10-K 1 syrg20150831-10k.htm 10-K 10-K


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

FORM 10-K


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

For the fiscal year ended August 31, 2015

OR

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

For the transition period from _______________________ to _______________________

Commission file number:  001-35245

 SYNERGY RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)

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

1625 Broadway, Suite 300, Denver, CO
80202
(Address of principal executive offices) 
(Zip Code)
 
Registrant's telephone number, including area code: (720) 616-4300

Securities registered pursuant to Section 12(b) of the Act:

Title of each class
 
Name of each exchange on which registered
Common Stock
 
NYSE MKT

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý  No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o   No ý

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

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





Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant's  knowledge,  in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer  x
Accelerated filer  o
 
 
Non-accelerated filer  o   (Do not check if a smaller reporting company)    
Smaller reporting company  o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act):  Yes ý No o

The aggregate market value of the voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant’s common stock on February 28, 2015, was approximately $1.1 billion.  Shares of the registrant’s common stock held by each officer and director and each person known to the registrant to own 10% or more of the outstanding voting power of the registrant have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not a determination for other purposes.

As of October 10, 2015, the Registrant had 105,111,133 issued and outstanding shares of common stock.




PART I

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.

The identification in this report of factors that may affect our future performance and the accuracy of forward-looking statements is meant to be illustrative and by no means exhaustive. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty.

Factors that could cause our actual results to differ materially from those expressed or implied by forward-looking statements include, but are not limited to:

extended or further decline in oil and natural gas prices;
operating hazards that adversely affect our ability to conduct business;
uncertainties in the estimates of proved reserves;
effect of seasonal weather conditions and wildlife restrictions on our operations;
our ability to fund, develop, produce and acquire additional oil and natural gas reserves that are economically recoverable;
our ability to obtain adequate financing;
effect of local and regional factors on oil and natural gas prices;
incurrence of ceiling test write-downs;
our inability to control operations on properties we do not operate;
availability and capacity of gathering systems and pipelines for our production;
the strength and financial resources of our competitors;
our ability to successfully identify, execute or effectively integrate future acquisitions;
effect of federal, state and local laws and regulations;
effects of new environmental legislation or regulatory initiatives, including those related to hydraulic fracturing;
our ability to market our production;
the effects of local moratoria or bans on our business;
effect of environmental liabilities;
effect of the adoption and implementation of new statutory and regulatory requirements for derivative transactions;
changes in U.S. tax laws;
our ability to satisfy our contractual obligations and commitments;
the amount of our indebtedness and ability to maintain compliance with debt covenants;
key executives allocating a portion of their time to other business interests;
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 in "Risk Factors."


1



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 Annual 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 recoveries.

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.

Fracture or 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.

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

2




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

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.

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 depreciation, depletion or amortization 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.

3




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.


4



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 liquids 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 August 31, 2015, we have completed, acquired or participated in 582 gross (407 net) productive oil and gas wells. As of August 31, 2015, we are the operator of 423 producing wells and participate as non-operators in 159 producing wells. In addition to the wells that reached productive status by August 31, 2015, there were 28 gross (17 net) wells in various stages of drilling or completion as of that date.

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 142 gross (78 net) horizontal wells. As of August 31, 2015, we are the operator of 33 gross (32 net) Codell horizontal wells and 38 gross (37 net) Niobrara horizontal wells.

For the fiscal year ended August 31, 2015, our average net daily production was 8,750 BOED. By comparison, during our 2014 and 2013 fiscal years, our average production rate was 4,290 BOED and 2,117 BOED, respectively. By the end of our 2015 fiscal year, over 80% of our daily operated production was from horizontal wells. At the beginning of fiscal 2014, less than 10% of our production was from horizontal wells.

2015 Key Developments
    
During the fiscal year ended August 31, 2015, we continued to execute our plans for rapid growth, more than doubling our oil and gas production on a BOE basis through development of our existing oil and gas properties and strategic acquisitions of producing properties. During the year, oil prices declined 49%, which directly impacted both our revenues for the year and our costs to produce oil and gas. Revenue for the year ended August 31, 2015 was $124.8 million and net income was $18.0 million, or $0.19 per diluted share, compared to revenue of $104.2 million and net income of $28.9 million for the prior fiscal year. See further discussion of our financial and operational results for the year ended August 31, 2015 in Part II, Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations.


5



Significant business developments for the year ended August 31, 2015 are described below.

Acquisition Activity

Pending Acquisition

Subsequent to our fiscal year end, on September 15, 2015, we announced an agreement for the purchase 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 5 net) horizontal wells in the Niobrara and Codell formations. Current net production associated with the purchased assets is approximately 1,200 BOED. The purchase price for the assets is $78.0 million, comprised of $35.0 million in cash and approximately 4.4 million restricted shares of Synergy common stock, subject to closing adjustments. The transaction has an effective date of September 1, 2015 and is expected to close on or before October 30, 2015.

2015 Acquisition

During the fiscal 2015, we completed the acquisition of certain assets from three independent oil and gas companies collectively known as “Bayswater”. 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, as part of the Bayswater acquisition, we acquired working interests in 17 non-operated horizontal wells, 73 operated vertical wells, and 11 non-operated vertical wells. Consideration paid to Bayswater, after customary closing and post-closing adjustments, consisted of approximately $74.2 million in cash and 4.6 million shares of our common stock plus the assumption of certain liabilities.

Financing

Equity offering

During fiscal 2015, we completed a public offering of 18,613,952 shares of our common stock (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. On February 2, 2015, we received net proceeds of approximately $190.8 million after deducting underwriting discounts, commissions and other offering expenses.

Revolving Credit Facility

We continue to maintain a borrowing arrangement with our bank syndicate to provide us with needed liquidity, which we will use to develop oil and gas properties, acquire new oil and gas properties, and for working capital and other general corporate purposes. This revolving credit facility (the "Revolver"), which was amended twice during our 2015 fiscal year to increase our maximum loan commitment and to increase our borrowing base, currently 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 August 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. See further discussion in Note 6 to our consolidated financial statements.

Commodity Contracts

We utilize put options, swaps and collars to reduce the impact of commodity price changes on a portion of our anticipated future oil and gas production. Our objective in using derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk. Using puts and collars as of October 1, 2015, we have contracted for approximately 0.7 million Bbls of oil and 3,036 MMcf of gas through August 31, 2017. The high average commodity prices experienced during 2014 enabled us to enter oil and natural gas contracts which were designed to protect us against potential price declines in 2015. The settlement and partial liquidation of these positions during the 2015 fiscal year created a realized 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. Additionally, the decline in posted prices at the end of our fiscal year created an unrealized increase in the fair value of our open commodity contracts of $1.8 million. Subsequent to August 31, 2015, the Company added an additional put option for 120,000 Bbls of oil at a floor price of $45 per Bbl.


6



Properties

As of August 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 27.7 MMBbls of oil and condensate and 174.0 Bcf of natural gas. As of August 31, 2015, we had approximately 442,000 gross and 342,000 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 50,000 gross and 37,000 net acres) and the “North East Extension Area” of the Wattenberg Field (approximately 109,000 gross and 52,000 net acres). In addition, we hold approximately 186,000 gross (182,000 net) acres in southwest Nebraska, a conventional oil-prone prospect, and approximately 90,000 gross (64,000 net) acres in far eastern Colorado.

Within our leasehold in the North East Extension Area we have drilled and as of the 2015 fiscal year end were in the process of completing our first horizontal well targeting the Greenhorn formation. Within our southwestern Nebraska leasehold, we have entered into a joint exploration agreement with a private operating company based in Denver to drill up to ten wells in a defined Area of Mutual Interest. 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.

We currently operate over 82% of our proved producing reserves and over 98% of our fiscal 2015 drilling and completion expenditures were 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.

During fiscal 2015, in addition to increasing our proved reserves via drilling activities and increasing our leasehold via organic leasing, we increased our estimated reserves and mineral leasehold acres through the acquisition of additional oil and gas properties and assets, as described in “2015 Acquisition” above.

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. We intend to follow a balanced risk strategy by allocating capital expenditures to a combination of lower risk development and exploitation activities and higher potential exploration prospects. Key elements of our business strategy include the following:

Concentrate on our existing core area in and around the D-J Basin, where we have significant operating experience.  All of our current wells are located within the D-J Basin and our undeveloped acreage is located either in or adjacent to the D-J Basin.  Focusing our operations in this area leverages our management, technical and operational experience in the basin.
 
Develop and exploit existing oil and natural gas properties.  Since inception our principal growth strategy has been to develop and exploit our acquired and leased properties to add proved reserves.  In the Wattenberg Field, we target three benches of the Niobrara formation as well as the Codell formation for horizontal drilling and production. Our plans focus on horizontal development as we believe horizontal drilling is the most efficient way to recover the potential hydrocarbons. We consider the Wattenberg Field to be relatively low-risk because information gained from the large number of existing wells can be applied to potential future wells.  There is enough similarity between wells in the Wattenberg Field that the exploitation process is generally repeatable.

Improve hydrocarbon recovery through increased well density.  We utilize the best available industry practices in our effort to determine the optimal recovery area for each well. When we began our operated horizontal well development program in the Wattenberg Field, we assumed spacing of 16 wells per 640 acre section. With increased experience and industry knowledge, we are now testing up to 24 horizontal wells per section.
 
Complete selective acquisitions.  We seek to acquire developed and undeveloped oil and gas properties, primarily in the D-J Basin and certain adjacent areas.  We generally seek acquisitions that will provide us with opportunities for reserve additions and increased cash flow through production enhancement and additional development and exploratory prospect generation.
 
Retain control over the operation of a substantial portion of our production. As operator of a majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled or existing wells to be re-completed.  This allows us to modify our capital spending as our financial resources and underlying lease terms allow and market conditions permit.


7



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

Use the latest technology to maximize returns.  Beginning in fiscal 2013, we shifted our emphasis away from drilling vertical wells towards drilling horizontal wells. In doing so, we have significantly increased our production and the value of our asset base. While horizontal drilling requires higher up-front costs, these wells have generated relatively higher returns on our capital deployed. Increasing the number of wells drilled within a given drilling section and applying technical advances in drilling and completion designs is leading to enhanced productivity. Production results from various well designs are analyzed and the conclusions from each analysis are factored into future well designs that take into account spacing between hydraulic fracturing stages, potential communication between wellbores, lateral length, timing and economics. Similarly, we evaluate the use of different completion fluids.
      
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 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 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 66% of our anticipated future net drilling locations, 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 of 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 August 31, 2015, approximately 49% of our estimated proved reserves were oil and condensate and 51% were natural gas and natural gas liquids, measured on a Btu equivalent basis. We believe 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.


8



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 fiscal year. During fiscal 2015, we drilled 67 horizontal wells that are classified as exploratory. Although the wells were drilled in an area that contained productive vertical wells, the area had not been proved on a horizontal basis. Therefore, the new wells met the definition of exploratory wells.

 
Years Ended August 31,
 
2015
 
2014
 
2013
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development Wells:
 
 
 
 
 
 
 
 
 
 
 
Productive:
 
 
 
 
 
 
 
 
 
 
 
Oil
8

 
1

 
47

 
22

 
48

 
32

Gas
1

 

 
2

 
1

 

 

Nonproductive

 

 

 

 

 

 
 
 
 
 
 
 
 
 
 
 
 
Exploratory Wells:
 
 
 
 
 
 
 
 
 
 
 
Productive:
 
 
 
 
 
 
 
 
 
 
 
Oil
67

 
40

 
11

 
10

 

 

Gas

 

 

 

 

 

Nonproductive

 

 
1

 

 

 


As of August 31, 2015, there were 28 gross (17 net) wells in progress that were not included in the above well counts. All of the oil wells are located in, or adjacent to, the Wattenberg Field of the D-J Basin. Three gas wells are located in Yuma County, Colorado.

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

 
Years Ended August 31,
 
2015
 
2014
 
2013
Production:
 
 
 
 
 
Oil (MBbls)
1,970

 
941

 
421

Gas (MMcf)
7,344

 
3,747

 
2,108

MBOE
3,194

 
1,566

 
773

 
 
 
 
 
 
Average sales price:
 
 
 
 
 
Oil ($/Bbl)
$
50.75

 
$
89.98

 
$
85.95

Gas ($/Mcf)
$
3.39

 
$
5.21

 
$
4.75

BOE
$
39.09

 
$
66.56

 
$
59.83

 
 
 
 
 
 
Average production cost per BOE
$
4.70

 
$
5.10

 
$
4.42



Major Customers

Historically, we sold our crude oil production to local refineries and, to a lesser degree, third-party marketers. During fiscal 2015, we secured contracts with additional oil purchasers who intend to transport oil via pipelines. Under the contracts, we

9



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 both gas processing and crude oil takeaway capacity are sufficient to meet our anticipated production growth. See further discussion in Note 14 to our consolidated financial statements.

Oil and Gas Properties, Wells, Operations and Acreage

We evaluate undeveloped oil and gas prospects and participate in drilling activities on those prospects that our management believes are favorable for the production of oil or gas.  If, through our review, a geographical area indicates geological and economic potential, we will attempt to acquire leases or other interests in the area.  We may then attempt to sell portions of our leasehold interests in a prospect to third parties, thus sharing the risks and rewards of the exploration and development of the prospect with the other owners.  One or more wells may be drilled on a prospect, and if the results indicate the presence of sufficient oil and gas reserves, additional wells may be drilled on the prospect.

We may also:

acquire a working interest in one or more prospects from others and participate with the other working interest owners in drilling, and if warranted, completing oil or gas wells on a prospect, or
 
purchase producing oil or gas properties.

We believe 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 under purchase agreements and leasehold assignments;

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.


10



The following table shows, as of October 10, 2015, 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
582

 
407

 
24,555

 
19,400

 
232,411

 
139,400

Nebraska

 

 

 

 
191,520

 
187,677

Wyoming

 

 

 

 
1,143

 
472

Kansas

 

 

 

 
840

 
840

Total
582

 
407

 
24,555

 
19,400

 
425,914

 
328,389


        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.

    The following table shows, as of October 10, 2015, the status of our gross acreage:

State
Held by Production
 
Not Held by Production
 
 
 
 
Colorado
24,555

 
232,411

Nebraska

 
191,520

Wyoming

 
1,143

Kansas

 
840

Total
24,555

 
425,914


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
76,537
 
2016
31,361
 
2017
51,110
 
2018
266,906
 
After 2018

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

Oil and Gas Reserves
 
As a result of our drilling, acquisition and participation activities, we increased our estimated proved reserve quantities by 76% from August 31, 2014 to August 31, 2015.  Our August 31, 2015, reserve report indicated that we had estimated proved reserves of 27.7 million barrels of oil and 174.0 billion cubic feet of gas. The estimated PV-10 value of our reserves at that date was $438.3 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 "Non-GAAP Financial Measures."

Ryder Scott Company, L.P. (“Ryder Scott”) prepared the estimates of our proved reserves, future production and income

11



attributable to our leasehold interests as of August 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 October 2, 2015, 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 to this Annual Report on Form 10-K.

Ed Holloway, our co-Chief Executive Officer, in collaboration with our lead engineer, oversaw the preparation of the reserve estimates by Ryder Scott to ensure accuracy and completeness of the data prior to and after submission.  Mr. Holloway has 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 Bbls 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 August 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 proved non-producing and undeveloped reserves were estimated by the analogy method.  The analogy method uses pertinent well data obtained from public sources that was available through August 31, 2015.
 
Below are estimates of our net proved reserves at August 31, 2015, all of which are located in Colorado:

 
Oil
(MBbls)
 
Gas
(MMcf)
 
MBOE
Proved:
 
 
 
 
 
Developed
7,393

 
46,026

 
15,064

Undeveloped
20,299

 
127,932

 
41,621

Total
27,692

 
173,958

 
56,685


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

 
Proved - August 31, 2015
 
Developed
 
 
 
Total
 
Producing
 
Nonproducing
 
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



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Proved - August 31, 2014
 
Developed
 
 
 
Total
 
Producing
 
Nonproducing
 
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
 
Nonproducing
 
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, partially offset by declining future 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 to the year ended August 31, 2014. However, future pre-tax net cash flow decreased $149.6 million from August 31, 2015 to August 31, 2014 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. The prices for the 2015 oil and gas reserves are based on the twelve-month arithmetic average for the first of month prices from September 1, 2014 through August 31, 2015. The 2015 crude oil price of $53.27 per barrel (West Texas Intermediate Cushing) was $36.21 lower than the 2014 crude oil price of $89.48 per barrel. The 2015 natural gas price of $3.28 per Mcf (Henry Hub) was $1.75 lower than the 2014 price of $5.03 per Mcf.

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.


13



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


At August 31, 2015, our proved undeveloped reserves were 41,621 MBOE. In an effort to delineate more of our acreage, much of our 2015 capital program 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 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.

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 fiscal year 2015, this effect has increased with the downturn in commodity prices as we have scaled back our drilling and completion operations in the reduced price environment. Based on our current drilling plans for the next five 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, we eliminated all undeveloped locations related to all vertical wellbores as well as all recompletion activities related to existing vertical wellbores. This reduced proved undeveloped reserves by 4.1 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 2,689 MBOE during fiscal 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, 2014, our proved undeveloped reserves were 19,211 MBOE. During fiscal 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 2014 capital program resulted in the addition of 13,436 MBOE in proved undeveloped reserves.

Delivery Commitments

See "Volume Commitments" in Note 14 to our consolidated 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

14



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 which 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 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.

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 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. This new rulemaking will address both local government collaboration with oil and gas operators concerning 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,

15



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. 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 we have been, nor do we anticipate 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 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.

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

16



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 may propose revised resource extraction payments disclosure rules applicable to our business.
 
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.  The recent trend in environmental legislation and regulation is 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 liabilities 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.  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 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.  In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” 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

17



and natural gas operations in such areas to become subject to more stringent emissions controls, emission offset requirements and increased permitting delays and costs.

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. Depending upon 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 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 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.

Climate change has emerged as an important topic in public policy debate regarding our environment.  It is a complex issue, with some scientific research suggesting that rising global temperatures are the result of an increase in greenhouse gases, which may ultimately pose a risk to society and the environment.  In 2009, the EPA found that emissions of greenhouse gases present an endangerment to human health and the environment because such emissions are, according to the EPA, contributing to global warming and other climatic changes. Congress has considered a number of legislative proposals to restrict greenhouse gas emissions, and a number of states have begun taking actions to control or reduce such emissions. Products produced by the oil and natural gas exploration and production industry are a source of certain greenhouse gases, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future 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 we commonly employ and expect to employ extensively in future wells that we drill and complete.

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 we are required to obtain and the notice of intent 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 fracture stimulation 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 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

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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 2015.

Federal agencies have also adopted or are considering additional regulation of hydraulic fracturing. In September 2013, the U.S. Occupational Safety and Health Administration (“OSHA”) proposed stricter standards for worker exposure to silica, which would apply to the use of 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 to hydraulically fracture 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.

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 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

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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

Beginning October 15, 2015, 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.

Previously, our Platteville offices, which included both our headquarters (until October 15, 2015) and which still include field offices and an equipment yard, are rented to us pursuant to a lease with HS Land & Cattle, LLC, a firm controlled by Ed Holloway and William E. Scaff, Jr., our co-Chief Executive Officers. The 2015 lease, which expired on July 1, 2015, required monthly payments of $15,000. The lease is currently on a month-to-month basis at a rental of $15,000 per month.

As of August 31, 2015, we had 36 full-time employees. Subsequent to August 31, 2015, concurrent with the relocation of our offices to Denver, CO, we have continued to add additional employees to better prepare the business for execution of our future growth strategy.

Available Information
    
We make available on our website, www.syrginfo.com, under “Investor Relations, SEC Filings,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to 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 annual report, the following factors should be considered carefully in evaluating an investment in our securities.

Risks Related to Our Business, Industry and Strategy

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.

The prices we will receive for our oil and natural gas will significantly affect 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 last two years, oil prices have fallen from highs of over $100 per Bbl to lows of under $40 per Bbl and natural gas prices have experienced declines of comparable magnitude. 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, Russia and Ukraine;
the level of global oil and domestic natural gas exploration and production;
the level of global oil and domestic natural gas inventories;
prevailing prices on local oil and natural gas price indexes in the areas in which we operate;
localized supply and demand fundamentals and gathering, processing and transportation availability;
weather conditions and natural disasters;
domestic and foreign governmental regulations;
authorization of exports from the United States of liquefied natural gas or oil;
speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
price and availability of competitors’ supplies of oil and natural gas;
technological advances affecting energy consumption; and
the price and availability of alternative fuels.
    
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 current acquisition, drilling and development plans. While our current revolving credit facility provides for borrowings 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 we can borrow under our revolving credit facility, which could affect our cash flows and ability to execute on our business plans.
    
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 compared to the value of our estimated proved reserves at August 31, 2015, our most recent fiscal year end.

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. 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.

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Any substantial or extended decline in the prices 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 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 we have may not continue to be available on acceptable terms. Moreover, some risks 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.

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 August 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 $481.2 million in estimated capital expenditures during the five years ending August 31, 2020. 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

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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 August 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 estimated oil and gas 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 populated areas in the Wattenberg Field, and our operations in those areas may be subject to additional expenses and limitations. In addition, 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 impact 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 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 specifically 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 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. 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.


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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 debt 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.

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 we receive for our production. 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. Many of our hedging arrangements are based on benchmark prices and therefore do not protect us from adverse changes in the differential applicable to our production.

Lower oil and natural gas prices may cause us to record ceiling test write-downs, 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. For the year ended August 31, 2015, we recognized a $16.0 million impairment related to our ceiling test calculations during the year. We may experience further ceiling test write-downs or other impairments in the future. In addition, any future ceiling test cushion would be subject to fluctuation as a result of acquisition or divestiture activity.


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We cannot control the activities on properties 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.

We are dependent on third party pipeline, trucking and rail systems to transport our production and, in the Wattenberg Field, 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 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 and production, particularly from our wells located in the Wattenberg Field, 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 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 face similar risks in other areas.

We may be unable to satisfy our contractual 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 a third party marketer and to two 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. Beginning in October of 2015, we must 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. In addition, we have committed to deliver 7,500 Bbls of oil per day for the remainder of calendar 2015 to a third party refiner. 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. This could adversely impact our cash flows, profit margins and net income.


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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. In the last several years, we have pursued and consummated acquisitions that have provided us opportunities to grow our production and reserves. 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 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 to assess 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 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 harm our 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,

26



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 concentration 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, 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.

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 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 a package of additional emission control requirements that likewise cover the completion and operation of hydraulically fractured wells and associated equipment. At this point, we cannot predict the final regulatory requirements or the cost to comply with them.

 Some activists have attempted to link hydraulic fracturing to various environmental problems, 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 to permitting and other restrictions on the use of hydraulic fracturing. In May 2014, the EPA issued an advance notice of proposed rulemaking under TSCA to obtain data on chemical substances and mixtures used in hydraulic fracturing. 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 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, and OSHA has proposed stricter standards for worker exposure to silica, which would apply to use of sand as a proppant for hydraulic fracturing. In 2013, OSHA proposed regulations lowering the permissible exposure limit for airborne silica, and 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 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

27



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.

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, and the BLM is expected to propose new regulations in 2015 or 2016 for flaring involving federal land and minerals. 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.

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, opponents of hydraulic fracturing could still pursue state legislation or additional local or statewide ballot initiatives to restrict hydraulic fracturing or oil and gas development generally. 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.

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, substantial liabilities to third parties or governmental entities may be incurred 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

28



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 regardless of whether we were responsible for the release or whether the operations at the time of the release were standard industry practice.

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, although the application of those provisions to us is uncertain at this time. 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 consolidated 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, make 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.

Our 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 August 31, 2015, the aggregate amount of our outstanding indebtedness was $78 million, which could have important consequences for you, 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, which, if interest rates increase, 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.

29




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.

To service our indebtedness, we will require a significant amount of cash. 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 our indebtedness and to fund planned capital expenditures will depend on our ability to generate sufficient cash flow from operations in the future. To a certain 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. 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 to enter into other business combination transactions; or
engage in certain other corporate activities.

Also, our credit facility requires us to maintain compliance with specified financial ratios and satisfy certain financial tests. 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.


30



Our two co-Chief Executive Officers may allocate some portion of their time to other business interests, which could have a negative impact on our operations.

Our two co-Chief Executive Officers have other business interests to which they allocate a portion of their professional time. Because of this, their employment agreements provide that they are only obligated to devote eighty percent of their time to our affairs. While in the past they have devoted substantially all of their time to our business, they could allocate more of their time to these other interests, which could have a negative impact on our operations.

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 co-Chief Executive Officers 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 our annual 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, we could lose investor 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.

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.


31



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

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.

Our stock price could be volatile, which could cause you to lose part or all of your investment.

The stock market has from time to time experienced significant price and volume fluctuations that may be unrelated to the operating performance of particular companies. In particular, the market price of our common stock, like that of the securities of other energy companies, has been and may continue to be highly volatile.

From time to time, there has been limited trading volume in our common stock. In addition, there can be no assurance that there will continue to be a trading market or that any securities research analysts will continue to provide research coverage with respect to our common stock. It is possible that such factors will adversely affect the market for our common stock.

The market valuation of our business may fluctuate due to factors beyond our control and the value of the investment of our stockholders may fluctuate correspondingly.

The market valuations of energy companies, such as us, frequently fluctuate due to factors unrelated to the past or present operating performance of such companies. Our market valuation may fluctuate significantly in response to a number of factors, many of which are beyond our control, including:

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;
Announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures or capital commitments;
Variations in our quarterly operating results;
Fluctuations in oil and natural gas prices;
Loss of a major customer;
Loss of a relationship with a partner; and
Additions or departures of key personnel.

As a result, the value of your investment in our common stock may fluctuate.

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 we receive in those markets could be adversely impacted by various factors, including changes in general market conditions and commodity price changes.

ITEM 1B.
UNRESOLVED STAFF COMMENTS

None.

32




ITEM 2.
PROPERTIES

See Item 1 of this report.


33



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 essence of the Defendants’ counterclaims is 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.

34



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 fiscal years. 

Quarter Ended
 
High
 
Low
November 30, 2014
 
$13.75
 
$8.05
February 29, 2015
 
$13.50
 
$8.14
May 31, 2015
 
$12.98
 
$10.40
August 31, 2015
 
$12.82
 
$9.04

Quarter Ended
 
High
 
Low
November 30, 2013
 
$11.40
 
$8.86
February 29, 2014
 
$10.69
 
$8.11
May 31, 2014
 
$12.96
 
$9.70
August 31, 2014
 
$14.11
 
$10.13

As of October 10, 2015, the closing price of our common stock on the NYSE MKT was $11.90.

As of October 10, 2015 we had 105,111,133 outstanding shares of common stock and 143 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)
June 1, 2015 - June 30, 2015 (1)
 
1,600

 
$
11.79

 

 

July 1, 2015 - July 31, 2015 (1)
 
1,600

 
$
10.75

 

 

August 1, 2015 - August 31, 2015 (1)
 
1,600

 
$
9.77

 

 

   Total
 
4,800

 
 
 
 
 
 

(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.



35



Comparison of Cumulative Return

The performance graph below compares the cumulative total return of our common stock over the five-year period ended August 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.

 
 
August 31,
 
 
2010
2011
2012
2013
2014
2015
 
 
 
 
 
 
 
 
Synergy Resources Corporation
 
100.00

138.22

124.44

416.00

598.22

477.33

S&P 500
 
100.00

118.50

139.83

165.99

207.89

208.88

SIC Code 1311
 
100.00

128.07

121.59

143.53

180.23

98.77

 
 
 
 
 
 
 
 

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

36



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.

 
For the Years Ended August 31,
 
2015
 
2014
 
2013
 
2012
 
2011
Results of Operations
(in thousands):
 
 
 
 
 
 
 
 
 
Revenues
$
124,843

 
$
104,219

 
$
46,223

 
$
24,969

 
$
10,002

Net income (loss)
18,042

 
28,853

 
9,581

 
12,124

 
(11,600
)
 
 
 
 
 
 
 
 
 
 
Net income (loss) per common share:
 
 
 
 
 
 
 
 
 
Basic
$
0.19

 
$
0.38

 
$
0.17

 
$
0.26

 
$
(0.45
)
Diluted
$
0.19

 
$
0.37

 
$
0.16

 
$
0.25

 
$
(0.45
)
 
 
 
 
 
 
 
 
 
 
Certain Balance Sheet Information (in thousands):
 
 
 
 
 
 
 
 
 
Total Assets
$
746,449

 
$
448,542

 
$
291,236

 
$
120,731

 
$
63,698

Working (Deficit) Capital
93,129

 
(35,338
)
 
50,608

 
10,875

 
685

Total Liabilities
174,052

 
167,052

 
88,016

 
19,619

 
14,590

Equity
572,397

 
281,490

 
203,220

 
101,112

 
49,108

 
 
 
 
 
 
 
 
 
 
Certain Operating Statistics:
 
 
 
 
 
 
 
 
 
Production:
 
 
 
 
 
 
 
 
 
Oil (MBbls)
1,970

 
941

 
421

 
236

 
90

Gas (MMcf)
7,344

 
3,747

 
2,108

 
1,109

 
451

Total production in MBOE
3,194

 
1,566

 
773

 
421

 
165

Average sales price per BOE
$
39.09

 
$
66.56

 
$
59.83

 
$
59.38

 
$
59.24

LOE per BOE
$
4.70

 
$
5.10

 
$
4.42

 
$
2.89

 
$
2.94

DDA per BOE
$
20.62

 
$
21.05

 
$
17.26

 
$
14.29

 
$
16.62


The fluctuation in results of operations and financial position is due in part to acquisitions of producing oil and gas properties coupled with the aggressive drilling program we executed during 2013, 2014 and 2015.

See Note 17 to the Financial Statements included as part of this report for our quarterly financial data.

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 August 31, 2015, and its results of operations 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 Annual Report on Form 10-K.

This section and other parts of this Annual 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 Annual 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

37



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 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 82% of our proved producing reserves and over 98% of our fiscal 2015 and 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. From inception through August 31, 2015, we have completed, acquired or participated in 582 gross (407 net) successful oil and gas wells. We are the operator of 423 producing wells and participate with other operators in 159 producing wells. In addition to the wells that had reached productive status at the end of our fiscal year, there are 28 gross (17 net) wells in various stages of drilling or completion as of August 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 142 gross (78 net) horizontal wells. As of August 31, 2015, we were the operator of 33 gross (32 net) Codell horizontal wells and 38 gross (37 net) horizontal Niobrara wells.

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
352

 
304

 
71

 
21

 
423

 
325

Horizontal Wells
Operated Wells
 
Non-Operated Wells
 
Totals
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
71

 
69

 
88

 
13

 
159

 
82


In addition to the producing wells summarized in the preceding table, as of August 31, 2015, we were the operator of 21 wells in progress and we were participating as a non-operating working interest owner in 7 wells in progress.

For the twelve months ended August 31, 2015, our average net daily production was 8,750 BOED. By comparison, during our 2014 and 2013 fiscal years, our average production rate was 4,290 BOED and 2,117 BOED, respectively. By the end of our 2015 fiscal year, over 80% of our daily production was from horizontal wells. At the beginning of 2014, less than 10% of our production was from horizontal wells.

38




During the twelve months ended August 31, 2015, crude oil prices declined by approximately 49%. 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 K.P. Kauffman assets

Subsequent to our fiscal year end, on September 15, 2015, we announced an agreement for the purchase 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 core Wattenberg Field and non-operated working interests in 25 gross (approximately 5 net) horizontal wells in the Niobrara and Codell formations. Current net production associated with the purchased assets is approximately 1,200 BOED. The purchase price for the assets is $78 million, comprised of $35 million in cash and approximately 4.4 million restricted shares of our common stock, subject to closing adjustments. The transaction has an effective date of September 1, 2015 and is expected to close on or before October 30, 2015.

Acquisition of Mineral Assets from Bayswater on December 15, 2014

On December 15, 2014, we completed the acquisition of certain assets from three independent oil and gas companies collectively known as “Bayswater.” Consideration paid to Bayswater, after customary closing and post-closing adjustments, consisted of approximately $74.2 million in cash and 4.6 million shares in our common stock plus the assumption of certain liabilities. For accounting purposes, the Bayswater acquisition was treated as a business combination and the assets acquired were recorded at fair value. The final purchase price allocation and evaluation of fair value was recognized during our fourth fiscal quarter and is described more fully in Note 3 to our consolidated financial statements, which are included as part of this report.

The Bayswater acquisition encompasses 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, we acquired working interests in 17 non-operated horizontal wells, 73 operated vertical wells, and 11 non-operated vertical wells.  We anticipate this acreage will provide a multi-year drilling inventory and, when fully developed, expect these assets to be accretive to cash flow and earnings per share.

Financing and Other

Completion of Public Stock Offering on February 2, 2015

During our second fiscal quarter, we completed a 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. On February 2, 2015, we received net proceeds of approximately $190.8 million after deducting underwriting discounts, commissions and other offering expenses. For more information, see “Liquidity and Capital Resources.”

Amendments to Revolving Credit Facility (“Revolver”)

On December 15, 2014, we closed on the Fifth Amendment to our Amended and Restated Credit Agreement (“Fifth Amendment”). The terms of the Fifth Amendment included an expansion of the bank syndicate to eight members, an increase in the loan commitment from $300 million to $500 million, and an increase in our borrowing base from $110 million to $230 million. On June 2, 2015, we closed on the Sixth Amendment to the Revolver in connection with the regular semi-annual borrowing base redetermination. The Sixth Amendment provides for a borrowing base of $175 million, which was subsequently revised to $163 million as a result of the liquidation of certain commodity derivative contracts. The facility continues to bear a minimum interest rate on borrowings of 2.5%, with the effective rate varying with utilization, and expires on December 15, 2019. Amounts borrowed under the Revolver will be used to develop oil and gas properties, acquire new oil and gas properties, and for working capital and other general corporate purposes. 

Early Liquidation of In-The-Money Commodity Contracts

During the fiscal year ended August 31, 2015, we liquidated a portion of our deep in-the-money commodity contracts and

39



purchased crude oil put contracts with $55/Bbl, $50/Bbl, and $45/Bbl strike prices. These transactions allowed us to monetize what would have otherwise been unrealized gains, thereby increasing cash flow. In addition to working with our existing counterparties, we purchased a portion of the put contracts on the Chicago Mercantile Exchange, which we believe will enhance the liquidity of our overall position.

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 our 2015 fiscal year, 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 $16.0 million during our 2015 fiscal year. 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 August 31, 2015, our estimated net proved oil and gas reserves, as prepared by Ryder Scott, were 27.7 MMBbls of oil and condensate and 174.0 Bcf of natural gas. As of August 31, 2015, we had approximately 442,000 gross and 342,000 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 50,000 gross and 37,000 net acres) and the “North East Extension Area” of the Wattenberg Field (approximately 109,000 gross and 52,000 net acres). In addition, we hold approximately 186,000 gross (182,000 net) acres in southwest Nebraska, a conventional oil-prone prospect, and approximately 90,000 gross (64,000 net) acres in far eastern Colorado.

Within our leasehold in the North East Extension Area we have drilled and, as of the 2015 fiscal year end were in the process of completing, our first horizontal well targeting the Greenhorn formation. Within our southwestern Nebraska leasehold, we have entered into a joint exploration agreement with a private operating company based in Denver to drill up to ten wells in a defined Area of Mutual Interest. 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.

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 over the preceding fiscal year, we have been able to reduce per well drilling and completion costs by approximately 35%. We believe we can achieve even lower costs in the future, but believe that at current drilling and completion cost levels and with currently prevailing commodity prices, we can achieve reasonable well-level rates of return. Should commodity prices weaken further, our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent. If management believes the well-level internal rate of return will be at or below our weighted-average cost of capital, we may choose to delay completions and/or forego drilling altogether.

During the twelve months ended August 31, 2015, we drilled 44 and completed 38 horizontal wells. This included drilling 20 “standard length” (approximately 4,200-foot lateral length) horizontal wells targeting the various benches of the Niobrara formation, and 15 standard length wells targeting the Codell formation. We drilled three “mid-length” (approximately 7,000-foot lateral length) horizontal Niobrara wells and one mid-length horizontal Codell well. In addition, we drilled four “extended length” (approximately 9,600-foot lateral length) horizontal wells, all of which targeted the Niobrara formation.

During fiscal 2015, we completed 20 Niobrara horizontal wells and 18 Codell horizontal wells. As of August 31, 2015, there are 21 horizontal wells in various stages of completion, comprised of 13 standard length, 4 mid-length, and 4 extended length wells.

Other Operations

We continue to be opportunistic with respect to acquisition efforts. We continue to enter into land and working interest swaps to increase our overall leasehold control. During the year ended August 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.


40



In our North East Extension Area, we drilled an exploratory well targeting the Greenhorn formation. As of August 31, 2015, this well was in the process of being completed. Initial results from the well are expected in the coming months.

In western Nebraska, we have entered into a joint exploration agreement with a Denver-based private operating company to drill up to ten wells in an AMI covering approximately 8,000 acres. 

In Yuma and Washington Counties, Colorado, we maintain leases covering over 63,000 net acres in an area that has historically produced dry gas from the Niobrara formation. We continue to evaluate the economics of this play to determine when or if it might be economic to develop further.

Production

Our production increased from 4,290 BOED for the fiscal year ended August 31, 2014 to 8,750 BOED for the fiscal 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 fiscal years.

 
Years Ended August 31,
 
2015
 
2014
 
2013
 
2012
 
2011
Average NYMEX prices
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
60.65

 
$
100.39

 
$
94.58

 
$
94.88

 
$
91.79

Natural gas (per Mcf)
$
3.12

 
$
4.38

 
$
3.55

 
$
2.82

 
$
4.12


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

 
Fiscal Years Ended August 31,
 
2015
 
2014
 
2013
Oil (NYMEX WTI)
 
 
 
 
 
Average NYMEX Price
$
60.65

 
$
100.39

 
$
94.58

Realized Price
$
50.75

 
$
89.98

 
$
85.95

Differential
$
(9.90
)
 
$
(10.41
)
 
$
(8.63
)
 
 
 
 
 
 
Gas (NYMEX Henry Hub)
 
 
 
 
 
Average NYMEX Price
$
3.12

 
$
4.38

 
$
3.55

Realized Price
$
3.39

 
$
5.21

 
$
4.75

Differential
$
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 we receive include payment for the natural gas liquids produced with the gas.


41



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 $95.96 per Bbl on Friday, August 29, 2014, the last trading day of our 2014 fiscal year.  Subsequently, the price of WTI declined 60%, to a low of $38.24 per Bbl on Monday, August 24, 2015. The price of oil settled at $49.20 per Bbl on Monday, August 31, 2015, the last trading day of our 2015 fiscal year, down 49% from the end of our 2014 fiscal year. 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 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 $16.0 million in our 2015 fiscal year, and additional impairments may occur in the future.

Results of Operations

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

For the 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 our 2015 fiscal year compared to earnings per share of $0.38 and $0.37 per basic and diluted share for the 2014 fiscal year. Revenues increased $20.6 million during the year ended August 31, 2015 compared to the year ended August 31, 2014 due to rapid growth production as discussed above. 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 2015 period 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.

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%.

Year over year, we added 48 net horizontal wells, including 3 (net) Bayswater horizontal wells, increasing our reserves, producing wells and daily production totals. 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. When the price of oil declined in 2014, we temporarily postponed the final completion of certain wells under development. With the exception of one pad, all of the temporarily delayed wells commenced production during the third and fourth quarters of fiscal 2015.

Our revenues are sensitive to changes in commodity prices. As shown in the following table, there has been a decrease of 41% in average realized prices between the periods presented. This decline in average sales prices mostly offset the effects of increased production. The following table presents actual realized prices, without the effect of commodity derivative transactions. The impact of commodity derivative transactions is presented later in this discussion.


42



Key production information is summarized in the following table:

 
Years Ended August 31,
 
 
 
2015
 
2014
 
Change
Production:
 
 
 
 
 
Oil (MBbls)
1,970

 
941

 
109
 %
Gas (MMcf)
7,344

 
3,747

 
96
 %
 
 
 
 
 


Total production in MBOE
3,194

 
1,566

 
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
 %

Lease Operating Expenses (“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 our 2015 fiscal year, 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. We continue to work diligently to mitigate production difficulties in the Wattenberg Field.

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.


43



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

 
Year Ended August 31,
(in thousands)
2015
 
2014
Depletion of oil and gas properties
$
65,158

 
$
32,132

Depreciation, accretion, and amortization
711

 
826

Total DDA
$
65,869

 
$
32,958

 
 
 
 
DDA 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 DDA 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 DDA expense represents amortization of historical costs, our recently implemented reductions in well costs are not fully reflected in the rate.

Full cost ceiling impairment - During the 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.

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

 
Years 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 employ a total staff of 36 employees and use consultants, advisors, and contractors to perform certain tasks when it is cost effective.

Although G&A costs have increased as we grow the business, we strive to maintain an efficient overhead structure.  For the 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. Stock-based compensation includes a calculated value for stock options or shares of common stock that we grant for compensatory purposes. It is a non-cash charge, which, for stock options, is calculated using the Black-Scholes-Merton option pricing model to estimate the fair value of options. Amounts are pro-rated over the vesting terms of the option agreements, which are generally three to five years.

Pursuant to the requirements under the full cost accounting method 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 are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from 2014 to 2015 reflects our increasing activities to acquire leases and develop the properties.

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 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

44



$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.

Income taxes - We reported income tax expense of $11.7 million for the twelve months 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 appears that the tax liability will be substantially deferred into future years. During both fiscal years the effective tax rate differed from the federal and state statutory rate primarily by the impact of deductions for percentage depletion.

For tax purposes, we have a net operating loss (“NOL”) carryover of $21.3 million, which is available to offset future taxable income. The NOL will begin to expire, if not used, in 2031.

Each year, management evaluates all the positive and negative evidence regarding our tax position and reaches a conclusion on the most likely outcome.  During 2015 and 2014, we concluded that it was more likely than not that we would be able to realize a benefit from the net operating loss carryforward, and have 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%.

As of August 31, 2014, we owned interests in 404 producing wells.  Net oil and gas production averaged 4,290 BOED in fiscal 2014, compared to 2,117 BOED for 2013, a year-over-year increase of 103%.  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 our 2014 fiscal year. During the fourth quarter of 2014, we completed 15 new horizontal wells. Production for the fourth fiscal quarter of 2014 averaged 5,894 BOED.

Our revenues are sensitive to changes in commodity prices.  As shown in the following table, there was an increase of 11% in average realized sales prices between 2013 and 2014. The following table presents actual realized prices, without the effect of commodity derivative transactions. The impact of derivative transactions is presented later in this discussion.


45



Key production information is summarized in the following table:

 
Years Ended August 31,
 
 
 
2014
 
2013
 
Change
Production:
 
 
 
 
 
Oil (MBbls)
941

 
421

 
123.5
%
Gas (MMcf)
3,747

 
2,108

 
77.8
%
 
 
 
 
 
 
Total production in MBOE
1,566

 
773

 
102.6
%
 
 
 
 
 
 
Revenues (in thousands):
 
 
 
 
 
Oil
$
84,693

 
$
36,206

 
133.9
%
Gas
19,526

 
10,017

 
94.9
%
 
$
104,219

 
$
46,223

 
125.5
%
Average sales price:
 
 
 
 
 
Oil
$
89.98

 
$
85.95

 
4.7
%
Gas
$
5.21

 
$
4.75

 
9.7
%
BOE
$
66.56

 
$
59.83

 
11.2
%

LOE and Production Taxes - 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):

 
Years 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 2013 to 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. We continue to work diligently to mitigate production difficulties within the Wattenberg Field. Additional wellhead compression was added at some well locations and older equipment was replaced or refurbished. During 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 make 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.



46



DDA - The following table summarizes the components of DDA:

 
Years ended August 31,
(in thousands)
2014
 
2013
Depletion of oil and gas properties
$
32,132

 
$
13,046

Depreciation, accretion, and amortization
826

 
290

Total DDA
$
32,958

 
$
13,336

 
 
 
 
DDA 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 DDA 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 fiscal year 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 EUR, our DDA 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 continue to increase with the success of horizontal development.  For acquisition of producing properties, substantially all of the costs are 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 amortization to the reserves acquired is greater than our internally developed properties. 

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

 
Years 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 fiscal year ended August 31, 2014, G&A was $6.48 per BOE compared to $7.36 for the fiscal year ended August 31, 2013, primarily as a result of the increase in BOE produced during fiscal 2014. Our G&A expense for fiscal 2014 includes stock-based compensation of $3.0 million, compared to $1.4 million in 2013.

The increase in capitalized costs from 2013 to 2014 reflects 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 fiscal 2014 or 2013. The interest costs that we incurred under our credit facility were eligible for capitalization into the full cost pool. We capitalize 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

47



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 fiscal 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 appears that the tax liability will be substantially deferred into future years. During fiscal year 2014, the effective tax rate was reduced from the federal and state statutory rate by the impact of deductions for percentage depletion.

During 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 have therefore included it in our inventory of deferred tax assets.

Liquidity and Capital Resources

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

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

As operator of the majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled 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 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 we receive for our production. Over the past year, the NYMEX-WTI oil price ranged from a high of $95.96 per Bbl on Friday, August 29, 2014, the last day of our 2014 fiscal year, to a low during the 2015 fiscal year of $38.24 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $4.49 per MMBtu to a recent low of $2.48 per MMBtu. These markets will likely continue to be volatile in the future. To deal with the volatility in commodity prices, we maintain a flexible capital investment program and seek to maintain a high operating interest in our leaseholds with limited long-term capital commitments. This enables us to accelerate or decelerate our activities quickly in response to changing industry environments. Additionally, we believe our conservative use of leverage and corresponding strong balance sheet helps mitigate the impact of lower commodity prices.

At August 31, 2015, we had cash and cash equivalents of $133.9 million and an outstanding balance of $78 million under our revolving credit facility. Our sources and (uses) of funds for the twelve months ended August 31, 2015, 2014, and 2013 are summarized below (in thousands):

 
For the years ended August 31,
 
2015
 
2014
 
2013
Cash provided by operations
$
125,087

 
$
74,905

 
$
32,120

Acquisitions and development of oil and gas properties and equipment
(275,808
)
 
(155,602
)
 
(80,469
)
Short-term investments

 
60,018

 
(60,000
)
Cash provided by other investing activities
6,239

 
704

 

Cash provided by equity financing activities
204,953

 
35,265

 
74,528

Net borrowings on Revolver
38,684

 

 
34,000

Net increase in cash and equivalents
$
99,155

 
$
15,290

 
$
179



48



Net cash provided by operations has improved during each of the last three years.  The significant improvement reflects the operating contribution from new wells that were drilled and producing wells that were acquired. The increase in net cash provided by operations allowed us to become less reliant on equity sales for financing our capital expenditures in fiscal 2015.

Net cash provided by operating activities was $125.1 million and $74.9 million for the years ended August 31, 2015 and 2014, respectively. The significant improvement in cash from operating activities reflects the operating contribution from new wells that were drilled and producing wells that were acquired.

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. These proceeds have been, or will be, used to fund additional asset acquisitions in the Wattenberg Field which may become available from time to time, 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.

Credit Arrangements

We maintain a borrowing arrangement with a banking syndicate.  The arrangement, in the form of a revolving credit facility, was most recently amended with the Sixth Amendment to the credit facility on June 2, 2015.  The arrangement provides for a maximum loan commitment of $500 million; however, the maximum amount we can borrow 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 August 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.

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.

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

 
For the years ended August 31,
 
2015
 
2014
 
2013
Cash payments for capital expenditures
$
275,808

 
$
155,602

 
$
80,469

Accrued costs, beginning of period
(71,849
)
 
(25,491
)
 
(5,733
)
Accrued costs, end of period
33,072

 
71,849

 
25,491

Non-cash acquisitions, common stock
60,221

 
11,184

 
16,684

Other
7,622

 
905

 
1,233

Accrual basis capital expenditures
$
304,874

 
$
214,049

 
$
118,144



49



Capital Expenditures

The majority of capital expenditures during our 2015 fiscal year were associated with the acquisition of the Bayswater assets, including goodwill and deferred taxes, and the costs of drilling and completing wells that we operate.  As of August 31, 2015, we had drilled, completed and brought into productive status 38 wells in our 2015 drilling program. In addition, we had drilled 21 gross (17 net) wells that had not been brought into productive status. All of the wells in progress are scheduled to commence production before August 31, 2016.

With respect to our ownership interest in wells operated by other companies, we participated in drilling and completion activities on 38 gross (4 net) wells.

Capital Requirements

Our primary need for cash will be to fund our drilling and acquisition programs for our 2016 fiscal year. Our cash requirements have increased significantly since May 2013, when we implemented our horizontal drilling program.  However, as commodity prices have dropped, we have negotiated lower costs from our service providers and have revised our completion design. Accordingly, we currently anticipate that the standard-length horizontal wells to be drilled in 2016 will cost between $2.5 million and $3.0 million each as compared to fiscal year 2015 costs of $2.5 million to $3.8 million.

Our preliminary capital expenditure plan for fiscal 2016 contemplates utilizing one drilling rig and provides for spending of $115 million to $135 million for drilling, completion and leasing activities. We are planning to drill 32 to 35 gross operated horizontal wells, including 18 gross extended reach lateral wells. In order to maximize the efficient use of our capital, we have reduced the amount of our working interests in wells operated by others, primarily by executing leasehold swaps. We currently anticipate participating in two to four net, standard length equivalent, non-operated wells at an estimated cost of $2.7 million to $3.5 million per well. Finally, leasing and other activities are planned at $10 million to $15 million. As has been our historical practice, we regularly review capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service costs and drilling success. Our level of exploration, development and acreage expenditures is largely discretionary and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among other factors.
 
We plan to generate profits by producing oil and natural gas from wells that we drill or acquire.  For the near term, we believe that we have sufficient liquidity to fund our needs through cash on hand, cash flow from operations, proceeds from the exercise of warrants, and additional borrowings available under our revolving credit facility.  However, to meet all of our long-term goals, we may need to raise some of the funds required 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 the wells.  We may not be successful in raising the capital needed to drill or acquire oil or gas wells.  Any wells which may be drilled by us may not produce oil or gas in commercial quantities.

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.  We typically enter into contracts covering between 45% and 85% of anticipated production from our proved developed producing reserves, as projected in our most recent semi-annual reserve report, for a period of 24 months. At October 1, 2015, we had open positions covering 0.7 million barrels of oil and 3,036 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 invest in oil and/or natural gas, and at what prices we invest, 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.

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


50



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

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

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

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 year ended August 31, 2015, we reported an unrealized commodity activity gain of $1.8 million.  Unrealized gains and losses are non-cash items.  We also reported a realized gain of $30.5 million, representing the cash settlement cost for contracts settled during the period and amortization of cash premiums paid for commodity contracts.

At August 31, 2015, we estimated that the fair value of our various commodity derivative contracts was a net asset of $4.5 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 August 31, 2015 may differ significantly from the realized values at their respective settlement dates.

Our commodity derivative contracts as of October 10, 2015 are summarized below:

 
 
Volumes
 
Average Collar Prices (1)
 
Average Put Prices (1)
Month
 
Oil
(Bbl)
 
Gas (MMBtu)
 
Average Oil (Bbl) Price
 
Average Gas (MMBtu) Price
 
Average Oil (Bbl) Price
 
Average Gas (MMBtu) Price
Oct 1 to Dec 31, 2015
 
152,000
 
516,000
 
N/A
 
$2.64 - $3.65
 
$50.99
 
N/A
Jan 1 to Dec 31, 2016
 
420,000
 
1,680,000
 
N/A
 
$3.03 - $3.47
 
$48.57
 
N/A
Jan 1 to Aug 31, 2017
 
160,000
 
840,000
 
N/A
 
$2.64 - $3.48
 
$50.50
 
N/A
(1) Price is at NYMEX WTI and NYMEX Henry Hub.


51



Contractual Commitments

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

 
Less than
One Year
 
One to
Three Years
 
Three to Five Years
 
More Than Five Years
 
Total
Rig Contract(1)
$
2,340

 
$

 
$

 
$

 
$
2,340

Volume commitments(2)
11,626

 
45,272

 
45,272

 
11,010

 
113,180

Revolving credit facility(3)
1,950

 
3,900

 
80,681

 

 
86,531

Operating Leases
408

 
101

 

 

 
509

Total
$
16,324

 
$
49,273

 
$