2014
Oil and gas properties, full cost method:
Costs of unproved properties, not subject to depletion:
Lease acquisition and other costs	$	89,122			$	58,068			$	41,531
Unproved wells in progress	9,823				19,496				53,747
Subtotal, unproved costs	98,945				77,564				95,278
Costs of proved properties:
Producing and non-producing	691,659				577,500				329,926
Proved wells in progress	11,487				11,302				—
Less, accumulated depletion and full cost ceiling impairments	(280,368		)		(136,409		)		(54,908		)
Subtotal, proved properties, net	422,778				452,393				275,018
Costs of other property and equipment:
Land	4,478				4,478				3,898
Other property and equipment	1,270				875				5,961
Less, accumulated depreciation	(624		)		(570		)		(755		)
Subtotal, other property and equipment, net	5,124				4,783				9,104
Total property and equipment, net	$	526,847			$	534,740			$	379,400

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. As a result of these periodic reviews, the Company concluded that its net capitalized costs for oil and natural gas properties exceeded the ceiling amount, resulting in the recognition of a ceiling test impairments totaling $125.2 million during the four months ended December 31, 2015. During the year ended August 31, 2015, the Company's ceiling tests resulted in total impairments of $16 million . No such ceiling test impairments were recognized during the years ended August 31, 2014 and 2013 .

The Company also reviews the fair value of its unproved properties. The review as of August 31, 2015 indicated that estimated carrying values of such assets exceeded fair values. Therefore, the Company recorded an impairment of $15.4 million , and these costs were moved into the full cost pool and subject to the aforementioned ceiling test. No such impairments were recognized during the four months ended December 31, 2015 and the year ended August 31, 2014 .

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

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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):

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
					(unaudited)
Capitalized overhead	$	1,091			$	714			$	2,049			$	1,230			$	637

Costs Incurred:   Costs incurred in oil and gas property acquisition, exploration, and development activities for the periods presented were (in thousands):

	Four Months Ended December 31, 2015				Year Ended August 31,
					2015				2014				2013
Acquisition of property:
Unproved	$	38,779			$	32,701			$	15,002			$	12,295
Proved	51,085				51,400				33,795				43,143
Exploration costs	23,697				146,892				43,089				—
Development costs	17,742				4,957				111,238				61,128
Other property and equipment	395				741				9,315				—
Asset retirement obligation and other	4,415				7,051				1,610				1,578
Total costs incurred	$	136,113			$	243,742			$	214,049			$	118,144

Capitalized Costs Excluded from Depletion:   The following table summarizes costs related to unproved properties that have been excluded from amounts subject to depletion at December 31, 2015 (in thousands):

	Period Incurred
	Four Months Ended December 31, 2015				Year Ended August 31, 2015				Year Ended August 31, 2014				Year Ended August 31, 2013				Year Ended August 31, 2012 and Prior				Total as of December 31, 2015
Unproved leasehold acquisition costs	$	38,754			$	32,701			$	546			$	8,007			$	9,114			$	89,122
Unproved development costs	5,653				4,170				—				—				—				9,823
Total unevaluated costs	$	44,407			$	36,871			$	546			$	8,007			$	9,114			$	98,945

There were no individually significant properties or significant development projects included in the Company’s unproved property balance.  The Company regularly evaluates these costs to determine whether impairment has occurred or proved reserves have been established.  The majority of these costs are expected to be evaluated and included in the depletion base within three years .

3 .	Acquisitions

During the four months ended December 31, 2015 and the years ended August 31, 2015 and 2014 , the Company acquired certain oil and gas and other assets, as described below.

K.P. 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

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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 BOED at the time of purchase. 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 resu lts of operations of the acquired assets from the October 20, 2015 closing date through December 31, 2015, representing approximately $1.1 million of revenue and $0.8 million of o perating income, have been included in the Company's statement of operations for the four months ended December 31, 2015.

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The following table presents the unaudited pro forma combined results of operations for the four months ended December 31, 2015 and for the two years ended August 31, 2015 as if the Kauffman transaction had occurred on September 1, 2014.  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.

	Four Months Ended December 31, 2015				Year Ended August 31,
(in thousands)					2015				2014
Oil and gas revenues	$	35,389			$	138,145			$	112,517
Net (loss) income	$	(122,529	)		$	21,592			$	33,402
Net (loss) income per common share
Basic	$	(1.12	)		$	0.22			$	0.41
Diluted	$	(1.12	)		$	0.22			$	0.41

Bayswater transaction

On December 15, 2014, the Company completed the acquisition of certain assets from three independent oil and gas companies (collectively known as “Bayswater”) for a total purchase price of $126.0 million , net of customary closing adjustments. The purchase price was composed of $74.2 million in cash and $48.4 million in restricted common stock plus the assumption of certain liabilities.

The Bayswater acquisition encompassed 4,227 net acres with rights to the Codell and Niobrara formations, and 1,480 net acres with rights to other formations including the Sussex, Shannon and J-Sand. Additionally, the Company acquired non-operated working interests in 17 horizontal wells, and 73 operated vertical wells as well as working interests in 11 non-operated vertical wells. The working interests in the horizontal wells range from 6% to 40% while the working interests in the vertical wells range from 5% to 100% . 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 and earnings per share.

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The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of December 15, 2014. Transaction costs related to the Bayswater acquisition were expensed as incurred. The following table summarizes the final purchase price and final fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price	December 15, 2014
Consideration given:
Cash	$	74,221
Synergy Resources Corp. Common Stock (1)	48,434
Net liabilities assumed, including asset retirement obligations	3,315
Total consideration given	$	125,970
Allocation of Purchase Price
Proved oil and gas properties (2)	$	51,400
Unproved oil and gas properties	6,500
Other assets, including accounts receivable	3,392
Deferred tax asset	23,967
Total fair value of assets acquired	$	85,259
Goodwill	$	40,711

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

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

The fair value analysis concluded that the purchase price exceeded the fair value of assets acquired. Accordingly, goodwill was recognized for book purposes. For tax purposes, no goodwill has been recognized as the entire purchase price was allocated to proved and unproved oil and gas properties. The difference between the book and tax basis of oil and gas properties created a deferred tax asset of $24.0 million .  In the accompanying balance sheet, the deferred tax asset was offset against deferred liabilities. The amount allocated to goodwill as a result of the Bayswater acquisition totaled  $40.7 million for book purposes. Goodwill is primarily attributable to the operational and financial benefits expected to be realized from the acquisition, including employing optimized completion techniques on Bayswater's undrilled acreage which will improve hydrocarbon recovery, realized savings in drilling and well completion costs, functional synergies due to geographic location, and the ability to participate in future commodity price increases.

Differences between the preliminary allocation and final allocation of the purchase price were treated as a change in accounting estimate, and no retroactive adjustments were made to previously reported financial statements. The preliminary analysis and allocation of the purchase price focused on the values inherent in the proved producing wells and the associated proved undeveloped reserves. The final analysis concluded that the fair value of unproved oil and gas properties was $6.5 million and that fair value should be attributed to deferred tax assets and goodwill. The re-allocation of $64.7 million from unproved properties not subject to depletion to goodwill and deferred tax asset did not impact the full cost depletion base, and no prior period adjustment was necessary.

The results of operations of Bayswater from the December 15, 2014 closing date through August 31, 2015, representing approximately $7.7 million of revenue and $4.8 million of net income, have been included in the Company's statement of operations for the year ended August 31, 2015.

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The following table presents the unaudited pro forma combined results of operations for the two years ended August 31, 2015 as if the Bayswater transaction had occurred on September 1, 2013, the first day of the year ended August 31, 2014. 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 unaudited 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 unaudited 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.

	Year Ended August 31,
(in thousands)	2015				2014
Oil and gas revenues	$	131,716			$	108,740
Net income	$	19,822			$	27,720
Earnings per common share
Basic	$	0.21			$	0.34
Diluted	$	0.21			$	0.34

During the year ended August 31, 2014, the Company closed on two transactions that qualified as Business Combinations under ASC 805. As of August 31, 2014, the initial accounting treatment of the transactions was based upon the preliminary analysis of the assets acquired. During the three months ended November 30, 2015, the Company completed its analysis and finalized the allocation of purchase price to the assets acquired. The values presented in this Note, including the tables herein, present the final result of the analysis.

Trilogy transaction

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

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

Purchase Price	November 12, 2013
Consideration given:
Cash	$	15,902
Synergy Resources Corp. Common Stock *	2,896
Net liabilities assumed, including asset retirement obligations	977
Total consideration given	$	19,775
Allocation of Purchase Price
Proved oil and gas properties	$	11,514
Unproved oil and gas properties	7,725
Other assets, including accounts receivable	536
Total fair value of assets acquired	$	19,775

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

Apollo transaction

On August 27, 2013, the Company entered into a definitive purchase and sale agreement (“the Agreement”), with Apollo Operating, LLC (“Apollo”), for its interests in 38 producing oil and gas wells, partial interest ( 25% ) in one water disposal well

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(the “Disposal Well”), and approximately 3,639 gross ( 1,000 net) mineral acres (“the Apollo Operating Assets”). On November 13, 2013, the Company closed the transaction for a combination of cash and stock. Apollo received cash consideration of approximately $11.0 million and 550,518 shares of the Company’s common stock valued at $5.2 million . Following the Company’s acquisition of the Apollo Operating Assets, the Company acquired all other remaining interests in the Disposal Well (the “Related Interests”) through several transactions with the individual owners of such interests. The Company acquired the Related Interests for approximately $3.7 million in cash consideration and 20,626 shares of the Company’s common stock, valued at $0.2 million . No material transaction costs were incurred in connection with this acquisition.

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

Purchase Price	November 13, 2013
Consideration given:
Cash	$	14,688
Synergy Resources Corp. Common Stock *	5,432
Net liabilities assumed, including asset retirement obligation	1,403
Total consideration given	$	21,523
Allocation of Purchase Price
Proved oil and gas properties	$	13,284
Unproved oil and gas properties	7,577
Other assets, including accounts receivable	662
Total fair value of assets acquired	$	21,523

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

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

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

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

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The following table presents the unaudited pro forma combined results of operations for the two years ended August 31, 2014 and 2013 as if the Trilogy and Apollo transactions had occurred on September 1, 2012, the first day of the year ended August 31, 2013. 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 unaudited 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 unaudited 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.

	Year Ended August 31,
(in thousands)	2014				2013
Oil and gas revenues	$	106,584			$	55,633
Net income	$	29,681			$	13,191
Earnings per common share
Basic	$	0.39			$	0.23
Diluted	$	0.38			$	0.22

4.	Depletion, depreciation, and accretion (“DD&A”)

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

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
					(unaudited)
Depletion of oil and gas properties	$	18,371			$	22,357			$	65,158			$	32,132			$	13,046
Depreciation and accretion	405				217				711				826				290
Total DD&A Expense	$	18,776			$	22,574			$	65,869			$	32,958			$	13,336

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 four months ended December 31, 2015 , production of 1,320 MBOE represented 2.0% of estimated total proved reserves. For the year ended August 31, 2015 , production of 3,194 MBOE represented 5.3% of estimated total proved reserves. For the year ended August 31, 2014 , production of 1,566 MBOE represented 4.6% of estimated total proved reserves. DD&A expense was $14.22 per BOE and $21.94 per BOE for the four months ended December 31, 2015 and 2014, respectively. DD&A expense was $20.62 per BOE, $21.05 per BOE, and $17.26 per BOE for the years ended August 31, 2015 , 2014 , and 2013 , respectively.

5 .	Asset Retirement Obligations

Upon completion or acquisition of a well, the Company recognizes obligations for its oil and gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling sites to its original use.  The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in regulations.  Changes in estimates are reflected in the obligations as they occur.  If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the capitalized asset retirement cost.  For the purpose of determining the fair value of ARO incurred during the periods presented, the Company used the following assumptions:

	Four Months Ended December 31, 2015		Year Ended August 31,
			2015		2014
Inflation rate	3.90%		3.90%		3.90%
Estimated asset life	16.0 - 30.0 years		16.0 - 30.0 years		25.0 - 39.0 years
Credit adjusted risk free rate	8%		8%		8%

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

	Four Months Ended December 31, 2015				Years Ended August 31,
					2015				2014
Beginning asset retirement obligation	$	12,334			$	4,730			$	2,777
Obligations incurred with development activities	1,590				1,372				1,024
Obligations assumed with acquisitions	229				1,913				586
Accretion expense	348				553				343
Obligations discharged with asset retirements and settlements	(1,101		)		—				—
Revisions in previous estimates	—				3,766				—
Ending asset retirement obligation	$	13,400			$	12,334			$	4,730

During the year ended August 31, 2015, the Company increased its asset retirement obligation by $3.8 million due to revising its assumption of the average cost to plug and abandon each well.

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 of December 31, 2015, the terms of the Revolver provide for up to $500 million in borrowings, subject to a borrowing base limitation which was $163 million . As of December 31, 2015, the outstanding principal balance was $78 million . The maturity date of the Revolver is December 15, 2019 .

On January 28, 2016, the Revolver was amended in connection with the previously postponed semi-annual redetermination. The borrowing base was reduced from $163 million to $145 million , and the Revolver was further amended to (i) delete the minimum interest rate floor, (ii) delete the minimum liquidity covenant, (iii) add a current ratio covenant of 1.0 to 1.0, and (iv) delete the minimum hedging requirement. On January 27, 2016, the Company reduced its outstanding borrowings under the Revolver from $78 million to nil .

Interest under the Revolver was payable monthly and accrued at a variable rate.  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 both the four months ended December 31, 2015 and the year ended August 31, 2015 was 2.5% .

Certain of the Company’s assets, including substantially all of the producing wells and proved oil and gas leases, have been designated as collateral under the Revolver. The borrowing base 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 could be prepared. As of March 31, 2016 , based upon a borrowing base of $145 million and an outstanding principal balance of nil , the unused borrowing base available for future borrowing totaled approximately $145 million .  The next semi-annual redetermination is scheduled for May 1, 2016 .

The Revolver also contains covenants that, among other things, restrict the payment of dividends.  Additionally, as of December 31, 2015, the Revolver generally required an overall commodity derivative position that covers a rolling 24 months of estimated future production with a maximum position of 85% of hydrocarbon production as projected in the semi-annual reserve report.

Furthermore, the Revolver requires the Company to maintain certain financial and liquidity ratio compliance covenants. Under the requirements, 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) not, as of the last day of any fiscal quarter, permit its current ratio, as defined in the agreement, to be less than 1.0 to 1.0. As of December 31, 2015, the most recent compliance date, the Company was in compliance with all loan covenants, including the minimum liquidity covenant, except the Company was not in compliance with the covenant related to its overall commodity derivative position whereby the

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Company did not meet the minimum hedging requirement of 45% . The Company has obtained a waiver for this covenant, and this covenant was subsequently deleted by the amendment described above.

7 .	Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, as described below. Our commodity derivative instruments may include but are not limited to “collars,” “swaps,” and “put” positions. Our derivative strategy, including the volume amounts, whether we utilize oil and/or natural gas instruments, and at what commodity prices the instruments are associated with, 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 as amended.

A “put” option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, purchase put options, which require us to pay premiums at the time we purchase the contracts. These premiums represent the fair value of the purchased put as of the date of purchase. The ownership of put options is consistent with our derivative strategy inasmuch as the value of the puts will increase as commodity prices decline, helping to offset the cash flow impact of a decline in realized prices for the underlying commodity. However, if the underlying commodity increases in value, there is a risk that the put option will expire worthless and the net premiums paid would be recognized as a loss.

Conversely, a “call” option gives the owner the right, but not the obligation, to purchase the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, sell call options in conjunction with the purchase of put options to create “collars”. We regularly utilize “no premium” (a.k.a. zero cost) collars constructed by selling call options while simultaneously buying put options, in which the premiums paid for the puts is offset by the premiums received for the calls. Collars are consistent with our derivative strategy inasmuch as the they establish a known range of prices to be received for the associated volume equivalents, that being bound at the upper end by the call’s strike price (the “ceiling”) and at the lower end by the put’s strike price (the “floor”).

Additionally, at times, we may enter into swaps. Swaps are derivative contracts which obligate two counterparties to effectively trade the underlying commodity at a set price over a specified term. Swaps are consistent with our derivative strategy inasmuch as they establish a known future price to be received for the associated equivalent volumes.

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 exit-price 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.

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The Company’s commodity derivative contracts as of December 31, 2015 are summarized below:

Settlement Period		Derivative Instrument		Average Volumes (Bbls per month)			Floor Price				Ceiling Price
Crude Oil - NYMEX WTI
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
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
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 December 31, 2015 and August 31, 2015 and 2014 , 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 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.

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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 December 31, 2015
Underlying Commodity		Balance Sheet Location		Gross Amounts of Recognized Assets and Liabilities				Gross Amounts Offset in the Balance Sheet				Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Commodity Derivative contracts		Current assets		$	6,719			$	(147	)		$	6,572
Commodity Derivative contracts		Noncurrent assets		$	3,354			$	(358	)		$	2,996
Commodity Derivative contracts		Current liabilities		$	147			$	(147	)		$	—
Commodity Derivative contracts		Noncurrent liabilities		$	358			$	(358	)		$	—

				As of August 31, 2015
Underlying Commodity		Balance Sheet Location		Gross Amounts of Recognized Assets and Liabilities				Gross Amounts Offset in the Balance Sheet				Net Amounts of Assets and Liabilities Presented in the Balance Sheet
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	)		$	—

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

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

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
					(unaudited)
Realized gain (loss) on commodity derivatives	$	1,577			$	3,683			$	30,466			$	(2,138	)		$	(395	)
Unrealized gain (loss) on commodity derivatives	4,905				24,018				1,790				2,459				(2,649		)
Total gain (loss)	$	6,482			$	27,701			$	32,256			$	321			$	(3,044	)

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Realized gains and losses include cash received from the monthly settlement of derivative contracts at their scheduled maturity date, the proceeds from early liquidation of in-the-money derivative contracts, and the previously incurred premiums attributable to settled commodity contracts. During the year ended August 31, 2015 , the Company liquidated oil derivatives with an average price of $82.79 and covering 372,500 barrels and received cash settlements of approximately $20.5 million . The following table summarizes derivative realized gains and losses during the periods presented (in thousands):

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
					(unaudited)
Monthly settlement	2,331				3,683				$	11,212			$	(2,138	)		$	(395	)
Previously incurred premiums attributable to settled commodity contracts	(754		)		—				(1,255		)		—				—
Early liquidation	—				—				20,509				—				—
Total realized gain (loss)	$	1,577			$	3,683			$	30,466			$	(2,138	)		$	(395	)

Credit Related Contingent Features

As of December 31, 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; and

•	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 risk free rate, inflation rate, 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. See Note 5 for additional information.

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

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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 market comparables. For the asset retirement obligation assumed, the fair value is determined using the same inputs as described 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  December 31, 2015 and August 31, 2015 and 2014 by level within the fair value hierarchy (in thousands):

	Fair Value Measurements at December 31, 2015
	Level 1				Level 2				Level 3				Total
Financial assets and liabilities:
Commodity derivative asset	$	—			$	9,568			$	—			$	9,568
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	$	—			$	—			$	—			$	—

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

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 market 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 December 31, 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 contracts (discussed above), and revolving 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 revolving credit facility approximated fair value as it bears interest at variable rates over the term of the loan.

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9 .	Interest Expense

The components of interest expense are (in thousands):

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
					(unaudited)
Revolving credit facility	$	661			$	677			$	2,776			$	986			$	1,067
Amortization of debt issuance costs	431				198				853				448				160
Less: interest capitalized	(1,092		)		(875		)		(3,384		)		(1,434		)		(1,130		)
Interest expense, net	$	—			$	—			$	245			$	—			$	97

10 .	Shareholders’ Equity

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

	As of December 31, 2015				As of August 31,
					2015				2014				2013
Preferred stock, shares authorized	10,000,000				10,000,000				10,000,000				10,000,000
Preferred stock, par value	$	0.01			$	0.01			$	0.01			$	0.01
Preferred stock, shares issued and outstanding	nil				nil				nil				nil
Common stock, shares authorized	300,000,000				200,000,000				200,000,000				100,000,000
Common stock, par value	$	0.001			$	0.001			$	0.001			$	0.001
Common stock, shares issued and outstanding	110,033,601				105,099,342				77,999,082				70,587,723

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. During the four months ended December 31, 2015, upon recommendation of the Board of Directors, the sharesholders approved an increase in the number of common shares authorized for issuance from 200,000,000 to 300,000,000 .

Shares of the Company’s common stock were issued during the four months ended December 31, 2015 and each of the years ended August 31, 2015 , 2014 , and 2013 , as described further below.

Sales of common stock

During the years ended August 31, 2015 and 2013 , the Company sold shares of its common stock in public offerings as follows:

•	In February 2015, the Company completed the sale of common stock in an underwritten public offering led by Seaport Global Securities LLC.

•	In June 2013, the Company completed the sale of common stock in an underwritten public offering led by Johnson Rice LLC.

Certain details of each transaction are shown in the following table.  Net proceeds represent amounts received by the Company after deductions for underwriting discounts, commissions and expenses of the offering.

	For the Four Months Ended December 31, 2015				Year Ended August 31,
					2015				2014				2013
Number of common shares sold	—				18,613,952				—				13,225,000
Offering price per common share	$	—			$	10.75			$	—			$	6.25
Net proceeds (in thousands)	$	—			$	190,845			$	—			$	78,243

    

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In January 2016, the Company completed a public offering of its common stock in an underwritten public offering led by Credit Suisse Securities (USA) LLC.  The Company agreed to sell 14,000,000 shares of its common stock to the Underwriters at a price of $5.545 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 2,100,000 shares of common stock on the same terms and conditions. The option was exercised on January 26, 2016, bringing the total number of shares issued to 16,100,000 .  Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $89.1 million .  Proceeds from the offering are expected to be used for general corporate purposes, which may include continuing to develop our acreage position in the Wattenberg Field in Colorado, repaying amounts borrowed under the Revolver, funding a portion of our capital expenditure program for the remainder of 2016, or other uses. Initially, proceeds were used to repay amounts borrowed under the Revolver.

In April 2016, the Company completed a public offering of its common stock in an underwritten public offering led by Credit Suisse Securities (USA) LLC.  The Company agreed to sell 19,500,000 shares of its common stock to the Underwriters at a price of $7.3535 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 2,925,000 shares of common stock on the same terms and conditions. The option was exercised on April 12, 2016, bringing the total number of shares issued to 22,425,000 .  Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $164.8 million .  Proceeds from the offering are expected to be used for general corporate purposes, which may include continuing to develop our acreage position in the Wattenberg Field in Colorado, funding a portion of our capital expenditure program for the remainder of 2016, or other uses. Initially, proceeds were used to repay amounts borrowed under the Revolver.

Common stock issued for acquisition of mineral property interests

During the periods 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.

	For the Four Months Ended December 31, 2015				Year Ended August 31,
					2015				2014				2013
Number of common shares issued for mineral property leases	37,051				995,672				357,901				687,122
Number of common shares issued for acquisitions	4,418,413				4,648,136				872,483				3,128,422
Total common shares issued	4,455,464				5,643,808				1,230,384				3,815,544
Average price per common share	$	11.28			$	10.67			$	9.09			$	4.37
Aggregate value of shares issues (in thousands)	$	50,265			$	60,221			$	11,184			$	16,684

Common stock warrants

The Company previously issued warrants to purchase common stock. There were no warrants outstanding as of August 31, 2015 and December 31, 2015. The following reflects the activity since September 1, 2012:

Series A – During the year ended August 31, 2009, the Company issued 4,098,000 Series A warrants, each of which was immediately exercisable.  Each Series A warrant entitled the holder to purchase one share of common stock for $6.00 .  All of the Series A warrants expired on December 31, 2012.

Series B – During the year ended August 31, 2009, the Company issued 1,000,000 Series B warrants, each of which was immediately exercisable.  Each Series B warrant entitled the holder to purchase one share of common stock for $10.00 .  All of the Series B warrants expired on December 31, 2012.

Series C – During the year ended August 31, 2010, the Company issued 9,000,000 Series C warrants in connection with a unit offering.  Each unit included one convertible promissory note with a face value of $100,000 and 50,000 Series C warrants.  Each Series C warrant entitled the holder to purchase one share of common stock for $6.00 and expired on December 31, 2014, if not previously exercised. During the years ended August 31, 2015 , 2014, and 2013, the following Series C warrants were exercised: 2,561,415 , 5,938,585 , and 500,000 , respectively.

Series D – During the year ended August 31, 2010, the Company issued 1,125,000 Series D warrants to the placement agent for the Series C unit offering.  Each Series D warrant entitled the holder to purchase one share of common stock for $1.60 , and contained a net settlement provision that provided for exercise of the warrants on a cashless basis.  The Series D warrants

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expired, if not previously exercised, on December 31, 2014.  During the years ended August 31, 2015, 2014, and 2013, the following warrants were exercised: 1,058 , 140,744 , and 627,799 , respectively.

Sales Agent Warrants – During the year ended August 31, 2009, the Company issued 31,733 warrants to the sales agent for an equity offering (the "Sales Agent Warrants").  Each Sales Agent Warrant entitled the holder to purchase two shares of common stock for $1.80 per share.  All of the Sales Agent Warrants were exercised during the year ended August 31, 2013.

Investor Relations Warrants – During the year ended August 31, 2012, the Company issued 100,000 warrants to a firm providing investor relations services (the "Investor Relations Warrants").  Each Investor Relations Warrant entitled the holder to purchase one share of common stock for $2.69 , and contained a net settlement provision that provided for exercise of the warrants on a cashless basis.  The warrants became exercisable in equal quarterly installments over a one year period.  During the year ended August 31, 2013, warrants to purchase 50,000 shares became exercisable and warrants to purchase 50,000 shares were forfeited due to early termination of the agreement with the firm.  During the years ended August 31, 2015 , 2014, and 2013, the following Investor Relations Warrants were exercised: nil , 25,000 , and 25,000 , respectively.

The following table summarizes activity for common stock warrants for the periods presented:

	Number of Shares Issuable Upon Warrant Exercise			Weighted-Average Exercise Price Per Share
Outstanding, August 31, 2012	15,031,067			$	6.02
Exercised	(1,216,265	)		$	3.44
Forfeited/Expired	(5,148,000	)		$	6.74
Outstanding, August 31, 2013	8,666,802			$	5.92
Exercised	(6,104,329	)		$	5.88
Forfeited / Expired	—			$	—
Outstanding, August 31, 2014	2,562,473			$	6.00
Exercised	(2,562,473	)		$	6.00
Forfeited / Expired	—			$	—
Outstanding, August 31, 2015	—			$	—
Exercised	—			$	—
Forfeited / Expired	—			$	—
Outstanding, December 31, 2015	—			$	—

11.    Earnings Per Share

    

Basic earnings per share includes no dilution and is computed by dividing net income (loss) by the weighted-average number of shares outstanding during the period.  Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of the Company.  The number of potential shares outstanding relating to stock options, 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.

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

	Four Months Ended December 31,						Year Ended August 31,
	2015			2014			2015			2014			2013
				(unaudited)
Weighted-average shares outstanding - basic	107,789,554			79,971,698			94,628,665			76,214,737			57,089,362
Potentially dilutive common shares from:
Stock options	—			721,712			672,493			479,222			1,881,682
Restricted stock	—			—			18,111			—			—
Warrants	—			—			—			1,114,095			117,717
Weighted-average shares outstanding - diluted	107,789,554			80,693,410			95,319,269			77,808,054			59,088,761

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

	Four Months Ended December 31,						Year Ended August 31,
	2015			2014			2015			2014			2013
				(unaudited)
Potentially dilutive common shares from:
Stock options	5,056,000			588,000			2,785,500			533,000			670,000
Restricted stock	915,867			—			145,000			—			—
Warrants	—			—			—			—			8,500,000
Total	5,971,867			588,000			2,930,500			533,000			9,170,000

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, restricted stock, stock bonus shares, warrants, and other equity awards.  The Company records its 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 was either classified 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.

The amount of stock-based compensation was as follows (in thousands):

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
					(unaudited)
Stock options	$	2,161			$	620			$	4,741			$	1,767			$	1,039
Restricted stock and stock bonus shares	7,162				340				2,950				1,201				277
Investor relations warrants	—				—				—				—				46
Total stock-based compensation	9,323				960				7,691				2,968				1,362
Less: stock-based compensation capitalized	(892		)		(275		)		(778		)		(514		)		(318		)
Total stock-based compensation expense	$	8,431			$	685			$	6,913			$	2,454			$	1,044

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General Description of Stock Award Plans

In December 2015, the Company's shareholders approved the 2015 Equity Incentive Plan (the "2015 Plan"). The 2015 Plan replaced three equity compensation plans: (i) a 2011 non-qualified stock option plan, (ii) a 2011 incentive stock option plan, and (iii) a 2011 stock bonus plan (the "2011 Plans").  No additional options or stock bonus shares will be issued under the 2011 Plans.

The 2015 Plan authorizes 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.  Employees, directors, officers, consultants, and advisors are eligible to receive such awards, provided that bona fide services be rendered by such consultants or advisors (other than services in connection with the offering or sale of securities or as a market maker or promoter of securities of the Company).

As of December 31, 2015, there were 4,500,000 common shares authorized for grant under the 2015 Plan, of which 4,093,200 shares were remaining for future issuance.

Stock options

During the respective periods, the Company granted the following stock options:

	Four Months Ended December 31, 2015				Year Ended August 31,
					2015				2014				2013
Number of options to purchase common shares	1,142,500				2,377,500				433,000				1,025,000
Weighted-average exercise price	$	10.84			$	11.55			$	10.37			$	6.05
Term (in years)	10 years				10 years				10 years				10 years
Vesting Period (in years)	3.7-5 years				3-5 years				5 years				3-5 years
Fair Value (in thousands)	$	6,591			$	13,266			$	3,009			$	4,179

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

	Four Months Ended December 31, 2015			Year Ended August 31,
				2015			2014			2013
Expected term	6.5 years			6.5 years			6.7 years			6.2 years
Expected volatility	53	%		47	%		73	%		77	%
Risk free rate	1.8 - 2.0%			1.4 - 2.0%			1.8 - 2.3%			0.9 - 2.1%
Expected dividend yield	0.0	%		0.0	%		0.0	%		0.0	%
Average forfeiture rate	0.1	%		3.5	%		0.0	%		0.0	%

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The following table summarizes activity for stock options for the periods presented:

	Number of Shares			Weighted-Average Exercise Price				Weighted-Average Remaining Contractual Life		Aggregate Intrinsic Value (thousands)
Outstanding, August 31, 2012	4,915,000			$	5.09			2.2 years		$	3,656
Granted	1,025,000			6.05
Exercised	(2,120,000	)		1.10						15,690
Forfeited	(2,000,000	)		10.00
Outstanding, August 31, 2013	1,820,000			4.88				8.7 years		8,160
Granted	433,000			10.37
Exercised	(61,000	)		3.71						481
Expired	(25,000	)		10.32
Outstanding, August 31, 2014	2,167,000			5.94				8.0 years		16,287
Granted	2,377,500			11.55
Exercised	(258,000	)		3.81						2,103
Forfeited	(110,000	)		4.97
Outstanding, August 31, 2015	4,176,500			9.29				8.6 years		8,187
Granted	1,142,500			10.84
Exercised	(188,000	)		6.56						981
Expired	(60,000	)		11.74
Forfeited	(15,000	)		11.68
Outstanding, December 31, 2015	5,056,000			$	9.71			8.7 years		$	4,351
Outstanding, Exercisable at December 31, 2015	1,451,450			$	7.22			7.3 years		$	3,330
Outstanding, Vested and expected to vest at December 31, 2015	4,943,937			$	9.66			8.6 years		$	4,351

The following table summarizes information about issued and outstanding stock options as of December 31, 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			5.7 years		$	3.51			509,000			$3.50
$5.00 - $6.99		480,000			7.1 years		6.46				375,000			6.54
$7.00 - $10.99		1,120,000			9.1 years		9.93				157,450			9.41
$11.00 - $13.46		2,802,000			9.4 years		11.62				410,000			11.62
Total		5,056,000			8.7 years		$	9.71			1,451,450			$7.22

The estimated unrecognized compensation cost from stock options not vested as of December 31, 2015, which will be recognized ratably over the remaining vesting phase, is as follows:

Unrecognized compensation, net of estimated forfeitures (in thousands)	$	17,199
Remaining vesting phase	3.8 years

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Restricted stock and stock bonus awards

The Company grants shares of restricted stock and stock bonus awards 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 or stock bonus award represents one share of the Company’s common stock to be released from restrictions upon completion of the vesting period. The awards typically vest in equal increments over  three to five years . Shares of restricted stock and stock bonus awards 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 and stock bonus awards for the periods presented:

	Number of Shares			Weighted-Average Grant-Date Fair Value
Not vested, August 31, 2012	13,750			$	3.06
Granted	109,096			6.41
Vested	(76,179	)		5.60
Forfeited	—			—
Not vested, August 31, 2013	46,667			6.75
Granted	343,780			11.34
Vested	(97,114	)		11.38
Forfeited	—			—
Not vested, August 31, 2014	293,333			10.60
Granted	547,699			11.17
Vested	(208,532	)		11.09
Forfeited	—			—
Not vested, August 31, 2015	632,500			10.93
Granted	919,604			10.08
Vested	(636,237	)		10.13
Forfeited	—			—
Not vested, December 31, 2015	915,867			$	10.63

The estimated unrecognized compensation cost from restricted stock and stock bonus awards not vested as of December 31, 2015, which will be recognized ratably over the remaining vesting phase, is as follows:

Unrecognized compensation, net of estimated forfeitures (in thousands)	$	7,982
Remaining vesting phase	3.4 years

13.	Defined Contribution Plan

The Company sponsors a 401(k) defined contribution plan for eligible employees. Company contributions to the 401(k) plan consist of a discretionary matching contribution equal to  100% of compensation deferrals not to exceed 3% of eligible compensation plus 50% of compensation deferrals in excess of 3% of eligible compensation not to exceed more than 5% of eligible compensation. The Company contributed approximately  $0.1 million and $0.1 million for the four months ended December 31, 2015 and 2014, respectively, and $0.1 million , $0.1 million , and less than $0.1 million during the years ended August 31, 2015, 2014, and 2013, respectively, to the plan.

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14 .	Income Taxes

The income tax provision is comprised of the following (in thousands):

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
Current:					(unaudited)
Federal	$	—			$	(4	)		$	(4	)		$	4			$	—
State	—				(111		)		(111		)		111				—
Total current income tax expense (benefit)	$	—			$	(115	)		$	(115	)		$	115			$	—
Deferred:
Federal	$	(45,332	)		$	14,604			$	10,820			$	13,748			$	6,367
State	(4,074		)		1,313				972				1,151				503
Total deferred income tax (benefit) expense	$	(49,406	)		$	15,917			$	11,792			$	14,899			$	6,870
Valuation allowance	39,399				—				—				—				—
Income tax provision (benefit)	$	(10,007	)		$	15,802			$	11,677			$	15,014			$	6,870

A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands):

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
					(unaudited)
Federal income tax at statutory rate	$	(45,200	)		$	14,484			$	10,105			$	14,915			$	5,594
State income taxes, net of federal tax	(4,062		)		1,302				908				1,341				503
Statutory depletion	(150		)		(156		)		(451		)		(1,266		)		(929		)
Stock-based compensation	—				—				92				—				1,911
Non-deductible compensation	—				—				850				125				—
Change in valuation allowance	39,399				—				—				—				—
Other	6				172				173				(101		)		(209		)
Income tax provision	$	(10,007	)		$	15,802			$	11,677			$	15,014			$	6,870
Effective rate expressed as a percentage	8		%		37		%		39		%		34		%		42		%

In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income, and tax planning strategies in making this assessment. Judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits, and other deferred tax assets will be utilized prior to their expiration. As a result, it may be determined that a deferred tax asset valuation allowance should be established or released. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense.

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The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the period ends is presented in the following table (in thousands):

	As of December 31, 2015				As of August 31,
					2015				2014
Deferred tax assets (liabilities):
Net operating loss carryforward	$	11,855			$	3,387			$	8,589
Stock-based compensation	3,304				2,788				1,115
Basis of oil and gas properties	23,656				(18,433		)		(33,409		)
Statutory depletion	2,802				2,652				2,194
Unrealized (gain) loss on commodity derivative	(2,410		)		(593		)		70
Other	192				192				4
	39,399				(10,007		)		(21,437		)
Valuation allowance on tax assets	(39,399		)		—				—
Deferred tax asset (liability), net	$	—			$	(10,007	)		$	(21,437	)

At December 31, 2015, the Company has a net operating loss carryforward for federal and state tax purposes of approximately $44.2 million that could be utilized to offset taxable income of future years. For financial reporting purposes, the Company has net operating losses of approximately $32.0 million for federal and state. The difference of $12.2 million relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable. The net operating loss carryovers may be carried back two years and forward twenty years from the year the net operating loss was generated. Substantially all of the carryforward will commence expiring in 2031 , 2032, and 2033 .

At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income, and tax planning strategies in making an assessment as to the future utilization of deferred tax assets. During the four months ended December 31, 2015, the Company recognized a full valuation allowance on its net deferred tax assets. This decision was based on the fact that for the preceding three-year period, the Company has reported cumulative net losses. 

The ability of the Company to utilize its NOL carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of a Company’s taxable income that can be offset by these carryforwards.

As of December 31, 2015, the Company had no 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.

15 .	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.

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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., members of the Company’s board of directors.  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):

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
					(unaudited)
Rent expense	$	60			$	60			$	180			$	180			$	130

Mineral Leasing Program:  During 2010, the Company initiated a program to acquire mineral interests in several Colorado and Nebraska counties that are considered the eastern portion of the D-J Basin.  George Seward, a member of the Company’s board of directors until his resignation in February 2016, agreed to lead that program.  The Company agreed to compensate certain persons, including Mr. Seward, to assist the Company with the acquisitions at a specific rate per qualifying net mineral acre.  The compensation was paid in the form of restricted shares of the Company’s common stock, as follows:

	Four Months Ended December 31, 2015				Year Ended August 31,
					2015				2014				2013
Shares of restricted common stock	—				—				15,883				31,454
Value of common stock (in thousands)	$	—			$	—			$	106			$	105

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.  The following table discloses the acquisition of mineral leases from Mr. Seward during each of the periods presented:

	Four Months Ended December 31, 2015				Year Ended August 31,
					2015				2014				2013
Mineral acres leased	6,498				—				4,844				2,263
Shares of restricted common stock	22,515				—				40,435				22,202
Value of common stock (in thousands)	$	248			$	—			$	313			$	91

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 four of the Company’s directors or their affiliates, Lynn A. Peterson, Ed Holloway, William Scaff, Jr., and George Seward.   The following table summarizes the aggregate royalty payments made to officers, directors or their affiliates for the periods presented (in thousands):

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
					(unaudited)
Total royalty payments	$	62			$	61			$	209			$	292			$	304

16 .	Other Commitments and Contingencies

Volume Commitments

During 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 four months ended December 31, 2015. Deliveries under the third transportation agreement are not expected to commence until late in 2016. The third party refinery volume commitment expired on December 31, 2015.

    

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Pursuant to these agreements, we must deliver specific amounts of crude oil either from our own production or from oil that 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 December 31,
(in MBbls/year)
2016		2,558
2017		4,072
2018		4,072
2019		4,072
2020		3,517
Thereafter		1,090
Total		19,381

During the four months ended December 31, 2015, the Company incurred a transportation deficiency charge of $2.8 million  as we were unable to meet all of the obligations during the period. 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 15 . 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.

17 .	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):

	Four Months Ended December 31,								Year Ended August 31,
	2015				2014				2015				2014				2013
Supplemental cash flow information:					(unaudited)
Interest paid	$	683			$	645			$	2,817			$	989			$	995
Income taxes paid (refunded)	(150		)		110				202				—				—
Non-cash investing and financing activities:
Accrued well costs payable	$	31,414			$	52,747			$	33,071			$	71,849			$	25,491
Assets acquired in exchange for common stock	50,265				50,330				60,221				11,184				16,684
Asset retirement costs and obligations	1,819				2,224				7,051				1,610				1,578

18.	Unaudited Oil and Gas Reserves Information

Oil and Natural Gas Reserve Information:   Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (prices and costs held constant as of the date the estimate is made).  Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing

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equipment and operating methods.  Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Proved oil and natural gas reserve information as of the period ends presented and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott Company LP.  Reserve information for the properties was prepared in accordance with guidelines established by the SEC.

The reserve estimates prepared as of each of the period ends presented were prepared in accordance with “Modernization of Oil and Gas Reporting” published by the SEC.  The guidance included updated definitions of proved developed and proved undeveloped oil and gas reserves, oil and gas producing activities and other terms.  Proved oil and gas reserves were calculated based on the prices for oil and gas during the twelve-month period before the respective reporting date, determined as the unweighted arithmetic average of the first day of the month price for each month within such period, rather than the year-end spot prices, which had been used in prior years.  This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows.  Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years of initial booking.  The guidance broadened the types of technologies that may be used to establish reserve estimates.

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The following table sets forth information regarding the Company’s net ownership interests in estimated quantities of proved developed and undeveloped oil and gas reserve quantities and changes therein for each of the periods presented:

	Oil (MBbl)			Gas (MMcf)			MBOE
Balance, August 31, 2012	5,086			33,446			10,660
Revision of previous estimates	(194	)		(2,924	)		(681	)
Purchase of reserves in place	1,000			7,361			2,228
Extensions, discoveries, and other additions	1,576			4,915			2,395
Sale of reserves in place	—			—			—
Production	(421	)		(2,108	)		(773	)
Balance, August 31, 2013	7,047			40,690			13,829
Revision of previous estimates	83			3,047			591
Purchase of reserves in place	1,028			5,956			2,021
Extensions, discoveries, and other additions	9,142			49,289			17,357
Sale of reserves in place	(35	)		(56	)		(44	)
Production	(941	)		(3,747	)		(1,566	)
Balance, August 31, 2014	16,324			95,179			32,188
Revision of previous estimates	(1,699	)		(4,889	)		(2,513	)
Purchase of reserves in place	4,201			21,957			7,860
Extensions, discoveries, and other additions	11,465			73,392			23,696
Sale of reserves in place	(629	)		(4,337	)		(1,352	)
Production	(1,970	)		(7,344	)		(3,194	)
Balance, August 31, 2015	27,692			173,958			56,685
Revision of previous estimates	(10,917	)		(38,931	)		(17,407	)
Purchase of reserves in place	4,380			58,959			14,207
Extensions, discoveries, and other additions	8,263			62,301			18,647
Sale of reserves in place	(2,297	)		(14,149	)		(4,655	)
Production	(742	)		(3,468	)		(1,320	)
Balance, December 31, 2015	26,379			238,670			66,157
Proved developed and undeveloped reserves:
Developed at August 31, 2013	4,659			25,866			8,970
Undeveloped at August 31, 2013	2,388			14,824			4,859
Balance, August 31, 2013	7,047			40,690			13,829
Developed at August 31, 2014	6,616			38,162			12,977
Undeveloped at August 31, 2014	9,708			57,017			19,211
Balance, August 31, 2014	16,324			95,179			32,188
Developed at August 31, 2015	7,393			46,026			15,064
Undeveloped at August 31, 2015	20,299			127,932			41,621
Balance, August 31, 2015	27,692			173,958			56,685
Developed at December 31, 2015	8,410			56,751			17,868
Undeveloped at December 31, 2015	17,969			181,919			48,289
Balance, December 31, 2015	26,379			238,670			66,157

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Notable changes in proved reserves for the four months ended December 31, 2015 included:

•	Purchases of reserves in place. For the four months ended December 31, 2015, purchases of reserves in place of 14,207 MBO E were attributable to the acquisition of proved reserves from K.P. Kauffman. Please see Note 3 for further information.

•

Revision of previous estimates. For the four months ended December 31, 2015, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 17,407 MBOE. As the Company continued to revise its drilling plans, the development plan removes undeveloped reserves that are not projected to be drilled in the next three years and reflects the lower development costs anticipated from transitioning to a monobore wellbore design and longer horizontal wells.

•

Extensions and discoveries. For the four months ended December 31, 2015, total extensions and discoveries of 18,647 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The Company drilled 9 successful exploratory wells; in addition, we high-graded our inventory of wells to be drilled. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations.

Notable changes in proved reserves for the year ended August 31, 2015 included:

•	Purchases of reserves in place. For the year ended August 31, 2015 , purchases of reserves in place of 7,860 MBO E were attributable to the acquisition of proved reserves from Bayswater. Please see Note 3 for further information.

•	Revision of previous estimates. For the year ended August 31, 2015 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 2,513 MBOE. As the Company continued to revise its drilling plans toward horizontal drilling, the vertical proved undeveloped and vertical developed non-producing locations were removed from its development plan.

•	Extensions and discoveries. For the year ended August 31, 2015 , total extensions and discoveries of 23,696 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The Company drilled 67 successful exploratory wells. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations.

Notable changes in proved reserves for the year ended August 31, 2014 included:

•	Purchases of reserves in place. For the year ended August 31, 2014 , purchases of reserves in place of 2,021 MBOE were attributable to the acquisition of producing oil and gas wells and undeveloped acreage from Trilogy Resources, LLC and Apollo Operating, LLC.  Please see Note 3 for further information.

•

Revision of previous estimates.   For the year ended August 31, 2014 , revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 591 MBOE. The prices for the August 31, 2014 oil and gas reserves are based on the 12 month arithmetic average for the first of month prices as adjusted for our differentials from September 1, 2013 through August 31, 2014 . The August 31, 2014 crude oil price of $89.48 per barrel (West Texas Intermediate Cushing) was $3.08 higher than the August 31, 2013 crude oil price of $86.40 per barrel. The August 31, 2014 natural gas price of $5.03 per Mcf (Henry Hub) was $0.63 higher than the August 31, 2013 price of $4.40 per Mcf.

•	Extensions and discoveries.  For the year ended August 31, 2014 , total extensions and discoveries of 17,357 MBOE were primarily attributable to successful drilling in the Wattenberg Field.  The new producing wells in this area and their adjacent proved undeveloped locations added during the year increased the Company’s proved reserves.

Notable changes in proved reserves for the year ended August 31, 2013 included:

•	Purchases of reserves in place.   For the year ended August 31, 2013 , purchases of reserves in place of 2,228 MBOE were attributable to the acquisition of 36 producing oil and gas wells and undeveloped acreage from Orr Energy, LLC.

•	Revision of previous estimates.  For the year ended August 31, 2013 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 681 MBOE as the Company’s drilling schedule was adjusted to reflect the elimination of previously planned vertical drilling locations as the development focus shifted from vertical to horizontal drilling.

•	Extensions and discoveries.   For the year ended August 31, 2013 , total extensions and discoveries of 2,395 MBOE were primarily attributable to successful drilling in the Wattenberg Field.  The new producing wells in this area and their adjacent proved undeveloped locations added during the year increased the Company’s proved reserves.

Standardized Measure of Discounted Future Net Cash Flows:  The following analysis is a standardized measure of future net cash flows and changes therein related to estimated proved reserves.  Future oil and gas sales have been computed by applying average prices of oil and gas during each of the periods presented.  Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the period,

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based on period-end costs.  The calculation assumes the continuation of existing economic conditions, including the use of constant prices and costs.  Future income tax expenses were calculated by applying period-end statutory tax rates, with consideration of future tax rates already legislated, to future pretax cash flows relating to proved oil and gas reserves, less the tax basis of properties involved and tax credits and loss carryforwards relating to oil and gas producing activities.  All cash flow amounts are discounted at 10% annually to derive the standardized measure of discounted future cash flows.  Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s oil and gas reserves.  Actual future net cash flows from oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and gas, the amount and timing of actual production, supply of and demand for oil and gas, and changes in governmental regulations or taxation.

The following table sets forth the Company’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed by the SEC (in thousands):

	As of December 31, 2015				As of August 31,
					2015				2014				2013
Future cash inflow	$	1,710,610			$	2,046,615			$	1,839,987			$	749,030
Future production costs	(462,097		)		(653,009		)		(395,019		)		(146,352		)
Future development costs	(340,449		)		(510,720		)		(412,517		)		(108,290		)
Future income tax expense	(108,172		)		(144,399		)		(252,925		)		(113,545		)
Future net cash flows	799,892				738,487				779,526				380,843
10% annual discount for estimated timing of cash flows	(408,939		)		(372,658		)		(376,827		)		(199,111		)
Standardized measure of discounted future net cash flows	$	390,953			$	365,829			$	402,699			$	181,732

There have been significant fluctuations in the posted prices of oil and natural gas during the last three years.  Prices actually received from purchasers of the Company’s oil and gas are adjusted from posted prices for location differentials, quality differentials, and Btu content. Estimates of the Company’s reserves are based on realized prices.

The following table presents the prices used to prepare the reserve estimates, based upon the unweighted arithmetic average of the first day of the month price for each month within the twelve-month period prior to the end of the respective reporting period presented as adjusted for our differentials:

	Oil (Bbl)				Gas (Mcf)
August 31, 2013 (Average)	$	86.40			$	4.40
August 31, 2014 (Average)	$	89.48			$	5.03
August 31, 2015 (Average)	$	53.27			$	3.28
December 31, 2015 (Average)	$	41.33			$	2.60

The prices for the December 31, 2015 oil and gas reserves are based on the twelve-month arithmetic average for the first of month prices as adjusted for our differentials from January 1, 2015 through December 31, 2015. The December 31, 2015 crude oil price of $41.33 per barrel (West Texas Intermediate Cushing) was $11.94 lower than the August 31, 2015 crude oil price of $53.27 per barrel. The December 31, 2015 natural gas price of $2.60 per Mcf (Henry Hub) was $0.68 lower than the August 31, 2015 price of $3.28 per Mcf.

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Changes in the Standardized Measure of Discounted Future Net Cash Flows:   The principle sources of change in the standardized measure of discounted future net cash flows are (in thousands):

	Four Months Ended December 31, 2015				Year Ended August 31,
					2015				2014				2013
Standardized measure, beginning of period	$	365,829			$	402,699			$	181,732			$	102,505
Sale and transfers, net of production costs	(25,222		)		(98,486		)		(86,808		)		(38,569		)
Net changes in prices and production costs	(81,968		)		(233,051		)		15,828				(4,550		)
Extensions, discoveries, and improved recovery	116,343				173,918				300,087				70,191
Changes in estimated future development costs	(7,195		)		10,002				(20,817		)		(6,006		)
Development costs incurred during the period	5,923				4,957				15,000				5,106
Revision of quantity estimates	(36,820		)		(38,340		)		4,589				(14,214		)
Accretion of discount	14,610				57,629				23,612				35,103
Net change in income taxes	25,263				58,547				(76,616		)		(7,850		)
Divestitures of reserves	(43,754		)		(19,234		)		(925		)		—
Purchase of reserves in place	77,024				56,795				47,017				40,016
Changes in timing and other	(19,080		)		(9,607		)		—				—
Standardized measure, end of period	$	390,953			$	365,829			$	402,699			$	181,732

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19 .	Unaudited Quarterly Financial Data

The Company’s unaudited quarterly financial information is as follows (in thousands, except share data):

	Three Months Ended November 30, 2015
Revenues	$	26,137
Expenses	161,664
Operating income (loss)	(135,527		)
Other income (expense)	3,192
Income (loss) before income taxes	(132,335		)
Income tax provision (benefit)	(10,007		)
Net income (loss)	$	(122,328	)
Net income (loss) per common share: (1)
Basic	$	(1.14	)
Diluted	$	(1.14	)
Weighted-average shares outstanding:
Basic	107,105,253
Diluted	107,105,253

	Year Ended August 31, 2015
	First Quarter				Second Quarter				Third Quarter				Fourth Quarter
Revenues	$	42,538			$	23,713			$	26,033			$	32,559
Expenses	27,783				25,417				29,102				44,919
Operating income (loss)	14,755				(1,704		)		(3,069		)		(12,360		)
Other income (expense)	18,140				9,563				(1,245		)		5,639
Income (loss) before income taxes	32,895				7,859				(4,314		)		(6,721		)
Income tax provision (benefit)	11,744				3,207				(1,833		)		(1,441		)
Net income (loss)	$	21,151			$	4,652			$	(2,481	)		$	(5,280	)
Net income (loss) per common share: (1)
Basic	$	0.27			$	0.05			$	(0.02	)		$	(0.05	)
Diluted	$	0.26			$	0.05			$	(0.02	)		$	(0.05	)
Weighted-average shares outstanding:
Basic	79,008,719				89,903,288				104,234,519				105,084,651
Diluted	80,141,152				90,636,107				(2)				(2)

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	Year Ended August 31, 2014
	First Quarter				Second Quarter				Third Quarter				Fourth Quarter
Revenues	$	19,266			$	23,028			$	25,672			$	36,253
Expenses	12,048				13,550				14,413				20,744
Operating income	7,218				9,478				11,259				15,509
Other income (expense)	2,269				(1,979		)		(983		)		1,096
Income before income taxes	9,487				7,499				10,276				16,605
Income tax provision	3,387				2,338				3,116				6,173
Net income	$	6,100			$	5,161			$	7,160			$	10,432
Net income per common share: (1)
Basic	$	0.08			$	0.07			$	0.09			$	0.13
Diluted	$	0.08			$	0.07			$	0.09			$	0.13
Weighted-average shares outstanding:
Basic	73,674,865				76,203,938				77,176,420				77,771,916
Diluted	76,044,605				77,990,416				79,008,619				79,698,720

1	The sum of net income (loss) per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year.

2	Common share equivalents were excluded from the calculation of net income (loss) per share as the inclusion of the common share equivalents was anti-dilutive.

20.	Subsequent Events

See Note 6 for discussion related to the Company's January 28, 2016 amendment of its Revolver.

See Note 10 for discussion related to the Company's January and April 2016 equity offerings.

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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 22th day of April, 2016 .

	SYNERGY RESOURCES CORPORATION
	/s/ Lynn A. Peterson
	Lynn A. Peterson, Principal Executive Officer
	/s/ James P. Henderson
	James P. Henderson, Principal Financial Officer
	/s/ Frank L. Jennings
	Frank L. Jennings, Principal Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of l934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature		Title		Date
/s/ Lynn A. Peterson		President, Chief Executive Officer, and Director		April 22, 2016
Lynn A. Peterson		(Principal Executive Officer)
/s/ Ed Holloway		Director		April 22, 2016
Ed Holloway
/s/ William E. Scaff, Jr.		Director		April 22, 2016
William E. Scaff, Jr.
/s/ Rick Wilber		Director		April 22, 2016
Rick Wilber
/s/ Raymond E. McElhaney		Director		April 22, 2016
Raymond E. McElhaney
/s/ R. W. Noffsinger, III		Director		April 22, 2016
R. W. Noffsinger, III
/s/ Jack N. Aydin		Director		April 22, 2016
Jack N. Aydin
/s/ Daniel E. Kelly		Director		April 22, 2016
Daniel E. Kelly