SYNERGY RESOURCES CORP (Form: 10-K, Received: 10/30/2014 16:03:49)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended August 31, 2014

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.)

20203 Highway 60, Platteville, CO	80651
(Address of principal executive offices)	(Zip Code)

Registrant's telephone number, including area code: (970) 737-1073

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 o No x

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 x

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 x 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 x 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. x

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 o No x

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, 2014, was approximately $704 million. 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, 2014, the Registrant had 79,293,688 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, indicates a forward-looking statement.

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

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

•

volatility of oil and natural gas prices;

•

operating hazards that result in losses;

•

uncertainties in the estimates of proved reserves;

•

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

•

our need to expand our oil and natural gas reserves;

•

our ability to obtain adequate financing;

•

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

•

effect of local and regional factors on oil and natural gas prices;

•

incurrence of ceiling test write-downs;

•

our inability to control operations on properties we do not operate;

•

our ability to market our production;

•

the strength and financial resources of our competitors;

•

identifying future acquisitions;

•

uncertainty in global economic conditions;

•

legal and/or regulatory compliance requirements;

•

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

•

our need for capital;

•

key executives allocating a portion of their time to other business interests; and

•

effectiveness of our disclosure controls and our internal controls over financial reporting.

ITEM 1. BUSINESS

Overview

We are an oil and natural gas operator focused on the acquisition, development, exploitation, exploration and production of oil and natural gas properties primarily located in the Denver-Julesburg Basin (“D-J Basin”) in northeast Colorado. We have concentrated on drilling and completing wells located in the Wattenberg Field, an area within the D-J Basin, which has a prolific production history. We serve as the operator for most of our wells and focus our efforts on those prospects in which we have a significant net revenue interest. For the prospects in which we own a minority mineral interest, we participate with other companies that drill and operate wells.

We commenced active operations in the D-J Basin in 2008. For the first four years of active operations, our focus was primarily on participating in and completing vertical wells. Beginning in fiscal 2013, our focus shifted towards drilling and completing horizontal wells. Our use of the term horizontal well includes 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. In contrast, the term vertical well includes directional wells that are drilled at an angle toward a target area and where the productive length of the wellbore intersects the target formation on a perpendicular basis. The productive length of the wellbore in a horizontal well is much greater than the productive length of a vertical well, which results in a longer wellbore and a higher completion volume. As of August 31, 2014, we had completed, participated in or otherwise acquired an interest in 404 gross (284 net) producing oil and gas wells, of which 334 gross (250 net) were vertical wells and 70 gross (34 net) were horizontal wells. We are the operator of 300 producing wells and participate with other operators in 104 producing wells. In addition to the wells that had reached productive status at the end of our fiscal year, there are 53 gross (14 net) wells in various stages of drilling or completion as of August 31, 2014.

Our daily production increased significantly during fiscal 2014 as new horizontal wells commenced productive operations. Our average production rate for fiscal 2014 was 4,290 barrels of oil equivalent per day (“BOED”). During fiscal 2013, our average production rate was 2,117 BOED. More significantly, our production rate for the fourth quarter of 2014 was 5,894 BOED, compared to 2,479 BOED during the fourth quarter of 2013. By the end of 2014, 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.

During fiscal 2014, we also continued to increase our estimated reserves and mineral leasehold acres. At August 31, 2014, our estimated net proved oil and gas reserves, as prepared by our independent reserve engineering firm, Ryder Scott Company, L.P., were 16.3 MMBbls of oil and condensate and 95.2 Bcf of natural gas. As of August 31, 2014, we had 451,000 gross and 309,000 net acres under lease, substantially all of which are located in the D-J Basin. We further classify our acreage into specific areas, including Wattenberg Field (46,000 gross and 31,000 net acres), Northern Extension Area (122,000 gross and 26,000 net acres), Eastern Colorado (90,000 gross and 64,000 net acres), and Western Nebraska (185,000 gross and 183,000 net acres).

In addition to the approximately 31,000 net developed and undeveloped acres that we hold in the Wattenberg Field, we hold approximately 26,000 undeveloped acres in an area directly to the north and east of the Wattenberg Field that is considered the Northern Extension area. We are currently permitting twelve wells targeting the Greenhorn formation on our leasehold in this area and plan to spud the first well in early calendar year 2015. We have a significant leasehold of undeveloped acreage in western Nebraska. We have entered into a joint exploration agreement with a private operating company based in Denver to drill up to ten wells in this area. We expect drilling activities to commence in Nebraska before December 31, 2014. We also have mineral assets in Yuma and Washington Counties, Colorado that are in an area that has a history of dry gas production from the Niobrara formation.

Business Strategy

Our primary objective is to enhance shareholder value by increasing our net asset value, net reserves and cash flow through acquisitions, development, exploitation, exploration and divestiture of oil and gas properties. We intend to follow a balanced risk strategy by allocating capital expenditures in 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, and the Codell formations for horizontal drilling and production. Our plans focus on horizontal development of our assets in the Wattenberg Field as we believe horizontal drilling is the most efficient manner 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 wells. There is enough similarity between wells in the Field that the exploitation process is generally repeatable.

Improve hydrocarbon recovery through increased well density. Use best available geological practices to determine optimum recovery area for each well. We have identified 932 potential horizontal wells in the Niobrara and Codell formations on existing Wattenberg acreage based on 21 wells per 640 acre sections and over 800 potential horizontal well locations in the Greenhorn and Niobrara formations in the Northern Wattenberg extension area in the D-J Basin.

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

Retain control over the operation of a substantial portion of our production. As operator on 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 recompleted. This allows us to modify our capital spending as our financial resources allow and market conditions support.

Maintain financial flexibility while focusing on controlling the costs of our operations. We strive to be, and have historically been, a low-cost operator in the D-J Basin. Central to our operating strategy is maintaining low debt levels, low general and administrative costs and low well completion costs, each of which is enabled by our ability to stay highly involved in our development, our emphasis on short time horizons for returns on our investment, as well as our focus on operating efficiencies and cost reductions. 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 ultimately have a higher return on investment. Latest industry practices are drilling horizontal wells in the Wattenberg Field in increasing density and technical advancements in completing these wells is leading to enhanced productivity. We are currently utilizing both “sliding sleeve” and “plug and perf liner” technologies to stimulate multi-stage horizontal wells. Production results from each technique are analyzed and the conclusions from each analysis are factored into future well design, considering the interactions between wellbore conditions, lateral length, timing and economics. Similarly, we evaluate the use of different completion fluids ranging from slick-water to gelled fluids, and different combinations thereof.

Competitive Strengths

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

·	Management experience. Our key management team possesses an average of thirty years of experience in oil and gas exploration and production, primarily within the Wattenberg Field in the D-J Basin, which is where over 90% of our capital expenditures took place in fiscal 2014.

Balanced oil and natural gas reserves and production. At August 31, 2014, approximately 51% of our estimated proved reserves were oil and condensate and 49% were natural gas and liquids, measured upon a BTU equivalent basis. We believe this balanced commodity mix will provide diversification of sources of cash flow and will lessen the risk of significant and sudden decreases in revenue from short-term commodity price movements.

·	Cost efficient operator. We have successfully demonstrated our ability to drill wells for lower costs than our major competitors 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 low risk and, as a result, have had a very high success rate in our drilling program throughout the Wattenberg Field.

2014 Operational and Financial Summary

We continued to expand our business during the fiscal year ended August 31, 2014. During the year, we:

·	increased production and sale of hydrocarbons by 123%;

·	commenced production from 31 new company operated horizontal wells;

·	commenced production from 3 (net) non-operated wells;

·	acquired producing properties and undeveloped acreage in two significant acquisitions described below under “2014 acquisitions”; and

·	increased reserves by 133%

These activities were funded with cash on hand at the beginning of the year and cash flow from operations. Significant developments are described in greater detail below.

Drilling operations

As an operator, we successfully transitioned from a focus on vertical drilling to horizontal drilling. Horizontal wells are significantly more expensive and take longer to drill and complete than vertical wells, but ultimately yield a greater return. As we transitioned toward horizontal drilling, we substantially ceased completion and re-completion of our vertical wells. Accordingly, our cost structure for both our capitalized well costs and our monthly operating costs has transformed significantly over the last two years.

After initiating horizontal drilling in May 2013, production from our first five horizontal wells at our Renfroe location began in September 2013. Subsequently, we drilled, completed and initiated production at the following locations: Leffler (6 wells), Phelps (5 wells), Union (6 wells), Eberle (5 wells) and Kelly Farms (4 wells). As of August 31, 2014, one additional well at Phelps and one additional well at Eberle had been drilled but not reached first production. Both wells began producing during September 2014.

Additionally, as of August 31, 2014, we had two locations where drilling operations are in progress. We have drilled four wells at the Weld 152 location and four wells at the Kiehn location. These eight wells are waiting on completion.

Our horizontal wells are currently being drilled under contracts with Ensign United States Drilling, Inc. (“Ensign”). The initial contract, as amended, covered the use of one rig to drill a total of 25 wells. To date, pricing is on a turn-key basis, with pricing adjustments based upon well location, target formation, and other technical details. Based upon our initial success with horizontal drilling at the Renfroe and Leffler prospects, we negotiated another drilling contract with Ensign to use one automated drilling rig for one year, commencing in January 2014. We contracted a third Ensign rig in September 2014 to drill eight wells on our Wiedeman pad, which is expected to finish in January 2015. At the conclusion of each contract, we have the option to continue use of the rigs. As currently structured, our capital expenditure plans for fiscal 2015 contemplate the use of two rigs for the entire year and use of the third rig for part of the year.

As a result of our drilling, acquisition and participation activities, we increased our estimated proved reserve quantities by 133% during the year. Our August 31, 2014, reserve report indicated that we had estimated proved reserves of 16.3 million barrels of oil and 95.2 billion cubic feet of gas. The estimated present value of future cash flows before tax (discounted at 10%) was $534 million.

During the last three months of the fiscal year ended August 31, 2014, we commenced production on three pads in the Wattenberg field, which significantly increased our daily production rate. Our consolidated daily production from producing wells increased during fiscal 2014 from 2,479 BOED as of August 31, 2013 to 5,894 BOED as of August 31, 2014.

2014 acquisitions

During the year, we completed two significant producing property acquisitions. On November 12, 2013, we acquired 21 net producing oil and gas wells along with leases covering 800 net acres from Trilogy Resources, LLC. Total consideration for the Trilogy assets included $16.0 million in cash and 301,339 shares of restricted common stock. On November 13, 2013, we acquired 38 operated wells (13 net) producing oil and gas wells along with leases covering 1,000 net acres from Apollo Operating LLC. The Apollo assets included non-operating interests in six wells we had drilled and completed and a 25% working interest in a Class II disposal well. Total consideration for the Apollo assets included $11.0 million in cash and 550,518 shares of restricted common stock. In several subsequent transactions, we acquired the remaining 75% interests in the Class II disposal well for cash and stock consideration aggregating $3.9 million.

On November 13, 2013, we acquired 38 wells (13 net) producing oil and gas wells along with leases covering 800 net acres from Apollo Operating LLC. The Apollo assets included non-operating interest in six wells we had drilled and completed and a 25% working interest in a Class II disposal well. Total consideration for the Apollo assets included $11.0 million in cash and 550,518 shares of restricted common stock.

Subsequently, in a separate transaction, we acquired the remaining 75% interests in the Class II disposal well for approximately approximated $3.9 million.

Financing updates

We continue to improve our borrowing arrangement with a bank syndicate led by Community Banks of Colorado. Maximum borrowings are subject to adjustment based upon a borrowing base calculation, which will be re-determined semi-annually using updated reserve reports. The arrangement contains covenants that, among other things, restrict the payment of dividends and require compliance with certain financial ratios. The borrowing arrangement is collateralized by certain of our assets, including producing properties.

In December 2013 and June 2014, we modified our borrowing arrangement to increase the maximum allowable borrowings. In December 2013, the arrangement was modified to increase the maximum lending commitment to $300 million from $150 million, to increase the borrowing base to $90 million, and to increase the number of banks involved in the borrowing arrangement. Based upon the semi-annual redetermination derived from the February 28, 2014 reserve report, the arrangement was further modified in June 2014 to increase the borrowing base to $110 million, to adjust the financial ratio compliance requirements, and to extend the maturity date to May 29, 2019. The next scheduled redetermination is currently in progress and will adjust the borrowing arrangement based upon our August 31, 2014 reserve report.

Interest accrues at a variable rate equal to or greater than a minimum rate of 2.5%. The interest rate pricing grid contains a graduated escalation in applicable margin for increased utilization. At our option, interest rates will be referenced to the Prime Rate plus a margin of 0.5% to 1.5%, or the London InterBank Offered Rate plus a margin of 1.75% to 2.75%.

Commodity contracts

We utilize swaps and collars to reduce the effect of price changes on a portion of our 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 swaps and collars, we have contracted for approximately 1.1 million barrels of oil and 1.7 million mcf of gas through December 31, 2016. Since we designed our commodity derivative activity to protect our cash flow during periods of oil and gas price declines, the high average prices experienced during 2014 created a realized loss of $2.1 million for the year. The decline in posted prices at the end of our fiscal year created an unrealized increase in the fair value of our commodity derivatives of $2.5 million.

Well and Production Data

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 2014 we drilled one test well that was immediately plugged and abandoned. Results from the test well were encouraging and our 2015 plans include additional drilling in that area. We also drilled 11 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. The following table excludes wells that are in the drilling or completion phase and had not reached the point at which they are capable of producing oil and gas as of August 31, 2014.

	Years Ended August 31,
	2014		2013		2012
	Gross	Net	Gross	Net	Gross	Net
Development Wells:
Productive:
Oil	47	22	48	32	64	52
Gas	2	1	—	—	—	—
Nonproductive	—	—	—	—	—	—
Exploratory Wells:
Productive:
Oil	11	10	—	—	—	—
Gas	—	—	—	—	—	—
Nonproductive	1	—	—	—	—	—

There were 53 gross (14.2 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. Two gas wells are located in Yuma County, Colorado.

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,
	2014		2013		2012
Production :
Oil (Bbls ¹ )		941,218		421,265		235,691
Gas (Mcf ² )		3,747,074		2,107,603		1,109,057
BOE ³		1,565,729		772,532		420,534

Average sales price:
Oil ($/Bbl)	$	89.98	$	85.95	$	87.59
Gas ($/Mcf)	$	5.21	$	4.75	$	3.90
BOE	$	66.56	$	59.83	$	59.37

Average production cost per BOE	$	5.10	$	4.42	$	2.73

¹		“Bbl” refers to one stock tank barrel, or 42 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.
²		“Mcf” refers to one thousand cubic feet of natural gas.
³		“BOE” refers to barrel of oil equivalent, which combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil.

Production costs generally include pumping fees, maintenance, repairs, labor, utilities and administrative overhead. Taxes on production, including ad valorem and severance taxes, are excluded from production costs. We experienced an increase in production costs as we transitioned to horizontal wells. In their initial months, horizontal wells have been more expensive to operate. We expect the operating costs to stabilize as the wells mature.

We are not currently obligated to provide a fixed and determined quantity of oil or gas to any third party. During the last three fiscal years, we have not had, nor do we now have, any long-term supply or similar agreement with any government or governmental authority.

Oil and Gas Properties, Wells, Operations and Acreage

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

·	royalties and other burdens and obligations, express 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, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles;

·	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 conventional in the industry for properties of the kind that we own.

The following table shows, as of October 10, 2014, 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		404		284		16,312		12,155		252,642		116,131
Nebraska		—		—		—		—		185,988		183,589
Wyoming		—		—		—		—		1,143		472
Kansas		—		—		—		—		840		840
Total		404		284		16,312		12,155		440,613		301,032

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, 2014, the status of our gross acreage:

State	Held by Production		Not Held by Production

Colorado		16,312		252,642
Nebraska		—		185,988
Wyoming		—		1,143
Kansas		—		840
Total		16,312		440,613

Acres that are Held by Production 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 first to occur of the following: 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, which are not Held by Production, will expire, unless a productive oil or gas well is drilled on the lease.

Leased Acres		Expiration of Lease

75,196		2015
45,079		2016
42,693		2017
277,645		After 2017

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

Oil and Gas Reserves

Ryder Scott Company, L.P. (“Ryder Scott”) prepared the estimates of our proved reserves, future productions and income attributable to our leasehold interests for the year ended August 31, 2014. Ryder Scott is an independent petroleum engineering firm that has been providing petroleum consulting services worldwide for over seventy years. The estimates of drilled reserves, future production and income attributable to certain leasehold and royalty interests are based on technical analysis 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 and price differentials for our wells. Additionally, authorizations for expenditure, geological and geophysical data, and other engineering data that complies with SEC guidelines are among that which we provide to Ryder Scott engineers for consideration in estimating our underground accumulations of crude oil and natural gas.

The report of Ryder Scott dated October 9, 2014, 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, 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 barrels (Bbls) for oil and for, natural gas, in thousands of cubic feet (Mcf) 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, 2014, in those cases where this data was considered to be definitive. The data used in this analysis was obtained from public data sources and were 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 data sources that were available through August 31, 2014.

Below are estimates of our net proved reserves at August 31, 2014, all of which are located in Colorado:

	Oil		Gas		BOE
	(Bbls)		(Mcf)
Proved:
Producing		4,537,061		25,921,459		8,857,304
Nonproducing		2,079,421		12,240,142		4,119,445
Undeveloped		9,708,471		57,016,746		19,211,262
Total		16,324,953		95,178,347		32,188,011

Below are estimates of our present value of estimated future net revenues from such reserves based upon the standardized measure of discounted future net cash flows relating to proved oil and gas reserves 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 period-end 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 years ended August 31, 2014, 2013 and 2012. The resulting estimated future cash inflows are then reduced by estimated future costs to develop and produce reserves based on period-end cost levels. No deduction has been made for depletion, depreciation or for indirect costs, such as general corporate overhead. Present values were computed by discounting future net revenues by 10% per year.

As of August 31, 2014, 2013 and 2012, our standardized oil and gas measurements were as follows (in thousands):

	Proved - August 31, 2014
	Developed									Total
	Producing			Nonproducing			Undeveloped			Proved
Future gross revenue	$	511,252		$	234,452		$	1,094,283		$	1,839,987
Deductions		(141,145	)		(78,393	)		(587,999	)		(807,537	)
Future net cash flow		370,107			156,059			506,284			1,032,450
Discounted future net cash flow (pre-tax)	$	250,749		$	76,593		$	206,356		$	533,698
Standardized measure of discounted future
net cash flows (after tax)										$	402,699


	Proved - August 31, 2013
	Developed									Total
	Producing			Nonproducing			Undeveloped			Proved
Future gross revenue	$	206,065		$	286,207		$	256,758		$	749,030
Deductions		(46,410	)		(78,691	)		(129,541	)		(254,642	)
Future net cash flow		159,655			207,516			127,217			494,388
Discounted future net cash flow (pre-tax)	$	92,888		$	104,392		$	38,836		$	236,116
Standardized measure of discounted future
net cash flows (after tax)										$	181,732


	Proved - August 31, 2012
	Developed									Total
	Producing			Nonproducing			Undeveloped			Proved
Future gross revenue	$	120,802		$	173,144		$	243,516		$	537,462
Deductions		(21,099	)		(48,536	)		(116,798	)		(186,433	)
Future net cash flow		99,703			124,608			126,718			351,029
Discounted future net cash flow (pre-tax)	$	57,797		$	56,196		$	34,890		$	148,883
Standardized measure of discounted future
net cash flows (after tax)										$	102,505

For standardized oil and gas measurement purposes, our drilling, acquisition, and participation activities during the year ended August 31, 2014, generated increases in projected future gross revenue from proved reserves of $1.1 billion and future net cash flow of $538.1 million from August 31, 2013. During that same period, when applying a 10% discount rate to our future net cash flows, our discounted future net cash flow from proved reserves increased by $297.5 million. Increases in our standardized oil and gas measures were the result of our expenditures during the year ended August 31, 2014, of approximately $185 million for the development of oil and gas properties and acquisitions of in place reserves, which directly related to proved oil and gas reserves.

For standardized oil and gas measurement purposes, our drilling, acquisition, and participation activities during the year ended August 31, 2013, generated increases in projected future gross revenue from proved reserves of $211.6 million and future net cash flow of $143.3 million from August 31, 2012. During that same period, when applying a 10% discount rate to our future net cash flows, our discounted future net cash flow from proved reserves increased by $87.2 million. Increases in our standardized oil and gas measures were the result of our expenditures during the year ended August 31, 2013, of approximately $104.3 million for the development of oil and gas properties and acquisitions of in place reserves, which directly related to proved oil and gas reserves.

For standardized oil and gas measurement purposes, our drilling, acquisition, and participation activities during the year ended August 31, 2012, generated increases in projected future gross revenue from proved reserves of $302.2 million and future net cash flow of $197.4 million from August 31, 2011. During that same period, when applying a 10% discount rate to our future net cash flows, our discounted future net cash flow from proved reserves increased by $77.1 million. Increases in our standardized oil and gas measures were the result of our expenditures during the year ended August 31, 2012, of approximately $33 million for the development of oil and gas properties and acquisitions of in place reserves, which directly related to proved oil and gas reserves.

In general, the volume of production from our oil and gas properties declines as reserves are depleted. Except to the extent 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 the level of success in acquiring or finding additional reserves and the costs incurred in doing so.

Proved Undeveloped Reserves

	Net Reserves, Boe
Beginning September 1, 2012		4,939,735
Converted to proved developed		(185,246	)
Additions from capital program		481,463
Acquisitions (sales)		674,531
Revisions (pricing and engineering)		(1,051,976	)
Ending August 31, 2013		4,858,507
Converted to proved developed		(586,974	)
Additions from capital program		13,436,253
Acquisitions (sales)		1,522,445
Revisions (pricing and engineering)		(18,969	)
Ending August 31, 2014		19,211,262

At August 31, 2014, our proved undeveloped reserves were 19,211,262 Boe. None of the proved undeveloped reserves have been in this category for more than 5 years and all are scheduled to be drilled within five years of their initial discovery. During 2014, 586,974 Boe or 12% of our proved undeveloped reserves (5 horizontal wells) 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 13,436,253 Boe in proved undeveloped reserves.

During 2014, a large percentage of our drilling budget was allocated to exploratory wells. During 2015, we expect to allocate a larger percentage to developmental wells. Additionally, to assist with our 2015 drilling schedule, we added a third rig in September 2014.

At August 31, 2013, our proved undeveloped reserves were 4,858,507 Boe. None of the proved undeveloped reserves have been in this category for more than 5 years and all are scheduled to be drilled within five years of their initial discovery. During 2013, 185,246 Boe or 4% of our proved undeveloped reserves (6 wells) were converted into proved developed reserves requiring $3.6 million of drilling and completion capital expenditures. Executing our 2013 capital program resulted in the addition of 481,463 Boe in proved undeveloped reserves (5 wells).

The transition from vertical drilling to horizontal drilling resulted in a conversion rate of less than 20% of proved undeveloped reserves to proved developed reserves for the year. In addition, the negative revision of 1,051,976 Boe is primarily the result from eliminating previously planned vertical proved undeveloped locations while planning for horizontal development.

Government Regulation

Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and 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.

Failure to comply with applicable laws and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are 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. Additional proposals and proceedings that affect the natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”), and the courts. We cannot predict when or whether any such proposals or proceedings may become effective.

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 permits for drilling operations, drilling bonds and the filing of reports concerning operations and impose other requirements relating to the exploration of oil and natural gas. Many states also have statutes or regulations addressing conservation matters including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and gas wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of some states limit the rate at which oil and gas is produced from our properties. 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 area in which we operate. Via the permitting and inspection process, COGCC regulates oil and gas operators and, among other criteria, enforces specifications regarding the mechanical integrity of wells as well as the prevention and mitigation of adverse environmental impacts. 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 a uniform 1,000 feet statewide setback from high occupancy building units. The new setback rules also require operators to utilize increased mitigation measures to limit potential drilling impacts to surface owners and the owners of occupied building units. The new rules also require operators to provide advance notice to surface owners within 500 feet of proposed operations, the owners of occupied buildings within 1,000 feet of proposed operations, and local governments prior to the filing of an Application for Permit to Drill or Oil and Gas Location Assessment. The new rules include expanded outreach and communication efforts by an operator. Additionally, in January 2013, the COGCC also approved two rules that require operators to sample groundwater for hydrocarbons and other indicator compounds both before and after drilling. The new statewide rule requires sampling of up to four water wells within a half mile radius of a new oil and natural gas well before drilling, two samples between six and 12 months after completion, and two more samples between five and six years after completion. The revised rule for the Greater Wattenberg Area requires operators to sample one water well per quarter governmental section before drilling and between six to 12 months after completion.

Regulation of sales and transportation of natural gas

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

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

Natural gas continues to supply a significant portion of North America's energy needs and we believe the importance of natural gas in meeting this energy need will continue. The impact of the ongoing economic downturn on natural gas supply and demand fundamentals has resulted in extremely volatile natural gas prices, which is expected to continue.

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, beginning in 2009, 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 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 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 believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from 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 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 these clearing and cash collateral requirements for commercial end-users. In addition, in August 2012, the SEC issued a final rule under Section 1504 of the Dodd-Frank Act, Disclosure of Payment by Resource Extraction Issuers, which would have required resource extraction issuers, such as us, to file annual reports that provide information about the type and total amount of payments made for each project related to the commercial development of oil, natural gas, or minerals to each foreign government and the federal government. In July 2013, the U.S. District Court for the District of Columbia vacated the rule, and the SEC has announced it will not appeal the court's decision. However, the SEC 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; impose substantial liabilities for pollution resulting from our operations; 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 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. 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 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.

Federal agencies are also considering additional regulation of hydraulic fracturing. The EPA has prepared draft guidance for issuing underground injection permits that would regulate hydraulic fracturing using diesel fuel, where the EPA has permitting authority under the SDWA; this guidance eventually could encourage other regulatory authorities to adopt permitting and other restrictions on the use of hydraulic fracturing. In addition, on October 21, 2011, the EPA announced its intention to propose regulations by 2014 under the federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production. The EPA is also collecting information as part of a nationwide study into the effects of hydraulic fracturing on drinking water. The EPA issued a progress report regarding the study in December 2012, which described generally the continuing focus of the study, but did not provide any data, findings, or conclusions regarding the safety of hydraulic fracturing operations. The EPA intends to issue a final draft report for peer review and comment in 2014. The results of this study, which is still ongoing, could result in additional regulations, which could lead to operational burdens similar to those described above. The EPA also has initiated a stakeholder and potential rulemaking process under the Toxic Substances Control Act (“TSCA”) to obtain data on chemical substances and mixtures used in hydraulic fracturing, and recently published in the Federal Register a petition from national environmental advocacy groups seeking to include the oil and gas sector in the Toxics Release Inventory reporting program established for many industries under TSCA. The United States Department of the Interior has also proposed a new rule regulating hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water. In addition, the U.S. Occupational Safety and Health Administration has proposed stricter standards for worker exposure to silica, which would apply to use of sand as a proppant for hydraulic fracturing.

The EPA recently amended the Underground Injection Control, (“UIC”) provisions of the federal Safe Drinking Water Act (the “SDWA”) to exclude hydraulic fracturing from the definition of “underground injection.” However, the U.S. Senate and House of Representatives are currently considering the Fracturing Responsibility and Awareness of Chemicals Act (the “FRAC Act”), which will amend the SDWA to repeal this exemption. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities, which could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements.

The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. While no federal law is presently in place, some states have enacted laws pertaining to chemical disclosure. In December 2011, the State of Colorado approved regulation requiring parties engaged in hydraulic fracturing to disclose the concentrations of the chemicals used in the process. The regulation went into effect in April 2012 and requires the reporting of additives used.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.

Consequently, the EPA proposed two sets of regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and, also, could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2012 for emissions occurring in 2011.

Also, on June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009 (the “ACESA”) which would establish an economy-wide cap-and-trade program to reduce United States emissions of greenhouse gases including carbon dioxide and methane that may contribute to the warming of the Earth’s atmosphere and other climatic changes. If it becomes law, ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas.

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. 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 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 forcing a mixture of fluid and white sand into a formation to create pores and fractures, thus creating a passageway for the release of oil and gas. All of our producing wells were hydraulic fractured and we expect to employ the technique 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 mixtures that are injected into our wells. These mixtures primarily consist of water and sand, with nominal amounts of other ingredients used as accelerants and proppants. The additional ingredients are designed to improve the resulting porosity of the shale and include food based compounds commonly found in consumer products. This mixture is injected into our wells at pressures of 4,500-6,000 psi at injection rates that that range between 25-55 barrels of mixture per minute. On average, a single stage stimulation will utilize approximately 4,500 barrels of water and 150,000 pounds of sand.

We require our service companies to carry adequate insurance covering incidents that could occur in connection with their activities. Our service providers are responsible for obtaining any regulatory permits necessary for them to perform their services in the respective 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 are considering the adequacy of current regulations.

The federal SDWA comparable state statutes may restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids, primarily via disposal wells or enhanced oil recovery (“EOR”) wells, is governed by federal or state regulatory authorities that, in some cases, include the state oil and gas regulatory or the state's environmental authority. The 2005 EPA amended the UIC, provisions of the SDWA to expressly exclude certain hydraulic fracturing from the definition of "underground injection," but disposal of hydraulic fracturing fluids and produced water or their injection for EOR is not excluded. The U.S. Senate and House of Representatives have considered bills to repeal this SDWA exemption for hydraulic fracturing. If 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, meet plugging and abandonment requirements, and provide additional public disclosure of chemicals used in the fracturing process as a consequence of additional SDWA permitting requirements.

In Colorado, the primary regulator is the COGCC, which requires parties engaged in hydraulic fracturing to disclose the concentrations of the chemicals used in the process.

Apart from these ongoing federal and state initiatives, local governments are adopting new requirements on hydraulic fracturing and other oil and gas operations. Some counties 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, in 2012, Longmont, Colorado prohibited the use of hydraulic fracturing. The oil and gas industry and the State have challenged that ban, and the authority of local jurisdictions to regulate oil and gas development, in court. In November 2013, four other Colorado cities and counties passed voter initiatives either placing a moratorium on hydraulic fracturing or banning new oil and gas development. These initiatives are also the subject of pending legal challenge. While these initiatives cover areas with little recent or ongoing oil and gas development, they could lead opponents of hydraulic fracturing to push for statewide referendums, especially in Colorado.

Competition and Marketing

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

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

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

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

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

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

General

Our offices are located at 20203 Highway 60, Platteville, CO 80651. Our office telephone number is (970) 737-1073 and our fax number is (970) 737-1045.

Our Platteville offices, including headquarters and 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 2014 lease, which expired on July 1, 2014, required monthly payments of $15,000. The 2015 lease, which expires on July 1, 2015, also requires monthly payments of $15,000.

We also occupy office space in Denver under a 42 month sublease that requires monthly payments of approximately $4,200. The lease expires on June 1, 2017.

As of October 10, 2014, we had 29 full time employees.

Neither we, nor any of our properties, are subject to any pending legal proceedings.

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”).

The “Investor Relations, News / Events” pages on our website contain press releases and investor presentations with more recent information than may have been available at the time of the most recent filing with the SEC.

Our Code of Ethics and Board of Directors Committee Charters (Audit and Compensation Committees) are also available on our website under “Investor Relations, Corporate Governance.”

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

Oil and natural gas prices are volatile. An extended decline in the prices of oil and natural gas would likely have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations and results of operations.

Our future financial condition, 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. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms also substantially depends upon oil and natural gas prices.

These factors include:

•

relatively minor changes in the supply of or the demand for oil and natural gas;

•

the condition of the United States and worldwide economies;

•

market uncertainty;

•

the level of consumer product demand;

•

weather conditions in the United States;

•

the actions of the Organization of Petroleum Exporting Countries;

•

domestic and foreign governmental regulation and taxes, including price controls adopted by the Federal Energy Regulatory Commission;

•

political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South America;

•

the price and level of foreign imports of oil and natural gas; and

•

the price and availability of alternate fuel sources.

We cannot predict future oil and natural gas prices and such prices may decline. An extended decline in oil and natural gas prices may adversely affect our financial condition, liquidity, ability to meet our financial obligations and results of operations. Lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and has required and may require us to record additional ceiling test write-downs. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices. Our sales are not made pursuant to long-term fixed price contracts.

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

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. These regulations may, in certain circumstances, impose strict liability for pollution damage or result in the interruption or termination of operations.

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 Company, L.P., 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 other 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 materially 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.

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Historically, there has been a difference between our actual production and the production estimated in a prior year’s reserve report. Our 2014 production was approximately 58% greater than amounts projected in our August 31, 2013 reserve report. We cannot assure you that these differences will not be material in the future.

Approximately 60% of our estimated proved reserves at August 31, 2014 are undeveloped and 12% were developed, non-producing. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop and produce our reserves. Although we have prepared estimates of our oil and natural gas reserves and the costs associated with these reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the actual results will be as estimated. In addition, the recovery of undeveloped reserves is generally subject to the approval of development plans and related activities by applicable state and/or federal agencies. Statutes and regulations may affect both the timing and quantity of recovery of estimated reserves. Such statutes and regulations, and their enforcement, have changed in the past and may change in the future, and may result in upward or downward revisions to current estimated proved reserves.

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, 2014 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 the 10% discount factor.

Seasonal weather conditions and wildlife restrictions 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 the ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations. 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 and 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.

In order to maintain or increase our reserves, we must constantly 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.

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 long-term 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 long-term capital as dictated by current economic conditions:

•

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.

Factors beyond our control affect our ability to market oil and natural gas.

The availability of markets and the volatility of product prices are beyond our control and represent a significant risk. The marketability of our production depends upon the availability and capacity of natural gas gathering systems, pipelines and processing facilities. The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Our ability to market oil and natural gas also depends on other factors beyond our control. These factors include:

•

the level of domestic production and imports of oil and natural gas;

•

the proximity of natural gas production to natural gas pipelines;

•

the availability of pipeline capacity;

•

the demand for oil and natural gas by utilities and other end users;

•

the availability of alternate fuel sources;

•

the effect of inclement weather;

•

state and federal regulation of oil and natural gas marketing; and

•

federal regulation of natural gas sold or transported in interstate commerce.

If these factors were to change dramatically, our ability to market oil and natural gas or obtain favorable prices for our oil and natural gas could be adversely affected.

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.

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 prior 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. 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.

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.

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, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, excessive pressures, maintenance, weather, field labor issues or disruptions in service. Curtailments and disruptions in these systems may last from a few days to several months. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines or gathering system capacity. These risks are greater for us than for some of our competitors because our operations are focused on areas where there is currently a substantial amount of development activity, which increases the likelihood that there will be periods of time in which there is insufficient midstream capacity to accommodate the resulting increases in production. For example, the gas gathering systems serving the Wattenberg Field recently experienced high line pressures reducing capacity and causing 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 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, a 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, continued acquisition financing may not be available or available on reasonable terms, 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 the ability to estimate accurately the recoverable volumes of reserves, 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. However, even an in-depth review of records and properties may not necessarily reveal existing or potential problems or permit us to become familiar enough with the properties to assess fully their deficiencies and potential. Even when problems are identified, we may assume certain 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 certain covenants that limit, or which may have the effect of limiting, among other things acquisitions, capital expenditures, the sale of assets and the incurrence of additional indebtedness.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil and natural gas, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

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 amount of governmental regulations that increase costs related to the drilling of wells and the transportation and processing of oil and natural gas. 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 that are primarily driven by concerns about wildlife and the environment. These government regulatory requirements may result in substantial costs that are not possible to pass through to our customers and which could impact the profitability of our operations.

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

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

•

require applying for and receiving a permit before drilling commences;

•

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

•

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; 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. 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 analogous state laws, we could be held strictly 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.

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 increasing 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.

Recently, 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 is evaluating whether reconsideration of other issues is warranted. At this point, we cannot predict the final regulatory requirements or the cost to comply with such air regulatory requirements.

Some activists have attempted to link hydraulic fracturing to various environmental problems, including potential adverse effects to 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 are expected to be released for public and peer review in 2014. In addition, on October 21, 2011, the EPA announced its intention to propose regulations by 2014 under the federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production. The EPA also has prepared draft guidance for issuing underground injection permits that would regulate hydraulic fracturing using diesel fuel, where 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. The U.S. Department of Interior, moreover, has proposed new rules for hydraulic fracturing activities on federal lands that, in general, would cover disclosure of fracturing fluid components, well bore integrity, and handling of flowback water. And the U.S. Occupational Safety and Health Administration has proposed stricter standards for worker exposure to silica, which would apply to use of sand as a proppant for hydraulic fracturing.

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

Apart from these ongoing federal initiatives, state governments where we operate have moved to impose stricter requirements on hydraulic fracturing and other aspects of oil and gas production. Colorado, for example, comprehensively updated its oil and gas regulations in 2008 and adopted significant additional amendments in 2011 and 2013. Among other things, the updated and amended regulations require operators to reduce methane emissions associated with hydraulic fracturing, compile and report additional information regarding well bore integrity, 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, and implement additional groundwater testing. The State is also considering new regulations for air emissions from oil and gas operations as well as potential legislation increasing the monetary penalties for regulatory violations. 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 adoption of future federal, state or local laws or implementing regulations 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 on hydraulic fracturing and other oil and gas operations. Some counties 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, in 2012, Longmont, Colorado prohibited the use of hydraulic fracturing. The oil and gas industry and the State are challenging that ban, and the authority of local jurisdictions to regulate oil and gas development, in court. In November 2013, four other Colorado cities and counties passed voter initiatives either placing a moratorium on hydraulic fracturing or banning new oil and gas development. These initiatives too are the subject of pending legal challenge. While these initiatives cover areas with little recent or ongoing oil and gas development, they could lead opponents of hydraulic fracturing to push for statewide referendums, especially in Colorado. 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 compliance costs and environmental liabilities could have a material adverse effect on our financial condition and operations.

Our operations are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:

•

require the acquisition of permits before drilling commences;

•

restrict the types, quantities and concentration of various substances that can be released into the environment from drilling and production activities;

•

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands 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.

The trend toward stricter standards in environmental legislation and regulation is likely to continue. The enactment of stricter legislation or the adoption of stricter regulations could have a significant impact on our operating costs, as well as on the oil and natural gas industry in general.

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, including limited coverage for sudden and accidental environmental damages, but this insurance may not extend to the full potential liability that could be caused by sudden and accidental environmental damages and further may not cover environmental damages that occur over time. 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.

The Oil Pollution Act of 1990 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 Oil Pollution Act, 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, which was signed into law on July 21, 2010, establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act also establishes margin requirements and certain transaction clearing and trade execution requirements. On October 18, 2011, the Commodities Futures Trading Commission (the "CFTC") approved regulations to set position limits for certain futures and option contracts in the major energy markets, which were successfully challenged in federal district court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association and largely vacated by the court. The CFTC has filed a notice of appeal with respect to this ruling. Under CFTC final rules promulgated under the Dodd-Frank Act, we believe our derivatives activity will qualify for the non-financial, commercial end-user exception, which exempts derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing requirement. The Dodd-Frank Act may also require us to comply with margin requirements in our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation 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 Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of derivative as a result of the Dodd-Frank Act and 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. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows

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, 2014 the aggregate amount of our outstanding indebtedness, net of cash on hand, was $2.2 million, which could have important consequences for you, including the following:

•

the covenants contained in our debt agreements 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 certain of our borrowings in the future may be at variable rates of interest, 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.

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 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. We cannot assure you that any of these remedies could, if necessary, be affected on commercially reasonable terms, 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 a number of significant covenants that, among other things, 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 condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests 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 limitations that the restrictive covenants under our credit facility.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our credit facility. A default, if not cured or waived, could result in all indebtedness outstanding under our credit facility to become 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.

Our two most senior executives may allocate some portion of their time to other business interests, which could have a negative impact on our operations.

Our two most senior executives 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 reasonably assure that information required to be disclosed by us in reports we file or submit under the Exchange Act is accumulated and communicated to management, 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 systems 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 to include in our annual reports 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.

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 our then-existing debt 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. During the year ended August 31, 2014, the sales price of our stock ranged from a low of $8.11 per share (on January 6, 2014) to a high of $14.11 per share (on June 25, 2014). Factors such as announcements concerning changes in prices of oil and natural gas, the success of our acquisition, exploration and development activities, the availability of capital, and economic and other external factors, as well as period-to-period fluctuations and financial results, may have a significant effect on the market price of our common stock.

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 valuation 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 us may fluctuate.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

See Item 1 of this report.

ITEM 3.

LEGAL PROCEEDINGS

None.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

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”.

Trading of our stock on the NYSE Amex (predecessor to the NYSE MKT) began on July 27, 2011. Prior to listing on the NYSE Amex, our stock traded on the OTC Bulletin Board. 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, 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

Quarter Ended	High	Low
November 30, 2012	$4.74	$2.70
February 28, 2013	$7.00	$3.75
May 31, 2013	$7.78	$6.14
August 31, 2013	$9.43	$6.23

As of October 10, 2014, the closing price of our common stock on the NYSE MKT was $10.19.

As of October 10, 2014, we had 79,293,688 outstanding shares of common stock and 131 shareholders of record. The number of beneficial owners of our common stock is in excess of 4,600.

Our articles of incorporation authorize our board of directors to issue up to 10,000,000 shares of preferred stock. The provisions in the articles of incorporation relating to the preferred stock allow our directors to issue preferred stock with multiple votes per share and dividend rights, which would have priority over any dividends paid with respect to the holders of our common stock. The issuance of preferred stock with these rights may make the removal of management difficult even if the removal would be considered beneficial to shareholders generally, and will have the effect of limiting shareholder participation in certain transactions such as mergers or tender offers if these transactions are not favored by our management.

Additional Shares Which May be Issued

The following table lists additional shares of our common stock, which may be issued as of October 10, 2014, upon the exercise of outstanding options or warrants.

	Number of Shares	Note Reference
Shares issuable upon the exercise of Series C warrants	1,240,330	A

Shares issuable upon the exercise of Series D warrants (also described as Placement Agent warrants)	1,058	A

Shares issuable upon exercise of options held by our officers and employees	2,118,000	B

A. We issued 9,000,000 Series C warrants in connection with the sale of 180 Units at a price of $100,000 per Unit to private investors during fiscal year 2010. Each Unit consisted of one $100,000 note and 50,000 Series C warrants. Each Series C warrant entitles the holder to purchase one share of our common stock at a price of $6.00 per share at any time prior to December 31, 2014. As of October 10, 2014, 7,759,670 warrants had been exercised. We received cash proceeds of $46.6 million from the exercise of the warrants.

In connection with the unit offering, we also sold to the placement agent, for a nominal price, warrants to purchase 1,125,000 shares of our common stock at a price of $1.60 per share (these warrants are sometimes described as Series D warrants). The placement agent’s warrants expire on December 31, 2014. As of October 10, 2014, warrants to purchase 1,123,942 shares had been exercised by their holders.

B. See Item 8 of this report for information regarding shares issuable upon exercise of options held by our officers and employees.

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, 2014, 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 is a weighted composite of 254 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 September 1, 2009 and in the S&P 500 Index and the SIC Code on the same date. The results shown in the graph below are not necessarily indicative of future performance.

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 U.S. Securities and Exchange Commission. 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,
	2014			2013		2012		2011			2010
Results of Operations (in thousands):
Revenues	$	104,219		$	46,223	$	24,969	$	10,002		$	2,158
Net income (loss)		28,853			9,581		12,124		(11,600	)		(10,794	)

Net income (loss) per common share:
Basic	$	0.38		$	0.17	$	0.26	$	(0.45	)	$	(0.88	)
Diluted	$	0.37		$	0.16	$	0.25	$	(0.45	)	$	(0.88	)

Certain Balance Sheet Information (in thousands):
Total Assets	$	448,542		$	291,236	$	120,731	$	63,698		$	24,842
Working Capital		(35,338	)		50,608		10,875		685			6,237
Total Liabilities		167,052			88,016		19,619		14,590			25,859
Equity (Deficit)		281,490			203,220		101,112		49,108			(1,017	)

Certain Operating Statistics:
Production:
Oil (Bbls)		941,218			421,265		235,691		89,917			21,080
Gas (Mcf)		3,747,074			2,107,603		1,109,057		450,831			141,154
Total production in BOE		1,565,729			772,532		420,534		165,056			44,606
Average sales price per BOE	$	66.56		$	59.83	$	59.38	$	59.24		$	48.39
LOE per BOE	$	5.10		$	4.42	$	2.89	$	2.94		$	1.94
DDA per BOE	$	21.05		$	17.26	$	14.29	$	16.62		$	15.52

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 2012, 2013 and 2014.

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 financial condition as of August 31, 2014, and the results of operations for the years ended August 31, 2014, 2013 and 2012. 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 Note Regarding 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 are not limited to, those discussed in the subsection entitled “Risk Factors” above, which are incorporated herein by reference. 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 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. 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 known as the Wattenberg Field covers the western flank of the D-J basin, particularly in Weld County. The area has produced oil and gas for over fifty years and has a history as one of the most prolific production areas in the country. Substantially all of our producing wells are either in or adjacent to the Wattenberg Field.

Since commencing active operations in September 2008, we have undergone significant growth. Our growth was primarily driven by (i) our activities as an operator where we drill and complete productive oil and gas wells; (ii) our participation as a part owner in wells drilled by other operating companies; and (iii) our acquisition of producing oil wells from other individuals or companies. As of August 31, 2014, we have completed, acquired, or participated in 404 gross (284 net) successful oil and gas wells. We drilled one exploratory test well during fiscal 2014, which was immediately plugged and abandoned. The following tables summarize activity with respect to operated and non-operated vertical and horizontal wells during the last three years:

	VERTICAL WELLS
	OPERATED WELLS				NON-OPERATED WELLS
	Completed				Participated				Acquired				Total
Years ended:	Gross		Net		Gross		Net		Gross		Net		Gross		Net

August 31, 2012		51		48		8		3		4		4		63		55
August 31, 2013		27		26		10		4		36		34		73		64
August 31, 2014		1		1		5		1		60		35		66		37

Total		79		75		23		8		100		73		202		156

	HORIZONTAL WELLS
	OPERATED WELLS				NON-OPERATED WELLS
	Completed				Participated				Acquired				Total
Years ended:	Gross		Net		Gross		Net		Gross		Net		Gross		Net

August 31, 2012		-		-		5		1		-		-		5		1
August 31, 2013		-		-		11		2		-		-		11		2
August 31, 2014		31		29		23		2		-		-		54		31

Total		31		29		39		5		-		-		70		34

As is evident in the tables above, we have undergone a shift in focus with respect to the types of wells we are completing. Whereas early development efforts were focused on drilling vertical wells into the Niobrara, Codell, and J-Sand formations, in May 2013, development efforts have shifted to horizontal wells. Horizontal wells are significantly more expensive and take longer to drill and complete than vertical wells, but ultimately generally yield a greater return. We substantially completed five Renfroe wells during 2013 and they commenced production during September 2013. During fiscal 2014, we also commenced production from 26 wells in the Leffler, Phelps, Union, Eberle and Kelly Farms prospects.

In addition to the 404 wells that had reached productive status as of August 31, 2014, we were the operator of 10 horizontal wells in progress. Two of those wells, including one well on the Eberle prospect and one well on the Phelps prospect, commenced production early in September 2014. We were participating as a non-operator in 43 gross (6 net) horizontal wells that were in various stages of the drilling or completion process. Generally, horizontal wells on a six well pad are expected to require 120 to 150 days to drill, complete and connect to the gathering system.

As of August 31, 2014, we:

·	were the operator of 31 horizontal wells that were producing oil and gas and we were participating as a non-operating working interest owner in 39 horizontal producing wells;

·	were the operator of 269 vertical wells that were producing oil and gas and we were participating as a non-operating working interest owner in 65 producing wells;

·	were the operator of 10 wells in progress and we were participating as a non-operating working interest owner in 43 wells in progress;

·	held approximately 451,000 gross acres and 309,000 net acres under lease; and

·	had estimated proved reserves of 16.3 million barrels (“Bbls”) of oil and 95.2 billion cubic feet (“Bcf”) of gas.

During our fiscal year ended August 31, 2014, we increased our estimated proved reserves by 133% on a BOE equivalent basis and increased our estimated proved reserves by 126% on a PV-10 basis. During the last three months of the fiscal year ended August 31, 2014, we commenced production on three pads in the Wattenberg field, which significantly increased our BOE production. Our consolidated daily production from our producing wells increased during fiscal 2014 from 2,479 BOED as of August 31, 2013 to 5,894 BOED as of August 31, 2014.

Strategy

Our basic strategy for continued growth includes additional drilling activities and acquisition of existing wells in well-defined areas that provide significant cash flow and rapid return on investment. We attempt to maximize our return on assets by drilling in low risk areas and by operating wells in which we have a majority net revenue interest. Our drilling efforts have been, and for the foreseeable future will continue to be, focused on the Wattenberg Field as it yields consistent results. Our drilling strategy has shifted during the past two years to focus our efforts towards drilling horizontal wells. During the year ended August 31, 2014, we drilled or participated in 31 net horizontal wells and substantially ceased completion and re-completion of our vertical wells. Our plans for 2015 contemplate drilling or participating in 41 to 48 net horizontal wells.

Historically, our cash flow from operations was not sufficient to fund our growth plans and we relied on proceeds from the sale of debt and equity securities. We had also arranged for a bank credit facility to fund our liquidity needs. During fiscal 2014, our primary source of capital resources was cash on hand at the beginning of the year, cash flow from operations and proceeds from the exercise of warrants. We plan to continue to finance an increasing percentage of our growth with internally generated funds. Ultimately, implementation of our growth plans will be dependent upon the success of our operations and the amount of financing we are able to obtain. For more information, see “Liquidity and Capital Resources.”

Significant Developments

Drilling operations

Our significant developments during fiscal 2014 are described in detail in Item 1 “Business” under the heading 2014 Operational and Financial Summary.

Market conditions

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

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

For the periods presented in this report, the following table presents the average NYMEX price as well as the differential between the NYMEX prices and the wellhead prices realized by us.

Fiscal years ended:	August 31,
	2014			2013			2012
Oil (NYMEX WTI)
Average NYMEX Price	$	100.39		$	94.58		$	94.88
Realized Price	$	89.98		$	85.95		$	87.59
Differential	$	(10.41	)	$	(8.63	)	$	(7.29	)

Gas (NYMEX Henry Hub)
Average NYMEX Price	$	4.38		$	3.55		$	2.82
Realized Price	$	5.21		$	4.75		$	3.90
Differential	$	0.83		$	1.20		$	1.08

Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX. The negative differential has increased during our 2014 fiscal year. However, we are able to sell gas at prices greater than the posted prices, primarily because prices we receive include payment for the natural gas liquids produced with the gas.

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, 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 reserves, producing wells and daily production totals, as well as the impact of changing prices on our commodity hedge 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 of inflow and outflow 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 BOE per day in fiscal 2014, compared to 2,117 BOE per day for 2013, a year-over-year increase of 103% in BOEPD production. 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 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 BOE per day.

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

Key production information is summarized in the following table:

	Years Ended August 31,
	2014		2013
Production:
Oil (Bbls ¹ )		941,218		421,265
Gas (Mcf ² )		3,747,074		2,107,603

Total production in BOE ³		1,565,729		772,532

Revenues (in thousands):
Oil	$	84,693	$	36,206
Gas		19,526		10,017
	$	104,219	$	46,223
Average sales price:
Oil	$	89.98	$	85.95
Gas	$	5.21	$	4.75
BOE	$	66.56	$	59.83

1		“Bbl” refers to one stock tank barrel, or 42 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.
2		“Mcf” refers to one thousand cubic feet of natural gas.
3		“BOE” refers to barrel of oil equivalent, which combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil.

Lease Operating Expenses (“LOE”) 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
Work-over		197		219
Lifting cost		7,991		3,417
Severance and ad valorem taxes		9,667		4,237
Total LOE	$	17,658	$	7,654

Per BOE:
Production costs	$	4.98	$	4.14
Work-over		0.12		0.28
Lifting cost		5.10		4.42
Severance and ad valorem taxes		6.17		5.48
Total LOE	$	11.27	$	9.90

Lease operating and work-over 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. 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.

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 has been added at some well locations and older equipment has been replaced or refurbished. During 2014, we incurred additional costs related to the integration of the 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 has 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 are significant.

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

	Years ended August 31,
(in thousands)	2014		2013
Depletion	$	32,132	$	13,046
Depreciation 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. Consistent with the expected decline curve for wells targeting the Niobrara and Codell formations, we expect horizontal wells to exhibit robust production during the first few weeks, decline rapidly over the first six months, and eventually stabilize over an expected life in excess of 30 years. However, the initial reserve estimates for horizontal wells have not incorporated all of the reserves that may ultimately be recovered. The initial reserves estimated for horizontal development prospects have been prepared using an average of 80 acre spacing, compared to 20 acre spacing for vertical well development. As we gain more experience with the development of horizontal sections, we believe that spacing units will decrease, effectively increasing the EUR for each section.

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. Both of these acquisitions include areas that have the potential for future development. Successful development of these areas that increased proved reserves would have the impact of reducing cost per BOE.

General and Administrative (“G&A”) –The following table summarizes G&A expenses incurred and capitalized during the last two years

	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. In an effort to minimize overhead costs, we employ a total staff of 29 employees, and use consultants, advisors, and contractors to perform certain tasks when it is cost-effective. We maintain our corporate office in Platteville, CO partially to avoid higher rents in other areas.

Although G&A costs have increased as we grow the business, we strive to maintain an efficient overhead structure. 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 2014 includes share-based compensation of $3.0 million, compared to $1.4 million in 2013. Share-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 agreement, 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 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 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) – As more fully described in the paragraphs titled “Oil and Gas Commodity Contracts” and “Hedge Activity Accounting” located in “Liquidity and Capital Resources,” we use commodity contracts to mitigate the risks inherent in the price volatility of oil and natural gas. In the year ended August 31, 2014, we realized a cash settlement loss of $2.1 million related to contracts that settled during the period. For the year ended August 31, 2013, we realized a cash settlement loss of $0.4 million.

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

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.

For tax purposes, we have a net operating loss (“NOL”) carryover for federal purposes of $33.2 million and for state tax purposes of approximately $41.1 million, which is available to offset future taxable income and will expire, if not utilized, beginning in year 2031. For book purposes, the NOL is $22.5 million, as there is a difference of $10.7 million related to deductions for stock based compensation.

Each year, management evaluates all the positive and negative evidence regarding our tax position and reaches a conclusion on the most likely outcome. 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 carry-forward, and have therefore included it in our inventory of deferred tax assets.

For the year ended August 31, 2013, compared to the year ended August 31, 2012

For the year ended August 31, 2013, we reported net income of $9.6 million, or $0.17 per basic share, $0.16 per diluted share, compared to net income of $12.1 million, or $0.26 per basic share and $0.25 per diluted share for the period ended August 31, 2012. The decline in net income for 2013 reflects significant non-cash charges for an unrealized loss of $2.6 million on our commodity derivatives and a provision for deferred income taxes of $6.9 million.

There was an improvement in operating income, which increased from $11.8 million in 2012 to $19.5 million. Our 66% improvement in operating profitability was driven by our successful drilling program and integration of producing wells added in the December 2012 Orr Energy acquisition. The significant variances between the two years were primarily caused by increased revenues and expenses associated with a greater number of producing wells. The following discussion expands upon significant items of inflow and outflow that affected results of operations.

Oil and Gas Production and Revenues – For the year ended August 31, 2013, we recorded total revenues of $46.2 million compared to $25.0 million for the year ended August 31, 2012, an increase of $21.2 million or 85%. We experienced an overall 84% annual increase in production quantities from the prior year having realized a full year of production from wells at the beginning of the year, and the addition of wells, including new wells drilled as well as those acquired with the December 2012 Orr Energy acquisition.

	Years Ended August 31,
	2013		2012
Production:
Oil (Bbls ¹ )		421,265		235,691
Gas (Mcf ² )		2,107,603		1,109,057

Total production in BOE ³		772,532		420,534

Revenues (in thousands):
Oil	$	36,206	$	20,644
Gas		10,017		4,325
	$	46,223	$	24,969
Average sales price:
Oil	$	85.95	$	87.59
Gas	$	4.75	$	3.90
BOE	$	59.83	$	59.38

1		“Bbl” refers to one stock tank barrel, or 42 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.
2		“Mcf” refers to one thousand cubic feet of natural gas.
3		“BOE” refers to barrel of oil equivalent, which combines Bbls of oil and Mcf of gas by converting each six Mcf of gas to one Bbl of oil.

As of August 31, 2013, we owned interests in 293 producing wells. Net oil and gas production averaged 2,117 BOE per day in 2013, as compared with 1,149 BOE per day for 2012, a year over year increase of 84% in BOEPD production. The significant increase in production from the prior year reflects 84 additional wells that went into productive status during 2013 and a full year of production from the 68 wells that were added over the course of fiscal year 2012. Production for the fourth fiscal quarter of 2013 averaged 2,479 BOE per day.

Revenues are sensitive to changes in commodity prices. From 2012 to 2013, our realized annual average sales price per barrel of oil decreased 2%; however, we experienced an increase of 22% in our realized annual average sales price per Mcf of natural gas. Overall on a BOE basis, 99% of the increase in oil and gas revenues was attributed to increased volumes and 1% was attributed to the increase of BOE prices received.

Lease Operating Expenses (“LOE”) and Production Taxes – Direct operating costs of producing oil and natural gas and taxes on production and properties are summarized as follows (in thousands):

	Years Ended August 31,
Lease Operating Expenses	2013		2012
Lifting costs	$	3,198	$	1,146
Work-over		219		66
Total LOE	$	3,417	$	1,212
LOE per BOE	$	4.42	$	2.88

	Years Ended August 31,
Production Taxes		2013		2012
Severance and ad valorem taxes	$	4,237	$	2,436
Production taxes per BOE	$	5.48	$	5.79

Lease operating and work-over costs tend to fluctuate with the number of producing wells, and, to a lesser extent, on variations in oil field service costs and changes in the production mix of crude oil and natural gas. From 2012 to 2013, we experienced an increase in production cost per BOE in connection with additional costs to bolster output from some of our older wells. Taxes, the largest component of lease operating expenses, generally move with the value of oil and gas sold. As a percent of revenues, taxes averaged 9.2% in 2013 and 9.8% in 2012.

Depletion, Depreciation and Amortization (“DDA”) – The following table summarizes the components of DDA. Depletion expense more than doubled, primarily as a result of growth in production and producing properties from 2012 to 2013.

	Years ended August 31,
(in thousands)	2013		2012
Depletion	$	13,046	$	5,838
Depreciation and amortization		290		172
Total DDA	$	13,336	$	6,010

DDA expense per BOE	$	17.26	$	14.29

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 2013, our depletable reserve base was 14,829,487 BOE. Fiscal year 2013 production represented 5.2% of the reserve base.

Depletion expense per BOE increased 21% from 2012 to 2013. For the fiscal year ended August 31, 2013, depletion of oil and gas properties was $17.26 per BOE compared to $14.29 for the fiscal year ended August 31, 2012. The increase in the DD&A rate was primarily the result of the allocation of the purchase price to proved properties related to our December 2012 acquisition of Orr Energy. Acquired proved reserves are valued at fair market value on the date of the acquisition, which contributes to a higher amortization base, as compared to our historical cost of acquiring leaseholds and developing our properties. To date, the fair value of our acquired reserves has been higher than our historical cost of developing our properties even though the resulting EURs are equivalent. Therefore, the increase in the ratio of costs subject to amortization to the reserves acquired is greater than our internally developed properties. We believe that, although initially acquisitions increase our DD&A rate per BOE over the development of the acquired properties, the resulting rates will decline with the drilling of horizontal wells and the addition of the related reserves.

General and Administrative (“G&A”) –The following table summarizes general and administration expenses incurred and capitalized during the last two years:

	Years Ended August 31,
(in thousands)	2013			2012
G&A costs incurred	$	6,325		$	3,902
Capitalized costs		(637	)		(345	)
Total G&A	$	5,688		$	3,557

G&A Expense per BOE	$	7.36		$	8.46

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 16 employees, and use consultants, advisors, and contractors to perform certain tasks when it is cost-effective. We maintain our corporate office in Platteville, CO partially to avoid higher rents in other areas.

Although G&A costs have increased as we grow the business we strive to maintain an efficient overhead structure. For the fiscal year ended August 31, 2013, G&A was $7.36 per BOE compared to $8.46 for the fiscal year ended August 31, 2012.

Our G&A expense for 2013 includes share based compensation of $1,362,000. The comparable amount for 2012 was $473,000. Share 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 agreement, 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 2012 to 2013 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 2013. Substantially all of the interest costs incurred under our credit facility were classified as costs related to our unevaluated assets or wells in progress and were eligible for capitalization into the full cost pool.

Beginning in 2013, we entered into commodity derivative contracts for the future sale of oil. We designed our derivative activity to protect our cash flow during periods of oil price declines. Using swaps and collars, we hedged 340,000 barrels of future production for a period of 22 months. Generally, contracts are based upon a reference price indexed to trading of West Texas Intermediate Crude Oil on the NYMEX. During the year ended August 31, 2013, the average index prices were higher than our average contract prices, and we realized a loss of $0.4 million for the year. As of August 31, 2013, the weighted average future index prices were $101.81 per barrel, approximately $7.64 higher than our contract price, creating an unrealized loss of $2.6 million at the end of the year.

Our commodity derivative contracts are revalued at fair value for each reporting period, and changes in the value of the contracts can have a significant impact on reported results of operations

Income Taxes – We reported income tax expense of $6.9 million for the fiscal year ended August 31, 2013. All of the tax liability will be deferred into future years, and it does not appear that any federal or state payments will be required for 2013. During 2012, we reported a net deferred tax benefit of $332,000, essentially representing a future refund, to record the benefit arising from the net operating loss carry-forward (NOL).

For tax purposes, we have a NOL of $41 million which will begin to expire, if not utilized, in year 2031. For book purposes, the NOL is $31 million, as there is a difference of $10 million related to deductions for stock based compensation.

For 2013, we reported an effective tax rate of 42%. Our estimated effective tax rate for future periods, based upon current tax laws, is 37%. The difference reflects several differences between book income and tax income, including adjustments for statutory depletion and an adjustment to the stock based compensation component included in our inventory of deferred tax assets. During 2013, we reversed the timing difference created for the future deduction of stock based compensation when the underlying options expired. Potential tax deductions for compensation are eliminated whenever options expire without exercise.

Each year, management evaluates all the positive and negative evidence regarding our tax position and reaches a conclusion on the most likely outcome. During 2013 and 2012, we concluded that it was more likely than not that we would be able to realize a benefit from the NOL, and in 2012 we eliminated our entire valuation allowance of $4.9 million. Prior to 2012, management concluded that it was more likely than not that our net deferred tax asset would not be realized in the foreseeable future and, accordingly, a full valuation allowance was provided against the net deferred tax asset.

Liquidity and Capital Resources

Historically, we have been reliant on net cash provided by sales and other issuances of equity and debt securities as a source of liquidity. We have also relied on cash flow from operations, proceeds from the sale of properties, and borrowings under bank credit facilities. Our primary use of capital has been for the exploration, development and acquisition of oil and natural gas properties. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us. We believe that, in the near future, the combination of cash on hand, cash flows from operations and available borrowings under our revolving credit facility will provide sufficient liquidity. However, unforeseen events may require us to obtain additional equity or debt financing. We have on file with the SEC an effective universal shelf registration statement that we may use for future securities offerings. Terms of future financings may be unfavorable, and we cannot assure investors that funding will be available on acceptable terms.

Sources and Uses

At August 31, 2014, we had cash and cash equivalents of $34.8 million and an outstanding balance of $37 million under our revolving credit facility. Our sources and (uses) of funds for the fiscal years ended August 31, 2014, 2013 and 2012, are summarized below (in thousands):

	Years Ended August 31,
	2014			2013			2012
Cash provided by operations	$	74,905		$	32,120		$	21,252
Capital expenditures		(155,602	)		(80,469	)		(46,751	)
Property conveyances		-			-			71
Cash used by other investing activities		60,722			(60,000	)		-
Cash provided by equity financing activities		35,265			74,528			37,421
Net borrowings		-			34,000			(2,200	)
Net increase in cash and equivalents	$	15,290		$	179		$	9,793

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 2014.

Credit Arrangements

In December 2013 and June 2014, we modified our borrowing arrangements. The new revolving line of credit increases the maximum lending commitment to $300 million, subject to the limitations of a borrowing base calculation. The bank group providing the facility is led by Community Banks of Colorado, a division of NBH Bank, NA.

The arrangement contains covenants that, among other things, restrict the payment of dividends and require compliance with certain financial ratios. The borrowing arrangement is primarily collateralized by certain of our assets, including producing properties. The maximum lending commitment is subject to reduction based upon a borrowing base calculation, which will be re-determined semi-annually using updated reserve reports. Based upon the semi-annual redetermination derived from the February 28, 2014 reserve report, the borrowing base was increased to $110 million.

We currently have approximately $73 million available for future borrowings if needed. Additional borrowings, if any, are expected to be used to fund acquisitions, expenditures for well drilling and development, and to provide working capital.

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. At our option, interest rates will be referenced to the Prime Rate plus a margin of 0.5% to 1.5%, or the London InterBank Offered Rate plus a margin of 1.75% to 2.75%. The amended maturity date for the arrangement is May 29, 2019.

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 “all-inclusive” basis used to calculate other amounts reported in our financial statements. Specifically, cash payments for acquisition of property and equipment as reflected in the statement of cash flows excludes non-cash capital expenditures and includes an adjustment (plus or minus) to reflect the timing of when the capital expenditure obligations are incurred and when the actual cash payment is made. On the “all-inclusive” basis, capital expenditures totaled $214.0 million and $118.1 million for the years ended August 31, 2014 and 2013, respectively. A reconciliation of the differences between cash payments and the “all-inclusive” amounts is summarized in the following table (in thousands):

	Years Ended August 31,
	2014			2013			2012
Cash payments for capital expenditures	$	155,602		$	80,469		$	46,751
Accrued costs, beginning of period		(25,491	)		(5,733	)		(4,967	)
Accrued costs, end of period		71,849			25,491			5,733
Non-cash acquisitions, common stock		11,184			16,684			1,985
Other		905			1,233			300
All inclusive capital expenditures	$	214,049		$	118,144		$	49,802

Capital Expenditures

During the fiscal year ended August 31, 2014, we engaged in drilling or completion activities on 31 producing horizontal wells that we will operate, including 26 producing wells on the Leffler, Phelps, Eberle, Union, and Kelly Farms prospects. Furthermore, five wells drilled during 2013 at the Renfroe prospect commenced production during fiscal 2014. Our drilling efforts accelerated in the second half of the year, as five of these wells commenced production during our third fiscal quarter and 15 commenced production during our fourth quarter. During 2014, we expended approximately $130 million on operated horizontal wells. As of August 31, 2014, we were drilling or completing 10 operated wells in progress that had not reached productive status. Most of the wells in progress were located at the Weld 152 and Kiehn prospects. We participated in drilling and completion activities on 71 gross (9 net) non-operated wells at a cost of $25 million. As of August 31, 2014, 28 gross well (3 net) had commenced production and 43 gross wells (6 net) were classified as wells in progress. Total capital expenditures classified as wells still in progress at August 31, 2014, was $53.7 million.

We also drilled a test well at the Buffalo Run prospect to examine the potential for production from the Niobrara, Codell, Greenhorn and D-Sand formation. Our analysis of core samples from the test well held sufficient potential that we plan to commence development drilling in the area during 2015. Further, we invested $39 million in the acquisition of assets from Trilogy Resources LLC and Apollo Operating LLC, including approximately $8.3 million paid in the form of our common stock. Other expenditures included $20 million for the acquisition of lands, leases and other mineral assets, including $2.9 million paid in the form of common stock.

Capital Requirements

Our primary need for cash will be to fund our drilling and acquisition programs for the fiscal year ending August 31, 2015. Our cash requirements have increased significantly as we implement our horizontal drilling program. Each horizontal well is estimated to cost between $3.6 million and $5.5 million, depending on the length of the lateral wellbore, the number of stages, and other variables. Our preliminary capital expenditure plan for fiscal 2015 provides for spending of $200 million to $225 million for drilling and leasing activities. We are planning to drill 35 to 40 operated wells with costs ranging from $3.6 million to $5.5 million and to participate in six to eight (net) non-operated wells at a per well cost of $4.5 million to $5.0 million. Finally, leasing and other activities are planned at $10 million to $15 million. Our capital expenditure estimate is subject to adjustment for drilling success, acquisition opportunities, operating cash flow, and available capital resources.

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 hedge against the variability in cash flows created by short-term price fluctuations associated with the sale of future oil and gas production. Our hedge positions will generally cover a substantial portion of our forecasted production for a period of 24 months. We typically enter into contracts covering between 45% and 85% of anticipated production levels. During the year ended August 31, 2014, we realized a cash loss from commodity derivatives of $2.1 million. Our contracts during fiscal 2014 covered crude oil sales of 470,670 bbls and natural gas sales of 390,000 mcf. At October 10, 2014, we had open positions covering of 1.1 million bbls of oil and 1.7 million mcf of natural gas. We do not use derivative instruments for trading purposes.

Hedge Activity Accounting

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

During the year ended August 31, 2014, we reported an unrealized commodity activity gain of $2.5 million. Unrealized gains and losses are non-cash items. We also reported a realized loss of $2.1 million, representing the cash settlement cost for contracts settled during the period.

At August 31, 2014, we estimate that the fair value of our various commodity derivative contracts was a net asset of $0.2 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, 2014 may differ significantly from the realized values at their respective settlement dates.

Our commodity derivative contracts as of October 10, 2014 as summarized below:

	Hedge Volumes				Average Collar Prices ⁽¹⁾				Average Swap 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, 2014		214,040		330,000		$87.00 -$96.25		$4.07 - $4.18		$88.49		$4.58
Jan 1 to Dec 31, 2015		596,000		864,000		$81.52-$96.89		$4.15 - $4.49		$85.29		N/A
Jan 1 to Dec 31, 2016		304,000		480,000		$77.92 - $98.51		$3.99 - $4.39		$85.02		N/A

⁽¹⁾ Hedge price is at NYMEX WTI and NYMEX Henry Hub.

Contractual Commitments

The following table summarizes our contractual obligations as of August 31, 2014 (in thousands):

	Less than One Year		One to Three Years		Three to Five Years		Total
Rig Contract ¹	$	24,000	$	—		—	$	24,000
Revolving credit facility		—		—		37,000		37,000
Operating Leases		200		88		—		288
Employment Agreements		1,755		1,850		—		3,605
Total	$	25,955	$	1,938		37,000	$	64,893

Represents an estimate of the remaining commitment under three contracts with Ensign United States Drilling, Inc. for the use of three rigs. Actual amounts will vary as a result of a number of variables, including target formations, measured depth, and other technical details.

Off-Balance Sheet Arrangements

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

Non-GAAP Financial Measures

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

We define adjusted EBITDA as net income adjusted to exclude the impact of interest expense, interest income, income tax expense, DDA (depreciation, depletion and amortization), stock based compensation, and the plus or minus change in fair value of derivative assets or liabilities. We believe adjusted EBITDA is relevant because it is a measure of cash flow available to fund our capital expenditures and service our debt and is a widely used industry metric which may provide comparability of our results with our peers. The following table presents a reconciliation of adjusted EBITDA, a non-GAAP financial measure, to net income, its nearest GAAP measure.

	Years Ended August 31,
	2014			2013		2012
Adjusted EBITDA:
Net income	$	28,853		$	9,581	$	12,124
Depreciation, depletion and amortization		32,958			13,336		6,010
Provision for income tax		15,014			6,870		(332	)
Stock based compensation		2,968			1,362		473
Commodity derivative change		(2,459	)		2,649		-
Interest expense (income)		(82	)		50		(38	)
Adjusted EBITDA	$	77,252		$	33,848	$	18,237

Trend and Outlook

As previously disclosed, in fiscal 2014 we focused our capital expenditures on drilling and completing horizontal wells and increasing our leasehold in the Wattenberg Field. Since September 2013 through September 2014 we have increased our leasehold by 81% in the Wattenberg Field. We have done so through organic leasing efforts and the asset purchases discussed earlier. Our operated rig count has expanded from one rig to three rigs in the past twelve months. All of the rigs are drilling multi-well pads in the Wattenberg Field. Our focus on the Wattenberg is driven by the increasingly compelling results derived from higher density of wells drilled per spacing unit and the optimization of completion techniques. We are currently spacing our well bores to allow for up to 24 wells per section of 640 acres and we are testing drilling patterns that could lead to an even higher number of wells per section. We are also testing longer lateral wells and utilizing different amounts of proppant in order to determine the most efficient recovery of the hydrocarbons in place.

The Wattenberg Field continues to experience elevated line pressure in the natural gas and liquids gathering system, a problem that has persisted since 2012 and has grown along with the expansion of horizontal drilling in the area. High line pressure restricts our ability to produce crude oil and natural gas. As line pressures increase, it becomes more difficult to inject gas produced by our wells into the pipeline. When line pressure is greater than the operating pressure of our wellhead equipment, the wellhead equipment is unable to inject gas into the pipeline, and our production is restricted or shut-in. Since our wells produce a mixture of crude oil and natural gas, restrictions in gas production also restrict oil production. Although various factors can cause increased line pressure, a significant factor in our area of the Wattenberg Field is the success of horizontal wells that have been drilled over the last several years. As new horizontal wells come on-line with increased pressures and volumes, they produce more gas than the gathering system was designed to handle. Once a pipeline is at capacity, pressures increase and older wells with less natural pressure are not able to compete with the new wells. The pace of horizontal drilling in the Wattenberg Field continues to accelerate and it appears that it will be some time before the gathering system will have sufficient capacity to eliminate the high line pressure issues.

We have taken and are continuing to take steps to mitigate high line pressures. Where it was cost beneficial, we have installed compressors to aid the wellhead equipment in its injection of gas into the system. Compression equipment at the wellhead has proven beneficial, especially at pad sites with multiple vertical wells. Along with our mid-stream service provider, we are evaluating the installation of larger diameter pipe to improve the gas gathering capacity.

In addition, companies that operate the gas gathering pipelines continue to make significant capital investments to increase system capacity. As publicly disclosed, DCP Midstream Partners (“DCP”), the principal third party provide that we employ to gather production from our wells, brought online a 160 Mcf/d gas processing plant in La Salle, CO (the O’Connor plant), which is part of an 8 plant system owned by the DCP enterprise with approximately 600 MMcf/d capacity. The addition of this plant to our area has served primarily to curb the increasing pressure issues, but has not resolved the high line pressure problems in the region. DCP has also announced the building of the Lucerne Plant II, northeast of Greeley in Weld County, with a maximum capacity of approximately 200 mmcf/d. The Lucerne Plant II is estimated to begin operations in the first quarter of 2015. At this time, we do not know how long it will take for the mitigation efforts to remedy the problem.

The success of horizontal drilling techniques in the D-J Basin has significantly increased quantities of oil and natural gas produced in the region. Local refineries do not have sufficient capacity to process all of the crude oil available. The imbalance of supply and demand in the area is expected to result in an increase in oil transported from the D-J Basin to other markets, generally via pipeline or railroad car. The imbalance is having an impact on prices paid by oil purchasers and increased the differential between crude oil prices posted on NYMEX and the average prices realized by us. Further details regarding posted prices and average realized prices are discussed in the section entitled “market conditions,” presented in this Item 7. We continue to explore various alternatives with various oil purchasers, including a local refiner and an oil pipeline, that we believe will provide sufficient take-away capacity for all of our oil production.

Other factors that will most significantly affect our results of operations include (i) activities on properties that we operate, (ii) the marketability of our production, (iii) our ability to satisfy our substantial capital requirements, (iv) completion of acquisitions of additional properties and reserves, (v) competition from larger companies and (vi) prices for oil and gas. Our revenues will also be significantly impacted by our ability to maintain or increase oil or gas production through exploration and development activities.

It is expected that our principal source of future cash flow will be from the production and sale of oil and gas reserves, which are depleting assets. Cash flow from the sale of oil and gas production depends upon the quantity of production and the price obtained for the production. An increase in prices will permit us to finance our operations to a greater extent with internally generated funds, may allow us to obtain equity financing from more sources or on better terms, and lessens the difficulty of obtaining financing. However, price increases heighten the competition for oil and gas prospects, increase the costs of exploration and development, and, because of potential price declines, increase the risks associated with the purchase of producing properties during times that prices are at higher levels.

Since oil prices peaked in June 2014, oil prices have declined more than 23%. A continuing decline in oil and gas prices (i) will reduce our cash flow which, in turn, will reduce the funds available for exploring and replacing oil and gas reserves, (ii) will potentially reduce our current LOC borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of oil and gas prospects which have reasonable economic terms, (iv) may cause us to permit leases to expire based upon the value of potential oil and gas reserves in relation to the costs of exploration, and (v) may result in marginally productive oil and gas wells being abandoned as non-commercial. However, price declines reduce the competition for oil and gas properties and correspondingly reduce the prices paid for leases and prospects.

Other than the foregoing, we do not know of any trends, events or uncertainties that will have had or are reasonably expected to have a material impact on our sales, revenues or expenses.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America.

The following paragraphs provide a discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Note 1 of the Notes to the Financial Statements for a detailed discussion of the nature of our accounting practices and additional accounting policies and estimates made by management.

Oil and Gas Sales: We derive revenue primarily from the sale of produced crude oil and natural gas. Revenues from production on properties in which we share an economic interest with other owners are recognized on the basis of our interest. Revenues are reported on a gross basis for the amounts received before taking into account production taxes and transportation costs, which are reported as separate expenses. Revenue is recorded and receivables are accrued using the sales method, which occurs in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser. Payment is generally received between thirty and ninety days after the date of production. Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.

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

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

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

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

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

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

Stock-Based Compensation: We recognize all equity-based compensation as stock-based compensation expense, included in general and administrative expenses, based on the fair value of the compensation measured at the grant date. The expense is recognized over the vesting period of the grant.

Commodity Derivative Instruments: We have entered into commodity derivative instruments, primarily utilizing swaps or “no premium” collars to reduce the effect of price changes on a portion of our future oil and gas production. Our commodity derivative instruments are measured at fair value. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. We value our derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk free interest rates, and estimated volatility factors, as well as other relevant economic measures. 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.

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

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

·	Future reversals of existing taxable temporary differences,
·	Taxable income in prior carry back years, if permitted,
·	Tax planning strategies, and
·	Future taxable income exclusive of reversing temporary differences and carry- forwards.

Recent Accounting Pronouncements

We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new pronouncements on US GAAP and the impact on us.

In May 2014, the FASB issued ASU 2014-09, which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. The ASU allows for the use of either the full or modified retrospective transition method, and the standard will be effective for us in the first quarter of our fiscal year 2018; early adoption is not permitted. The Company is currently evaluating which transition approach to use and the impact of the adoption of this standard on its consolidated financial statements.

In December 2011, the Financial Accounting Standards Board issued Accounting Standards Update 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”), and issued Accounting Standards Update 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“ASU 2013-01”) in January 2013. These updates require disclosures about the nature of an entity’s rights of offset and related arrangements associated with its recognized derivative contracts. The new disclosure requirements, which are effective for interim and annual periods beginning on or after January 1, 2013, were implemented by the Company on September 1, 2013. The implementation of ASU 2011-11 and ASU 2013-01 had no impact on the Company’s financial position or results of operations. See Note 7 for the Company’s derivative disclosures .

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

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

Commodity Price Risk - Our primary market risk exposure results from volatility in the prices we receive for our oil and natural gas production. Realized commodity pricing for our production is primarily driven by the prevailing worldwide price for oil and spot prices applicable to natural gas. The volatility of oil prices affects our results to a greater degree than the volatility of gas prices, as approximately 81% of 2014 revenues were from the sale of oil. Although pricing for oil and natural gas production has been less volatile in recent years, we expect volatility to increase in the future. During the last three years, the average realized prices per barrel of oil have ranged from $90 to $86. Similarly, the average realized prices per mcf of gas have ranged from $5 to $4. However, a longer term view reveals that since 2008 the price of oil has ranged from $145 per bbl to $33 per bbl and the price of gas has ranged from $13 per mcf to $2 per mcf.

We attempt to mitigate fluctuations in short term cash flow resulting from changes in commodity prices by entering into derivative positions on a portion of our expected oil and gas production. We use derivative contracts to cover no less than 45% and no more than 85% of expected hydrocarbon production, generally over a period of two years. We do not enter into derivative contracts for speculative or trading purposes. As of August 31, 2014, we had open crude oil derivatives in a net liability position with a fair value of $0.2 million. A hypothetical upward shift of 10% in the NYMEX forward curve of crude oil or natural gas prices would change the fair value of our position by $(1.1) million. A hypothetical downward shift of 10% in the NYMEX forward curve of crude oil or natural gas prices would change the fair value of our position by $0.6 million.

There was no material change in the underlying commodity price risk from 2013 to 2014.

Interest Rate Risk - At August 31, 2014, we had debt outstanding under our bank credit facility totaling $37.0 million. Interest on our bank credit facility accrues at a variable rate, based upon either the Prime Rate or the London InterBank Offered Rate (LIBOR). At August 31, 2014, we were incurring interest at a rate of 2.5%. We are exposed to interest rate risk on the bank credit facility if the variable reference rates increase. A decrease in the variable interest rates would not have a significant impact on us, as the bank credit facility has a minimum interest rate of 2.5%. If interest rates increase, our monthly interest payments would increase and our available cash flow would decrease. We estimate that if market interest rates increase by 1% to an annual percentage rate of 3.5%, our interest payments would increase by approximately $0.4 million.

Under current market conditions, we do not anticipate significant changes in prevailing interest rates for the next year and we have not undertaken any activities to mitigate potential interest rate risk. There was no material change in interest rate risk from 2013 to 2014.

Counterparty Risk – As described in the discussion about Commodity Price Risk, we enter into commodity derivative agreements to mitigate short term price volatility. These derivative financial instruments present certain counterparty risks. We are exposed to potential loss if a counterparty fails to perform according to the terms of the agreement. The failure of any of the counterparties to fulfill their obligations to us could adversely affect our results of operations and cash flows. We do not require collateral or other security to be furnished by counterparties. We seek to manage the counterparty risk associated with these contracts by limiting transactions to well capitalized, well established and well known counterparties that have been approved by our senior officers. There can be no assurance, however, that our practice effectively mitigates counterparty risk. There was no material change in counterparty risk from 2013 to 2014.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See the financial statements and accompanying notes included with this report.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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

Management's Report on Internal Control over Financial Reporting

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

Under the supervision and with the participation of our management, including Ed Holloway and William E. Scaff, Jr., our Co-Chief Executive Officers, and Frank L. Jennings, our Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of August 31, 2014 based on criteria established in the Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission, or the “COSO Framework.” Based on this evaluation, management concluded that our internal control over financial reporting was effective as of August 31, 2014.

Attestation Report of Registered Public Accounting Firm

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

ITEM 9B.

OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information responsive to Items 401, 405, 406, and 407 of Regulation S-K to be included in our definitive Proxy Statement for our Annual Meeting of Shareholders, to be filed within 120 days of August 31, 2014, pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the “2014 Proxy Statement”), is incorporated herein by reference.

ITEM 11.

EXECUTIVE COMPENSATION

The information responsive to Items 402 and 407 of Regulation S-K to be included in our 2014 Proxy statement is incorporated herein by reference.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information responsive to Items 201(d) and 403 of Regulation S-K to be included in our 2014 Proxy statement is incorporated herein by reference.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR INDEPENDENCE

The information responsive to Items 404 and 407 of Regulation S-K to be included in our 2014 Proxy statement is incorporated herein by reference.

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

For each of the three years ended August 31, 2014, 2013 and 2012, EKS&H, LLLP (“EKS&H”) served as our independent registered public accounting firm. The table below shows the amount we paid EKS&H during these years (in thousands).

	Year Ended		Year Ended		Year Ended
	August 31, 2014		August 31, 2013		August 31, 2012
Audit Fees	$	275	$	220	$	175
Audit-Related Fees		42		84		42
Tax Fees		66		65		41
All Other Fees		50		25		—
Total Fees		433		394		258

Audit fees represent amounts billed for professional services rendered for the audit of our annual financial statements, our system of internal control over financial reporting and the reviews of the financial statements included in our Form 10-Q and Form 10-K reports. Audit-related fees include amounts billed for the review of our registration statement on Form S-3 and the audits of the historical financial statements of companies acquired. All other fees represent due diligence activities performed on our behalf. Prior to contracting with EKS&H to render audit or non-audit services, each engagement was approved by our audit committee.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Exhibits

1.1	Purchase Agreement, dated as of December 16, 2011, by and between Synergy Resources Corporation and Northland Securities, Inc., acting severally on behalf of itself and the underwriters named in Schedule I thereto ¹

3.1.1

Articles of Incorporation ²

3.1.2

Amendment to Articles of Incorporation ¹

3.1.3

Bylaws ²

4.1	Form of Common Stock Certificate ¹

5.1	Opinion of Hart & Trinen, LLP ¹

10.1	Employment Agreement with Ed Holloway ³

10.2	Employment Agreement with William E. Scaff, Jr. ³

10.3	Administrative Services Agreement ⁴

10.4	Agreement regarding Conflicting Interest Transactions ⁴

10.5	Consulting Services Agreement with Raymond McElhaney and Bill Conrad ⁵

10.6.1

Form of Convertible Note ⁵

10.6.2

Form of Subscription Agreement ⁵

10.6.3

Form of Series C Warrant ⁵

10.7	Purchase and Sale Agreement with Petroleum Exploration and Management, LLC (wells, equipment and well bore leasehold assignments) ⁵

10.8	Purchase and Sale Agreement with Petroleum Management, LLC (operations and leasehold) ⁵

10.9	Purchase and Sale Agreement with Chesapeake Energy ⁵

10.10

Lease with HS Land & Cattle, LLC ⁵

10.11

Employment Agreement with Frank L. Jennings ⁶

10.12

Purchase and Sale Agreement with Petroleum Exploration and Management, LLC ⁷

10.13

Loan Agreement with Bank of Choice (presently known as Guarantee Bank of Colorado) ⁸

10.14

Purchase and Sale Agreement with DeClar Oil & Gas, Inc. and Wolf Point Exploration, LLC ⁹

10.15

Amendment #1 to Loan Agreement ¹⁰

10.16

Amendment #2 to Loan Agreement ¹²

10.17

Purchase and Sale Agreement with ORR ENERGY LLC (Weld County, Colorado oil and gas property) ¹²

10.18

Exploration Agreement dated March 1, 2013 (Morgan and Weld Counties Colorado, properties) ¹³

10.19

Amendment to Drilling Contract with Ensign United States Drilling, Inc. ¹⁴

10.20

(Reserved)

10.21

Amended and Restated Credit Agreement dated November 28, 2012, together with all Amendments.

10.24

Employment Agreement with Frank Jennings ¹⁶

10.25

Employment Agreement with Craig Rasmuson ¹⁶

10.26

Employment Agreement with Valerie Dunn ¹⁶

10.27

Drilling contract with Ensign United States Drilling, Inc. dated April 19, 2014 ¹⁷

10.28	Amendment #3 to Loan Agreement dated December 20, 2013 ¹⁸

10.29	Purchase and Sale Agreement dated September 16, 2013, with Trilogy Resources, LLC ¹⁹

10.30	Purchase and Sale Agreement dated August 27, 2013, with Apollo Operating, LLC ¹⁹

10.31	Amendment #4 to Loan Agreement dated December 20, 2013 ²⁰

14	Code of Ethics (as amended) ¹¹

23.1	Consent of EKS&H LLLP

31.1	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 for Ed Holloway

31.2	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 for William Scaff, Jr.

31.3	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 for Frank L. Jennings

32	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 for Ed Holloway, William Scaff, Jr., and Frank L. Jennings

99.1	Report of Ryder Scott Company, L.P.

____________________________________

1.	Incorporated by reference to the same exhibit filed with the Company’s report on Form 8-K filed on December 16, 2011.

2.	Incorporated by reference to the same exhibit filed with the Company’s registration statement on Form SB-2, File #333-146561.

3.	Incorporated by reference to the same exhibit filed with the Company’s report on Form 8-K filed on June 7, 2013.

4.	Incorporated by reference to the same exhibit filed with the Company’s transition report on Form 10-K for the year ended August 31, 2008.

5.	Incorporated by reference to the same exhibit filed with the Company’s report on Form 10-K/A filed on June 3, 2011.

6.	Incorporated by reference to the same exhibit filed with the Company’s report on Form 8-K filed on June 24, 2011.

7.	Incorporated by reference to Exhibit 10.12 filed with the Company’s report on Form 8-K filed on August 5, 2011.

8.	Incorporated by reference to Exhibit 10.13 filed with the Company’s report on Form 8-K filed on December 2, 2011.

9.	Incorporated by reference to Exhibit 10.14 filed with the Company’s report on Form 8-K filed on February 23, 2012.

10.	Incorporated by reference to Exhibit 10.15 filed with the Company’s report on Form 8-K filed on April 25, 2012.

11.	Incorporated by reference to Exhibit 14 filed with the Company’s report on Form 8-K filed on July 22, 2011.

12.	Incorporated by reference to the same exhibit filed with the Company’s report on Form 8-K filed on October 25, 2012.

13.	Incorporated by reference to Exhibit 10.18 filed with the Company’s report on Form 10-Q for the period ended February 28, 2013.

14.	Incorporated by reference to Exhibit 10.19 filed with the Company’s 8-K report dated July 24, 2013.

15.	Incorporated by reference to same exhibit filed with the Company’s registration statement on Form S-8, File #333-191684

16.	Incorporated by reference to Exhibits 10.24, 10.25 and 10.26 filed with the Company’s report on Form 8-K filed on June 10, 2014.

17.	Incorporated by reference to Exhibit 10.27 filed with amendment no.1 to the Company’s annual report on Form 10-K/A filed on June 20, 2014.

18.	Incorporated by reference to Exhibit 10.22 filed with the Company’s current report on Form 8-K filed on December 26, 2013.

19.	Incorporated by reference to Exhibits 10.18 and 10.19 filed with the Company’s quarterly report on Form 10-Q filed on January 9, 2014.

20.	Incorporated by reference to Exhibit 10.23 filed with the Company’s current report on Form 8-K filed on June 10, 2014.

SYNERGY RESOURCES CORPORATION

INDEX TO FINANCIAL STATEMENTS

Index to Financial Statements	F-1

Report of Independent Registered Public Accounting Firm	F-2

Balance Sheets as of August 31, 2014 and 2013	F-3

Statements of Operations for the years ended August 31, 2014, 2013 and 2012	F-4

Statements of Changes in Shareholders’ Equity for the years ended August 31, 2014, 2013 and 2012	F-5

Statements of Cash Flows for the years ended August 31, 2014, 2013 and 2012	F-6

Notes to Financial Statements	F-7

To the Board of Directors and Shareholders

Synergy Resources Corporation

Platteville, Colorado

We have audited the accompanying balance sheets of Synergy Resources Corporation (the Company) as of August 31, 2014 and 2013, and the related statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended August 31, 2014. We also have audited the Company’s internal control over financial reporting as of August 31, 2014, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

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

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

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Synergy Resources Corporation as of August 31, 2014 and 2013, and the results of its operations and its cash flows for each of the years in the three-year period ended August 31, 2014, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, Synergy Resources Corporation maintained, in all material respects, effective internal control over financial reporting as of August 31, 2014, based on criteria established in Internal Control – Integrated Framework (1992) , issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

/s/ EKS&H LLLP

October 28, 2014

Denver, Colorado

● DENVER ● FORT COLLINS ● BOULDER ●

www.EKSH.com

F-2

SYNERGY RESOURCES CORPORATION

BALANCE SHEETS

(in thousands, except share data)

	August 31,		August 31,
ASSETS	2014		2013
Current assets:
Cash and cash equivalents	$	34,753	$	19,463
Short-term investments		—		60,018
Accounts receivable:
Oil and gas sales		16,974		7,361
Joint interest billing		15,398		4,700
Inventory		310		194
Commodity derivative		365		—
Other current assets		440		239
Total current assets		68,240		91,975

Property and equipment:
Evaluated oil and gas properties, net		275,018		132,979
Unevaluated oil and gas properties		95,278		64,715
Other property and equipment, net		9,104		271
Property and equipment, net		379,400		197,965

Commodity derivative		54		—
Other assets		848		1,296

Total assets	$	448,542	$	291,236

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Trade accounts payable	$	1,747	$	949
Well costs payable		71,849		25,491
Revenue payable		14,487		6,081
Production taxes payable		14,376		6,277
Other accrued expenses		817		254
Commodity derivative		302		2,315
Total current liabilities		103,578		41,367

Revolving credit facility		37,000		37,000
Commodity derivative		307		334
Deferred tax liability, net		21,437		6,538
Asset retirement obligations		4,730		2,777
Total liabilities		167,052		88,016

Commitments and contingencies (See Note 14)

Shareholders' equity:
Preferred stock - $0.01 par value, 10,000,000 shares authorized:
no shares issued and outstanding		—		—
Common stock - $0.001 par value, 200,000,000 shares authorized:
77,999,082 and 70,587,723 shares issued and outstanding,
respectively		78		71
Additional paid-in capital		265,793		216,383
Retained earnings (accumulated deficit)		15,619		(13,234	)
Total shareholders' equity		281,490		203,220

Total liabilities and shareholders' equity	$	448,542	$	291,236

The accompanying notes are an integral part of these financial statements

F-3

SYNERGY RESOURCES CORPORATION

STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)

	For the Years Ended August 31,
	2014			2013			2012

Oil and gas revenues	$	104,219		$	46,223		$	24,969

Expenses
Lease operating expenses		7,991			3,417			1,212
Production taxes		9,667			4,237			2,436
Depreciation, depletion,
and amortization		32,958			13,336			6,010
General and administrative		10,139			5,688			3,557
Total expenses		60,755			26,678			13,215

Operating income		43,464			19,545			11,754

Other income (expense)
Commodity derivative realized loss		(2,138	)		(395	)		-
Commodity derivative unrealized gain (loss)		2,459			(2,649	)		-
Interest expense, net		-			(97	)		-
Interest income		82			47			38
Total other income (expense)		403			(3,094	)		38

Income before income taxes		43,867			16,451			11,792

Deferred income tax provision (benefit)		15,014			6,870			(332	)
Net income	$	28,853		$	9,581		$	12,124

Net income per common share:
Basic	$	0.38		$	0.17		$	0.26
Diluted	$	0.37		$	0.16		$	0.25

Weighted average shares outstanding:
Basic		76,214,737			57,089,362			46,587,558
Diluted		77,808,054			59,088,761			48,359,905

The accompanying notes are an integral part of these financial statements

F-4

SYNERGY RESOURCES CORPORATION

STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY

for the years ended August 31, 2014, 2013 and 2012

(in thousands, except share data)


	Number of Common		Par Value		Additional			Accumulated Earnings			Total Shareholders'
	Shares		Common Stock		Paid - In Capital			(Deficit)			Equity

Balance, August 31, 2011		36,098,212	$	36	$	84,011		$	(34,939	)	$	49,108

Shares issued in exchange for mineral leases and services		669,765		1		1,998			—			1,999
Shares issued for cash at $2.75 per share pursuant to the October 7, 2011 offering memorandum, net of offering costs of $2,028,215		14,636,363		15		37,407			—			37,422
Stock based compensation		5,000		—		460			—			460
Net income		—		—		—			12,124			12,124
Balance, August 31, 2012		51,409,340	$	52	$	123,876		$	(22,815	)	$	101,113

Shares issued for Orr Energy acquisition		3,128,422		3		13,515						13,518
Shares issued in exchange for mineral assets		687,122		1		3,165						3,166
Shares issued for cash at $6.25 per share pursuant to the June 13, 2013 offering memorandum, net of offering costs of $4.4 million		13,225,000		13		78,230						78,243
Shares issued for exercise of warrants		1,052,698		1		3,274						3,275
Payment of tax withholdings using withheld shares		—		—		(6,990	)					(6,990
Shares issued for exercise of stock option		1,030,057		1		(1	)					—
Stock based compensation		55,084		—		1,314						1,314
Net income									9,581			9,581
Balance, August 31, 2013		70,587,723	$	71	$	216,383		$	(13,234	)	$	203,220

Shares issued in exchange for mineral assets		357,901		—		2,856			—			2,856
Shares issued for Trilogy and Apollo acquisitions		872,483		1		8,327			—			8,328
Shares issued for exercise of warrants		6,063,801		6		35,628			—			35,634
Shares issued under stock bonus plan		89,875		—		1,201						1,201
Shares issued for exercise of stock options		27,299		—		—			—			—
Stock based compensation for vested options		—		—		1,767			—			1,767
Payment of tax withholdings using withheld shares		—		—		(369	)					(369
Net income									28,853			28,853
Balance, August 31, 2014		77,999,082	$	78	$	265,793		$	15,619		$	281,490

The accompanying notes are an integral part of these financial statements

F-5

SYNERGY RESOURCES CORPORATION

STATEMENTS OF CASH FLOWS

(in thousands)


	For the Years Ended August 31,
	2014			2013			2012
Cash flows from operating activities:
Net income	$	28,853		$	9,581		$	12,124
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depletion, depreciation, and amortization		32,958			13,336			6,010
Provision for deferred taxes		15,014			6,870			(332	)
Stock-based compensation		2,968			1,362			473
Valuation decrease in commodity derivatives		(2,459	)		2,649			-
Changes in operating assets and liabilities:
Accounts receivable
Oil and gas sales		(9,613	)		(3,756	)		(1,597	)
Joint interest billing		(10,698	)		(1,432	)		(685	)
Inventory		(116	)		(16	)		282
Accounts payable
Trade		798			(550	)		(155	)
Revenue		8,406			1,921			4,161
Production taxes		8,099			2,472			2,279
Accrued expenses		448			(141	)		(1,291	)
Other		247			(176	)		(17	)
Total adjustments		46,052			22,539			9,128
Net cash provided by operating activities		74,905			32,120			21,252

Cash flows from investing activities:
Acquisition of property and equipment		(155,602	)		(80,469	)		(46,751	)
Short-term investments		60,018			(60,000	)		-
Net proceeds from sales of oil and gas properties		704			-			71
Net cash used in investing activities		(94,880	)		(140,469	)		(46,680	)

Cash flows from financing activities:
Proceeds from sale of stock		-			82,656			40,250
Offering costs		-			(4,413	)		(2,829	)
Proceeds from exercise of warrants		35,634			3,275			3,000
Shares withheld for payment of employee payroll taxes		(369	)		(6,990	)		-
Net proceeds from revolving credit facility		-			34,000			-
Principal repayment of related party notes payable		-			-			(5,200	)
Net cash provided by financing activities		35,265			108,528			35,221

Net increase in cash and equivalents		15,290			179			9,793

Cash and equivalents at beginning of period		19,463			19,284			9,491

Cash and equivalents at end of period	$	34,753		$	19,463		$	19,284

Supplemental Cash Flow Information (See Note 15)

The accompanying notes are an integral part of these financial statements

F-6

SYNERGY RESOURCES CORPORATION

NOTES TO FINANCIAL STATEMENTS

August 31, 2014, 2013 and 2012

1.	Organization and Summary of Significant Accounting Policies

Organization : Synergy Resources Corporation (the “Company”) is engaged in oil and gas acquisition, exploration, development and production activities, primarily in the Denver-Julesburg Basin ("D-J Basin") of Colorado.

Basis of Presentation: The Company has adopted August 31st as the end of its fiscal year. The Company does not utilize any special purpose entities.

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

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

Reclassifications : Certain amounts previously presented for prior periods have been reclassified to conform to the current presentation. The reclassifications had no effect on net income, working capital or equity previously reported.

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

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

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

Inventory: Inventories consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market

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

F-7

Wells in progress represent the costs associated with the drilling of oil and gas wells that have yet to be completed as of August 31, 2014. Since the wells had not been completed as of August 31, 2014, they were classified within unevaluated oil and gas properties and were withheld from the depletion calculation and the ceiling test. The costs for these wells will be transferred into proved property when the wells commence production and will become subject to depletion and the ceiling test calculation in subsequent periods.

Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC regulations. The ceiling test determines a limit on the book value of oil and gas properties. The capitalized costs of proved and unproved oil and gas properties, net of accumulated depreciation, depletion, and amortization, and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, less future cash outflows associated with asset retirement obligations that have been accrued, plus the cost of unproved properties not being amortized, plus the lower of cost or estimated fair value of unproven properties being amortized. Prices are held constant for the productive life of each well. Net cash flows are discounted at 10%. If net capitalized costs exceed this limit, the excess is charged to expense and reflected as additional accumulated depreciation, depletion and amortization. The calculation of future net cash flows assumes continuation of current economic conditions. Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount. No provision for impairment was required for the twelve months ended August 31, 2014 or 2013.

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

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

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

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

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

	For the Years Ended August 31,
	2014		2013		2012
Capitalized overhead	$	1,230	$	637	$	345

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

Other Property and Equipment: Support equipment (including such items as vehicles, well servicing equipment, and office furniture and equipment) is stated at the lower of cost or market. Depreciation of support equipment is computed using primarily the straight-line method over periods ranging from five to seven years. The Class II disposal well is depreciated based on a units of production method using barrels of water disposed.

F-8

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

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

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

Major Customers and Operating Region: The Company operates exclusively within the United States of America. Except for cash and short-term investments, all of the Company’s assets are employed in and all of its revenues are derived from the oil and gas industry. The table below presents the percentages of oil and gas revenue resulting from purchases by major customers.

	For the Years Ended August 31,
	2014	2013	2012
Company A	54%	50%	68%
Company B	13%	15%	11%

The Company sells production to a small number of customers, as is customary in the industry. Based on the current demand for oil and natural gas, the availability of other buyers, and the Company having the option to sell to other buyers if conditions so warrant, the Company believes that its oil and gas production can be sold in the market in the event that it is not sold to the Company’s existing customers. However, in some circumstances, a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer.

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

F-9

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

	As of August 31,
	2014	2013	2012
Company A	37%	24%	35%
Company B	*	23%	30%
Company C	*	12%	*

* less than 10%

Lease Operating Expenses: Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred. Lease operating expenses (also referred to as production or lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities, property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

Stock-Based Compensation: The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date, calculated using the Black-Scholes-Merton option pricing model. The expense is recognized over the vesting period of the grant. See Note 11 below for additional information.

Income Tax: Income taxes are computed using the asset and liability method. Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, their respective tax bases as well as the effect of net operating losses, tax credits and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.

No significant uncertain tax positions were identified as of any date on or before August 31, 2014. The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of August 31, 2014, the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 12 for further information.

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

Financial instruments, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board, prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

As discussed in Note 5, the Company incurred asset retirement obligations during the periods presented, the value of which was determined using unobservable pricing inputs (or Level 3 inputs). The Company uses the income valuation technique to estimate the fair value of the obligation using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, and timing of settlement .

Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps or “no premium” collars to reduce the effect of price changes on a portion of our future oil and gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the statement of operations. We value our derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk free interest rates, and estimated volatility factors, as well as other relevant economic measures. 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. For additional discussion, please refer to Note 7 – Commodity Derivative Instruments.

F-10

Earnings Per Share Amounts: Basic earnings per share includes no dilution and is computed by dividing net income or loss by the weighted-average number of shares outstanding during the period. Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of the Company. The number of potential shares outstanding relating to stock options and warrants is computed using the treasury stock method. Potentially dilutive securities outstanding are not included in the calculation when such securities would have an anti-dilutive effect on earnings per share.

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

	For the Years Ended August 31,
	2014		2013		2012
Weighted-average shares outstanding - basic		76,214,737		57,089,362		46,587,558
Potentially dilutive common shares from:
Stock options		479,222		1,881,682		1,380,861
Warrants		1,114,095		117,717		391,486
Weighted-average shares outstanding - diluted		77,808,054		59,088,761		48,359,905

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

	For the Years Ended August 31,
	2014		2013		2012
Potentially dilutive common shares from:
Stock options		533,000		670,000		2,495,000
Warrants		-		8,500,000		14,098,000
Total		533,000		9,170,000		16,593,000

Recent Accounting Pronouncements:

We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new pronouncements on US GAAP and the impact on us.

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2014-09 (“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. The ASU allows for the use of either the full or modified retrospective transition method, and the standard will be effective for us in the first quarter of our fiscal year 2018; early adoption is not permitted. The Company is currently evaluating which transition approach to use and the impact of the adoption of this standard on its consolidated financial statements.

In December 2011, the FASB issued Accounting Standards Update 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”), and issued Accounting Standards Update 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“ASU 2013-01”) in January 2013. These updates require disclosures about the nature of an entity’s rights of offset and related arrangements associated with its recognized derivative contracts. The new disclosure requirements, which are effective for interim and annual periods beginning on or after January 1, 2013, were implemented by the Company on September 1, 2013. The implementation of ASU 2011-11 and ASU 2013-01 had no impact on the Company’s financial position or results of operations. See Note 7 for the Company’s derivative disclosures .

F-11

2.	Property and Equipment

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

	As of August 31,
	2014			2013
Oil and gas properties, full cost method:
Unevaluated costs, not subject to amortization:
Lease acquisition and other costs	$	41,531		$	38,826
Wells in progress		53,747			25,889
Subtotal, unevaluated costs		95,278			64,715

Evaluated costs:
Producing and non-producing		329,926			155,755
Total capitalized costs		425,204			220,470
Less, accumulated depletion		(54,908	)		(22,776	)
Oil and gas properties, net		370,296			197,694

Land		3,898			44
Other property and equipment		5,961			500
Less, accumulated depreciation		(755	)		(273	)
Other property and equipment, net		9,104			271

Total property and equipment, net	$	379,400		$	197,965

Periodically, the Company reviews its unevaluated properties to determine if the carrying value of such assets exceeds estimated fair value. The reviews as of each of the fiscal year ends presented, indicated that estimated fair values of such assets exceeded carrying values, thus revealing no impairment. The full cost ceiling test, explained in Note 1, and, as performed as of each of the fiscal year ends presented, similarly revealed no impairment of oil and gas assets.

Costs Incurred: Costs incurred in oil and gas property acquisition, exploration and development activities for the fiscal years presented were (in thousands):

	For the Years Ended August 31,
	2014		2013		2012
Acquisition of property:
Unproved	$	15,002	$	12,295	$	9,145
Proved		33,795		43,143		459
Exploration costs		43,089		-		-
Development costs		111,238		61,128		39,739
Other property and equipment		9,315		-		-
Asset retirement obligation		1,610		1,578		300
Total costs incurred	$	214,049	$	118,144	$	49,643

F-12

Capitalized Costs Excluded from Amortization: The following table summarizes costs related to unevaluated properties that have been excluded from amounts subject to depletion, depreciation, and amortization at August 31, 2014 (in thousands). There were no individually significant properties or significant development projects included in the Company’s unevaluated property balance. The Company regularly evaluates these costs to determine whether impairment has occurred. The majority of these costs are expected to be evaluated and included in the amortization base within three years.

	Period Incurred								Total as of
							2011		August 31,
	2014		2013		2012		and prior		2014
Unproved leasehold acquisition costs	$	15,002	$	11,021	$	6,159	$	9,349	$	41,531
Unevaluated development costs		53,747		-		-		-	$	53,747
Total unevaluated costs	$	68,749	$	11,021	$	6,159	$	9,349	$	95,278

3.	Acquisitions

On September 16, 2013, the Company entered into a definitive purchase and sale agreement, with Trilogy Resources, LLC (“Trilogy”), for its interests in 21 producing oil and gas wells and approximately 800 net mineral acres (the “Trilogy Assets”). On November 12, 2013, the Company closed the transaction for a combination of cash and stock. Trilogy received 301,339 shares of the Company’s common stock valued at $2.9 million and cash consideration of approximately $16.0 million. No material transaction costs were incurred in connection with this acquisition.

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

Preliminary Purchase Price	November 12, 2013
Consideration Given
Cash	$	16,008
Synergy Resources Corp. Common Stock *		2,896

Total consideration given	$	18,904

Preliminary Allocation of Purchase Price
Proved oil and gas properties	$	19,374
Total fair value of oil and gas properties acquired		19,374

Working capital	$	(119	)
Asset retirement obligation		(351	)

Fair value of net assets acquired	$	18,904

Working capital acquired was estimated as follows:
Accounts receivable		500
Accrued liabilities and expenses		(619	)

Total working capital	$	(119	)

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

F-13

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

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

Preliminary Purchase Price	November 13, 2013
Consideration Given
Cash	$	14,679
Synergy Resources Corp. Common Stock *		5,432

Total consideration given	$	20,111

Preliminary Allocation of Purchase Price
Proved oil and gas properties	$	16,009
Disposal Well	$	5,220
Total fair value of oil and gas properties acquired		21,229

Working capital	$	(883	)
Asset retirement obligation		(235	)

Fair value of net assets acquired	$	20,111

Working capital acquired was estimated as follows:
Accounts receivable		380
Accrued liabilities and expenses		(1,263	)

Total working capital	$	(883	)

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

F-14

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

Pro Forma Financial Information

As stated above, on November 12 and 13, 2013, the Company completed acquisitions of oil and gas properties from Trilogy Resources, LLC and Apollo Operating, LLC. Below are the combined results of operations for the twelve months ended August 31, 2014 and 2013 as if the acquisitions had occurred on September 1, 2012 (in thousands).

The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock, additional depreciation expense, costs directly attributable to the acquisitions and costs incurred as a result of the Trilogy and Apollo acquisitions. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

	For the years ended August 31,
	(Unaudited)
	2014		2013

Oil and Gas Revenues	$	106,584	$	55,633

Net income	$	29,681	$	13,191

Earnings per common share
Basic	$	0.39	$	0.23
Diluted	$	0.38	$	0.22

On October 23, 2012, the Company entered into a definitive purchase and sale agreement (“the Agreement”), with Orr Energy, LLC (“Orr”), for its interests in 36 producing oil and gas wells and approximately 3,933 gross (3,196 net) mineral acres (the “Orr Assets”). On December 5, 2012, the Company closed the transaction for a combination of cash and stock. Orr received 3,128,422 shares of the Company’s common stock valued at $13.5 million and cash consideration of approximately $29.0 million. Transaction costs related to the acquisition were approximately $109,000, all of which were recorded in the statement of operations within the general and administrative expenses line item for the twelve months ended August 31, 2013. No material costs were incurred for the issuance of the shares of common stock.

F-15

Pro Forma Financial Information

As stated above, on December 5, 2012, the Company completed an acquisition of oil and gas properties from Orr Energy. Below are the combined results of operations for the twelve months ended August 31, 2013 and 2012 as if the acquisition had occurred on September 1, 2011 (in thousands, except per share data).

The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock, additional depreciation expense, costs directly attributable to the acquisition and costs incurred as a result of the Orr Energy acquisition. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

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

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

	For the Years Ended August 31,
	2014		2013		2012
Depletion	$	32,132	$	13,046	$	5,838
Depreciation and amortization		826		290		172
Total DDA Expense	$	32,958	$	13,336	$	6,010

Capitalized costs of evaluated oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter.

5.	Asset Retirement Obligations

Upon completion or acquisition of a well, the Company recognizes obligations for its oil and gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling sites to its original use. The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in regulations. Changes in estimates are reflected in the obligations as they occur. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. For the purpose of determining the fair value of ARO incurred during the fiscal years presented, the Company used the following assumptions:

	For the Years Ended August 31,
	2014	2013
Inflation rate	3.90%	3.9 - 4.0%
Estimated asset life	25.0 - 39.0 years	24.0 - 40.0 years
Credit adjusted risk free interest rate	8%	8.0 - 11.2%

F-16

The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands). The revisions recognized during 2013 were primarily from increases in the undiscounted abandonment cost estimates.

	As of August 31,
	2014		2013
Beginning asset retirement obligation	$	2,777	$	1,027
Liabilities incurred		1,024		376
Liabilities assumed		586		240
Accretion expense		343		172
Revisions in previous estimates		-		962
	$	4,730	$	2,777

6.	Revolving Credit Facility

The Company maintains a revolving credit facility (“LOC”) with a bank syndicate. The LOC is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit. As most recently amended on June 4, 2014, the terms provide for $300 million in the maximum amount of borrowings available to the Company, subject to a borrowing base limitation. Community Banks of Colorado acts as the administrative agent for the bank syndicate with respect to the LOC. The credit facility expires on May 29, 2019.

Interest under the LOC is payable monthly and accrues at a variable rate, subject to a minimum rate of 2.5%. For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin of 0.5% to 1.5%, or the London Interbank Offered Rate (LIBOR) plus a margin of 1.75% to 2.75%. The interest rate margin, as well as other bank fees, varies with utilization of the LOC. The average annual interest rate for borrowings during the twelve months ended August 31, 2014, was 2.7%. As of August 31, 2014, the interest rate on the outstanding balance was 2.5%, representing the minimum rate.

Certain of the Company’s assets, including substantially all developed properties, have been designated as collateral under the arrangement. The borrowing commitment is subject to adjustment based upon a borrowing base calculation that includes the value of oil and gas reserves. The borrowing base limitation is subject to scheduled redeterminations on a semi-annual basis. In certain events, and at the discretion of the bank syndicate, an unscheduled redetermination could be prepared. The most recent redetermination in June 2014 increased the borrowing base to $110 million from $90 million. As of August 31, 2014, based upon a borrowing base of $110 million and an outstanding principal balance of $37 million, the unused borrowing base available for future borrowing totaled approximately $73 million. The next scheduled redetermination will occur in November 2014 and will reflect the value of oil and gas reserves computed as of August 31, 2014.

The arrangement contains covenants that, among other things, restrict the payment of dividends. In addition, the LOC generally requires an overall hedge position that covers a rolling 24 months of estimated future production with a minimum position of no less than 45% and a maximum position of no more than 85% of hydrocarbon production.

As amended on June 4, 2014, the arrangement revised the financial ratio compliance covenants. Under the amended requirements, on a quarterly basis, the Company must (a) not, at any time, permit its ratio of total funded debt as of such time to EBITDAX to be greater than or equal to 4.0 to 1.0; and (b) not, as of the last day of the fiscal quarter, permit its adjusted current ratio, as defined, to be less than 1.0 to 1.0. As of August 31, 2014 and during the year ended, the most recent compliance date, the Company was in compliance with all loan covenants.

F-17

7.	Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, as described below. The Company has utilized swaps or “no premium” collars to reduce the effect of price changes on a portion of its future oil and gas production. A swap requires a payment to the counterparty if the settlement price exceeds the strike price and the same counterparty is required to make a payment if the settlement price is less than the strike price. A collar requires a payment to the counterparty if the settlement price is above the ceiling price and requires the counterparty to make a payment if the settlement price is below the floor price. The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

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

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from contract settlement of derivatives are recorded in the commodity derivative line on the statements of operations. The Company’s cash flow is only impacted when the actual settlements under commodity derivative contracts result in making or receiving a payment to or from the Counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s statements of cash flows.

The Company’s commodity derivative contracts as of August 31, 2014 are summarized below:

Settlement Period	Derivative Instrument	Average Volumes (BBls/MMBtu per month)		Average Fixed Price		Floor Price		Celling Price
Crude Oil - NYMEX WTI
Sep 1, 2014 - Dec 31, 2014	Collar		1,840		-	$	85.00	$	98.50
Sep 1, 2014 - Dec 31, 2014	Collar		20,000		-	$	87.00	$	96.25
Sep 1, 2014 - Dec 31, 2014	Swap		18,340	$	94.50		-		-

Jan 1, 2015 - Jun 30, 2015	Collar		7,000		-	$	80.00	$	92.50
Jan 1, 2015 - Jun 30, 2015	Collar		2,500		-	$	80.00	$	95.75
Jul 1, 2015 - Dec 31, 2015	Collar		9,000		-	$	80.00	$	92.25
Jan 1, 2015 - Dec 31, 2015	Collar		4,500		-	$	80.00	$	99.40
Jan 1, 2015 - Dec 31, 2015	Collar		6,000		-	$	85.00	$	101.30

Jan 1, 2016 - May 31, 2016	Collar		10,000		-	$	75.00	$	96.00
Jan 1, 2016 - May 31, 2016	Collar		5,000		-	$	80.00	$	100.75
Jun 1, 2016 - Aug 31, 2016	Collar		15,000		-	$	80.00	$	100.05

Natural Gas - NYMEX Henry Hub
Sep 1, 2014 - Dec 31, 2014	Swap		80,000	$	4.58	$	-	$	-
Sep 1, 2014 - Dec 31, 2014	Collar		30,000		-	$	4.07	$	4.18
Jan 1, 2015 - Dec 31, 2015	Collar		72,000		-	$	4.15	$	4.49
Jan 1, 2016 - May 31, 2016	Collar		60,000		-	$	4.05	$	4.54
Jun 1, 2016 - Aug 31, 2016	Collar		60,000			$	3.90	$	4.14

Subsequent to August 31, 2014, the Company entered into the following commodity derivative contracts:


Settlement Period	Derivative Instrument	Average Volumes (BBls/MMBtu per month)		Average Fixed Price
Crude Oil - NYMEX WTI
Oct 1, 2014 - Dec 31, 2014	Swap		15,000	$	90.85
Nov 1, 2014 - Dec 31, 2014	Swap		25,000	$	80.04

Jan 1, 2015 - Jun 30, 2015	Swap		20,000	$	90.10
Jul 1, 2015 - Dec 31, 2015	Swap		15,500	$	89.52
Jan 1, 2015 - Oct 31 2015	Swap		14,600	$	78.65

Jan 1, 2016 - Aug 31, 2016	Swap		5,000	$	88.55
Sept 1. 2016 - Dec 2016	Swap		20,000	$	88.10
Jan 1, 2016 - Oct 2016	Swap		6,400	$	78.96

F-18

Offsetting of Derivative Assets and Liabilities

As of August 31, 2014 and 2013, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at election of both parties, for transactions that occur on the same date and in the same currency. They Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its accompanying balance sheets.

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

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

		As of August 31, 2013
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Derivative contracts	Current assets	$	28	$	(28	)	$	-
Derivative contracts	Noncurrent assets	$	182	$	(182	)	$	-
Derivative contracts	Current liabilities	$	2,343	$	(28	)	$	2,315
Derivative contracts	Noncurrent liabilities	$	516	$	(182	)	$	334

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

	For the Years Ended August 31,
	2014			2013			2012
Realized (loss) on commodity derivatives	$	(2,138	)	$	(395	)		-
Unrealized gain (loss) on commodity derivatives		2,459			(2,649	)		-
Total gain (loss)	$	321		$	(3,044	)	$	-

F-19

Credit Related Contingent Features

As of August 31, 2014, one of the three counterparties was a member of the Company’s credit facility syndicate. The Company’s obligations under its credit facility and derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties. The agreement with one counterparty which is not a member of the credit facility is based on an unsecured basis and does not require posting of collateral. The agreement with one counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility.

8.	Fair Value Measurements

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

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

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

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

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

The Company’s non-recurring fair value measurements include asset retirement obligations, please refer to Note 5—Asset Retirement Obligations, and for the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to Note 3—Acquisitions.

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

The acquisition of a group of assets in a business combination transaction requires fair value estimates for assets acquired and liabilities assumed. The fair value of assets and liabilities acquired through business combinations is calculated using a discounted-cash flow approach using primarily unobservable inputs. Inputs are reviewed by management on an annual basis. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices and operating costs.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of August 31, 2014 and 2013 by level within the fair value hierarchy (in thousands):

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

	Fair Value Measurements at August 31, 2013
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	-	$	-	$	-	$	-
Commodity derivative liability	$	-	$	2,649	$	-	$	2,649

F-20

Commodity Derivative Instruments

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At August 31, 2014, derivative instruments utilized by the Company consist of both “no premium” collars and swaps. The crude oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors including public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as level 2.

Fair Value of Financial Instruments

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

9.	Interest Expense

The components of interest expense are (in thousands):

	For the Years Ended August 31,
	2014			2013			2012

Revolving bank credit facility	$	986		$	1,067		$	108
Amortization of debt issuance costs		448			160			32
Other		-			-			68
Less, interest capitalized		(1,434	)		(1,130	)		(208	)
Interest expense, net	$	-		$	97		$	-

10.	Shareholders’ Equity

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

	For the Years Ended August 31,
	2014		2013		2012
Preferred stock, shares authorized		10,000,000		10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01	$	0.01
Preferred stock, shares issued and outstanding	nil		nil		nil
Common stock, shares authorized		200,000,000		100,000,000		100,000,000
Common stock, par value	$	0.001	$	0.001	$	0.001
Common stock, shares issued and outstanding		77,999,082		70,587,723		51,409,340

F-21

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

The following shares of common stock were issued during the fiscal years presented:

Sales of common stock

In June 2013, the Company completed the sale of common stock in an underwritten public offering led by Johnson Rice LLC.

In fiscal year 2012, the Company completed the sale of common stock in an underwritten public offering led by Northland Capital Markets.

Certain details of each transaction are shown in the following table. Net proceeds represent amounts received by the Company after deductions for underwriting discounts, commissions and expenses of the offering .

	For the Years Ended August 31,
	2014		2013		2012
Number of common shares sold		-		13,225,000		14,363,363
Offering price per common share	$	-	$	6.25	$	2.75
Net proceeds (in thousands)	$	-	$	78,243	$	37,422

Common stock issued for acquisition of mineral property interests

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

	For the Years Ended August 31,
	2014		2013		2012
Number of common shares issued for mineral property leases		357,901		687,122		669,765
Number of common shares issued for acquisitions		872,483		3,128,422		-
Total common shares issued		1,230,384		3,815,544		669,765

Average price per common share	$	9.09	$	4.37	$	3.12
Aggregate value of shares issues (in thousands)	$	11,184	$	16,684	$	2,090

F-22

Common stock warrants

The Company has issued warrants to purchase common stock. The relevant terms of the warrants are described in the following paragraphs.

Series A – During the year ended August 31, 2009, the Company issued 4,098,000 Series A warrants, each of which was immediately exercisable. Each Series A warrant entitled the holder to purchase one share of common stock for $6.00 per share. All of the Series A warrants expired on December 31, 2012.

Series B – During the year ended August 31, 2009, the Company issued 1,000,000 Series B warrants, each of which was immediately exercisable. Each Series B warrant entitled the holder to purchase one share of common stock for $10.00 per share. All of the Series B warrants expired on December 31, 2012.

Series C – During the year ended August 31, 2010, the Company issued 9,000,000 Series C warrants in connection with a unit offering. Each unit included one convertible promissory note with a face value of $100,000 and 50,000 Series C warrants. Each Series C warrant entitles the holder to purchase one share of common stock for $6.00 per share. The Series C warrants will expire, if not previously exercised, on December 31, 2014. During each of the three years ended August 31, 2014, the following warrants were exercised: 5,938,585, during fiscal 2014, 500,000 during fiscal 2013, and nil during fiscal 2012.

Series D – During the year ended August 31, 2010, the Company issued 1,125,000 Series D warrants to the placement agent for the Series C unit offering. Each Series D warrant entitles the holder to purchase one share of common stock for $1.60 per share, and contains a net settlement provision that provides for exercise of the warrants on a cashless basis. The Series D warrants will expire, if not previously exercised, on December 31, 2014. During each of the three years ended August 31, 2014, the following warrants were exercised: 140,744 during fiscal 2014, 627,799 during fiscal 2013, and nil during fiscal 2012.

Sales Agent Warrants – During the year ended August 31, 2009, the Company issued 31,733 warrants to the sales agent for an equity offering. Each Sales Agent Warrant entitled the holder to purchase two shares of common for $1.80 per share. The Sales Agent Warrants had an expiration date of December 31, 2012, and all of the warrants were exercised during the year ended August 31, 2013.

Investor Relations Warrants – During the year ended August 31, 2012, the Company issued 100,000 warrants to a firm providing investor relations services. Each Investor Relations Warrant entitles the holder to purchase one share of common stock for $2.69 per share, and contains a net settlement provision that provides for exercise of the warrants on a cashless basis. The warrants were to become exercisable in equal quarterly installments over a one year period. During the year ended August 31, 2013, warrants to purchase 50,000 shares became exercisable and warrants to purchase 50,000 shares were forfeited due to early termination of the agreement with the firm. During each of the three years ended August 31, 2014, the following warrants were exercised: 25,000 during fiscal 2014, 25,000 during fiscal 2013, and nil during fiscal 2012.

The following table summarizes activity for common stock warrants for the fiscal years presented:

	Number of Shares Issuable Upon Warrant Exercise		Weighted Average Exercise Price Per Share
Outstanding, August 31, 2011		14,931,067	$	6.02
Granted		100,000	$	2.69
Exercised		-	$	-
Outstanding, August 31, 2012		15,031,067	$	6.02
Exercised		1,216,265	$	3.44
Forfeited / Expired		5,148,000	$	6.74
Outstanding, August 31, 2013		8,666,802	$	5.92
Exercised		6,104,329	$	5.88
Forfeited / Expired		-	$	-
Outstanding, August 31, 2014		2,562,473	$	6.00

F-23

The following table summarizes information about the Company’s issued and outstanding common stock warrants as of August 31, 2014:

Number of Shares		Exercise Price		Remaining Contractual Life (in years)		Exercise Price times number of shares
	2,561,415	$	6.00		0.33	$	15,368,490
	1,058	$	1.60		0.33	$	1,693
	2,562,473					$	15,370,183

11.	Stock-Based Compensation

In addition to cash compensation, the Company may compensate certain service providers, including employees, directors, consultants, and other advisors, with equity based compensation in the form of stock options, restricted stock grants, and warrants. The Company records an expense related to equity compensation by pro-rating the estimated fair value of each grant over the period of time that the recipient is required to provide services to the Company (the “vesting phase”). The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock. Indirect valuations are calculated using the Black-Scholes-Merton option pricing model. For the periods presented, all stock based compensation expense was classified as a component within General and Administrative expense on the Statement of Operations.

The amount of stock based compensation expense is as follows (in thousands):

	For the Years Ended August 31,
	2014		2013		2012
Stock options	$	1,767	$	1,039	$	443
Restricted stock grants		1,201		277		17
Investor relations warrants		-		46		13
	$	2,968	$	1,362	$	473

General Description of Stock Option and Other Stock Award Plans

The Company has three stock award plans: (i) a 2011 non-qualified stock option plan, (ii) a 2011 incentive stock option plan, and (iii) a 2011 stock bonus plan. The plans adopted during 2011 replaced a non-qualified stock option plan and a stock bonus plan originally adopted during 2005 (the “2005 Plans”). No additional options or shares will be issued under the 2005 Plans.

Each plan authorizes the issuance of shares of the Company's common stock to persons that exercise options granted pursuant to the Plan. Employees, directors, officers, consultants and advisors are eligible to receive such awards, provided that bona fide services be rendered by such consultants or advisors and such services must not be in connection with promoting our stock or the sale of securities in a capital-raising transaction. The option exercise price is determined by the Board of Directors, though is generally the closing market price of Company stock on the date of grant.

As of August 31, 2014, there were 5,000,000 shares authorized for issuance under the non-qualified plan and 2,000,000 shares authorized for each of the incentive stock option and stock bonus plans.

F-24

During the respective fiscal years, the Company granted the following non-qualified stock options:

	For the Years Ended August 31,
	2014		2013		2012
Number of options to purchase common shares		433,000		1,025,000		275,000
Weighted average exercise price	$	10.37	$	6.05	$	2.96
Term (in years)	10 years		10 years		10 years
Vesting Period (in years)	5 years		3-5 years		4-5 years
Fair Value (in thousands)	$	3,009	$	4,179	$	519

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

	For the Years Ended August 31,
	2014			2013			2012
Expected term	6.7 years			6.2 years			6.5 years
Expected volatility		73	%		77	%		56.7 - 69.4	%
Risk free rate		1.8 - 2.3	%		0.9 - 2.1	%		1.0-1.4	%
Expected dividend yield		0.0	%		0.0	%		0.0	%
Forfeiture rate		0.0	%		0.0	%		0.0 - 0.7	%

The following table summarizes activity for stock options for the fiscal years presented:

	Number of Shares			Weighted Average Exercise Price
Outstanding, August 31, 2011		4,645,000		$	5.21
Granted		275,000		$	2.96
Exercised		-		$	-
Forfeited		(5,000	)	$	3.40
Outstanding, August 31, 2012		4,915,000		$	5.09
Granted		1,025,000		$	6.05
Exercised		(2,120,000	)	$	1.10
Expired		(2,000,000	)	$	10.00
Outstanding, August 31, 2013		1,820,000		$	4.88
Granted		433,000		$	10.37
Exercised		(61,000	)	$	3.71
Forfeited		(25,000	)	$	10.32
Outstanding, August 31, 2014		2,167,000		$	5.94

F-25

The following table summarizes information about issued and outstanding stock options as of August 31, 2014:

	As of August 31, 2014

	Outstanding Options		Vested Options
Number of shares		2,167,000		797,500
Weighted average remaining contractual life	8 years		7.2 years
Weighted average exercise price	$	5.94	$	4.55
Aggregate intrinsic value (in thousands)	$	16,287	$	7,103

The estimated unrecognized compensation cost from unvested stock options as of August 31, 2014, which will be recognized ratably over the remaining vesting phase, is as follows:

	Unvested Options at August 31, 2014
Unrecognized compensation expense (in thousands)	$	5,410,960
Remaining vesting phase	3.4 years

12.	Income Taxes

The income tax provision (benefit) is comprised of the following (in thousands):

	As of August 31,
	2014		2013		2012
Current:
Federal	$	4	$	-	$	-
State		111		-		-
Total current income tax	$	115	$	-	$	-

Deferred:
Federal	$	13,748	$	6,367	$	4,219
State		1,151		503		360
Total deferred income tax	$	14,899	$	6,870	$	4,579

Valuation allowance		-		-		(4,911	)
Income tax provision (benefit)	$	15,014	$	6,870	$	(332	)

F-26

A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands):

	As of August 31,
	2014			2013			2012
Federal income tax at statutory rate	$	14,915		$	5,594		$	4,009
State income taxes, net of federal tax		1,341			503			360
Statutory depletion		(1,266	)		(929	)		-
Stock based compensation		-			1,911			-
Other		24			(209	)		210
Change in valuation allowance		-			-			(4,911	)
Income tax provision (benefit)	$	15,014		$	6,870		$	(332	)
Effective rate expressed as a percentage		34	%		42	%		3	%

The Company reported a change in valuation allowance of $4,911,000 for the year ended August 31, 2012. In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carry-forwards, credits and other deferred tax assets will be utilized prior to their expiration. As a result, it may be determined that a deferred tax asset valuation allowance should be established or released. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense. In 2012, the Company determined that the weight of the evidence indicated that it would more likely than not be able to realize its deferred tax asset, and the entire valuation allowance was released.

The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the fiscal year ends is presented in the following table (in thousands):

	As of August 31,
	2014		2013
Deferred tax assets:
Net operating loss carry-forward	$	8,589	$	11,485
Stock-based compensation		1,115		515
Statutory depletion		2,194		929
Unrealized loss on commodity derivative		70		982
Other		4		3
Gross deferred tax assets	$	11,972	$	13,914

Deferred tax liabilities:
Basis of oil and gas properties		33,409		20,452
Gross deferred tax liabilities		33,409		20,452
Deferred tax liability (asset), net	$	21,437	$	6,538

At August 31, 2014 the Company has a net operating loss carry-forward for federal tax purposes of approximately $33.2 million and state tax purposes of approximately $41.1 million that could be utilized to offset taxable income of future years. For financial reporting purposes the Company has net operating losses of approximately $22.5 million and $30.4 million for federal and state, respectively. The difference of $10.7 million relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable. The net operating loss carryovers may be carried back two years and forward twenty years from the year the net operating loss was generated. Substantially all of the carry-forward will commence expiring in 2031, 2032, and 2033.

The realization of the deferred tax assets related to the NOL carry-forwards is dependent on the Company’s ability to generate sufficient future taxable income within the applicable carryforward periods. As of August 31, 2014, the Company believes it will be able to generate sufficient future taxable income within the carryforward periods, and accordingly believes that it is more likely than not that its net deferred income tax assets will be fully realized.

F-27

The ability of the Company to utilize its NOL carry-forwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carry-forwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of a Company’s taxable income that can be offset by these carry-forwards. The Company completed a study of the impact of the Code Section 382 limitation on future payments and determined that the statutory provisions were unlikely to limit the Company's ability to realize future tax benefits.

As of August 31, 2014, the Company had no unrecognized tax benefits. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position. Given the substantial NOL carry-forwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carry-forwards, and would not result in significant interest expense or penalties. Substantially of the Company's tax returns filed since inception are still subject to examination by tax authorities.

13.	Related Party Transactions

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

Lease Agreement: The Company leases its headquarters, a field office, and an equipment storage yard under a twelve month lease agreement with HS Land & Cattle, LLC (“HSLC”). HSLC is controlled by Ed Holloway and William Scaff, Jr., the Company’s Co-Chief Executive Officers. The current lease terminates on June 30, 2015. Historically, the lease has been renewed annually. Under this agreement, the Company incurred the following expenses to HSLC for the fiscal years presented (in thousands):

	For the Years Ended August 31,
	2014		2013		2012
Rent expense	$	180	$	130	$	120

Mineral Leasing Program : During 2010, the Company initiated a program to acquire mineral interests in several Colorado and Nebraska counties that are considered the eastern portion of the D-J Basin. George Seward, a member of the Company’s board of directors, agreed to lead that program. The Company agreed to compensate the persons, including Mr. Seward, to assist the Company with the acquisitions at a specific rate per qualifying net mineral acre. The compensation is paid in the form of restricted shares of the Company’s common stock, as follows:

	For the Years Ended August 31,
	2014		2013		2012
Shares of restricted common stock		15,883		31,454		188,137
Value of common stock (in thousands)	$	106	$	105	$	491

Mineral Leases Acquired from Director : Mr. Seward owns mineral interests in several Colorado and Nebraska counties. He agreed to lease his interests to the Company in exchange for restricted shares of common stock. The following table discloses the acquisition of mineral leases from Mr. Seward during each of the fiscal years presented:

	For the Years Ended August 31,
	2014		2013		2012
Mineral acres leased		4,844		2,263		-
Shares of restricted common stock		40,435		22,202		-
Value of common stock (in thousands)	$	313,000	$	91,000	$	-

F-28

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

	For the Years Ended August 31,
	2014		2013		2012
Total Royalty Payments	$	292	$	304	$	196

14.	Other Commitments and Contingencies

As of August 31, 2014, the Company was using three rigs under contracts with Ensign United States Drilling, Inc. The Company estimates that its minimum future obligation to Ensign under the terms of the existing contracts will aggregate $24 million, based upon its current drilling schedule and time required to drill each well. All of the contracts are based upon turn-key pricing and have termination dates during the first half of fiscal year 2015. At the option of the Company, the drilling commitments can be extended into future months, although pricing terms may be modified. Actual payments due to Ensign will depend upon a number of variables, including the surface location, the target formation, measured depth of well and other technical details.

From time to time, the Company receives notice from other operators of their intent to drill and operate a well in which the Company will own a working interest (a “non-operated well”). The Company has the option to participate in the well and assume the obligation for its pro-rata share of the costs. As of August 31, 2014, the Company was participating in 43 gross (6 net) new horizontal wells, with aggregate costs to its interest estimated at $26.9 million. It is the Company’s policy to accrue costs on a non-operated well when it receives notice that active drilling operations have commenced. Accordingly, the August 31, 2014 financial statements include costs of $26.9 million for these wells.

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

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

	For the Years Ended August 31,
Supplemental cash flow information:	2014		2013		2012
Interest paid	$	989	$	995	$	74
Income taxes paid		-		-		-

Non-cash investing and financing activities:
Accrued well costs	$	71,849	$	25,491	$	5,733
Assets acquired in exchange for common stock		11,184		16,684		1,985
Asset retirement costs and obligations		1,610		1,578		300

16.	Unaudited Oil and Gas Reserves Information

Oil and Natural Gas Reserve Information: Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (prices and costs held constant as of the date the estimate is made). Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

F-29

Proved oil and natural gas reserve information as of the fiscal year ends presented, and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott Company LP. Reserve information for the properties was prepared in accordance with guidelines established by the SEC.

The reserve estimates prepared as of each of the fiscal year ends presented were prepared in accordance with “Modernization of Oil and Gas Reporting” published by the SEC. The recent guidance included updated definitions of proved developed and proved undeveloped oil and gas reserves, oil and gas producing activities and other terms. Proved oil and gas reserves were calculated based on the prices for oil and gas during the 12 month period before the respective reporting date, determined as the unweighted arithmetic average of the first day of the month price for each month within such period, rather than the year-end spot prices, which had been used in prior years. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years. The recent guidance broadened the types of technologies that may be used to establish reserve estimates.

The following table sets forth information regarding the Company’s net ownership interests in estimated quantities of proved developed and undeveloped oil and gas reserve quantities and changes therein for each of the fiscal years presented:

	Oil (Bbl)			Gas (McF)			Boe
Balance, August 31, 2011		2,069,705			14,261,158			4,446,564
Revision of previous estimates		429,783			3,298,906			979,601
Purchase of reserves in place		33,328			706,842			151,135
Extensions, discoveries, and other additions		2,788,686			16,288,125			5,503,374
Sale of reserves in place		-			-			-
Production		(235,691	)		(1,109,057	)		(420,534	)
Balance, August 31, 2012		5,085,811			33,445,974			10,660,140
Revision of previous estimates		(194,236	)		(2,923,919	)		(681,556	)
Purchase of reserves in place		1,000,664			7,360,752			2,227,456
Extensions, discoveries, and other additions		1,576,301			4,914,627			2,395,406
Sale of reserves in place		-			-			-
Production		(421,265	)		(2,107,603	)		(772,532	)
Balance, August 31, 2013		7,047,275			40,689,831			13,828,914
Revision of previous estimates		83,592			3,046,893			591,408
Purchase of reserves in place		1,028,200			5,956,437			2,020,939
Extensions, discoveries, and other additions		9,141,836			49,288,543			17,356,592
Sale of reserves in place		(34,732	)		(56,282	)		(44,113	)
Production		(941,218	)		(3,747,074	)		(1,565,729	)
Balance, August 31, 2014		16,324,953			95,178,348			32,188,011


Proved developed and undeveloped reserves:
Developed at August 31, 2012		2,823,604			17,380,806			5,720,405
Undeveloped at August 31, 2012		2,262,207			16,065,168			4,939,735
Balance, August 31, 2012		5,085,811			33,445,974			10,660,140

Developed at August 31, 2013		4,659,405			25,866,008			8,970,406
Undeveloped at August 31, 2013		2,387,870			14,823,823			4,858,507
Balance, August 31, 2013		7,047,275			40,689,831			13,828,913

Developed at August 31, 2014		6,616,482			38,161,602			12,976,749
Undeveloped at August 31, 2014		9,708,471			57,016,746			19,211,262
Balance, August 31, 2014		16,324,953			95,178,348			32,188,011

F-30

Notable changes in proved reserves for the year ended August 31, 2014 included:

Purchases of reserves in place . In 2014, purchases of minerals in place of 2.0 million Boe were attributable to the acquisition of producing oil and gas wells and undeveloped acreage from Trilogy Resources, LLC and Apollo Operating, LLC. Please see the Acquisitions footnote for further information.

Revision of previous estimates. In 2014, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 591,408 Boe. The prices for the 2014 oil and gas reserves are based on the 12 month arithmetic average for the first of month price September 1, 2013 through August 31, 2014. The 2014 crude oil price of $89.48 per barrel (West Texas Intermediate Cushing) was $3.08 higher than the 2013 crude oil price of $86.40 per barrel. The 2014 natural gas price of $5.03 per mcf (Henry Hub) was $0.63 higher than the 2013 price of $4.40 per mcf.

Extensions and discoveries. In 2014, total extensions and discoveries of 17.4 million Boe were primarily attributable to successful drilling in the Wattenberg Field. The new producing wells in this area and their adjacent proved undeveloped locations added during the year increased the Company’s proved reserves.

Notable changes in proved reserves for the year ended August 31, 2013 included:

·	Purchases of reserves in place. In 2013, purchases of minerals in place of 2.2 million Boe were attributable to the acquisition of 36 producing oil and gas wells and undeveloped acreage from Orr Energy, LLC. Please see the Acquisitions footnote for further information.

Revision of previous estimates. In 2013, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 681,556 Boe as the Company’s drilling schedule was adjusted to reflect the elimination of previously planned vertical drilling locations as the development focus shifted from vertical to horizontal drilling.

Extensions and discoveries. In 2013, total extensions and discoveries of 2.4 million Boe were primarily attributable to successful drilling in the Wattenberg Field. The new producing wells in this area and their adjacent proved undeveloped locations added during the year increased the Company’s proved reserves.

Notable changes in proved reserves for the year ended August 31, 2012 included:

·	Purchases of reserves in place. In 2012, purchases of minerals in place of 151,135 Boe were attributable to the acquisition of additional working interests in existing wells that the Company already operates.

Revision of previous estimates. In 2012, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 979,601 Boe. Included in these revisions were 451,000 Boe of upward adjustments caused by higher crude oil and natural gas prices, and 528,601 Boe of net upward adjustments attributable to reservoir analysis and well performance.

Extensions and discoveries. In 2012, total extensions and discoveries of 5.5 million Boe were primarily attributable to successful drilling in the Wattenberg Field. The new producing wells in this area and their adjacent proved undeveloped locations added during the year increased the Company’s proved reserves.

F-31

Standardized Measure of Discounted Future Net Cash Flows: The following analysis is a standardized measure of future net cash flows and changes therein related to estimated proved reserves. Future oil and gas sales have been computed by applying average prices of oil and gas during each of the fiscal years presented. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs. The calculation assumes the continuation of existing economic conditions, including the use of constant prices and costs. Future income tax expenses were calculated by applying year-end statutory tax rates, with consideration of future tax rates already legislated, to future pretax cash flows relating to proved oil and gas reserves, less the tax basis of properties involved and tax credits and loss carry-forwards relating to oil and gas producing activities. All cash flow amounts are discounted at 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s oil and gas reserves. Actual future net cash flows from oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and gas, the amount and timing of actual production, supply of and demand for oil and gas, and changes in governmental regulations or taxation.

The following table sets forth the Company’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in the ASC (in thousands):

	For the Years Ended August 31,
	2014			2013			2012
Future cash inflow	$	1,839,987		$	749,030		$	537,462
Future production costs		(395,019	)		(146,352	)		(85,612	)
Future development costs		(412,517	)		(108,290	)		(100,821	)
Future income tax expense		(252,925	)		(113,545	)		(109,349	)
Future net cash flows		779,526			380,843			241,680
10% annual discount for estimated timing of cash flows		(376,827	)		(199,111	)		(139,175	)
Standardized measure of discounted future net cash flows	$	402,699		$	181,732		$	102,505

There have been significant fluctuations in the posted prices of oil and natural gas during the last three years. Prices actually received from purchasers of the Company’s oil and gas are adjusted from posted prices for location differentials, quality differentials, and BTU content. Estimates of the Company’s reserves are based on realized prices.

The following table presents the prices used to prepare the reserve estimates, based upon the unweighted arithmetic average of the first day of the month price for each month within the 12 month period prior to the end of the respective reporting period presented:

	Oil (Bbl)		Gas (Mcf)
August 31, 2012 (Average)	$	86.68	$	3.76
August 31, 2013 (Average)	$	86.40	$	4.40
August 31, 2014 (Average)	$	89.48	$	4.20

F-32

Changes in the Standardized Measure of Discounted Future Net Cash Flows: The principle sources of change in the standardized measure of discounted future net cash flows are (in thousands):

	For the Years Ended August 31,
	2014			2013			2012
Standardized measure, beginning of year	$	181,732		$	102,505		$	57,550
Sale and transfers, net of production costs		(86,808	)		(38,569	)		(21,321	)
Net changes in prices and production costs		15,828			(4,550	)		(6,023	)
Extensions, discoveries, and improved recovery		300,087			70,191			69,073
Changes in estimated future development costs		(20,817	)		(6,006	)		(42,578	)
Development costs incurred during the period		15,000			5,106			39,739
Revision of quantity estimates		4,589			(14,214	)		21,058
Accretion of discount		23,612			35,103			15,379
Net change in income taxes		(76,616	)		(7,850	)		(30,832	)
Divestitures of reserves		(925	)		-			-
Purchase of reserves in place		47,017			40,016			460
Standardized measure, end of year	$	402,699		$	181,732		$	102,505

F-33

17.	Unaudited Quarterly Financial Data

The Company’s quarterly financial information for the years ended August 31, 2014 and 2013 is as follows (in thousands, except share data):

	For the Year Ended August 31, 2014
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
Revenues	$	19,266	$	23,028		$	25,672		$	36,253
Expenses		12,048		13,550			14,413			20,744
Operating income		7,218		9,478			11,259			15,509
Other income (expense)		2,269		(1,979	)		(983	)		1,096
Income before income taxes		9,487		7,499			10,276			16,605
Income tax provision		3,387		2,338			3,116			6,173
Net income	$	6,100	$	5,161		$	7,160		$	10,432
Net income per common share: ⁽¹⁾
Basic	$	0.08	$	0.07		$	0.09		$	0.13
Diluted	$	0.08	$	0.07		$	0.09		$	0.13
Weighted average shares outstanding:
Basic		73,674,865		76,203,938			77,176,420			77,771,916
Diluted		76,044,605		77,990,416			79,008,619			79,698,720

	For the Year Ended August 31, 2013
	First Quarter		Second Quarter			Third Quarter		Fourth Quarter
Revenues	$	8,314	$	10,921		$	12,314	$	14,674
Expenses		4,768		6,439			7,449		8,022
Operating income		3,546		4,482			4,865		6,652
Other income (expense)		7		(146	)		451		(3,406	)
Income before income taxes		3,553		4,336			5,316		3,246
Income tax provision ⁽²⁾		1,315		1,604			1,701		2,250
Net income	$	2,238	$	2,732		$	3,615	$	996
Net income per common share: ⁽¹⁾
Basic	$	0.04	$	0.05		$	0.07	$	0.02
Diluted	$	0.04	$	0.05		$	0.06	$	0.01
Weighted average shares outstanding:
Basic		51,661,704		54,900,326			55,238,098		66,283,325
Diluted		53,616,182		56,481,752			58,918,586		70,176,105

The sum of net income per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year.

²	For the three months ended August 31, 2013, income taxes were provided at a higher than expected rate due to a downward adjustment in the deferred tax asset related to the expiration of underlying stock options.

F-34

18.	Subsequent Events

Exercise of Series C Warrants

Subsequent to August 31, 2014, the Company issued approximately 1.3 million shares pursuant to the exercise of Series C warrants and received proceeds of approximately $7.9 million.

F-35

SIGNATURES

Pursuant to the requirements of Section 13 or 15(a) of the Exchange Act, the Registrant has caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized on the 29 th day of October, 2014.

	SYNERGY RESOURCES CORPORATION

	/s/ Ed Holloway
	Ed Holloway, Co-Chief Executive Officer (Principal Executive Officer)


	/s/ William E Scaff, Jr
	William E Scaff, Jr, Co- Chief Executive Officer (Principal Executive Officer)


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

Pursuant to the requirements of the Securities Exchange Act of l934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date

/s/ Ed Holloway	Co-Chief Executive Officer and Director	October 29, 2014
Ed Holloway	(Principal Executive Officer)

/s/ William E. Scaff, Jr.	Co-Chief Executive Officer, Treasurer and Director	October 29, 2014
William E. Scaff, Jr.	(Principal Execuive Officer)

/s/ Frank L. Jennings	Chief Financial Officer	October 29, 2014
Frank L. Jennings	(Principal Financial and Principal Accounting Officer)

/s/ Rick Wilber	Director	October 29, 2014
Rick Wilber

/s/ Raymond E. McElhaney	Director	October 29, 2014
Raymond E. McElhaney

/s/ Bill M. Conrad	Director	October 29, 2014
Bill M. Conrad

/s/ R. W. Noffsinger, III	Director	October 29, 2014
R. W. Noffsinger, III

/s/ George Seward	Director	October 29, 2014
George Seward

/s/ Jack Aydin	Director	October 29, 2014
Jack Aydin

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

Synergy Resources Corporation

Platteville, Colorado

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File numbers 333-186726 and 333-188364) and Form S-8 (File number 333-191684) of our report dated October 28, 2014 relating to the financial statements and the effectiveness of Synergy Resources Corporation’s internal control over financial reporting, which appear in this Form 10-K.

/s/ EKS&H, LLLP

Denver, Colorado

October 28, 2014

Exhibit 31.1

CERTIFICATIONS

I, Ed Holloway, certify that;

1. I have reviewed this annual report on Form 10-K of Synergy Resources Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by the report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

October 29, 2014

/s/ Ed Holloway

Ed Holloway,

Co-Chief Executive Officer

Exhibit 31.2

CERTIFICATIONS

I, William Scaff, Jr., certify that;

1. I have reviewed this annual report on Form 10-K of Synergy Resources Corporation;

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

October 29, 2014

/s/ William Scaff, Jr.

William Scaff, Jr.,

Co-Chief Executive Officer

CERTIFICATIONS

I, Frank L. Jennings, certify that;

1. I have reviewed this annual report on Form 10-K of Synergy Resources Corporation;

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

October 29, 2014

/s/ Frank L. Jennings

Frank L. Jennings,

Principal Financial Officer

Exhibit 32

In connection with the annual report of Synergy Resources Corporation, (the "Company") on Form 10-K for the fiscal year ended August 31, 2014 as filed with the Securities Exchange Commission on the date hereof (the "Report") Ed Holloway, the Co-Chief Executive Officer of the Company, William Scaff, Jr., The Co-Chief Executive Officer of the Company, and Frank L. Jennings, the Principal Financial Officer of the Company, certify pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of their knowledge:

(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Company.


Date: October 29, 2014	By:	/s/ Ed Holloway
		Ed Holloway, Co-Chief Executive Officer



Date: October 29, 2014	By:	/s/ William Scaff, Jr.
		William Scaff, Jr., Co-Chief Executive Officer



Date: October 29, 2014	By:	/s/ Frank L. Jennings
		Frank L. Jennings, Principal Financial Officer

AMENDED AND RESTATED CREDIT AGREEMENT

dated as of November 28, 2012

among

Synergy Resources Corporation,
as Borrower,

Community Banks of Colorado, a division of NBH Bank, N.A.,
as Lender and Administrative Agent,

CoBiz Bank, a Colorado corporation, dba Colorado Business Bank, as Lender

and

Amegy Bank National Association, as Lender

TABLE OF CONTENTS

			Page
ARTICLE I Definitions and Accounting Matters			1
	Section 1.01	Certain Defined Terms	1
	Section 1.02	Types of Loans and Borrowings	20
	Section 1.03	Terms Generally; Rules of Construction	20
	Section 1.04	Accounting Terms and Determinations; GAAP	21

ARTICLE II The Credits			21
	Section 2.01	Commitments	21
	Section 2.02	Loans and Borrowings	21
	Section 2.03	Requests for Borrowings	22
	Section 2.04	Interest Elections; Conversions	23
	Section 2.05	Funding of Borrowings	25
	Section 2.06	Termination, Reduction and Increase of Aggregate Maximum Credit Amounts	25
	Section 2.07	Borrowing Base	27
	Section 2.08	Letters of Credit	30

ARTICLE III Payments of Principal and Interest; Prepayments; Fees			35
	Section 3.01	Repayment of Loans	35
	Section 3.02	Interest	35
	Section 3.03	Alternate Rate of Interest	36
	Section 3.04	Prepayments	36
	Section 3.05	Fees	38

ARTICLE IV Payments; Pro Rata Treatment; Sharing of Set‑offs			40
	Section 4.01	Payments Generally; Pro Rata Treatment; Sharing of Set‑offs	40
	Section 4.02	Presumption of Payment by the Borrower	41
	Section 4.03	Deductions by the Administrative Agent; Defaulting Lender	41
	Section 4.04	Disposition of Proceeds	43

ARTICLE V Increased Costs; Break Funding Payments; Taxes; Illegality			44
	Section 5.01	Increased Costs	44
	Section 5.02	Break Funding Payments	45
	Section 5.03	Taxes	46
	Section 5.04	Illegality	47

ARTICLE VI Conditions Precedent			47
	Section 6.01	Effective Date	47
	Section 6.02	Each Credit Event	50
	Section 6.03	Additional Conditions to Credit Events	51

ARTICLE VII Representations and Warranties			51
	Section 7.01	Organization; Powers	51
	Section 7.02	Authority; Enforceability	51

	Section 7.03	Approvals; No Conflicts	51
	Section 7.04	Financial Condition; No Material Adverse Change	52
	Section 7.05	Litigation	52
	Section 7.06	Environmental Matters	53
	Section 7.07	Compliance with the Laws and Agreements; No Defaults	54
	Section 7.08	Investment Company Act	54
	Section 7.09	Taxes	54
	Section 7.10	ERISA	55
	Section 7.11	Disclosure; No Material Misstatements	55
	Section 7.12	Insurance	56
	Section 7.13	Restriction on Liens	56
	Section 7.14	Subsidiaries	56
	Section 7.15	Location of Business and Offices	56
	Section 7.16	Properties; Titles, Etc.	57
	Section 7.17	Maintenance of Properties	57
	Section 7.18	Gas Imbalances, Prepayments	58
	Section 7.19	Marketing of Production	58
	Section 7.20	Hedging Agreements	58
	Section 7.21	Use of Loans and Letters of Credit	58
	Section 7.22	Solvency	59
	Section 7.23	Casualty Events	59
	Section 7.24	Material Agreements	59
	Section 7.25	No Brokers	59
	Section 7.26	Reliance	60
	Section 7.27	Payments by Purchasers of Production	60
	Section 7.28	Existing Accounts Payable	60
	Section 7.29	Foreign Corrupt Practices	60
	Section 7.30	Money Laundering	61
	Section 7.31	OFAC	61

ARTICLE VIII Affirmative Covenants			61
	Section 8.01	Financial Statements; Other Information	61
	Section 8.02	Notices of Material Events	64
	Section 8.03	Existence; Conduct of Business	65
	Section 8.04	Payment of Obligations	65
	Section 8.05	Performance of Obligations under Loan Documents	65
	Section 8.06	Operation and Maintenance of Properties	65
	Section 8.07	Insurance	66
	Section 8.08	Books and Records; Inspection Rights	66
	Section 8.09	Compliance with Laws	66
	Section 8.10	Environmental Matters	66
	Section 8.11	Further Assurances	68
	Section 8.12	Reserve Reports	68
	Section 8.13	Title Information	69
	Section 8.14	Additional Collateral; Additional Guarantors	70
	Section 8.15	ERISA Compliance	71
	Section 8.16	Marketing Activities	71

	Section 8.17	Hedging Agreements	71
	Section 8.18	Operating Accounts	71

ARTICLE IX Negative Covenants			72
	Section 9.01	Financial Covenants	72
	Section 9.02	Debt	72
	Section 9.03	Liens	73
	Section 9.04	Dividends and Distributions	73
	Section 9.05	Investments, Loans and Advances	73
	Section 9.06	Nature of Business	74
	Section 9.07	Limitation on Leases	74
	Section 9.08	Proceeds of Notes	74
	Section 9.09	ERISA Compliance	75
	Section 9.10	Mergers, Etc	75
	Section 9.11	Sale of Properties	75
	Section 9.12	Environmental Matters	76
	Section 9.13	Material Agreements	76
	Section 9.14	Transactions with Affiliates	77
	Section 9.15	Subsidiaries	77
	Section 9.16	Negative Pledge Agreements	77
	Section 9.17	Gas Imbalances, Take‑or‑Pay or Other Prepayments	77
	Section 9.18	Hedging Agreements	77
	Section 9.19	Sale and Leasebacks	78
	Section 9.20	Amendments to Organizational Documents	78

ARTICLE X Events of Default; Remedies			78
	Section 10.01	Events of Default	78
	Section 10.02	Remedies	80
	Section 10.03	Limitation on Rights and Waivers	81

ARTICLE XI The Administrative Agent			81
	Section 11.01	Appointment; Powers	81
	Section 11.02	Duties and Obligations of Administrative Agent	81
	Section 11.03	Action by Administrative Agent	82
	Section 11.04	Reliance by Administrative Agent	83
	Section 11.05	Subagents	83
	Section 11.06	Resignation or Removal of Administrative Agent	83
	Section 11.07	Administrative Agent as Lender	84
	Section 11.08	No Reliance	84
	Section 11.09	Administrative Agent May File Proofs of Claim	84
	Section 11.10	Authority of Administrative Agent to Release Collateral and Liens	85

ARTICLE XII Miscellaneous			85
	Section 12.01	Notices	85
	Section 12.02	Waivers; Amendments	86
	Section 12.03	Expenses, Indemnity; Damage Waiver	87

iii

Section 12.04	Successors and Assigns	90
Section 12.05	Survival; Revival; Reinstatement	93
Section 12.06	Counterparts; Integration; Effectiveness	94
Section 12.07	Severability	94
Section 12.08	Right of Setoff	95
Section 12.09	Governing Law; Jurisdiction; Consent to Service of Process	95
Section 12.10	Headings	96
Section 12.11	Confidentiality	96
Section 12.12	Interest Rate Limitation	97
Section 12.13	Exculpation Provisions	98
Section 12.14	Collateral Matters; Hedging Agreements	98
Section 12.15	No Third Party Beneficiaries	98
Section 12.16	USA Patriot Act Notice	98
Section 12.17	Existing Credit Agreement	99

ANNEXES, EXHIBITS AND SCHEDULES

Annex I	List of Maximum Credit Amounts

Exhibit A	Form of Note
Exhibit B	Form of Borrowing Request
Exhibit C	Form of Interest Election Request
Exhibit D	Form of Compliance Certificate
Exhibit E	Security Instruments
Exhibit F	Form of Assignment and Assumption
Exhibit G	Form of Hedging Agreement Certificate
Exhibit H	Form of Reserve Report Certificate
Exhibit I	List of Mortgaged Properties
Exhibit J	Form of Guaranty Agreement

Schedule 7.05	Litigation
Schedule 7.18	Gas Imbalances
Schedule 7.19	Marketing Agreements
Schedule 7.20	Hedging Agreements
Schedule 7.24	Material Agreements
Schedule 7.28	Existing Accounts Payable

AMENDED AND RESTATED CREDIT AGREEMENT

This Amended and Restated Credit Agreement, dated as of November 28, 2012, is made and entered into by and among Synergy Resources Corporation, a Colorado corporation (the “ Borrower ”), each of the Lenders from time to time party hereto, and Community Banks of Colorado, a division of NBH Bank, N.A., individually, as Issuing Lender and as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “ Administrative Agent ”).

R E C I T A L S

A. The Borrower and the Administrative Agent, formally known as Bank of Choice, a division of Bank Midwest, N.A., entered into that certain Loan Agreement effective November 30, 2011 (as amended before the date of this Agreement, the “ Existing Credit Agreement ”) pursuant to which the Administrative Agent, in its capacity as lender, provided the Borrower with a revolving credit facility.

B. The Borrower has requested certain amendments to the Existing Credit Agreement which include, among other things, appointing the Administrative Agent as administrative agent and the addition of other lenders.

C. The Lenders have agreed to amend and restate in its entirety the Existing Credit Agreement on the terms and conditions set forth herein, to renew and rearrange the indebtedness outstanding under the Existing Credit Agreement (but not to repay or pay off any such indebtedness) and to adjust their pro rata shares.

B. In consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties hereto agree as follows:

ARTICLE I
Definitions and Accounting Matters

Section 1.01 Certain Defined Terms . As used in this Agreement, the following terms have the meanings specified below:

“ ABR ”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Alternate Base Rate.

“ Administration Fee ” has the meaning assigned such term in Section 3.05(d) .

“ Adjusted LIBO Rate ” means, with respect to any Eurodollar Borrowing for any Interest Period, an interest rate per annum (rounded upwards, if necessary, to the next 1/100 of 1%) equal to the sum of (a) the product of (i) the LIBO Rate for such Interest Period, multiplied by (ii) the Statutory Reserve Rate.

“ Affected Loans ” has the meaning assigned such term in Section 5.04 .

“ Affiliate ” means, with respect to a specified Person, another Person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the Person specified.

“ Aggregate Maximum Credit Amounts ” at any time shall equal the sum of the Maximum Credit Amounts, as the same may be reduced or terminated pursuant to Section 2.06 .

“ Agreement ” means this Amended and Restated Credit Agreement, as the same may from time to time be amended, modified, supplemented or restated.

“ Alternate Base Rate ” means the Prime Rate in effect on such day.

“ Applicable Margin ” means, for any day, the rate per annum set forth in the Utilization Grid below based upon the Type of Loan or Borrowing and the Borrowing Base Utilization Percentage then in effect, subject to a minimum interest rate floor of 2.5% per annum:

Borrowing Base Utilization	LIBOR Margin	ABR Margin
≥ 90%	325 bps	100 bps
≥ 75% and < 90%	300 bps	75 bps
≥ 50% and < 75%	275 bps	50 bps
≥ 25% and < 50%	250 bps	25 bps
< 25%	250 bps	0 bps

“ Applicable Percentage ” means, with respect to any Lender, the percentage of the Aggregate Maximum Credit Amounts represented by such Lender’s Maximum Credit Amount as such percentage is set forth on Annex I .

“ Approved Counterparty ” means (a) any Lender or any Affiliate of a Lender, or (b) any other Person whose long term senior unsecured debt rating at the time of entry into the applicable Hedging Agreement is A-/A3 by S&P or Moody’s (or their equivalent) or higher .

“ Approved Petroleum Engineers ” means Ryder Scott Company or any independent petroleum engineering consulting company reasonably acceptable to the Required Lenders.

“ Arrangement Fee ” has the meaning assigned such term in Section 3.05(d) .

“ Assignment and Assumption ” means an assignment and assumption entered into by a Lender and an assignee (with the consent of any party whose consent is required by Section 12.04(a) ), and accepted by the Administrative Agent, in the form of Exhibit F or any other form approved by the Administrative Agent.

“ Availability Period ” means the period from and including the Effective Date to but excluding the Termination Date.

“ Board ” means the Board of Governors of the Federal Reserve System of the United States of America or any successor Governmental Authority.

“ Borrowing ” means Loans of the same Type, made, converted or continued on the same date and, in the case of Eurodollar Loans, as to which a single Interest Period is in effect.

“ Borrowing Base ” means at any time an amount equal to the amount determined in accordance with Section 2.07 , as the same may be adjusted from time to time pursuant to Section 2.07(f) , Section 8.13(c) or Section 9.11(d) .

“ Borrowing Base Deficiency ” occurs if at any time the total Revolving Credit Exposures exceeds the Borrowing Base then in effect.

“ Borrowing Base Hedging Agreement ” means any Hedging Agreement in respect of commodities that was in effect at the time of the most recent Borrowing Base determination.

“ Borrowing Base Utilization Percentage ” means, as of any day, the fraction expressed as a percentage, the numerator of which is the sum of the Revolving Credit Exposures of the Lenders on such day, and the denominator of which is the Borrowing Base on such day, regardless of the Aggregate Maximum Credit Amounts.

“ Borrowing Request ” means a request by the Borrower for a Borrowing in accordance with Section 2.03 .

“ Business Day ” means any day that is not a Saturday, Sunday or other day on which commercial banks in Colorado are authorized or required by law to remain closed; and if such day relates to a Borrowing or continuation of, a payment or prepayment of principal of or interest on, or a conversion of or into, or the Interest Period for, a Eurodollar Loan or a notice by the Borrower with respect to any such Borrowing or continuation, payment, prepayment, conversion or Interest Period, any day which is also a day on which banks are open for dealings in dollar deposits in the London interbank market.

“ Capital Expenditures ” means, in respect of any Person, for any period, the aggregate (determined without duplication) of all exploration and development expenditures and costs that should be capitalized in accordance with GAAP and any other expenditures that are capitalized on the balance sheet of such Person in accordance with GAAP.

“ Capital Leases ” means, in respect of any Person, all leases which shall have been, or should have been, in accordance with GAAP, recorded as capital leases on the balance sheet of the Person liable (whether contingent or otherwise) for the payment of rent thereunder.

“ Cash Collateral ” has the meaning assigned such term in Section 2.08(i) .

“ Cash Collateralize ” means to pledge and deposit with or deliver to the Administrative Agent (as a first‑priority, perfected security interest), for the benefit of the Issuing Banks and the Lenders, cash in dollars, at a location and pursuant to documentation in form and substance satisfactory to the Administrative Agent. “ Cash Collateralized ” has a correlative meaning.

“ Cash Receipts ” means all cash or cash equivalents received by or on behalf of the Borrower and its Subsidiaries with respect to the following: (a) sales from the Oil and Gas Properties (including any other working interest owner receipts received by the Borrower or its Affiliates as operator of Oil and Gas Properties), (b) cash representing operating revenue earned or to be earned by the Borrower and its Subsidiaries, (c) any insurance proceeds received by the Borrower or its Subsidiaries, (d) any net proceeds from Hedging Agreements and (e) any other cash or cash equivalents received by the Borrower from whatever source; provided that advances under the Loans, and any capital contributions or transfers made to the Borrower by any of its shareholders, or by the Borrower to any of its Subsidiaries, shall not constitute “ Cash Receipts ”.

“ Casualty Event ” means any loss, casualty or other insured damage to any Property of the Borrower or any of its Subsidiaries in an amount greater than two and one-half percent (2.5%) of the Borrowing Base then in effect, or any taking under power of eminent domain or by condemnation or similar proceeding of, any Property of the Borrower or any of its Subsidiaries having a fair market value in excess of two and one-half percent (2.5%) of the Borrowing Base then in effect.

“ Change in Control ” means the occurrence of the following events: (a) the acquisition of ownership, directly or indirectly, beneficially or of record, by any Person or group (within the meaning of the Securities Exchange Act of 1934 and the rules of the SEC thereunder as in effect on the date hereof) of Equity Interests so that such Person or group owns 50% or more of the aggregate ordinary voting power represented by the issued and outstanding Equity Interests of the Borrower, or (b) occupation of a majority of the seats (other than vacant seats) on the board of directors of the Borrower by Persons who were neither (i) nominated by the board of directors of the Borrower nor (ii) appointed by directors so nominated.

“ Change in Law ” means (a) the adoption of any law, rule or regulation after the date of this Agreement by any Governmental Authority, (b) any change in any law, rule or regulation or in the interpretation or application thereof by any Governmental Authority after the date of this Agreement or (c) compliance by any Lender or any Issuing Bank (or, for purposes of Section 5.01(b)), by such Lender’s or Issuing Bank’s holding company, if any) with any request, guideline or directive (whether or not having the force of law) of any Governmental Authority made or issued after the date of this Agreement; provided that notwithstanding anything herein to the contrary (i) the Dodd‑Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (ii) all requests, rules, guidelines or directives concerning capital adequacy promulgated by the Bank for International Settlements, the Basel Committee on Banking Regulations and Supervisory Practices (or any successor similar authority) or the United States financial regulatory authorities, in each case pursuant to Basel III, shall be deemed to be a “Change in Law”, regardless of the date enacted, adopted, promulgated or issued.

“ Code ” means the Internal Revenue Code of 1986, as amended from time to time, and any successor statute.

“ Collateral Account ” has the meaning assigned such term in Section 2.08(i).

“ Commitment ” means, with respect to each Lender, the commitment of such Lender to make Loans and to acquire participations in Letters of Credit hereunder, expressed as an amount representing the maximum aggregate amount of such Lender’s potential Revolving Credit Exposure hereunder, as such commitment may be (a) modified from time to time pursuant to Section 2.06 and (b) modified from time to time pursuant to assignments by or to such Lender pursuant to Section 12.04. The amount representing each Lender’s Commitment shall at any time be the lesser of such Lender’s Maximum Credit Amount and such Lender’s Applicable Percentage of the then effective Borrowing Base.

“ Commitment Reduction Notice ” has the meaning assigned such term in Section 2.07(d).

“ Consolidated Net Income ” means with respect to the Borrower and the Consolidated Subsidiaries, for any period, the aggregate of the net income (or loss) of the Borrower and the Consolidated Subsidiaries after allowances for taxes for such period determined on a consolidated basis in accordance with GAAP; provided that there shall be excluded from such net income (to the extent otherwise included therein) the following: (a) the net income of any Person in which the Borrower or any Consolidated Subsidiary has an interest (which interest does not cause the net income of such other Person to be consolidated with the net income of the Borrower and the Consolidated Subsidiaries in accordance with GAAP), except to the extent of the amount of dividends or distributions actually paid in cash during such period by such other Person to the Borrower or to a Consolidated Subsidiary, as the case may be; (b) the net income (but not loss) during such period of any Consolidated Subsidiary to the extent that the declaration or payment of dividends or similar distributions or transfers or loans by that Consolidated Subsidiary is not at the time permitted by operation of the terms of its charter or any agreement, instrument or Governmental Requirement applicable to such Consolidated Subsidiary or is otherwise restricted or prohibited, in each case determined in accordance with GAAP; (c) the net income (or loss) of any Person acquired in a pooling-of-interests transaction for any period prior to the date of such transaction; (d) any extraordinary gains or losses during such period; (e) the cumulative effect of a change in accounting principles and any gains or losses attributable to writeups or writedowns of assets; (f) any writeups or writedowns of non-current assets; and (g) non-cash gain and loss under ASC 815. If the Borrower or any of its Consolidated Subsidiaries have consummated an acquisition or disposition during such period, Consolidated Net Income shall be determined on a pro forma basis as if such acquisition or disposition had occurred on the first day of such period; provided that such pro forma adjustments shall be reasonably acceptable to the Administrative Agent.

“ Consolidated Subsidiaries ” means each Subsidiary of the Borrower (whether now existing or hereafter created or acquired) the financial statements of which shall be (or should have been) consolidated with the financial statements of the Borrower in accordance with GAAP.

“ Control ” means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ability to exercise voting power, by contract or otherwise. For the purposes of this definition, and without limiting the generality of the foregoing, any Person that owns directly or indirectly 10% or more of the Equity Interests having ordinary voting power for the election of the directors or other governing body of a Person (other than as a limited partner of such other Person) will be deemed to “ control ” such other Person. “ Controlling ” and “ Controlled ” have meanings correlative thereto.

“ Debt ” means, for any Person, the sum of the following (without duplication): (a) all obligations of such Person for borrowed money or evidenced by bonds, bankers’ acceptances, debentures, notes or other similar instruments; (b) all obligations of such Person (whether contingent or otherwise) in respect of letters of credit, surety or other bonds and similar instruments; (c) all accounts payable and all accrued expenses, liabilities or other obligations of such Person to pay the deferred purchase price of Property or services that are more than sixty (60) days past the due date other than those which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (d) all obligations of such Person under Capital Leases; (e) all obligations of such Person under Synthetic Leases; (f) all Debt (as defined in the other clauses of this definition) of others secured by (or for which the holder of such Debt has an existing right, contingent or otherwise, to be secured by) a Lien on any Property of such Person, whether or not such Debt is assumed by such Person; (g) all Debt (as defined in the other clauses of this definition) of others guaranteed by such Person or in which such Person otherwise assures a creditor against loss of the Debt (howsoever such assurance shall be made) to the extent of the lesser of the amount of such Debt and the maximum stated amount of such guarantee or assurance against loss; (h) all obligations or undertakings of such Person to maintain or cause to be maintained the financial position or covenants of others or to purchase the Debt or Property of others; (i) all obligations of such Person to deliver commodities, goods or services, including Hydrocarbons, in consideration of one or more advance payments, other than gas balancing arrangements in the ordinary course of business; (j ) any Debt of a partnership for which such Person is liable either by agreement, by operation of law or by a Governmental Requirement but only to the extent of such liability; (k) any Disqualified Capital Stock issued by such Person; and (l) the undischarged balance of any production payment created by such Person or for the creation of which such Person received payment. The Debt of any Person shall include all obligations of such Person of the character described above to the extent such Person remains legally liable in respect thereof notwithstanding that any such obligation is not included as a liability of such Person under GAAP.

“ Default ” means any event or condition which constitutes an Event of Default or that upon notice, lapse of time or both would, unless cured or waived, become an Event of Default.

“ Defaulting Lender ” means, at any time, a Lender as to which the Administrative Agent has notified the Borrower that such Lender, as reasonably determined by the Administrative Agent, has (a) failed to fund any portion of its Loans or participations in Letters of Credit within three Business Days of the date required to be funded by it hereunder (other than due to a failure of a condition precedent to be satisfied), (b) notified the Borrower, the Administrative Agent, any Issuing Bank or any Lender in writing that it does not intend to comply with its funding obligations under this Agreement or has made a public statement to the effect that it does not intend to comply with its funding obligations under this Agreement or under any other agreement in which it commits to extend credit (other than due to a failure of a condition precedent to be satisfied), (c) failed, within three (3) Business Days after request by the Administrative Agent, to confirm that it will comply with the terms of this Agreement relating to its obligations to fund prospective Loans and participations in then outstanding Letters of Credit (but such Lender shall cease to be a Defaulting Lender upon providing this confirmation), (d) otherwise failed to pay over to the Administrative Agent, any Issuing Bank or any Lender any other amount required to be paid by it hereunder within three Business Days of the date when due, unless the subject of a good faith dispute, (e) become or is insolvent or has a parent company that has become or is insolvent, or (f) become the subject of a bankruptcy or insolvency proceeding, or has had a receiver, conservator, trustee or custodian appointed for it, or has taken any action in furtherance of, or indicating its consent to, approval of or acquiescence in any such proceeding or appointment or has a parent company that has become the subject of a bankruptcy or insolvency proceeding, or has had a receiver, conservator, trustee or custodian appointed for it, or has taken any action in furtherance of, or indicating its consent to, approval of or acquiescence in any such proceeding or appointment.

“ Disqualified Capital Stock ” means any Equity Interest that, by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable) or upon the happening of any event, matures or is mandatorily redeemable for any consideration other than other Equity Interests (which would not constitute Disqualified Capital Stock), pursuant to a sinking fund obligation or otherwise, or is convertible or exchangeable for Debt or redeemable for any consideration other than other Equity Interests (which would not constitute Disqualified Capital Stock) at the option of the holder thereof, in whole or in part, on or prior to the date that is one year after the earlier of (a) the Termination Date and (b) the date on which there are no Loans, LC Exposure or other obligations hereunder outstanding and all of the Commitments are terminated.

“ Dollars ” or “ $ ” refers to lawful money of the United States of America.

“ EBITDAX ” means, as of any date of determination, the sum of the Consolidated Net Income for the four fiscal quarters ending on the last day of the most recently completed fiscal quarter on or prior to such date of determination plus (a) the following expenses or charges to the extent deducted from Consolidated Net Income in such period: interest, income taxes, depreciation, depletion, amortization (including amortization of deferred loan costs), exploration expenditures and costs, unrealized losses on any Hedging Agreement, accretion expense associated with asset retirement obligations and other similar noncash charges, minus (b) without duplication and to the extent added to Consolidated Net Income in such period: income tax benefits, unrealized gains on Hedging Agreements, and gains on sales of assets.

“ Effective Date ” means the later of (i) date on which the conditions specified in Section 6.01 are satisfied (or waived in accordance with Section 12.02 ) or (ii) November 30, 2012.

“ Eligible Assignee ” means any Person that meets the requirements to be an assignee under Section 12.04 .

“ Eligible Lender ” means (a) a financial institution organized under the laws of the United States, or any state thereof, and having a combined capital and surplus of at least $100,000,000; or (b) a Person controlled by, controlling, or under common control with any entity identified in clause (a) above.

“ Engineering Reports ” has the meaning assigned such term in Section 2.07(c) .

“ Environmental Laws ” means any and all Governmental Requirements pertaining in any way to health, safety, the environment, the preservation or reclamation of natural resources, or the management, Release or threatened Release of any Hazardous Materials, in effect in any and all jurisdictions in which the Borrower or any Subsidiary is conducting, or at any time has conducted, business, or where any Property of the Borrower or any Subsidiary is located, including the Oil Pollution Act of 1990, as amended, the Clean Air Act, as amended, the Comprehensive Environmental, Response, Compensation, and Liability Act of 1980 (“ CERCLA ”), as amended, the Federal Water Pollution Control Act, as amended, the Occupational Safety and Health Act of 1970, as amended, the Resource Conservation and Recovery Act of 1976 (“ RCRA ”), as amended, the Safe Drinking Water Act, as amended, the Toxic Substances Control Act, as amended, the Superfund Amendments and Reauthorization Act of 1986, as amended, the Hazardous Materials Transportation Law, as amended, and other environmental conservation or protection Governmental Requirements.

“ Environmental Permit ” means any permit, registration, license, notice, approval, consent, exemption, variance, or other authorization required under or issued pursuant to applicable Environmental Laws.

“ Equity Interests ” means shares of capital stock, partnership interests, membership interests in a limited liability company, beneficial interests in a trust or other equity ownership interests in a Person, and any warrants, options or other rights entitling the holder thereof to purchase or acquire any such Equity Interest.

“ ERISA ” means the Employee Retirement Income Security Act of 1974, as amended, and any successor statute, and all regulations and guidance promulgated thereunder.

“ ERISA Affiliate ” means each trade or business (whether or not incorporated) which together with the Borrower or a Subsidiary would be deemed to be a “ single employer ” within the meaning of section 4001(b)(1) of ERISA or subsections (b), (c), (m) or (o) of section 414 of the Code.

“ Eurodollar ”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Adjusted LIBO Rate.

“ Event of Default ” has the meaning assigned such term in Section 10.01 .

social security, old age pension or public liability obligations which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (c) statutory landlord’s liens, operators’, vendors’, carriers’, warehousemen’s, repairmen’s, mechanics’, suppliers’, workers’, materialmen’s, construction or other like Liens arising by operation of law in the ordinary course of business or incident to the exploration, development, operation and maintenance of Oil and Gas Properties each of which is in respect of obligations that are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (d) contractual Liens which arise in the ordinary course of business under operating agreements, joint venture agreements, oil and gas partnership agreements, oil and gas leases, farm‑out agreements, division orders, contracts for the sale, transportation or exchange of oil and natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements, royalty agreements, overriding royalty agreements, marketing agreements, processing agreements, net profits agreements, development agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or other geophysical permits or agreements and other agreements which are usual and customary in the oil and gas business and are for claims which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP, provided that any such Lien referred to in this clause does not materially impair the use of the Property covered by such Lien for the purposes for which such Property is held by the Borrower or any Subsidiary or materially impair the value of such Property subject thereto; (e) Liens arising solely by virtue of any statutory or common law provision relating to banker’s liens, rights of set‑off or similar rights and remedies and burdening only deposit accounts or other funds maintained with a creditor depository institution, provided that no such deposit account is a dedicated cash collateral account or is subject to restrictions against access by the depositor in excess of those set forth by regulations promulgated by the Board and no such deposit account is intended by the Borrower or any of its Subsidiaries to provide collateral to the depository institution; (f) easements, restrictions, servitudes, permits, conditions, covenants, exceptions or reservations in any Property of the Borrower or any Subsidiary for the purpose of roads, pipelines, transmission lines, transportation lines, distribution lines for the removal of gas, oil, coal or other minerals or timber, and other like purposes, or for the joint or common use of real estate, rights of way, facilities and equipment, and Liens related to surface leases and surface operations, that do not secure any monetary obligations and which in the aggregate do not materially impair the use of such Property for the purposes of which such Property is held by the Borrower or any Subsidiary or materially impair the value of such Property subject thereto; (g) Liens on cash or securities pledged to secure performance of tenders, surety and appeal bonds, government contracts, performance and return of money bonds, bids, trade contracts, leases, statutory obligations, regulatory obligations and other obligations of a like nature incurred in the ordinary course of business and (h) judgment and attachment Liens not giving rise to an Event of Default, provided that any appropriate legal proceedings which may have been duly initiated for the review of such judgment shall not have been finally terminated or the period within which such proceeding may be initiated shall not have expired and no action to enforce such Lien has been commenced; provided, further that Liens described in clauses (a) through (e) shall remain “Excepted Liens” only for so long as no action to enforce such Lien has been commenced and no intention to subordinate the first priority Lien granted in favor of the Administrative Agent and the Lenders is to be hereby implied or expressed by the permitted existence of such Excepted Liens.

“ Excluded Taxes ” means, with respect to the Administrative Agent, any Lender, any Issuing Bank or any other recipient of any payment to be made by or on account of any obligation of the Borrower hereunder or under any other Loan Document, (a) income taxes or franchise taxes (imposed in lieu of net income taxes), by the United States of America or such other jurisdiction (or any political subdivision) under the laws of which such recipient is organized or in which its principal office is located or, in the case of any Lender, in which its applicable lending office is located, (b) any branch profits taxes imposed by the United States of America or any similar tax imposed by any other jurisdiction in which the Borrower is located, (c) in the case of a Foreign Lender, any withholding tax that is imposed by the United States of America on amounts payable to such Foreign Lender and (d) any U.S. Federal withholding taxes imposed by FATCA.

“ Existing Credit Agreement ” has the meaning assigned such term in the Recitals to this Agreement.

“ FATCA ” means Sections 1471 through 1474 of the Code (or any amended or successor version that is substantively comparable) and any current or future regulations or official interpretations thereof.

“ FCPA ” means the U.S. Foreign Corrupt Practices Act of 1977, as amended.

“ Federal Funds Effective Rate ” means, for any day, an interest rate per annum equal to the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System arranged by federal funds brokers, as published for such day by the Federal Reserve Bank of New York, or if such rate is not so published for such day, the average of the quotations for such day on such transactions received by the Administrative Agent from three federal funds brokers of recognized standing selected by it.

“ Fee Letter ” means that letter agreement dated October 11, 2012, by and between the Borrower and the Administrative Agent, related to, among other things, the payment of certain fees by the Borrower.

“ Financial Officer ” means, for any Person, the chief financial officer, principal accounting officer, treasurer, manager or controller of such Person. Unless otherwise specified, all references herein to a Financial Officer means a Financial Officer of the Borrower.

“ Financial Statements ” means the financial statement or statements of the Borrower and its Consolidated Subsidiaries referred to in Section 7.04(a) .

“ Foreign Lender ” means any Lender that is organized under the laws of a jurisdiction other than that in which the Borrower is located. For purposes of this definition, the United States of America, each State thereof and the District of Columbia shall be deemed to constitute a single jurisdiction.

“ GAAP ” means generally accepted accounting principles in the United States of America as in effect from time to time subject to the terms and conditions set forth in Section 1.04 .

“ Governmental Authority ” means the government of the United States of America, any other nation or any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government.

“ Governmental Requirement ” means any law, statute, code, ordinance, order, determination, rule, regulation, judgment, decree, injunction, franchise, permit, certificate, license, rules of common law, authorization or other directive or requirement, whether now or hereinafter in effect, of any Governmental Authority.

“ Guarantors ” means any Subsidiary of the Borrower that guarantees the Indebtedness.

“ Hazardous Material ” means any substance regulated or as to which liability might arise under any applicable Environmental Law, including: (a) any chemical, compound, material, product, byproduct, substance or waste defined as or included in the definition or meaning of “hazardous substance,” “hazardous material,” “hazardous waste,” “solid waste,” “toxic waste,” “extremely hazardous substance,” “toxic substance,” “contaminant,” “pollutant,” or words of similar meaning or import found in any applicable Environmental Law; (b) Hydrocarbons, petroleum products, petroleum substances, natural gas, oil, oil and gas waste, crude oil, and any components, fractions, or derivatives thereof; and (c) radioactive materials, explosives, asbestos or asbestos containing materials, polychlorinated biphenyls, radon, infectious or medical wastes.

“ Hedging Agreement ” means any agreement with respect to any swap, forward, future or derivative transaction or option or similar agreement, whether exchange traded, “over‑the‑counter” or otherwise, involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions; provided that no phantom stock or similar plan providing for payments only on account of services provided by current or former directors, officers, employees or consultants of the Borrower or the Subsidiaries shall be a Hedging Agreement.

“ Highest Lawful Rate ” means, with respect to each Lender, the maximum nonusurious interest rate, if any, that at any time or from time to time may be contracted for, taken, reserved, charged or received on the Notes or on other Indebtedness under laws applicable to such Lender which are presently in effect or, to the extent allowed by law, under such applicable laws which may hereafter be in effect and which allow a higher maximum nonusurious interest rate than applicable laws allow as of the date hereof.

“ Hydrocarbon Interests ” means all rights, titles, interests and estates now or hereafter acquired in and to oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases, mineral fee interests, overriding royalty and royalty interests, net profit interests and production payment interests, including any reserved or residual interests of whatever nature.

“ Hydrocarbons ” means oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all products refined or separated therefrom.

“ Increase Effective Date ” has the meaning assigned such term in Section 2.06(c)(ii) .

“ Indebtedness ” means any and all amounts owing or to be owing by the Borrower or any Guarantor (whether direct or indirect (including those acquired by assumption), absolute or contingent, due or to become due, now existing or hereafter arising): (a) to the Administrative Agent, any Issuing Bank, any Lender or any Affiliate of a Lender, or any Secured Hedging Counterparty under any Loan Document; and (b) all renewals, extensions and/or rearrangements of any of the above; provided that solely with respect to any Guarantor that is not an “eligible contract participant” under the Commodity Exchange Act, Excluded Swap Obligations of such Guarantor shall in any event be excluded from “Indebtedness” owing by such Guarantor.

“ Indemnified Taxes ” means Taxes other than Excluded Taxes.

“ Indemnitee ” has the meaning set forth in Section 12.03.

“ Initial Commitment ” the aggregate Commitment made by Lenders as of the Effective Date, as set forth in Annex I to this Agreement.

“ Initial Reserve Report ” means the report dated as of November 2, 2012, and referencing an effective date of August 31, 2012, prepared by Ryder Scott Company, with respect to certain Oil and Gas Properties of the Borrower.

“ Interest Election Request ” means a request by the Borrower to convert or continue a Borrowing in accordance with Section 2.04.

“ Interest Payment Date ” means (a) with respect to any ABR Loan the last day of each calendar quarter or, if sooner, the Termination Date and (b) with respect to any Eurodollar Loan, the last day of the Interest Period applicable to the Borrowing of which such Loan is a part.

“ Interest Period ” means with respect to any Eurodollar Borrowing, the period commencing on the date of such Borrowing and ending on the numerically corresponding day in the calendar month that is thirty, sixty or ninety days thereafter, as the Borrower may elect; provided , that (a) if any Interest Period would end on a day other than a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless such next succeeding Business Day would fall in the next calendar month, in which case such Interest Period shall end on the next preceding Business Day and (b) any Interest Period pertaining to a Eurodollar Borrowing that commences on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the last calendar month of such Interest Period) shall end on the last Business Day of the last calendar month of such Interest Period. For purposes hereof, the date of a Borrowing initially shall be the date on which such Borrowing is made and thereafter shall be the effective date of the most recent conversion or continuation of such Borrowing.

“ Interim Redetermination ” has the meaning assigned such term in Section 2.07(b) .

“ Interim Redetermination Date ” means the date on which a Borrowing Base that has been redetermined pursuant to an Interim Redetermination becomes effective as provided in Section 2.07( c).

“ Investment ” means, for any Person: (a) the acquisition (whether for cash, Property, services or securities or otherwise) of Equity Interests of any other Person, the contribution of capital to any other Person or any agreement to make any such acquisition (including any “ short sale ” or any sale of any securities at a time when such securities are not owned by the Person entering into such short sale) or capital contribution; (b) the making of any deposit with, or advance, loan or capital contribution to, assumption of Debt of, purchase or other acquisition of any other Debt or equity participation or interest in, or other extension of credit to, any other Person (including the purchase of Property from another Person subject to an understanding or agreement, contingent or otherwise, to resell such Property to such Person, but excluding any such advance, loan or extension of credit having a term not exceeding ninety (90) days representing the purchase price of inventory or supplies sold by such Person in the ordinary course of business); (c) the purchase or acquisition (in one or a series of transactions) of Property of another Person that constitutes a business unit or (d) the entering into of any guarantee of, or other contingent obligation (including the deposit of any Equity Interests to be sold) with respect to, Debt or other liability of any other Person and (without duplication) any amount committed to be advanced, lent or extended to such Person.

“ Issuing Bank ” means Community Banks of Colorado, in its capacity as the issuer of Letters of Credit and, from time to time as determined by the Administrative Agent, any Lender that agrees to act as an Issuing Bank hereunder. The Issuing Bank may, in its discretion, arrange for one or more Letters of Credit to be issued by Affiliates of the Issuing Bank, in which case the term “ Issuing Bank ” shall include any such Affiliate with respect to Letters of Credit issued by such Affiliate.

“ LC Commitment ” at any time means an amount equal to the lesser of (i) ten percent (10%) of the lesser of (A) the aggregate Commitments of the Lenders or (B) the Borrowing Base, and (ii) $15,00,000.

“ LC Disbursement ” means a payment made by any Issuing Bank pursuant to a Letter of Credit issued by such Issuing Bank.

“ LC Exposure ” means, at any time, the sum of (a) the aggregate undrawn amount of all outstanding Letters of Credit at such time plus (b) the aggregate amount of all LC Disbursements that have not yet been reimbursed by or on behalf of the Borrower at such time. The LC Exposure of any Lender at any time shall be its Applicable Percentage of the total LC Exposure at such time.

“ Lenders ” means the Persons listed on Annex I and any Person that shall have become a party hereto pursuant to an Assignment and Assumption, other than any such Person that ceases to be a party hereto pursuant to an Assignment and Assumption.

“ Letter of Credit ” means any letter of credit issued pursuant to this Agreement.

“ Letter of Credit Agreements ” means all letter of credit applications and other agreements (including any amendments, modifications or supplements thereto) submitted by the Borrower, or entered into by the Borrower, with any Issuing Bank relating to any Letter of Credit.

“ LIBO Rate ” means, with respect to any Eurodollar Borrowing for any Interest Period , the rate of interest per annum, expressed on the basis of a year of 360 days, determined by the Administrative Agent, which is equal to the offered rate that appears on the on the relevant page of the Bloomberg Financial Market Information System (or any other information service selected by the Administrative Agent) that displays an average British Bankers Association Interest Settlement Rate for deposits in dollars with a term equivalent to such Interest Period, determined as of approximately 11:00 a.m . (London time) two (2) Business Days prior to the first day of such Interest Period.

“ Lien ” means any interest in Property securing an obligation owed to, or a claim by, a Person other than the owner of the Property, whether such interest is based on the common law, statute or contract, and whether such obligation or claim is fixed or contingent, and including (a) the lien or security interest arising from a mortgage, encumbrance, pledge, security agreement, conditional sale or trust receipt or a lease, consignment or bailment for security purposes or (b) production payments and the like payable out of Oil and Gas Properties. The term “ Lien ” shall include easements, restrictions, servitudes, permits, conditions, covenants, encroachments, exceptions or reservations. For purposes of this Agreement, the Borrower and its Subsidiaries shall be deemed to be the owner of any Property which it has acquired or holds subject to a conditional sale agreement, or leases under a financing lease or other arrangement pursuant to which title to the Property has been retained by or vested in some other Person in a transaction intended to create a financing.

“ Loan Documents ” means this Agreement, the Notes, the Fee Letter, any Secured Hedging Agreement, the Letter of Credit Agreements, the Letters of Credit and the Security Instruments.

“ Loans ” means the loans made by the Lenders to the Borrower pursuant to this Agreement.

“ Material Adverse Effect ” means a material adverse change in, or material adverse effect on (a) the business, operations, Property condition (financial or otherwise) or prospects of the Borrower and any of its Subsidiaries taken as a whole, (b) the ability of the Borrower, any Subsidiary or any Guarantor to perform any of its obligations under any Loan Document to which it is a party, (c) the validity or enforceability of any Loan Document or (d) the rights and remedies of or benefits available to the Administrative Agent, any Issuing Bank or any Lender under any Loan Document.

“ Material Agreements ” has the meaning assigned such term in Section 7.24.

“ Material Debt ” means Debt (other than the Loans and Letters of Credit), or obligations in respect of one or more Hedging Agreements, of the Borrower and its Subsidiaries in an aggregate principal amount exceeding $200,000. For purposes of determining Material Debt, the “ principal amount ” of the obligations of the Borrower or any Subsidiary in respect of any Hedging Agreement at any time shall be the maximum aggregate amount (giving effect to any legally enforceable netting agreements) that the Borrower would be required to pay if such Hedging Agreement were terminated at such time.

“ Maximum Credit Amount ” means, as to each Lender, the amount set forth opposite such Lender’s name on Annex I under the caption “Maximum Credit Amount”, as the same may be (a) terminated in accordance with Section 2.06(b) , (b) reduced from time to time in Commitment Reduction Notice pursuant to Section 2.06(b) , (c) increased from time in connection with an increase of any Lender’s Maximum Credit Amount pursuant to Section 2.06(c) , or (d) modified from time to time pursuant to any assignment permitted by Section 12.04.

“ Money Laundering Laws ” means the laws, rules and regulations created pursuant to the Money Laundering Control Act of 1986.

“ Mortgaged Property” means any Property owned by Borrower which is subject to the Liens existing and to exist under the terms of the Security Instruments.

“ Moody’s ” means Moody’s Investors Service, Inc. and any successor thereto that is a nationally recognized rating agency.

“ New Borrowing Base Notice ” has the meaning assigned such term in Section 2.07(e) .

“ Non‑Defaulting Lender ” means, at any time, each Lender that is not a Defaulting Lender at such time.

“ Notes ” means the promissory notes of the Borrower described in Section 2.02(d) and being substantially in the form of Exhibit A , together with all amendments, modifications, replacements, extensions and rearrangements thereof.

“ NPV ” means, with respect to any Proved Reserves, the present value ascribed to such Proved Reserves (taking into account the cash flows and expenses, including capital expenditures, associated therewith) in the most recent Reserve Report, based upon the economic assumptions (including the discount rate) provided to the Approved Petroleum Engineers by the Administrative Agent.

“ OFAC ” means the U.S. Treasury Department Office of Foreign Assets Control.

“ Oil and Gas Properties ” means (a) Hydrocarbon Interests; (b) the Properties now or hereafter pooled or unitized with Hydrocarbon Interests; (c) all presently existing or future unitization, pooling agreements and declarations of pooled units and the units created thereby (including all units created under orders, regulations and rules of any Governmental Authority) which may affect all or any portion of the Hydrocarbon Interests; (d) all operating agreements, contracts and other agreements, including production sharing contracts and agreements, which relate to any of the Hydrocarbon Interests or the production, sale, purchase, exchange or processing of Hydrocarbons from or attributable to such Hydrocarbon Interests; (e) all Hydrocarbons in and under and which may be produced and saved or attributable to the Hydrocarbon Interests, including all oil in tanks, and all rents, issues, profits, proceeds, products, revenues and other incomes from or attributable to the Hydrocarbon Interests; (f) all tenements, hereditaments, appurtenances and Properties in any manner appertaining, belonging, affixed or incidental to the Hydrocarbon Interests and (g) all Properties, rights, titles, interests and estates described or referred to above, including any and all Property, real or personal, now owned or hereafter acquired and situated upon, used, held for use or useful in connection with the operating, working or development of any of such Hydrocarbon Interests or Property (excluding drilling rigs, automotive equipment, rental equipment or other personal Property which may be on such premises for the purpose of drilling a well or for other similar temporary uses) and including any and all oil wells, gas wells, injection wells or other wells, buildings, structures, fuel separators, liquid extraction plants, plant compressors, pumps, pumping units, field gathering systems, tanks and tank batteries, fixtures, valves, fittings, machinery and parts, engines, boilers, meters, apparatus, equipment, appliances, tools, implements, cables, wires, towers, casing, tubing and rods, surface leases, rights‑of‑way, easements and servitudes together with all additions, substitutions, replacements, accessions and attachments to any and all of the foregoing.

“ Organizational Documents ” means, with respect to any Person, (a) in the case of any corporation, the articles or certificate of incorporation and by‑laws (or similar documents) of such Person, (b) in the case of any limited liability company, the certificate of formation and limited liability company agreement (or similar documents) of such Person, (c) in the case of any limited partnership, the certificate of formation and limited partnership agreement (or similar documents) of such Person, (d) in the case of any general partnership, the partnership agreement (or similar document) of such Person and (e) in any other case, the functional equivalent of the foregoing.

“ Orr Acquisition ” shall mean the acquisition of certain oil and gas properties of Orr Energy, LLC by the Borrower pursuant to that Purchase and Sale Agreement, dated October 23, 2012, by and between such parties.

“ Other Taxes ” means any and all present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies arising from any payment made hereunder or from the execution, delivery or enforcement of, or otherwise with respect to, this Agreement and any other Loan Document, except Excluded Taxes.

“ Participant ” has the meaning set forth in Section 12.04(c) .

“ Patriot Act ” has the meaning assigned such term in Section 12.16 .

“ Person ” means any natural person, corporation, limited liability company, trust, joint venture, association, company, partnership, Governmental Authority or other entity.

“ Plan ” means any employee pension benefit plan, as defined in section 3(2) of ERISA, which (a) is currently or hereafter sponsored, maintained or contributed to by the Borrower, a Subsidiary or an ERISA Affiliate or (b) was at any time during the six calendar years preceding the date hereof, sponsored, maintained or contributed to by the Borrower or a Subsidiary or an ERISA Affiliate.

“ Post Default Rate ” shall mean, in respect of the principal of any Loan or any other amount payable by the Borrower under this Agreement or any other Loan Document, a rate per annum during the period commencing on the date of occurrence of an Event of Default until such amount is paid in full or all Events of Default are cured or waived equal to the Alternate Base Rate plus: (i) the Applicable Margin and (ii) two percent (2.0%) per annum, but in no event to exceed the Highest Lawful Rate.

“ Prime Rate ” means the base rate on corporate loans posted by at least seventy percent (70%) of the ten (10) largest US. banks as reported by the Eastern print edition of the Wall Street Journal®.

“ Property ” means any interest in any kind of property or asset, whether real, personal or mixed, or tangible or intangible, including cash, securities, accounts and contract rights.

“ Proposed Borrowing Base ” has the meaning assigned to such term in Section 2.07(c)(i)(A) .

“ Proposed Borrowing Base Notice ” has the meaning assigned to such term in Section 2.07(c)(iii) .

“ Proved Reserves ” means “Proved Reserves” as defined in the Definitions for Oil and Gas Reserves (in this paragraph, the “Definitions”) promulgated by the Society of Petroleum Engineers (or any generally recognized successor) as in effect at the time in question. “ Proved Developed Producing Reserves ” means Proved Reserves which are categorized as both “Developed” and “Producing” in the Definitions, “ Proved Developed Nonproducing Reserves ” means Proved Reserves which are categorized as both “Developed” and “Nonproducing” in the Definitions, “ Proved Developed Reserves ” means collectively the Proved Developed Producing Reserves and Proved Developed Nonproducing Reserves, and “ Proved Undeveloped Reserves ” means Proved Reserves which are categorized as “ Undeveloped ” in the Definitions.

“ Redemption ” means with respect to any Debt, the repurchase, redemption, prepayment, repayment, defeasance or any other acquisition or retirement for value (or the segregation of funds with respect to any of the foregoing) of such Debt. “ Redeem ” has the correlative meaning thereto.

“ Regulation D ” means Regulation D of the Board, as the same may be amended, supplemented or replaced from time to time.

“ Related Parties ” means, with respect to any specified Person, such Person’s Affiliates and the respective directors, officers, employees, agents and advisors (including attorneys, accountants and experts) of such Person and such Person’s Affiliates.

“ Release ” means any depositing, spillings, leaking, pumping, pouring, placing, emitting, discarding, abandoning, emptying, discharging, migrating, injecting, escaping, leaching, dumping, or disposing.

“ Remedial Work ” has the meaning assigned such term in Section 8.10(a).

“ Reserve Report ” means a report, in form and substance reasonably satisfactory to the Administrative Agent, setting forth, as of each August 31 or February 28 (or such other date in the event of an Interim Redetermination) the oil and gas reserves attributable to the Oil and Gas Properties of the Borrower and its Subsidiaries, together with a projection of the rate of production and future net income, taxes, operating expenses and Capital Expenditures with respect thereto as of such date, based upon economic assumptions established by the Administrative Agent and reflecting Hedging Agreements in place with respect to such production.

“ Responsible Officer ” means, as to any Person, the Chief Executive Officer, the President, any Financial Officer, any Vice President or any Manager of such Person. Unless otherwise specified, all references to a Responsible Officer herein shall mean a Responsible Officer of the Borrower.

“ Restricted Payment ” means any dividend or other distribution (whether in cash, securities or other Property) with respect to any Equity Interests in the Borrower or any of its Subsidiaries, or any payment (whether in cash, securities or other Property), including any return of capital, sinking fund or similar deposit, on account of the purchase, redemption, retirement, acquisition, cancellation or termination of any such Equity Interests in the Borrower or any of its Subsidiaries or any option, warrant or other right to acquire any such Equity Interests in the Borrower or any of its Subsidiaries.

“ Revolving Credit Exposure ” means, with respect to any Lender at any time, the sum of the outstanding principal amount of such Lender’s Loans and its LC Exposure at such time.

“ Scheduled Redetermination ” has the meaning assigned such term in Section 2.07(b) .

“ Scheduled Redetermination Date ” means the date on which a Borrowing Base that has been redetermined pursuant to a Scheduled Redetermination becomes effective as provided in Section 2.07(c)(iii)(B) .

“ SEC ” means the U.S. Securities and Exchange Commission or any successor Governmental Authority.

“ Security Instruments ” means the mortgages, deeds of trust and other agreements, instruments or certificates described or referred to in Exhibit E , and any and all other agreements, guarantees, instruments, consents or certificates now or hereafter executed and delivered by the Borrower or any other Person (other than Hedging Agreements with Secured Hedging Counterparties with respect to any Indebtedness pursuant to this Agreement) in connection with, or as security for the payment or performance of the Indebtedness, the Notes, if any, this Agreement, or reimbursement obligations under the Letters of Credit, as such agreements may be amended, modified, supplemented or restated from time to time.

“ Secured Hedging Agreement ” means any Hedging Agreement of the Borrower or any Subsidiary with a Secured Hedging Counterparty.

“ Secured Hedging Counterparty ” means any Approved Counterparty that is party to a Hedging Agreement with the Borrower or any Subsidiary, whether or not such Person at any time ceases to be an Approved Counterparty; provided, however, that in the case of any Approved Counterparty who is not a Lender, such Approved Counterparty shall have entered into an intercreditor or similar agreement with the Lenders, which agreement shall be in form and substance acceptable to the Required Lenders.

“ S&P ” means Standard & Poor’s Ratings Group, a division of The McGraw‑Hill Companies, Inc., and any successor thereto that is a nationally recognized rating agency.

“ Statutory Reserve Rate ” means a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the maximum reserve percentages (including any marginal, special, emergency or supplemental reserves) expressed as a decimal established by the Board to which the Administrative Agent is subject with respect to the Adjusted LIBO Rate, for eurocurrency funding (currently referred to as “Eurocurrency Liabilities” in Regulation D of the Board). Such reserve percentages shall include those imposed pursuant to such Regulation D. Eurodollar Loans shall be deemed to constitute eurocurrency funding and to be subject to such reserve requirements without benefit of or credit for proration, exemptions or offsets that may be available from time to time to any Lender under such Regulation D or any comparable regulation. The Statutory Reserve Rate shall be adjusted automatically on and as of the effective date of any change in any reserve percentage.

“ Subsidiary ” means: (a) any Person of which at least a majority of the outstanding Equity Interests having by the terms thereof ordinary voting power to elect a majority of the board of directors or managers or other governing body of such Person (irrespective of whether or not at the time Equity Interests of any other class or classes of such Person shall have or might have voting power by reason of the happening of any contingency) is at the time directly or indirectly owned or controlled by the Borrower or one or more of its Subsidiaries or by the Borrower and one or more of its Subsidiaries and (b) any partnership of which the Borrower or any of its Subsidiaries is a general partner. Unless otherwise indicated herein, each reference to the term “Subsidiary” shall mean a Subsidiary of the Borrower.

“ Synthetic Leases ” means, in respect of any Person, all leases which shall have been, or should have been, in accordance with GAAP, treated as operating leases on the financial statements of the Person liable (whether contingently or otherwise) for the payment of rent thereunder and which were properly treated as indebtedness for borrowed money for purposes of U.S. federal income taxes, if the lessee in respect thereof is obligated to either purchase for an amount in excess of, or pay upon early termination an amount in excess of, 80% of the residual value of the Property subject to such operating lease upon expiration or early termination of such lease.

“ Tangible Net Worth ” means the total assets of the Borrower less the total liabilities and intangible assets of the Borrower and any amounts attributable to promissory notes or other obligations of any employee or Affiliate of the Borrower due or owing to the Borrower, all as determined in accordance with GAAP.

“ Taxes ” means any and all present or future taxes, levies, imposts, duties, deductions, charges or withholdings imposed by any Governmental Authority.

“ Termination Date ” means the earlier to occur of (i) November 28, 2016 or (ii) the date that the Aggregate Maximum Credit Amount is sooner terminated pursuant to Section 2.06 or Section 10.02 .

“ Total Funded Debt ” means, at any date, all Debt of the Borrower and the Consolidated Subsidiaries on a consolidated basis, excluding (a) non-cash obligations under ASC 815, and (b) accounts payable and other accrued liabilities (for the deferred purchase price of Property or services) from time to time incurred in the ordinary course of business which are not greater than sixty ( 60) days past the date of invoice or delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP.

“ Total Capitalization ” means the Total Funded Debt plus Shareholders’ Equity (as determined in accorandance with GAAP).

“ Transactions ” means, with respect to (a) the Borrower, the execution, delivery and performance by the Borrower of this Agreement, and each other Loan Document to which it is a party, the borrowing of Loans, the use of the proceeds thereof and the issuance of Letters of Credit hereunder, and the grant of Liens by the Borrower on Mortgaged Properties and other Properties pursuant to the Security Instruments, and (b) each Guarantor, the execution, delivery and performance by such Guarantor of each Loan Document to which it is a party, the guaranteeing of the Indebtedness and the other obligations under the Guaranty Agreement by such Guarantor and such Guarantor’s grant of the security interests and provision of collateral under the Security Instruments, and the grant of Liens by such Guarantor on Mortgaged Properties and other Properties pursuant to the Security Instruments.

“ Type ”, when used in reference to any Loan or Borrowing, refers to whether the rate of interest on such Loan, or on the Loans comprising such Borrowing, is determined by reference to the Alternate Base Rate, the Adjusted LIBO Rate based upon a 30-day Interest Period, the Adjusted LIBO Rate based upon a 60-day Interest Period or the Adjusted LIBO Rate based upon a 90-day Interest Period.

“ Unwinds ” has the meaning assigned such term in Section 2.07(f)(i) .

Section 1.02 Types of Loans and Borrowings . For purposes of this Agreement, Loans and Borrowings, respectively, may be classified and referred to by Type ( e.g. , a “ Eurodollar Loan ” or a “ Eurodollar Borrowing ”).

Section 1.03 Terms Generally; Rules of Construction . The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “ include ”, “ includes ” and “ including ” as used in this Agreement shall be deemed to be followed by the phrase “ without limitation ”. The word “ will ” shall be construed to have the same meaning and effect as the word “ shall ”. Unless the context requires otherwise (a) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments, supplements or modifications set forth in the Loan Documents), (b) any reference herein to any law shall be construed as referring to such law as amended, modified, codified or reenacted, in whole or in part, and in effect from time to time, (c) any reference herein to any Person shall be construed to include such Person’s successors and assigns (subject to the restrictions contained in the Loan Documents), (d) the words “ herein ”, “ hereof ” and “ hereunder ”, and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof, (e) with respect to the determination of any time period, the word “ from ” means “ from and including ” and the word “ to ” means “ to and including ” and (f) any reference herein to Articles, Sections, Annexes, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Annexes, Exhibits and Schedules to, this Agreement. No provision of this Agreement or any other Loan Document shall be interpreted or construed against any Person solely because such Person or its legal representative drafted such provision.

Section 1.04 Accounting Terms and Determinations; GAAP . Unless otherwise specified herein, all accounting terms used herein shall be interpreted, all determinations with respect to accounting matters hereunder shall be made, and all financial statements and certificates and reports as to financial matters required to be furnished to the Administrative Agent or the Lenders hereunder shall be prepared, in accordance with GAAP, applied on a basis consistent with the Financial Statements except for changes in which the Borrower’s independent certified public accountants concur and which are disclosed to the Administrative Agent on the next date on which financial statements are required to be delivered to the Lenders pursuant to Section 8.01(a) ; provided that, unless the Borrower and the Lenders shall otherwise agree in writing, no such change shall modify or affect the manner in which compliance with the covenants contained herein is computed such that all such computations shall be conducted utilizing financial information presented consistently with prior periods.

ARTICLE II
The Credits

Section 2.01 Commitments . Subject to the terms and conditions set forth herein, each Lender agrees to make Loans to the Borrower during the Availability Period in an aggregate principal amount that will not result in (a) such Lender’s Revolving Credit Exposure exceeding such Lender’s Commitment or (b) the total Revolving Credit Exposures exceeding the total Commitments. Within the foregoing limits and subject to the terms and conditions set forth herein, the Borrower may borrow, repay and reborrow the Loans.

Section 2.02 Loans and Borrowings .

(a) Borrowings; Several Obligations . Each Loan shall be made as part of a Borrowing consisting of Loans made by the Lenders ratably in accordance with their respective Commitments. The failure of any Lender to make any Loan required to be made by it shall not relieve any other Lender of its obligations hereunder; provided that the Commitments are several and no Lender shall be responsible for any other Lender’s failure to make Loans as required.

(b) Types of Loans . Subject to Section 3.03 , each Borrowing shall be comprised entirely of ABR Loans or Eurodollar Loans as the Borrower may request in accordance herewith. Each Lender at its option may make any Eurodollar Loan by causing any domestic or foreign branch or Affiliate of such Lender to make such Loan; provided that any exercise of such option shall not affect any other obligation of such Lender or the obligation of the Borrower to repay such Loan in accordance with the terms of this Agreement.

(c) Minimum Amounts; Limitation on Number of Borrowings . At the commencement of each Interest Period for any Eurodollar Borrowing, such Borrowing shall be in an aggregate amount that is an integral multiple of $100,000 and not less than $1,000,000. At the time that each ABR Borrowing is made, such Borrowing shall be in an aggregate amount that is an integral multiple of $100,000 and not less than $1,000,000; provided that an ABR Borrowing may be in an aggregate amount that is equal to the entire unused balance of the total Commitments or that is required to finance the reimbursement of an LC Disbursement as contemplated by Section 2.08(e) . Borrowings of more than one Type may be outstanding at the same time, provided that there shall not at any time be more than a total of three ( 3) Types of Borrowings outstanding. Notwithstanding any other provision of this Agreement, the Borrower shall not be entitled to request, or to elect to convert or continue, any Borrowing if the Interest Period requested with respect thereto would end after the Termination Date.

(d) Notes . The Loans made by each Lender shall be evidenced by a single promissory note of the Borrower to such Lender in substantially the form of Exhibit A , dated, in the case of (i) any Lender party hereto as of the date of this Agreement, as of the date of this Agreement or (ii) any Lender that becomes a party hereto pursuant to an Assignment and Assumption, as of the effective date of the Assignment and Assumption, payable to such Lender or its registered assigns in a principal amount equal to its Maximum Credit Amount as in effect on such date, and otherwise duly completed. In the event that any Lender’s Maximum Credit Amount decreases for any reason (whether pursuant to Section 2.06 , Section 12.04 or otherwise), the Borrower shall deliver or cause to be delivered on the effective date of such decrease, a new Note payable to such Lender, in replacement of the Note then outstanding, in a principal amount equal to its Maximum Credit Amount after giving effect to such decrease, and otherwise duly completed. The date, amount, Type, interest rate and, if applicable, Interest Period of each Loan made by each Lender, and all payments made on account of the principal thereof, shall be recorded by such Lender on its books for its Note. Failure to make any such notation shall not affect any Lender’s or the Borrower’s rights or obligations in respect of such Loans. Upon assignment of any Note in accordance with the terms in this Agreement and surrender of such Note at the principal office of Administrative Agent for registration of transfer or exchange (and in the case of a surrender for registration of transfer, duly endorsed or accompanied by a written instrument of transfer duly executed by the registered holder or its attorney duly authorized in writing and accompanied by the address for notices of each transferee of such Note or part thereof), and an assignment agreement in form and substance acceptable to Administrative Agent whereby the assignee holder agrees to be bound by the terms hereof that are applicable to holders, the Borrower shall execute and deliver, at Borrower’s expense, a new Note in exchange therefor.

Section 2.03 Requests for Borrowings . To request a Borrowing, the Borrower shall notify the Administrative Agent of such request by telephone (a) in the case of a Eurodollar Borrowing, not later than 11:00 a.m., Denver time, three (3) Business Days before the date of the proposed Borrowing or (b) in the case of an ABR Borrowing, not later than 11:00 a.m., Denver time, one (1) Business Day before the date of the proposed Borrowing; provided that no such notice shall be required for any deemed request of an ABR Borrowing to finance the reimbursement of an LC Disbursement as provided in Section 2.08(e) . Each such telephonic Borrowing Request shall be irrevocable and shall be confirmed promptly by hand delivery or facsimile transmission or, to the extent provided in Section 12.01(c) , electronic communication to the Administrative Agent of a written Borrowing Request in substantially the form of Exhibit B and signed by the Borrower. Each such telephonic and written Borrowing Request shall specify the following information:

(i)	the aggregate amount of the requested Borrowing;

(ii)	the date of such Borrowing, which shall be a Business Day;

(iii)

whether such Borrowing is to be an ABR Borrowing or a Eurodollar Borrowing;

(iv)	in the case of a Eurodollar Borrowing, the initial Interest Period to be applicable thereto, which shall be a period contemplated by the definition of the term “Interest Period” and which shall not extend beyond the Termination Date;

(v)

the amount of the then effective Borrowing Base (or Aggregate Maximum Credit Amounts, if such amount is less than the then effective Borrowing Base), the current total Revolving Credit Exposures (without regard to the requested Borrowing) and the pro forma total Revolving Credit Exposures (giving effect to the requested Borrowing); and

(vi)	the location and number of the Borrower’s account to which funds are to be disbursed, which shall comply with the requirements of Section 2.05 .

If no election as to the Type of Borrowing is specified, then the requested Borrowing shall be an ABR Borrowing. If no Interest Period is specified with respect to any requested Eurodollar Borrowing, then the Borrower shall be deemed to have selected an Interest Period of thirty day’s duration. Each Borrowing Request shall constitute a representation that no Borrowing Base Deficiency exists and that the amount of the requested Borrowing shall not cause the total Revolving Credit Exposures to exceed the total Commitments (i.e., the lesser of the Aggregate Maximum Credit Amounts and the then effective Borrowing Base).

Promptly following receipt of a Borrowing Request in accordance with this Section 2.03 , the Administrative Agent shall advise each Lender of the details thereof and of the amount of such Lender’s Loan to be made as part of the requested Borrowing.

Section 2.04 Interest Elections; Conversions .

(a) Conversion and Continuance . Each Borrowing initially shall be of the Type specified in the applicable Borrowing Request and, in the case of a Eurodollar Borrowing, shall have an initial Interest Period as specified in such Borrowing Request. Thereafter, the Borrower may elect to convert such Borrowing to a different Type or to continue such Borrowing and, in the case of a Eurodollar Borrowing, may elect Interest Periods therefor, all as provided in this Section 2.04 ; provided, however, that in the case of any Eurodollar Borrowing, unless the Borrower timely delivers a conversion request in accordance with Section 2.04(b) , such Eurodollar Borrowing shall automatically be continued at the expiration of the relevant Interest Period for a new Eurodollar Borrowing of the same Type. The Borrower may elect different options with respect to different portions of the affected Borrowing, in which case each such portion shall be allocated ratably among the Lenders holding the Loans comprising such Borrowing, and the Loans comprising each such portion shall be considered a separate Borrowing; provided that, each such portion of the affected Borrowing shall be in an aggregate amount that is an integral multiple of $100,000 and not less than $1,000,000, and provided further that at no time shall there be more than three (3) Types of Loans outstanding.

(b) Interest Election Requests; Conversion Requests . To make an election or conversion, as the case may be, pursuant to this Section 2.04, the Borrower shall notify the Administrative Agent of such election by telephone by the time that a Borrowing Request would be required under Section 2.03 if the Borrower was requesting a Borrowing of the Type resulting from such election to be made on the effective date of such election. Each such telephonic Interest Election Request shall be irrevocable and shall be confirmed promptly by hand delivery or facsimile transmission or, to the extent provided in Section 12.01(c) , electronic communication to the Administrative Agent of a written Interest Election Request in substantially the form of Exhibit C and signed by the Borrower.

(c) Information in Interest Election Requests . Each telephonic and written Interest Election Request shall specify the following information in compliance with Section 2.02 :

(i) the Borrowing to which such Interest Election Request applies and, if different options are being elected with respect to different portions thereof, the portions thereof to be allocated to each resulting Borrowing (in which case the information to be specified pursuant to Section 2.04(c)(iii) and (iv) shall be specified for each resulting Borrowing);

(ii) the effective date of the election made pursuant to such Interest Election Request, whch shall be a Business Day;

(iii) whether the resulting Borrowing is to be an ABR Borrowing or a Eurodollar Borrowing; and

(iv) if the resulting Borrowing is a Eurodollar Borrowing, the Interest Period to be applicable thereto after giving effect to such election, which shall be a period contemplated by the definition of the term “Interest Period” and which shall not extend beyond the Termination Date.

If any such Interest Election Request requests a Eurodollar Borrowing but does not specify an Interest Period, then the Borrower shall be deemed to have selected an Interest Period of thirty day’s duration.

(d) Notice to Lenders by the Administrative Agent . Promptly following receipt of an Interest Election Request, the Administrative Agent shall advise each Lender of the details thereof and of such Lender’s portion of each resulting Borrowing.

(e) Effect of Failure to Deliver Timely Interest Election Request and Events of Default on Interest Election . If the Borrower fails to deliver a timely Interest Election Request with respect to a Eurodollar Borrowing prior to the end of the Interest Period applicable thereto, then, unless such Borrowing is repaid as provided herein, at the end of such Interest Period such Borrowing shall be converted to an ABR Borrowing. Notwithstanding any contrary provision hereof, if an Event of Default has occurred and is continuing: (i) no outstanding Borrowing may be converted to or continued as a Eurodollar Borrowing (and any Interest Election Request that requests the conversion of any Borrowing to, or continuation of any Borrowing as, a Eurodollar Borrowing shall be ineffective) and (ii) unless repaid, each Eurodollar Borrowing shall be converted to an ABR Borrowing at the end of the Interest Period applicable thereto.

Section 2.05 Funding of Borrowings .

(a) Funding by Lenders . Each Lender shall make each Loan to be made by it hereunder on the funding date in the Borrowing Request by wire transfer of immediately available funds by 12:00 noon, Denver time, to the account of the Administrative Agent most recently designated by it for such purpose by notice to the Lenders. The Administrative Agent will make such Loans available to the Borrower by promptly crediting the amounts so received, in like funds, to an account of the Borrower and designated by the Borrower in the applicable Borrowing Request; provided that ABR Loans made to finance the reimbursement of an LC Disbursement as provided in Section 2.08(e) shall be remitted by the Administrative Agent to the Issuing Bank. Nothing herein shall be deemed to obligate any Lender to obtain the funds for its Loan in any particular place or manner or to constitute a representation by any Lender that it has obtained or will obtain the funds for its Loan in any particular place or manner.

(b) Presumption of Funding by the Lenders . Unless the Administrative Agent shall have received notice from a Lender prior to the proposed date of any Borrowing that such Lender will not make available to the Administrative Agent such Lender’s share of such Borrowing, the Administrative Agent may assume that such Lender has made such share available on such date in accordance with Section 2.05(a) and may, in reliance upon such assumption, make available to the Borrower a corresponding amount. In such event, if a Lender has not in fact made its share of the applicable Borrowing available to the Administrative Agent, then the applicable Lender and the Borrower severally agree to pay to the Administrative Agent forthwith on demand such corresponding amount with interest thereon, for each day from and including the date such amount is made available to the Borrower to but excluding the date of payment to the Administrative Agent, at (i) in the case of such Lender, the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation or (ii) in the case of the Borrower, the interest rate applicable to ABR Loans. If such Lender pays such amount to the Administrative Agent, then such amount shall constitute such Lender’s Loan included in such Borrowing.

Section 2.06 Termination, Reduction and Increase of Aggregate Maximum Credit Amounts .

(a) Scheduled Termination of Commitments . Unless previously terminated, the Commitments shall terminate on the Termination Date. If at any time the Aggregate Maximum Credit Amounts are terminated or reduced to zero by the Borrower in accordance with the provisions of this Agreement, or the Borrowing Base is reduced to zero by the Lenders in accordance with the provisions of this Agreement, then the Commitments shall terminate on the effective date of such termination or reduction.

(b) Optional Termination by the Borrower .

(i) The Borrower may at any time terminate and reduce to zero the Aggregate Maximum Credit Amounts if (1) after giving effect to any concurrent prepayment of the Loans in accordance with Section 3.04(a), there is no outstanding balance on the Loans, and (ii) the LC Exposure at such time is zero.

(ii) The Borrower shall notify the Administrative Agent of any election to terminate the Aggregate Maximum Credit Amounts under Section 2.06(b)(i) at least three (3) Business Days prior to the effective date of such termination, specifying such election and the effective date thereof. Promptly following receipt of any notice, the Administrative Agent shall advise the Lenders of the contents thereof. Each notice delivered by the Borrower pursuant to this Section 2.06(b)(ii) shall be irrevocable. Any termination of the Aggregate Maximum Credit Amounts shall be permanent and may not be reinstated.

(i) Increase in Aggregate Maximum Credit Amount . In connection with any Scheduled Redetermination, the Borrower shall have the right (in consultation with, and with the consent of, the Administrative Agent) to cause an increase in the Aggregate Maximum Credit Amount by adding to this Agreement one or more additional Eligible Lenders to become Lenders pursuant to a joinder agreement in form and substance reasonably satisfactory to the Administrative Agent and its counsel and/or by allowing one or more Lenders to increase their respective Commitments, provided , however, (i) no Default shall exist, (ii) no such increase shall result in the Aggregate Maximum Credit Amount exceeding $150,000,000, (iii) no such increase shall be in an amount less than $5,000,000, and (iv) no Lender’s Commitment shall be increased without the consent of such Lender.

(ii) Procedures for Increases . If the Aggregate Maximum Credit Amount is increased in accordance with Section 2.06(c)(i), the Administrative Agent and the Borrower shall determine the effective date (the “ Increase Effective Date ”) and the final allocation of such increase. The Administrative Agent shall promptly notify the Borrower and the Lenders of the final allocation of such increase and the Increase Effective Date. The Borrower shall pay any Loans outstanding on the Increase Effective Date (and pay any additional amounts required pursuant to Section 5.02 ), or the Lenders will assign their interests in the Loans among themselves, to the extent necessary to keep the outstanding Loans ratable with any revised Applicable Percentages arising from any nonratable increase in the Commitments under this section.

(iii) Conditions Precedent . Any increase in the Aggregate Maximum Credit Amount under this Section 2.06(c) shall become effective upon the later of the Increase Effective Date and receipt by the Administrative Agent of:

(A) An amendment to this Agreement, duly signed by the Borrower, the Administrative Agent and all Lenders, modifying Annex I , setting forth any other agreements of the Borrower, the Administrative Agent and the Lenders with respect to pricing affecting such increase, and setting forth the agreement of each Eligible Lender to become a party to this Agreement and to be bound by all the terms and provisions hereof;

(B) Amendments to any other Loan Documents reasonably requested by the Administrative Agent in relation to such increase, which amendments the Administrative Agent is hereby authorized to execute and deliver on behalf of the Lenders;

(D) Evidence of appropriate corporate authorization on the part of the Borrower with respect to such increase and the execution and delivery of the documents described in this Section 2.06(c)(iii);

(E) A Responsible Officer certifies to the Administrative Agent and the Lenders (including each Eligible Lender) that (x) the representations and warranties of the Borrower set forth in the Agreement and in the other Loan Documents are true and correct in all material respects, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, on and as of the Increase Effective Date, such representations and warranties shall continue to be true and correct in all material respects as of such specified earlier date; and (y) no Default exists;

(F) Such opinions of counsel for the Borrower and other assurances as the Administrative Agent may reasonably request; and

(G) Reimbursement of the Administrative Agent’s out-of-pocket costs and expenses (including reasonable attorney’s fees) incurred in connection therewith.

Section 2.07 Borrowing Base .

(a) Initial Borrowing Base . For the period from and including the Effective Date to but excluding the first Redetermination Date, the amount of the Borrowing Base shall be $47,000,000. Notwithstanding the foregoing, the Borrowing Base may be subject to further adjustments from time to time pursuant to Section 2.07(f) , Section 8.13(c) or Section 9.11 .

(b) Scheduled and Interim Redeterminations . The Borrowing Base shall be redetermined semi‑annually in accordance with this Section 2.07 (a “ Scheduled Redetermination ”). In addition, ( y ) each of the Borrower and Required Lenders shall have the right to request one additional Borrowing Base determination in each period between scheduled Borrowing Base determinations, and ( z ) the Required Lenders shall have the right to request an additional Borrowing Base determination to the extent contemplated by Section 9.11 (each, an “ Interim Redetermination ”) in accordance with this Section 2.07 . It is expressly agreed that:

(i) No Lenders shall have any obligation to agree upon or designate the Borrowing Base at any particular amount;

(ii) No Lenders shall have any obligation to increase the Commitment concurrent with any increase in the Borrowing Base; and

(iii) The Borrowing Base shall be calculated by each Lender in accordance with its usual and customary oil and gas lending practices without regard to the current Borrowing Base or such Lender’s Commitment; and

(iv) Increases in the Borrowing Base may require the addition of one or more Lenders.

(i) Each Scheduled Redetermination shall be effectuated as follows:

(A) Commencing on or about May 15, 2013, and on or about each November 15 and May 15 thereafter, if the Administrative Agent has received (1) the Reserve Report and the certificate required to be delivered by the Borrower to the Administrative Agent pursuant to Section 8.12(a) and (c) , and (2) such other reports, data and supplemental information, including the information provided pursuant to Section 8.12(b), as may, from time to time, be reasonably requested by the Administrative Agent (the Reserve Report, such certificate and such other reports, data and supplemental information being the “ Engineering Reports ”), the Administrative Agent and the Lenders shall evaluate the information contained in the Engineering Reports and shall, upon the consent of all Lenders for an increase in the Borrowing Base or the consent of all Required Lenders for a reduction or reaffirmation of the Borrowing Base, propose a new Borrowing Base (the “ Proposed Borrowing Base ”) based upon such information and such other information (including the status of title information with respect to the Oil and Gas Properties as described in the Engineering Reports and the existence of any other Debt, the internal credit evaluation and other financial information) and factors (including each Lender’s usual and customary oil and gas lending practices) as each Lender deems appropriate in its sole discretion.

(ii) Each Interim Redetermination shall be effectuated as follows:

(A) Upon receipt by the Administrative Agent of (1) the Reserve Report and the certificate required to be delivered by the Borrower to the Administrative Agent, pursuant to Section 8.12(b), (2) such other reports, data and supplemental information, including the information provided pursuant to Section 8.12(b), as may, from time to time, be reasonably requested by the Administrative Agent and (3) in the case of an Interim Determination requested by the Borrower, a redetermination fee pursuant to Section 3.05(c)(ii ), the Administrative Agent shall evaluate the information contained in the Engineering Reports and shall, upon the consent of all Lenders for an increase in the Borrowing Base or the consent of all Required Lenders for a reduction or reaffirmation of the Borrowing Base, propose a new Borrowing Base based upon such information and such other information (including the status of title information with respect to the Oil and Gas Properties as described in the Engineering Reports and the existence of any other Debt, the internal credit evaluation and other financial information) and factors (including each Lender’s usual and customary oil and gas lending practices) as each Lender deems appropriate in its sole discretion.

(iii) The Administrative Agent shall notify the Borrower of the Proposed Borrowing Base (the “ Proposed Borrowing Base Notice ”):

(A) in the case of a Scheduled Redetermination or an Interim Redetermination initiated by the Borrower, within thirty (30) days after the Administrative Agent has received the required Engineering Reports; and

(B) in the case of an Interim Redetermination initiated by the Administrative Agent, promptly, and in any event within five (5) days, after the Lenders have determined the Proposed Borrowing Base.

(d) Notice of Reduction of Commitment . After the receipt of the Proposed Borrowing Base Notice, the Borrower may reduce the aggregate Commitment of the Lenders (the “ Reduced Commitment ”), provided that (1) the reduction shall be in an amount that is an integral multiple of $1,000,000 and not less than $1,000,000, (2) the Revolving Credit Exposures do not exceed the Reduced Commitment. To effectuate a Reduced Commitment, within three (3) Business Days after the Administrative Agent has sent out the Proposed Borrowing Base Notice, the Borrower must submit a written notice to the Administrative Agent of its election to reduce the Commitment (the “ Commitment Reduction Notice ”) within 5 Business Days of the receipt of such Proposed Borrowing Base Notice. Each Commitment Reduction Notice shall be irrevocable. Each reduction of the aggregate Commitment amounts shall be made ratably among the Lenders in accordance with each Lender’s Applicable Percentage. Notwithstanding any Commitment Reduction Notice, all relevant determinations under this Agreement based upon the Borrowing Base shall use the Borrowing Base as set forth in the Proposed Borrowing Base Notice until the next Scheduled Redetermination or Interim Redetermination. If the Borrower desires to reinstate any Commitment reduction set forth in a Commitment Reduction Notice, the Borrower may do so only (i) with the written consent of all Lenders, and (ii) after paying to each Lender (A) any fees that would have accrued to such Lender under Section 3.05 had such reduced Commitment not occurred, and (B) a processing fee of $2,500.

(e) Effectiveness of a Redetermined Borrowing Base . After a redetermined Borrowing Base is established pursuant to Section 2.07(c) , or adjusted pursuant to Section 2.07(f) , Section 8.13(c) or Section 9.11 ( d) , the Administrative Agent shall notify the Borrower and the Lenders of the amount of the redetermined or adjusted Borrowing Base (the “ New Borrowing Base Notice ”). Any increase in the Borrowing Base from a Scheduled Redetermination or an Interim Redetermination shall require approval of all Lenders. Any decrease or reaffirmation of the Borrowing Base by a Scheduled Redetermination or an Interim Redetermination shall require approval of the Required Lenders. Once approval has been obtained by the relevant parties, such amount shall become the new Borrowing Base, effective and applicable to the Borrower, the Administrative Agent, any Issuing Bank and the Lenders in the case of a Scheduled or Interim Redetermination, upon the earliest of three (3) Business Days following such notice or the Administrative Agent’s receipt of the Commitment Reduction Notice (the “ Redetermination Date ”).

(f) Borrowing Base Reduction Events .

(i) If the Borrower or any Subsidiary novates, sells, assigns, unwinds, terminates, restructures, modifies, amends or otherwise affects (“ Unwinds ”) any Borrowing Base Hedging Agreement, the Borrowing Base then in effect shall automatically be reduced by an amount equal to the mark-to-market value (as determined by the Administrative Agent) of such Borrowing Base Hedging Agreement as of the date of such Unwind, if any, resulting from such event (which right shall be in addition to the Administrative Agent’s right to request Interim Redetermination between each Scheduled Redetermination).

(ii) If the Borrower or any Subsidiary sells any of the Oil and Gas Properties during any period between two successive Scheduled Redetermination Dates having a fair market value in excess of 2.5% of the then effective Borrowing Base, individually or in the aggregate, the Borrowing Base then in effect shall automatically be reduced by an amount equal to the value, if any, assigned such Property in the most recently delivered Reserve Report (which reduction shall be in addition to the Administrative Agent’s right to request an Interim Redetermination between each Scheduled Redetermination).

Such amount shall then become the Borrowing Base until the next Scheduled Redetermination Date, the next Interim Redetermination Date or the next adjustment to the Borrowing Base under Section 2.07(f) , Section 8.13(c) or Section 9.11 , whichever occurs first.

Section 2.08 Letters of Credit .

(a) General . Subject to the terms and conditions set forth herein, the Borrower may request the issuance of dollar denominated Letters of Credit for its own account or for the account of any of its Subsidiaries, in a form reasonably acceptable to the Administrative Agent and the Issuing Bank, at any time and from time to time during the Availability Period; provided that (1) the Borrower may not request the issuance, amendment, renewal or extension of Letters of Credit hereunder if a Borrowing Base Deficiency exists at such time or would exist as a result thereof and (2) the aggregate LC Exposure of the Letters of Credit issued hereunder and the requested Letter of Credit shall not exceed the LC Commitment. In the event of any inconsistency between the terms and conditions of this Agreement and the terms and conditions of any form of letter of credit application or other agreement submitted by the Borrower to, or entered into by the Borrower with, the Issuing Bank relating to any Letter of Credit, the terms and conditions of this Agreement shall control.

(b) Notice of Issuance, Amendment, Renewal, Extension; Certain Conditions . To request the issuance of a Letter of Credit (or the amendment, renewal or extension of an outstanding Letter of Credit), the Borrower shall deliver by hand delivery or facsimile transmission (or, to the extent provided in Section 12.01(c), electronic communication) to the Issuing Bank and the Administrative Agent (not less than seven (7) Business Days in advance of the requested date of issuance, amendment, renewal or extension) a notice:

(i) requesting the issuance of a Letter of Credit or identifying the Letter of Credit to be amended, renewed or extended;

(ii) specifying the date of issuance, amendment, renewal or extension (which shall be a Business Day);

(iii) specifying the date on which such Letter of Credit is to expire (which shall comply with Section 2.08(c));

(iv) specifying the amount of such Letter of Credit;

(v) specifying the name and address of the beneficiary thereof and such other information as shall be necessary to prepare, amend, renew or extend such Letter of Credit; and

(vi) specifying the amount of the then effective Borrowing Base and whether a Borrowing Base Deficiency exists at such time, the current total Revolving Credit Exposures (without regard to the requested Letter of Credit or the requested amendment, renewal or extension of an outstanding Letter of Credit) and the pro forma total Revolving Credit Exposures (giving effect to the requested Letter of Credit or the requested amendment, renewal or extension of an outstanding Letter of Credit).

Each notice shall constitute a representation that after giving effect to the requested issuance, amendment, renewal or extension, as applicable, (i) the LC Exposure shall not exceed the LC Commitment and (ii) the total Revolving Credit Exposures shall not exceed the total Commitments (i.e., the lesser of the Aggregate Maximum Credit Amounts and the then effective Borrowing Base).

If requested by the Issuing Bank, the Borrower also shall submit a letter of credit application on the Issuing Bank’s standard form in connection with any request for a Letter of Credit.

Subject to the terms and conditions contained herein, the Issuing Bank shall then issue the requested Letter of Credit on the Borrower’s behalf.

(c) Expiration Date . Each Letter of Credit shall expire at or prior to the close of business on the earlier of (i) the date one year after the date of the issuance of such Letter of Credit (or, in the case of any renewal or extension thereof, one year after such renewal or extension) and (ii) the date that is five (5) Business Days prior to the Termination Date.

(d) Participations . By the issuance of a Letter of Credit (or an amendment to a Letter of Credit increasing the amount thereof) and without any further action on the part of the Issuing Bank or the Lenders, the Issuing Bank hereby grants to each Lender, and each Lender hereby acquires from the Issuing Bank, a participation in such Letter of Credit equal to such Lender’s Applicable Percentage of the aggregate amount available to be drawn under such Letter of Credit. In consideration and in furtherance of the foregoing, each Lender hereby absolutely and unconditionally agrees to pay to the Administrative Agent, for the account of the Issuing Bank, such Lender’s Applicable Percentage of each LC Disbursement made by the Issuing Bank and not reimbursed by the Borrower on the date due as provided in Section 2.08(e), or of any reimbursement payment required to be refunded to the Borrower for any reason. Each Lender acknowledges and agrees that its obligation to acquire participations pursuant to this Section 2.08(d) in respect of Letters of Credit is absolute and unconditional and shall not be affected by any circumstance whatsoever, including any amendment, renewal or extension of any Letter of Credit or the occurrence and continuance of a Default, the existence of a Borrowing Base Deficiency or reduction or termination of the Commitments, and that each such payment shall be made without any offset, abatement, withholding or reduction whatsoever.

(e) Reimbursement . If any Issuing Bank shall make any LC Disbursement in respect of a Letter of Credit, the Borrower shall reimburse the Administrative Agent (for itself or any of its Affiliates) such LC Disbursement by paying to the Administrative Agent an amount equal to such LC Disbursement not later than 11:00 a.m., Denver time, on the date that such LC Disbursement is made, if the Borrower shall have received notice of such LC Disbursement prior to 9:00 a.m., Denver time, on such date, or, if such notice has not been received by the Borrower prior to such time on such date, then not later than 11:00 a.m., Denver time, on the Business Day immediately following the day that the Borrower receives such notice; provided that any such LC Disbursement shall, subject to the conditions to Borrowing set forth herein, be deemed to have requested, and the Borrower does hereby request under such circumstances, that such payment be financed with an ABR Borrowing in an equivalent amount and, to the extent so financed, the Borrower’s obligation to make such payment shall be discharged and replaced by the resulting ABR Borrowing. If the Borrower fails to make such payment when due, the Administrative Agent shall notify each Lender of the applicable LC Disbursement, the payment then due from the Borrower in respect thereof and such Lender’s Applicable Percentage thereof. Promptly following receipt of such notice, each Lender shall pay to the Administrative Agent its Applicable Percentage of the payment then due from the Borrower, in the same manner as provided in Section 2.05 with respect to Loans made by such Lender (and Section 2.05 shall apply, mutatis mutandis , to the payment obligations of the Lenders), and the Administrative Agent shall promptly pay to the Issuing Bank the amounts so received by it from the Lenders. Promptly following receipt by the Administrative Agent of any payment from the Borrower pursuant to this Section 2.08(e), the Administrative Agent shall distribute such payment to the Issuing Bank or, to the extent that any Lenders that have made payments pursuant to this Section 2.08(e) to reimburse the Issuing Bank, then to such Lenders and the Issuing Bank as their interests may appear. Any payment made by a Lender pursuant to this Section 2.08(e) to reimburse the Issuing Bank for any LC Disbursement (other than the funding of ABR Loans as contemplated above) shall not constitute a Loan and shall not relieve the Borrower of its obligation to reimburse such LC Disbursement.

(f) Obligations Absolute . The Borrower’s obligation to reimburse LC Disbursements as provided in Section 2.08(e) shall be absolute, unconditional and irrevocable, and shall be performed strictly in accordance with the terms of this Agreement under any and all circumstances whatsoever and irrespective of (i) any lack of validity or enforceability of any Letter of Credit, any Letter of Credit Agreement or this Agreement, or any term or provision therein, (ii) any draft or other document presented under a Letter of Credit proving to be forged, fraudulent or invalid in any respect or any statement therein being untrue or inaccurate in any respect, (iii) payment by any Issuing Bank under a Letter of Credit against presentation of a draft or other document that does not comply with the terms of such Letter of Credit or any Letter of Credit Agreement, or (iv) any other event or circumstance whatsoever, whether or not similar to any of the foregoing, that might, but for the provisions of this Section 2.08(f) , constitute a legal or equitable discharge of, or provide a right of setoff against, the Borrower’s obligations hereunder. Neither the Administrative Agent, the Lenders nor any Issuing Bank, nor any of their Related Parties shall have any liability or responsibility by reason of or in connection with the issuance or transfer of any Letter of Credit or any payment or failure to make any payment thereunder (irrespective of any of the circumstances referred to in the preceding sentence), or any error, omission, interruption, loss or delay in transmission or delivery of any draft, notice or other communication under or relating to any Letter of Credit (including any document required to make a drawing thereunder), any error in interpretation of technical terms or any consequence arising from causes beyond the control of the Issuing Bank or the Administrative Agent. In furtherance of the foregoing and without limiting the generality thereof, the Borrower agrees that, with respect to documents presented which appear on their face to be in substantial compliance with the terms of a Letter of Credit, the Issuing Bank may, in its sole discretion, either accept and make payment upon such documents without responsibility for further investigation, regardless of any notice or information to the contrary, or refuse to accept and make payment upon such documents if such documents are not in strict compliance with the terms of such Letter of Credit.

(g) Disbursement Procedures . The Issuing Bank shall, promptly following its receipt thereof, examine all documents purporting to represent a demand for payment under a Letter of Credit. The Issuing Bank shall promptly notify the Administrative Agent and the Borrower by telephone, facsimile or email of such demand for payment and whether the Issuing Bank has made or will make an LC Disbursement thereunder; provided that any failure to give or delay in giving such notice shall not relieve the Borrower of its obligation to reimburse the Issuing Bank and the Lenders with respect to any such LC Disbursement.

(h) Interim Interest . If the Issuing Bank shall make any LC Disbursement, then, until the Borrower shall have reimbursed the Issuing Bank for such LC Disbursement (either with its own funds or a Borrowing under Section 2.08(e)) , the unpaid amount thereof shall bear interest, for each day from and including the date such LC Disbursement is made to but excluding the date that the Borrower reimburses such LC Disbursement, at the rate per annum then applicable to ABR Loans. Interest accrued pursuant to this Section 2.08(h) shall be for the account of the Issuing Bank, except that interest accrued on and after the date of payment by any Lender pursuant to Section 2.08(e) to reimburse the Issuing Bank shall be for the account of such Lender to the extent of such payment.

(i) Cash Collateralization .

(i) If (A) any Event of Default shall occur and be continuing and the Borrower receives notice from the Administrative Agent demanding that the Borrower Cash Collateralize the outstanding LC Exposure pursuant to this Section 2.08(i) , (B) the Borrower is required to Cash Collateralize the excess attributable to an LC Exposure in connection with any prepayment pursuant to Section 3.04(c) , or (C) the Borrower is required to Cash Collateralize a Defaulting Lender’s LC Exposure pursuant to Section 4.03(c)(iii)(B) , then the Borrower shall Cash Collateralize such LC Exposure or the excess attributable to such LC Exposure, as the case may be, as of such date plus any accrued and unpaid interest thereon; provided that the obligation to Cash Collateralize pursuant to this Section 2.08(i ) shall become effective immediately, and immediately due and payable, without demand or other notice of any kind, upon the occurrence of any Event of Default described in Section 10.01(g) or Section 10.01(h) .

(ii) The Borrower hereby grants to the Administrative Agent, for the benefit of each Issuing Bank and the Lenders, an exclusive first priority and continuing perfected security interest in and Lien on each account (a “ Collateral Account ”) in which the Borrower has Cash Collateralized any obligation hereunder and all cash, checks, drafts, certificates and instruments, if any, from time to time deposited or held in such Collateral Account, all deposits or wire transfers made thereto, any and all investments purchased with funds deposited in such account, all interest, dividends, cash, instruments, financial assets and other Property from time to time received, receivable or otherwise payable in respect of, or in exchange for, any or all of the foregoing, and all proceeds, products, accessions, rents, profits, income and benefits therefrom, and any substitutions and replacements therefor (collectively, the “ Cash Collateral ”).

(iii) The Borrower’s obligation to Cash Collateralize pursuant to this Section 2.08(i) shall be absolute and unconditional, without regard to whether any beneficiary of any Letter of Credit has attempted to draw down all or a portion of such amount under the terms of a Letter of Credit, and, to the fullest extent permitted by applicable law, shall not be subject to any defense or be affected by a right of set‑off, counterclaim or recoupment which the Borrower or any Subsidiary may now or hereafter have against any such beneficiary, any Issuing Bank, the Administrative Agent, the Lenders or any other Person for any reason whatsoever.

(iv) Each Collateral Account and all Cash Collateral shall secure the payment and performance of the Borrower’s obligations under this Agreement and the other Loan Documents. The Administrative Agent shall have exclusive dominion and control, including the exclusive right of withdrawal, over each Collateral Account and the Cash Collateral. Other than any interest earned on the investment of such deposits, which investments shall be made at the option and reasonable sole discretion of the Administrative Agent and at the Borrower’s risk and expense, such deposits shall not bear interest. Interest or profits, if any, on such investments shall accumulate in each Collateral Account. Moneys in such account shall be applied by the Administrative Agent to reimburse each Issuing Bank for LC Disbursements for which it has not been reimbursed and, to the extent not so applied, shall be held for the satisfaction of the reimbursement obligations of the Borrower for the LC Exposure at such time or, if the maturity of the Loans has been accelerated, be applied to satisfy other obligations of the Borrower and the Guarantors under this Agreement or the other Loan Documents. If the Borrower is required to Cash Collateralize hereunder as a result of the occurrence of an Event of Default, and the Borrower is not otherwise required to pay to the Administrative Agent the excess attributable to an LC Exposure in connection with any prepayment pursuant to Section 3.04(c) or Cash Collateralize a Defaulting Lender’s LC Exposure pursuant to Section 4.03(c)(iii)(B) , then such amount (to the extent not applied as aforesaid) shall be returned to the Borrower within one (1) Business Day after written notice by the Borrower to the Administrative Agent that after all Events of Default have been cured or waived and that no Defaults exist.

(j) Confirmation . Upon written request of the Borrower, each Issuing Bank shall provide the Borrower, at the sole cost and expense of the Borrower, with a confirmation of the existence of an outstanding Letter of Credit issued by such Issuing Bank within seven (7) days of such request.

ARTICLE III
Payments of Principal and Interest; Prepayments; Fees

Section 3.01 Repayment of Loans . The Borrower hereby unconditionally promises to pay to the Administrative Agent for the account of each Lender the then unpaid principal amount of each Loan in full in cash on the Termination Date. All payments by the Borrower of principal, interest, fees and other obligations shall be made in dollars in immediately available funds, and shall be absolute and unconditional, without defense, rescission, recoupment, setoff or counterclaim, free of any restriction or condition.

Section 3.02 Interest .

(a) ABR Loans . The Loans comprising each ABR Borrowing shall bear interest at the Alternate Base Rate plus the Applicable Margin, but in no event to exceed the Highest Lawful Rate.

(b) Eurodollar Loans . The Loans comprising each Eurodollar Borrowing shall bear interest at the Adjusted LIBO Rate for the Interest Period in effect for such Borrowing plus the Applicable Margin, but in no event to exceed the Highest Lawful Rate.

(c) Post Default Rate . Notwithstanding the foregoing, if an Event of Default has occurred and is continuing, or if any principal of or interest on any Loan or any fee or other amount payable by the Borrower hereunder or under any other Loan Document is not paid when due, whether at stated maturity, upon acceleration or otherwise, and including any payments in respect of a Borrowing Base Deficiency under Section 3.04(c) then all Loans outstanding, in the case of an Event of Default, and such overdue amount, in the case of a failure to pay amounts when due, shall bear interest, until paid (whether before or after judgment) at the lesser of (i) the Highest Lawful Rate or (ii) the Post Default Rate.

(d) Interest Payment Dates . Accrued interest on each Loan shall be payable in arrears on each Interest Payment Date for such Loan and on the Termination Date; provided that (i) interest accrued pursuant to Section 3.02(c) shall be payable on demand, (ii) in the event of any repayment or prepayment of any Loan (other than an optional prepayment of an ABR Loan prior to the Termination Date), accrued interest on the principal amount repaid or prepaid shall be payable on the date of such repayment or prepayment, and (iii) in the event of any conversion of any Eurodollar Loan prior to the end of the current Interest Period therefor, accrued interest on such Loan shall be payable on the effective date of such conversion.

(e) Interest Rate Computations . All interest hereunder shall be computed on the basis of a year of 360 days (or 365/366 days, in the case of an ABR Loan), unless such computation would exceed the Highest Lawful Rate, in which case interest shall be computed on the basis of a year of 365 days (or 366 days in a leap year), and in each case shall be payable for the actual number of days elapsed (including the first day but excluding the last day). The applicable Alternate Base Rate, Adjusted LIBO Rate or the LIBO Rate shall be determined by the Administrative Agent, and such determination shall be conclusive absent manifest error, and be binding upon the parties hereto.

Section 3.03 lternate Rate of Interest . If prior to the commencement of any Interest Period for a Eurodollar Borrowing:

(a) the Administrative Agent determines (which determination shall be conclusive absent manifest error) that (i) adequate and reasonable means do not exist for ascertaining the Adjusted LIBO Rate or the LIBO Rate for such Interest Period or (ii) deposits (whether in dollars or an alternative currency) are not being offered to Lenders in the applicable offshore interbank market for such currency for the applicable amount and Interest Period of such Eurodollar Borrowing; or

(b) the Administrative Agent is advised by the Lenders that the Adjusted LIBO Rate or LIBO Rate, as applicable, for such Interest Period will not adequately and fairly reflect the cost to such Lenders of making or maintaining their Loans included in such Borrowing for such Interest Period;

then the Administrative Agent shall give notice thereof to the Borrower and the Lenders by telephone or facsimile transmission, or, to the extent provided in Section 12.01(c) , electronic communication, as promptly as practicable thereafter and, until the Administrative Agent notifies the Borrower and the Lenders that the circumstances giving rise to such notice no longer exist, (i) any Interest Election Request that requests the conversion of any Borrowing to, or continuation of any Borrowing as, a Eurodollar Borrowing shall be ineffective, and (ii) if any Borrowing Request requests a Eurodollar Borrowing, such Borrowing shall be made either as an ABR Borrowing or at an alternate rate of interest (not to exceed the Alternate Base Rate) determined by all Lenders, sufficient to cover each Lender’s cost of funds.

Section 3.04 Prepayments .

(a) Optional Prepayments . Subject to any break funding costs payable pursuant to Section 5.02 and prior notice in accordance with Section 3.04(b) , the Borrower shall have the right at any time and from time to time to prepay any Borrowing in whole or in part, in an aggregate amount that is an integral multiple of $100,000 and not less than $1,000,000, or if less than $1,000,000, the remaining balance of the Loans.

(b) Notice and Terms of Optional Prepayment . The Borrower shall notify the Administrative Agent by telephone (confirmed by facsimile transmission, or to the extent provided in Section 12.01(c) , electronic communication) of any prepayment hereunder (i) in the case of prepayment of a Eurodollar Borrowing, not later than 11:00 a.m., Denver time, three (3) Business Days before the date of prepayment, or (ii) in the case of prepayment of an ABR Borrowing, not later than 11:00 a.m., Denver time, one Business Day before the date of prepayment. Each such notice shall be irrevocable and shall specify the prepayment date and the principal amount of each Borrowing or portion thereof to be prepaid. Promptly following receipt of any such notice relating to a Borrowing, the Administrative Agent shall advise the Lenders of the contents thereof. Each prepayment of a Borrowing shall be applied ratably to the Loans included in the prepaid Borrowing. Prepayments shall be accompanied by accrued interest to the extent required by Section 3.02.

(i) Upon any redetermination of or adjustment to the amount of the Borrowing Base in accordance with Section 2.07 or Section 8.13(c) , if the total Revolving Credit Exposures exceeds the redetermined or adjusted Borrowing Base, then the Borrower shall either:

(A) prepay the Borrowings on the schedule set forth below in an aggregate principal amount equal to such excess and if any excess remains as a result of an LC Exposure, after prepaying all of the Borrowings, Cash Collateralize such excess as provided in Section 2.08 (i) ;

(B) pledge additional collateral not included in the most recent Reserve Report to the Administrative Agent having a fair market value (as determined by the Administrative Agent, in its sole discretion) equal to at least the amount of the deficiency or otherwise satisfactory to the Administrative Agent such that the total Revolving Credit Exposures are less than or equal to the Borrowing Base as redetermined or adjusted;

(D) take any combination of the actions outlined in Section 3.04(c)(i) .

The Borrower shall be obligated to make any prepayment pursuant to Section 3.04(c)(i)(A) as follows: (i) twenty percent (20%) of such excess shall be paid within forty-five (45) days following its receipt of the New Borrowing Base Notice in accordance with Section 2.07(e) or the date the adjustment occurs; (ii) forty percent (40%) of such excess shall be paid within sixty (60) days following its receipt of the New Borrowing Base Notice in accordance with Section 2.07(e) or the date the adjustment occurs; (iii) sixty percent (60%) of such excess shall be paid within ninety (90) days following its receipt of the New Borrowing Base Notice in accordance with Section 2.07(e) or the date the adjustment occurs; (iv) eighty percent (80%) of such excess shall be paid within one hundred and twenty (120) days following its receipt of the New Borrowing Base Notice in accordance with Section 2.07(e) or the date the adjustment occurs; (v) and one-hundred percent (100%) of such excess shall be paid within one hundred and fifty (150) days following its receipt of the New Borrowing Base Notice in accordance with Section 2.07(e) or the date the adjustment occurs, provided that all payments required to be made pursuant to this Section 3.04(c)(i) must be made on or prior to the Termination Date.

(ii) Upon any adjustments to the Borrowing Base pursuant to Section 9.11 , if the total Revolving Credit Exposures exceed the Borrowing Base as adjusted, then the Borrower shall (A) prepay the Borrowings in an aggregate principal amount equal to such excess, and (B) if any excess remains after prepaying all of the Borrowings as a result of an LC Exposure, Cash Collateralize such excess as provided in Section 2.08(i) . The Borrower shall be obligated to make such prepayment and/or Cash Collateralize such excess on the date it or any Subsidiary receives proceeds as a result of such disposition; provided that all payments required to be made pursuant to this Section 3.04(c)(ii) must be made on or prior to the Termination Date.

(iii) If a Borrowing Base Deficiency exists, or during the period an Event of Default remains uncured and has not been waived, the Borrower shall pay any Borrowings with (a) all net cash proceeds received from sales and other dispositions of Properties and (b) any proceeds received pursuant to the termination of any Hedging Agreement. In the case of a Borrowing Base Deficiency, this clause (iii) shall only require prepayments of Borrowings until the Borrowing Base Deficiency has been cured.

(iv) Each prepayment of Borrowings pursuant to this Section 3.04(c) shall be applied, first, ratably to any ABR Borrowings then outstanding, and, second, to any Eurodollar Borrowings then outstanding, and if more than one Eurodollar Borrowing is then outstanding, to each such Eurodollar Borrowing in order of priority beginning with the Eurodollar Borrowing with the least number of days remaining in the Interest Period applicable thereto and ending with the Eurodollar Borrowing with the most number of days remaining in the Interest Period applicable thereto.

(v) Each prepayment of Borrowings shall be applied ratably to the Loans of each Lender included in the prepaid Borrowings. Prepayment pursuant to this Section 3.04(c) shall be accompanied by accrued interest to the extent required by Section 3.02.

(d) No Premium or Penalty . Prepayments permitted or required under this Section 3.04 shall be without premium or penalty, except as required under Section 5.02 .

Section 3.05 Fees .

(a) Letter of Credit Fees . The Borrower agrees to pay (i) to the Administrative Agent for the account of each Lender, a participation fee with respect to its participations in Letters of Credit equal to (A) the aggregate LC Exposure of such Lender from time to time, times (B) the Applicable Margin for a LIBO Rate Borrowing, determined on a per annum basis during the period from and including the date of this Agreement to but excluding the later of the date on which such Lender’s Commitment terminates and the date on which such Lender ceases to have any LC Exposure, and (ii) to the Issuing Bank, a fronting fee, of 0.125% per annum of the aggregate undrawn amount of all outstanding Letters of Credit issued by such Issuing Bank. Participation fees and fronting fees accrued through and including the last day of March, June, September and December of each year shall be payable on such last day, commencing on the first such date to occur after the date of this Agreement; provided that all such fees shall be payable on the Termination Date and any such fees accruing after the Termination Date shall be payable on demand. All participation fees and fronting fees shall be computed on the aggregate stated among of each Letter of Credit on the basis of a year of 360 days, unless such computation would exceed the Highest Lawful Rate, in which case interest shall be computed on the basis of a year of 365 days (or 366 days in a leap year), and shall be payable for the actual number of days elapsed (including the first day but excluding the last day).

(b) Commitment Fee . The Borrower agrees to pay to each Lender a commitment fee equal to 0.5% of such Lender’s Commitment on the Effective Date. In addition, the Borrower shall pay an early response fee of (i) $12,500 to CoBiz Bank, a Colorado corporation, dba Colorado Business Bank and (ii) $18,750 to Amegy Bank National Association.

(c) Threshold Commitment Fee . The Borrower agrees to pay to the Administrative Agent for the account of each Lender (i) 0.375% of each increase in the Borrowing Base and the resulting increase in the Commitment of such Lender over such Lender’s Initial Commitment (as adjusted by previous increases in its Commitment and after taking into account any Commitment Reduction Notice); and (ii) in connection with each Interim Redetermination initiated by the Borrower, a redetermination fee of $2,500 per Lender.

(d) Administrative Agent Fees . The Borrower agrees to pay to the Administrative Agent, for its own account, (i) an arrangement fee as set forth in the Fee Letter, which shall be payable upon the closing of this Agreement (the “ Arrangement Fee ”); and (ii) an annual administration or agency fee as set forth in the Fee Letter (the “ Administration Fee ”). The Administration Fee shall be paid on the Effective Date and on each annual anniversary thereof. In the event of any adjustment to the Administration Fee as contemplated by the Engagement Letter, such adjusted amount shall be prorated for the remainder of the period from the date such payment is due through the next annual anniversary of the Effective Date and thereafter shall be included in the amount due and payable on each anniversary of the Effective Date.

(e) Unused Commitment Fee . The Borrower agrees to pay to the Administrative Agent for the account of each Lender an unused commitment fee equal to 0.5% per annum of the average daily amount of the unused Commitment of such Lender during the period from and including the date of this Agreement to but excluding the later of the date of termination of the Commitments. Fees accrued under this Section 3.05(e) through and including the last day of March, June, September and December of each year shall be payable on the third Business Day following such last day, commencing on the first such date to occur after the date of this Agreement; provided that all such fees shall be payable on the Termination Date and any such fees accruing after the Termination Date shall be payable on demand. All unused commitment fees shall be computed on the basis of a year of 360 days, unless such computation would exceed the Highest Lawful Rate, in which case interest shall be computed on the basis of a year of 365 days (or 366 days in a leap year), and shall be payable for the actual number of days elapsed (including the first day but excluding the last day). Such fee shall be disbursed by the Administrative Agent to the Lenders in accordance with their respective Commitments.

ARTICLE IV
Payments; Pro Rata Treatment; Sharing of Set‑offs

Section 4.01 Payments Generally; Pro Rata Treatment; Sharing of Set‑offs .

(a) Payments by the Borrower . The Borrower shall make each payment required to be made by it hereunder (whether of principal, interest, fees or reimbursement of LC Disbursements, or of amounts payable under Section 5.01 , Section 5.02 , Section 5.03 or otherwise) prior to 11:00 a.m., Denver time, on the date when due, in immediately available funds, without defense, deduction, recoupment, set‑off or counterclaim. Fees, once paid, shall be fully earned and shall not be refundable under any circumstances. Any amounts received after such time on any date may, in the discretion of the Administrative Agent, be deemed to have been received on the next succeeding Business Day for purposes of calculating interest thereon. All such payments shall be made to the account of the Administrative Agent most recently designated by it for such purpose, except payments to be made directly to the Issuing Bank as expressly provided herein and except that payments pursuant to Section 5.01 , Section 5.02 , Section 5.03 and Section 12.03 shall be made directly to the Persons entitled thereto. The Administrative Agent shall distribute any such payments received by it for the account of any other Person to the appropriate recipient promptly following receipt thereof. If any payment hereunder shall be due on a day that is not a Business Day, the date for payment shall be extended to the next succeeding Business Day, and, in the case of any payment accruing interest, interest thereon shall be payable for the period of such extension. All payments hereunder shall be made in dollars.

(b) Application of Insufficient Payments . If at any time insufficient funds are received by and available to the Administrative Agent to pay fully all amounts of principal, unreimbursed LC Disbursements, interest and fees then due hereunder, such funds shall be applied (i) first, towards payment of interest and fees then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of interest and fees then due to such parties, and (ii) second, towards payment of principal and unreimbursed LC Disbursements then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of principal and unreimbursed LC Disbursements then due to such parties.

(c) Sharing of Payments by Lenders . If any Lender shall, by exercising any right of set‑off or counterclaim or otherwise, obtain payment in respect of any principal of or interest on any of its Loans or participations in LC Disbursements resulting in such Lender receiving payment of a greater proportion of the aggregate amount of its Loans and participations in LC Disbursements and accrued interest thereon than the proportion received by any other Lender, then the Lender receiving such greater proportion shall purchase (for cash at face value) participations in the Loans and participations in LC Disbursements of other Lenders to the extent necessary so that the benefit of all such payments shall be shared by the Lenders ratably in accordance with the aggregate amount of principal of and accrued interest on their respective Loans and participations in LC Disbursements; provided that (i) if any such participations are purchased and all or any portion of the payment giving rise thereto is recovered, such participations shall be rescinded and the purchase price restored to the extent of such recovery, without interest, and (ii) the provisions of this Section 4.01(c) shall not be construed to apply to any payment made by the Borrower pursuant to and in accordance with the express terms of this Agreement or any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Loans or participations in LC Disbursements to any assignee or participant, other than to the Borrower or any Subsidiary or Affiliate thereof (as to which the provisions of this Section 4.01(c) shall apply). The Borrower consents to the foregoing and agrees, to the extent it may effectively do so under applicable law, that any Lender acquiring a participation pursuant to the foregoing arrangements may exercise against the Borrower rights of set‑off and counterclaim with respect to such participation as fully as if such Lender were a direct creditor of the Borrower in the amount of such participation.

Section 4.02 Presumption of Payment by the Borrower . Unless the Administrative Agent shall have received notice from the Borrower prior to the date on which any payment is due to the Administrative Agent for the account of the Lenders or any Issuing Bank that the Borrower will not make such payment, the Administrative Agent may assume that the Borrower has made such payment on such date in accordance herewith and may, in reliance upon such assumption, distribute to the Lenders or the Issuing Bank, as the case may be, the amount due. In such event, if the Borrower has not in fact made such payment, then each of the Lenders or the Issuing Bank, as the case may be, severally agrees to repay to the Administrative Agent forthwith on demand the amount so distributed to such Lender or Issuing Bank with interest thereon, for each day from and including the date such amount is distributed to it to but excluding the date of payment to the Administrative Agent, at the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation.

Section 4.03 Deductions by the Administrative Agent; Defaulting Lender .

(a) If any Lender shall fail to make any payment required to be made by it pursuant to Section 2.05(b) , Section 2.08(d) , Section 2.08(e) or Section 4.02 , then the Administrative Agent may, in its sole discretion (notwithstanding any contrary provision hereof), apply any amounts thereafter received by the Administrative Agent for the account of such Lender to satisfy such Lender’s obligations under such Sections until all such unsatisfied obligations are fully paid in cash.

(b) Payments to Defaulting Lenders . If a Defaulting Lender (or a Lender who would be a Defaulting Lender but for the expiration of the relevant grace period) as a result of the exercise of a set‑off shall have received a payment in respect of its Revolving Credit Exposure which results in its Revolving Credit Exposure being less than its Applicable Percentage of the aggregate Revolving Credit Exposures, then no payments will be made to such Defaulting Lender until such time as such Defaulting Lender shall have complied with Section 4.03(c) and all amounts due and owing to the Lenders have been equalized in accordance with each Lender’s respective pro rata share of the Indebtedness. Further, if at any time prior to the acceleration or maturity of the Loans, the Administrative Agent shall receive any payment in respect of principal of a Loan or a reimbursement of an LC Disbursement while one or more Defaulting Lenders shall be party to this Agreement, the Administrative Agent shall apply such payment first to the Borrowing(s) for which such Defaulting Lender(s) shall have failed to fund its pro rata share until such time as such Borrowing(s) are paid in full or each Lender (including each Defaulting Lender) is owed its Applicable Percentage of all Loans then outstanding. After acceleration or maturity of the Loans, subject to the first sentence of this Section 4.03(b) , all principal will be paid ratably as provided in Section 10.02(c) .

(c) Defaulting Lenders . Notwithstanding any provision of this Agreement to the contrary, if any Lender becomes a Defaulting Lender, then the following provisions shall apply for so long as such Lender is a Defaulting Lender:

(i) Fees otherwise payable pursuant to Section 3.05 shall cease to accrue on the unfunded portion of the Commitment of such Defaulting Lender.

(ii) The Commitment and Revolving Credit Exposure of such Defaulting Lender shall not be included in determining whether all Lenders have taken or may take any action hereunder (including any consent to any amendment or waiver pursuant to Section 12.02 ), provided that any waiver, amendment or modification (A) that would increase the Commitment or the Maximum Credit Amount of such Defaulting Lender or (B) requiring the consent of all Lenders or each adversely affected Lender which affects such Defaulting Lender differently than all other Lenders or all other adversely affected Lenders, as the case may be, shall require the consent of such Defaulting Lender; and provided further that any redetermination or affirmation of the Borrowing Base shall occur without the participation of a Defaulting Lender, but the Commitment (i.e. the Applicable Percentage of the Borrowing Base of a Defaulting Lender) may not be increased without the consent of such Defaulting Lender.

(iii) If any LC Exposure exists at the time a Lender becomes a Defaulting Lender then:

(A) all or any part of such LC Exposure shall be reallocated among the Non‑Defaulting Lenders in accordance with their respective Applicable Percentages but only to the extent (1) the sum of all Non‑Defaulting Lenders’ Revolving Credit Exposures plus such Defaulting Lender’s LC Exposure does not exceed the total of all Non‑Defaulting Lenders’ Commitments, (2) the conditions set forth in Section 6.02 are satisfied at such time, and (3) the sum of each Non‑Defaulting Lender’s Revolving Credit Exposure plus its reallocated share of such Defaulting Lender’s LC Exposure does not exceed such Non‑Defaulting Lender’s Commitment; provided , that no such reallocation will constitute a waiver or release of any claim the Borrower, the Administrative Agent, any Issuing Bank or any Lender may have against such Defaulting Lender or cause such Defaulting Lender to be a Non‑Defaulting Lender;

(B) if the reallocation described in Section 4.03(c)(iii)(A) cannot, or can only partially, be effected, then the Borrower shall within three Business Days following notice by the Administrative Agent Cash Collateralize such Defaulting Lender’s LC Exposure (after giving effect to any partial reallocation pursuant to Section 4.03(c)(iii)(A) ) for so long as such LC Exposure is outstanding;

(C) if the Borrower Cash Collateralizes any portion of such Defaulting Lender’s LC Exposure pursuant to Section 4.03(c)(iii)(B) ), then the Borrower shall not be required to pay any fees to such Defaulting Lender pursuant to Section 3.05(a) with respect to such Defaulting Lender’s LC Exposure during the period such Defaulting Lender’s LC Exposure is Cash Collateralized;

(D) if the LC Exposure of the Non‑Defaulting Lenders is reallocated pursuant to Section 4.03(c)(iii)(A) , then the fees payable to the Lenders pursuant to Section 3.05(a) shall be adjusted in accordance with such Non‑Defaulting Lenders’ Applicable Percentages; and

(E) if any Defaulting Lender’s LC Exposure is neither Cash Collateralized nor reallocated pursuant to Section 4.03(c)(iii) , then, without prejudice to any rights or remedies of any Issuing Bank or any Lender hereunder, all letter of credit fees payable under Section 3.05(a) with respect to such Defaulting Lender’s LC Exposure shall be payable to each Issuing Bank (in proportion to the undrawn amount of all outstanding Letters of Credit issued by each Issuing Bank) until such LC Exposure is Cash Collateralized and/or reallocated.

(d) In the event that the Administrative Agent, the Borrower and each Issuing Bank each agrees that a Defaulting Lender has adequately remedied all matters that caused such Lender to be a Defaulting Lender, then the LC Exposure of the Lenders shall be readjusted to reflect the inclusion of such Lender’s Commitment and on such date such Lender shall purchase at par such of the Loans of the other Lenders as the Administrative Agent shall determine may be necessary in order for such Lender to hold such Loans in accordance with its Applicable Percentage; provided, that no adjustments will be made retroactively with respect to fees accrued while such Lender was a Defaulting Lender; and provided, further, that except to the extent otherwise expressly agreed by the affected parties, no change hereunder from Defaulting Lender to Non‑Defaulting Lender will constitute a waiver or release of any claim of any party hereunder arising from such Lender having been a Defaulting Lender.

Section 4.04 Disposition of Proceeds . The Security Instruments contain an assignment by the Borrower unto and in favor of the Administrative Agent for the benefit of the Lenders of all of the Borrower’s interest in and to production and all proceeds attributable thereto which may be produced from or allocated to the Borrower’s Property. The Security Instruments further provide in general for the application of such proceeds to the satisfaction of the Indebtedness and other obligations described therein and secured thereby. Notwithstanding the assignment contained in such Security Instruments, until an Event of Default has occurred and is continuing, (a) the Administrative Agent and the Lenders agree that they will neither notify the purchaser or purchasers of such production nor take any other action to cause such proceeds to be remitted to the Administrative Agent or the Lenders, but the Lenders will instead permit such proceeds to be paid to the Borrower and its Subsidiaries and (b) the Lenders hereby authorize the Administrative Agent to take such actions as may be necessary to cause such proceeds to be paid to the Borrower and/or such Subsidiaries.

ARTICLE V
Increased Costs; Break Funding Payments; Taxes; Illegality

Section 5.01 Increased Costs .

(a) Eurodollar Changes in Law . If any Change in Law shall:

(i) impose, modify or deem applicable any reserve, special deposit or similar requirement against assets of, deposits with or for the account of, or credit extended by, any Lender (except any such reserve requirement reflected in the Adjusted LIBO Rate); or

(ii) impose on any Lender or the London interbank market any other condition affecting this Agreement or Eurodollar Loans made by such Lender;

and the result of any of the foregoing shall be to increase the cost to such Lender of making or maintaining any Eurodollar Loan (or of maintaining its obligation to make any such Loan) or to reduce the amount of any sum received or receivable by such Lender (whether of principal, interest or otherwise), then the Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender for such additional costs incurred or reduction suffered.

(b) Capital Requirements . If any Change in Law regarding capital requirements has the effect of reducing the rate of return on a Lender’s or Issuing Bank’s capital or on the capital of such Lender’s or Issuing Bank’s holding company, if any, as a consequence of this Agreement or the Loans made by, or participations in Letters of Credit held by, such Lender, or the Letters of Credit issued by any Issuing Bank, to a level below that which such Lender or Issuing Bank or such Lender’s or Issuing Bank’s holding company could have achieved but for such Change in Law (taking into consideration such Lender’s or Issuing Bank’s policies and the policies of such Lender’s or Issuing Bank’s holding company with respect to capital adequacy), then from time to time the Borrower will pay to such Lender or Issuing Bank, as the case may be, such additional amount or amounts as will compensate such Lender or Issuing Bank or such Lender’s or Issuing Bank’s holding company for any such reduction suffered.

(c) Certificates . A certificate of a Lender or an Issuing Bank setting forth the amount or amounts necessary to compensate such Lender or Issuing Bank or its holding company, as the case may be, as specified in Section 5.01(a) or (b) shall be delivered to the Borrower and shall be conclusive absent manifest error. The Borrower shall pay such Lender or Issuing Bank, as the case may be, the amount shown as due on any such certificate within ten (10) days after receipt thereof.

(d) Effect of Failure or Delay in Requesting Compensation . Failure or delay on the part of any Lender or any Issuing Bank to demand compensation pursuant to this Section 5.01 shall not constitute a waiver of such Lender’s or Issuing Bank’s right to demand such compensation; provided that the Borrower shall not be required to compensate a Lender or an Issuing Bank pursuant to this Section 5.01 for any increased costs or reductions incurred more than 180 days prior to the date that such Lender or Issuing Bank, as the case may be, notifies the Borrower of the Change in Law giving rise to such increased costs or reductions and of such Lender’s or Issuing Bank’s intention to claim compensation therefor; provided further that, if the Change in Law giving rise to such increased costs or reductions is retroactive, then the 180‑day period referred to above shall be extended to include the period of retroactive effect thereof.

Section 5.02 Break Funding Payments . In the event of (a) the payment of any principal of any Eurodollar Loan other than on the last day of an Interest Period applicable thereto (including as a result of an Event of Default), (b) the conversion of any Eurodollar Loan into an ABR Loan other than on the last day of the Interest Period applicable thereto, (c) the failure to convert, continue or prepay any Eurodollar Loan on the date specified in any notice delivered pursuant hereto, then, in any such event, the Borrower shall compensate each Lender for the loss, cost and expense attributable to such event. In the case of a Eurodollar Loan, such loss, cost or expense to any Lender shall be deemed to include an amount determined by such Lender to be the excess, if any, of (i) the amount of interest which would have accrued on the principal amount of such Loan had such event not occurred, at the Adjusted LIBO Rate that would have been applicable to such Loan, for the period from the date of such event to the last day of the then current Interest Period therefor (or, in the case of a failure to borrow, convert or continue, for the period that would have been the Interest Period for such Loan), minus (ii) the amount of interest which would accrue on such principal amount for such period at the interest rate which such Lender would bid were it to bid, at the commencement of such period, for dollar deposits of a comparable amount and period from other banks in the Eurodollar market.

A certificate of any Lender setting forth any amount or amounts that such Lender is entitled to receive pursuant to this Section 5.02 shall be delivered to the Borrower and shall be conclusive absent manifest error. The Borrower shall pay such Lender the amount shown as due on any such certificate within ten (10) days after receipt thereof.

Section 5.03 Taxes .

(a) Payments Free of Taxes . Any and all payments by or on account of any obligation of the Borrower under any Loan Document shall be made free and clear of and without deduction for any Indemnified Taxes or Other Taxes; provided that if the Borrower shall be required to deduct any Indemnified Taxes or Other Taxes from such payments, then (i) the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 5.03(a) ), the Administrative Agent, each Lender or each Issuing Bank, as the case may be, receives an amount equal to the sum it would have received had no such deductions been made, (ii) the Borrower shall make such deductions and (iii) the Borrower shall pay the full amount deducted to the relevant Governmental Authority in accordance with applicable law.

(b) Payment of Other Taxes by the Borrower . The Borrower shall pay any Other Taxes to the relevant Governmental Authority in accordance with applicable law.

(c) Indemnification by the Borrower . The Borrower shall indemnify the Administrative Agent, each Lender and each Issuing Bank, within ten (10) days after written demand therefor, for the full amount of any Indemnified Taxes or Other Taxes paid by the Administrative Agent, such Lender or Issuing Bank, as the case may be, on or with respect to any payment by or on account of any obligation of the Borrower hereunder (including Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under this Section 5.03 ) and any penalties, interest and reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate of the Administrative Agent, a Lender or an Issuing Bank as to the amount of such payment or liability under this Section 5.03 shall be delivered to the Borrower and shall be conclusive absent manifest error.

(d) Indemnification by the Lenders . Each Lender shall severally indemnify the Administrative Agent for the full amount of any Excluded Taxes attributable to such Lender that are paid or payable by the Administrative Agent in connection with any Loan Documents and any reasonable expenses arising therefrom or with respect thereto, whether or not such Excluded Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. The indemnity under this Section 5.03(d) shall be paid within 10 days after the Administrative Agent delivers to the applicable Lender a certificate stating the amount of Excluded Taxes so payable by the Administrative Agent. Such certificate shall be conclusive of the amount so payable absent manifest error.

(e) Evidence of Payments . As soon as practicable after any payment of Indemnified Taxes or Other Taxes by the Borrower to a Governmental Authority, the Borrower shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(f) Effect of Tax Refund . If a Lender determines, in its sole discretion, that it has received a benefit in the nature of a refund, deduction or credit (including a refund in the form of a deduction from or credit against taxes that are otherwise payable by such Lender) of any Taxes or Other Taxes with respect to which the Borrower has made a payment under this Section 5.03 , such Lender will notify the Borrower and agrees to reimburse the Borrower to the extent of the benefit of such refund, deduction or credit, including any interest paid by the relevant Governmental Authority, promptly after such Lender reasonably determines that such refund, deduction or credit has become final; provided , that the Borrower, upon request of the Lender, agrees to repay the amount paid over to the Borrower (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) to such Lender in the event that such Lender is required to repay such refund to such Governmental Authority. Nothing contained in this Section 5.03(f) shall require any Lender to make available its tax returns (or any other information relating to its taxes which it deems to be confidential) or to attempt to obtain any such refund, deduction or credit (including any interest paid by the relevant Governmental Authority and received by such Lender), which attempt would be inconsistent with any reporting position otherwise taken by any Lender on its applicable tax returns.

(g) FATCA . If a payment made to a Lender under this Agreement would be subject to U.S. Federal withholding tax imposed by FATCA if such Lender fails to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such Lender shall deliver to the Borrower or the Administrative Agent, at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Administrative Agent, such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Code) and such additional documentation reasonably requested by the Borrower or the Administrative Agent as may be necessary for the Borrower or the Administrative Agent to comply with its obligations under FATCA, to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from any such payments. For purposes of this Section 5.03(g) , FATCA shall include any regulations or official interpretations of FATCA.

Section 5.04 Illegality . Notwithstanding any other provision of this Agreement, in the event that it becomes unlawful for any Lender to honor its obligation to make or maintain Eurodollar Loans either generally or having a particular Interest Period hereunder, then (a) such Lender shall promptly notify the Borrower and the Administrative Agent thereof and such Lender’s obligation to make such Eurodollar Loans shall be suspended (the “ Affected Loans ”) until such time as such Lender may again make and maintain such Eurodollar Loans and (b) all Affected Loans which would otherwise be made by such Lender shall be made instead as ABR Loans (and, if such Lender so requests by notice to the Borrower and the Administrative Agent, all Affected Loans of such Lender then outstanding shall be automatically converted into ABR Loans on the date specified by such Lender in such notice) and, to the extent that Affected Loans are so made as (or converted into) ABR Loans, all payments of principal which would otherwise be applied to such Lender’s Affected Loans shall be applied instead to its ABR Loans.

ARTICLE VI
Conditions Precedent

Section 6.01 Effective Date . The obligations of the Lenders to make Loans and of any Issuing Bank to issue Letters of Credit hereunder shall not become effective until the date on which each of the following conditions is satisfied (or waived in accordance with Section 12.02 ):

(a) The Administrative Agent and the Lenders shall have received all fees required to be paid under Section 3.05 , and all other fees and amounts due and payable on or prior to the Effective Date, including, to the extent invoiced, reimbursement or payment of all out‑of‑pocket expenses required to be reimbursed or paid by the Borrower hereunder (including the fees and expenses of Faegre Baker Daniels LLP, counsel to the Administrative Agent).

(b) The Administrative Agent shall have received a certificate of the Responsible Officer of the Borrower setting forth (i) resolutions of its board of directors with respect to the authorization of the Borrower to execute and deliver the Loan Documents to which it is a party and to enter into the transactions contemplated in those documents, (ii) the officers of the Borrower (A) who are authorized to sign the Loan Documents to which the Borrower is a party and (B) who will, until replaced by another officer or officers duly authorized for that purpose, act as its representative for the purposes of signing documents and giving notices and other communications in connection with this Agreement and the transactions contemplated hereby, (iii) specimen signatures of such authorized officers, and (iv) the Organizational Documents of the Borrower, certified as being true and complete. The Administrative Agent and the Lenders may conclusively rely on such certificate until the Administrative Agent receives notice in writing from the Borrower to the contrary.

(c) The Administrative Agent shall have received certificates of the appropriate State agencies with respect to the existence, qualification and good standing of the Borrower.

(d) The Administrative Agent shall have received a compliance certificate which shall be substantially in the form of Exhibit D , duly and properly executed by a Responsible Officer of the Borrower and dated as of the Effective Date.

(e) The Administrative Agent shall have received from each party hereto counterparts (in such number as may be requested by the Administrative Agent) of this Agreement signed on behalf of such party.

(f) The Administrative Agent shall have received duly executed Notes payable to each such Lender in a principal amount equal to its Maximum Credit Amount dated as of the date hereof.

(g) The Administrative Agent shall have received from each party thereto duly executed counterparts (in such number as may be requested by the Administrative Agent) of the Security Instruments described on Exhibit E . In connection with the execution and delivery of the Security Instruments, the Administrative Agent shall be reasonably satisfied that the Security Instruments create first priority, perfected Liens (subject only to Excepted Liens identified in clauses (a) to (d) and (f) of the definition thereof, but subject to the provisos at the end of such definition) on at least 80% of the Proved Developed Reserves attributable to the Oil and Gas Properties evaluated in the Initial Reserve Report, with such 80% first being satisfied from Proved Developed Producing Reserves and thereafter from Proved Developed Nonproducing Reserves.

(h) The Administrative Agent shall have received from each Subsidiary duly executed counterparts (in such number as may be requested by the Administrative Agent) of the Guaranty Agreement.

(i) The Administrative Agent shall be reasonably satisfied with the environmental condition and compliance with Environmental Laws of the Oil and Gas Properties of the Borrower and its Subsidiaries.

(j) The Administrative Agent shall have completed a satisfactory due diligence investigation of Borrower, including, without limitation, an environmental assessment of both the Acquired Assets and existing Properties and operations of Borrower.

(k) The Administrative Agent shall have received a certificate of a Responsible Officer of the Borrower certifying that the Borrower has received all consents and approvals required by Section 7.03 .

(l) The Administrative Agent shall have received the financial statements referred to in Section 7.04(a) and the Initial Reserve Report accompanied by a certificate covering the matters described in Section 8.12(b) .

(m) The Administrative Agent shall have received appropriate UCC search certificates reflecting no prior Liens encumbering the Properties of the Borrower and the Subsidiaries for Colorado and any other jurisdiction requested by the Administrative Agent; other than those being assigned or released on or prior to the Effective Date or Liens permitted by Section 9.03 .

(n) The Administrative Agent shall have received title information as the Administrative Agent may reasonably require satisfactory to the Administrative Agent setting forth the status of title to at least 80% of the Proved Reserves attributable to the Oil and Gas Properties evaluated in the Initial Reserve Report, with such 80% first being satisfied from Proved Developed Producing Reserves and thereafter from Proved Developed Nonproducing Reserves.

(o) The Administrative Agent shall have received an opinion of Hart & Trinen LLP counsel to the Borrower substantially in form and substance satisfactory to the Administrative Agent.

(p) The Administrative Agent shall have received a certificate of insurance coverage of the Borrower evidencing that the Borrower is carrying insurance in accordance with Section 7.12 , which the Administrative Agent, in its sole discretion, may determine is satisfactory.

(q) The Administrative Agent shall have received from the Borrower a list of all Oil and Gas Properties of the Borrower not subject to a Lien of the Security Instruments as of the Effective Date substantially in the form of Exhibit I attached hereto.

(r) The absence of any action, suit investigation or proceeding pending or threatened in any court or before any arbitrator or Governmental Authority that purports to affect any transaction contemplated in the Loan Documents or on the ability of the Borrower to perform its obligations under the Loan Documents.

(s) The Administrative Agent shall have received Borrower’s audited consolidated balance sheet and statements of income, stockholders equity and cash flows as of and for the fiscal year ended August 31, 2012.

(t) The Administrative Agent shall have received a pro forma consolidated balance sheet, income statement and cash flow statement and projections (the “ Pro Forma Statements ”) reflecting the Orr Acquisition with such information as the Administrative Agent may reasonably request to confirm the tax, legal and business assumptions made in such Pro Forma Statements. The Pro Forma Statements must demonstrate, in reasonable judgment of the Administrative Agent, together with all other information then available to the Administrative Agent, that, after the Orr Acquisition, Borrower has the ability to repay its Debts and satisfy its other obligations as and when due to comply with the financial covenants set forth in the Loan Documents.

(u) The Administrative Agent shall have received and reviewed, with results satisfactory to the Administrative Agent, of information regarding litigation, tax, accounting, labor, insurance, pension liabilities (actual or contingent), real estate leases, material contracts, debt agreements, property ownership, and contingent liabilities of Borrower and Guarantors.

(v) The Borrower and Lenders shall have received satisfactory credit documentation.

(w) The Administrative Agent shall have received such other documents as the Administrative Agent or counsel to the Administrative Agent or any Lender may reasonably request.

The Administrative Agent shall notify the Borrower and the Lenders of the Effective Date, and such notice shall be conclusive and binding.

Section 6.02 Each Credit Event . The obligation of each Lender to make a Loan on the occasion of any Borrowing (including the initial funding), and of any Issuing Bank to issue, amend, renew or extend any Letter of Credit, is subject to the satisfaction of the following conditions:

(a) At the time of and immediately after giving effect to such Borrowing or the issuance, amendment, renewal or extension of such Letter of Credit, as applicable, no Default shall have occurred and be continuing.

(b) At the time of and immediately after giving effect to such Borrowing or the issuance, amendment, renewal or extension of such Letter of Credit, as applicable, no event, development or circumstance has occurred or shall then exist that has resulted in, or could reasonably be expected to have, a Material Adverse Effect.

(c) The representations and warranties of the Borrower set forth in this Agreement and in the other Loan Documents shall be true and correct on and as of the date of such Borrowing or the date of issuance, amendment, renewal or extension of such Letter of Credit, as applicable, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, on and as of the date of such Borrowing or the date of issuance, amendment, renewal or extension of such Letter of Credit, as applicable, such representations and warranties shall continue to be true and correct as of such specified earlier date.

(d) The making of such Loan or the issuance, amendment, renewal or extension of such Letter of Credit, as applicable would not conflict with, or cause any Lender or any Issuing Bank to violate or exceed, any applicable Governmental Requirement, and no Change in Law shall have occurred that enjoins, prohibits or restrains the making or repayment of any Loan, the issuance, amendment, renewal, extension or repayment of any Letter of Credit or any participations therein or the consummation of the transactions contemplated by this Agreement or any other Loan Document.

(e) No litigation shall be pending or threatened, which does or, with respect to any threatened litigation, seeks to, enjoin, prohibit or restrain, the making or repayment of any Loan, the issuance, amendment, renewal, extension or repayment of any Letter of Credit or any participations therein or the consummation of the transactions contemplated by this Agreement or any other Loan Document.

(f) The receipt by the Administrative Agent of a Borrowing Request in accordance with Section 2.03 or a request for a Letter of Credit in accordance with Section 2.08(b) , as applicable.

Each request for a Borrowing and each request for the issuance, amendment, renewal or extension of any Letter of Credit shall be deemed to constitute a representation and warranty by the Borrower on the date thereof as to the matters specified in Section 6.02(a) through (f) , except that the Borrower’s representation and warranty with respect to Section 6.02(d) shall be deemed to be to its knowledge.

Section 6.03 Additional Conditions to Credit Events . In addition to the conditions precedent set forth in Section 6.02 , so long as any Lender is a Defaulting Lender, any Issuing Bank shall not be required to issue, amend or increase any Letter of Credit, unless it is satisfied that the LC Exposure will be 100% covered by the Commitments of the Non-Defaulting Lenders and/or the Borrower will Cash Collateralize the LC Exposure in accordance with Section 4.03(c)(iii)(B) , and participating interests in any such newly issued or increased Letter of Credit shall be allocated among the Non-Defaulting Lenders in accordance with Section 4.03(c)(iii)(A) (and the Defaulting Lenders shall not participate therein).

ARTICLE VII
Representations and Warranties

The Borrower represents and warrants to the Lenders that:

Section 7.01 Organization; Powers . Each of the Borrower and its Subsidiaries is duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization, has all requisite power and authority, and has all material governmental licenses, authorizations, consents and approvals necessary, to own its assets and to carry on its business as now conducted, and is qualified to do business in, and is in good standing in, every jurisdiction where such qualification is required, except where failure to have such power, authority, licenses, authorizations, consents, approvals and qualifications could not reasonably be expected to have a Material Adverse Effect.

Section 7.02 Authority; Enforceability . The Transactions are within the Borrower’s and each Guarantor’s corporate power and authority and have been duly authorized by all necessary corporate, and, if required, shareholder action. Each Loan Document to which the Borrower and each Guarantor is a party has been duly executed and delivered by the Borrower and such Gurantor and constitutes a legal, valid and binding obligation of the Borrower and such Guarantor, as applicable, enforceable in accordance with its terms, subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting creditors’ rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.

Section 7.03 Approvals; No Conflicts . The Transactions (a) do not require any consent or approval of, registration or filing with, or any other action by, any Governmental Authority or any other third Person, nor is any such consent, approval, registration, filing or other action necessary for the validity or enforceability of any Loan Document or the consummation of the transactions contemplated thereby, except such as have been obtained or made and are in full force and effect other than (i) the recording and filing of the Security Instruments as required by this Agreement, and (ii) those third party approvals or consents which, if not made or obtained, would not cause a Default hereunder, could not reasonably be expected to have a Material Adverse Effect or do not have an adverse effect on the enforceability of the Loan Documents, (b) will not violate any applicable law or regulation to which the Borrower or any Guarantor is subject or any Organizational Document of the Borrower or any Guarantor or any order of any Governmental Authority to which the Borrower or any Guarantor is subject, (c) will not violate or result in a default under any indenture, agreement or other instrument binding upon the Borrower or any Guarantor or their Properties, or give rise to a right thereunder to require any payment to be made by the Borrower of any Guarantor and (d) will not result in the creation or imposition of any Lien on the Properties of the Borrower or any Guarantor (other than the Liens created by the Loan Documents).

Section 7.04 Financial Condition; No Material Adverse Change .

(a) The Borrower has heretofore furnished to the Lenders its concolidated balance sheet and statements of income, shareholders equity and cash flows as of and for the fiscal years ended August 31, 2011 and 2012, audited by Ehrhardt Keefe Steiner & Hoffman P.C., independent public accountants, certified by its chief financial officer. Such financial statements present fairly, in all material respects, the financial position and results of operations and cash flows of the Borrower and its Consolidated Subsidiaries as of such dates and for such periods in accordance with GAAP, subject to year‑end audit adjustments and the absence of footnotes in the case of the unaudited quarterly financial statements.

(b) Since August 31, 2012, (i) there has been no event, development or circumstance that has had or could reasonably be expected to have a Material Adverse Effect and (ii) the business of the Borrower and its Subsidiaries has been conducted only in the ordinary course consistent with past business practices.

(c) On the date hereof, neither the Borrower nor any Subsidiary has any Debt (including Disqualified Capital Stock) or any contingent liabilities, off‑balance sheet liabilities or partnerships, liabilities for taxes or unrealized or anticipated losses from any unfavorable commitments, except as referred to or reflected or provided for in the financial statements described in Section 7.04(a) or in the most recent financial statements delivered pursuant to Section 8.01(a) or (b) .

Section 7.05 Litigation .

(a) Except as set forth on Schedule 7.05 on the Effective Date or as otherwise disclosed in writing to the Administrative Agent and the Lenders after the Effective Date (which shall supplement Schedule 7.05 ), there are no actions, suits, investigations or proceedings by or before any arbitrator or Governmental Authority pending or, to the knowledge of the Borrower, threatened against or affecting the Borrower or any Subsidiary (i) as to which there is a reasonable possibility of an adverse determination that could be expected, individually or in the aggregate, to result in a Material Adverse Effect or (ii) that involve any Loan Document or the Transactions.

(b) Since the date of this Agreement, there has been no change in the status of the matters disclosed in Schedule 7.05 that, individually or in the aggregate, has resulted in, or materially increased the likelihood of, a Material Adverse Effect.

Section 7.06 Environmental Matters . Except for such matters that, individually or in the aggregate, could not reasonably be expected to have a Material Adverse Effect:

(a) The Borrower and its Subsidiaries and each of their respective Properties and operations thereon are, and within all applicable statute of limitation periods have been, in compliance with all applicable Environmental Laws.

(b) The Borrower and its Subsidiaries have obtained all Environmental Permits required for their operations on each of their Properties, with all such Environmental Permits being currently in full force and effect, and neither the Borrower nor any Subsidiary has received any written notice or otherwise has knowledge that any such existing Environmental Permit will be revoked or that any application for any new Environmental Permit or renewal of any existing Environmental Permit will be protested or denied.

(c) There are no claims, demands, suits, orders, inquiries, or proceedings concerning any violation of, or any liability (including as a potentially responsible party) under, any applicable Environmental Laws that is pending or, to Borrower’s knowledge, threatened against the Borrower or any Subsidiary or any of their respective Properties or as a result of any operations at such Properties.

(d) None of the Properties of the Borrower or any Subsidiary contain or have contained any: (i) underground storage tanks; (ii) asbestos‑containing materials; (iii) landfills or dumps; (iv) hazardous waste management units as defined pursuant to RCRA or any comparable state law; or (v) sites on or nominated for the National Priority List promulgated pursuant to CERCLA or any state remedial priority list promulgated or published pursuant to any comparable state law.

(e) There has been no Release or, to the Borrower’s knowledge, threatened Release, of Hazardous Materials at, on, under or from any of the Properties or the Borrower or any Subsidiary, there are no investigations, remediations, abatements, removals, or monitorings of Hazardous Materials required under applicable Environmental Laws at such Properties and, to the knowledge of the Borrower, none of such Properties are adversely affected by any Release or threatened Release of a Hazardous Material originating or emanating from any other real property.

(f) Neither the Borrower nor any Subsidiary has received any written notice asserting an alleged liability or obligation under any applicable Environmental Laws with respect to the investigation, remediation, abatement, removal, or monitoring of any Hazardous Materials at, under, or Released or threatened to be Released from any real properties offsite of the Borrower’s or any Subsidiary’s Properties and, to the Borrower’s knowledge, there are no conditions or circumstances that could reasonably be expected to result in the receipt of such written notice.

(g) There has been no exposure of any Person or Property to any Hazardous Materials as a result of or in connection with any operations and businesses conducted on the Properties of the Borrower or any Subsidiary that could reasonably be expected to form the basis for a claim for damages or compensation.

(h) The Borrower and each Subsidiary has provided to the Lenders complete and correct copies of all environmental site assessment reports, investigations, studies, analyses, and correspondence on environmental matters (including matters relating to any alleged non‑compliance with or liability under Environmental Laws) that are in the possession or control of the Borrower or any Subsidiary and relating to any of their Properties or the operations thereon.

Section 7.07 Compliance with the Laws and Agreements; No Defaults .

(a) The Borrower and each Subsidiary is in compliance with all Governmental Requirements applicable to it or its Property and all agreements and other instruments binding upon it or its Property, and possesses all licenses, permits, franchises, exemptions, approvals and other authorizations granted by Governmental Authorities necessary for the ownership of its Property and the conduct of its business, except where the failure to do so, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect.

(b) Neither the Borrower nor any Subsidiary is in default nor has any event or circumstance occurred which, but for the expiration of any applicable grace period or the giving of notice, or both, would constitute a default or would require the Borrower or any Subisidary to Redeem or make any offer to Redeem under any indenture, note, credit agreement or instrument pursuant to which any Material Debt is outstanding or by which the Borrower or any Subsidiary or any of their Properties is bound.

Section 7.08 Investment Company Act . Neither the Borrower nor any Subsidiary is an “investment company” or a company “controlled” by an “investment company,” within the meaning of, or subject to regulation under, the Investment Company Act of 1940, as amended.

Section 7.09 Taxes . Each of the Borrower and its Subsidiaries has timely filed or caused to be filed all Tax returns and reports required to have been filed and has paid or caused to be paid all Taxes required to have been paid by it, except (a) Taxes that are being contested in good faith by appropriate proceedings and for which the Borrower or any Subsidiary, as applicable, has set aside on its books adequate reserves in accordance with GAAP or (b) to the extent that the failure to do so could not reasonably be expected to result in a Material Adverse Effect. The charges, accruals and reserves on the books of the Borrower and its Subsidiaries in respect of Taxes and other governmental charges are, in the reasonable opinion of the Borrower, adequate. No Liens for Taxes have been filed and, to the knowledge of the Borrower, no claim is being asserted with respect to any such Tax or other such governmental charge.

Section 7.10 ERISA .

(a) The Borrower, its Subsidiaries and each ERISA Affiliate have complied in all material respects with ERISA and, where applicable, the Code regarding each Plan except to the extent the failure to do so could not reasonably be expected to result in a Material Adverse Effect.

(b) Each Plan is, and has been, established and maintained in substantial compliance with its terms, ERISA and, where applicable, the Code except to the extent the failure to do so could not reasonably be expected to result in a Material Adverse Effect.

(c) No act, omission or transaction has occurred which could result in imposition on the Borrower, any Subsidiary or any ERISA Affiliate (whether directly or indirectly) of (i) either a civil penalty assessed pursuant to subsections (c), (i), (l) or (m) of section 502 of ERISA or a tax imposed pursuant to Chapter 43 of Subtitle D of the Code or (ii) breach of fiduciary duty liability damages under section 409 of ERISA except to the extent such penalty or liability could not reasonably be expected to result in a Material Adverse Effect.

(d) Full payment when due has been made of all amounts which the Borrower, the Subsidiaries or any ERISA Affiliate is required under the terms of each Plan or applicable law to have paid as contributions to such Plan as of the date hereof and no accumulated funding deficiency (as defined in section 302 of ERISA and section 412 of the Code), whether or not waived, exists with respect to any Plan.

(e) Neither the Borrower, the Subsidiaries nor any ERISA Affiliate sponsors, maintains, or contributes to an employee welfare benefit plan, as defined in section 3(1) of ERISA, including any such plan maintained to provide benefits to former employees of such entities, that may not be terminated by the Borrower, any Subsidiary or any ERISA Affiliate in its sole discretion at any time without any material liability.

(f) Neither the Borrower, the Subsidiaries nor any ERISA Affiliate sponsors, maintains or contributes to, or has at any time in the six-year period preceding the date hereof sponsored, maintained or contributed to, any employee pension benefit plan, as defined in section 3(2) of ERISA, that is subject to Title IV of ERISA, section 302 of ERISA or section 412 of the Code.

Section 7.11 Disclosure; No Material Misstatements . The Borrower has disclosed to the Administrative Agent and the Lenders all agreements, instruments and corporate or other restrictions to which it is subject, and all other matters known to it, that, individually or in the aggregate, could reasonably be expected to result in a Material Adverse Effect. None of the reports, financial statements, certificates or other information furnished by or on behalf of the Borrower or any Subsidiary to the Administrative Agent or any Lender or any of their Affiliates in connection with the negotiation of this Agreement or any other Loan Document or delivered hereunder or under any other Loan Document (as modified or supplemented by other information so furnished) contains any material misstatement of fact or omits to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided that, with respect to projected financial information, the Borrower represents only that such information was prepared in good faith based upon assumptions believed to be reasonable at the time. There is no fact peculiar to the Borrower or any Subsidiary which could reasonably be expected to have a Material Adverse Effect or in the future is reasonably likely to have a Material Adverse Effect and which has not been set forth in this Agreement or the Loan Documents or the other documents, certificates and statements furnished to the Administrative Agent or the Lenders by or on behalf of the Borrower or any Subsidiary prior to, or on, the date hereof in connection with the transactions contemplated hereby. There are no statements or conclusions known to the Borrower in the preparation of any Reserve Report which were based upon or include misleading information or failed to take into account material information regarding the matters reported therein, it being understood that projections concerning volumes attributable to the Oil and Gas Properties of the Borrower and the Subsidiaries and production and cost estimates contained in each Reserve Report are necessarily based upon professional opinions, estimates and projections and that the Borrower and the Subsidiaries do not warrant that such opinions, estimates and projections will ultimately prove to have been accurate.

Section 7.12 Insurance . The Borrower has, and has caused its Subsidiaries, to have (a) all insurance policies sufficient for its compliance by each of them with all material Governmental Requirements and all material agreements and (b) insurance coverage in at least amounts and against such risk (including public liability) that are usually insured against by companies similarly situated and engaged in the same or a similar business for the assets and operations of the Borrower and its Subsidiaries. The Administrative Agent and the Lenders have been named as additional insureds in respect of such liability insurance policies and the Administrative Agent has been named as loss payee with respect to the Property loss insurance maintained by the Borrower.

Section 7.13 Restriction on Liens . Neither the Borrower nor any Subsidiary is a party to any agreement or arrangement, or subject to any order, judgment, writ or decree, which either restricts or purports to restrict its ability to grant Liens to the Administrative Agent and the Lenders on or in respect of their Properties to secure the Indebtedness and the Loan Documents.

Section 7.14 Subsidiaries . The Borrower has no Subsidiaries (other than the Guarantors listed on Schedule 7.14 and any Subsidiary that has been approved in writing by the Administrative Agent pursuant to Section 9.15 ).

Section 7.15 Location of Business and Offices . The Borrower’s jurisdiction of organization is Colorado; the name of the Borrower as listed in the public records of its jurisdiction of organization, as of the date hereof, is Synergy Resources Corporation; and the organizational identification number of the Borrower in its jurisdiction of organization is 20051109690 (or, in each case, as set forth in a notice delivered to the Administrative Agent pursuant to Section 8.01(l) in accordance with Section 12.01 ). The Borrower’s principal place of business and chief executive office is located at the address specified in Section 12.01 (or as set forth in a notice delivered pursuant to Section 8.01(l) and Section 12.01(d) ). Each Subsidiary’s jurisdiction of organization, organizational identification number in its jurisdiction or organization, and the location of its principal place of business and chief executive office is stated on Schedule 7.15 (or as set forth in a notice delivered pursuant to Section 8.01(l) in accordance with Section 12.01 ).

Section 7.16 Properties; Titles, Etc .

(a) The Borrower and its Subsidiaries have good and defensible title to the Hydrocarbon Interests in the Oil and Gas Properties evaluated in the most recently delivered Reserve Report and good title to all their personal Properties, in each case, free and clear of all Liens except Liens permitted by Section 9.03 . After giving full effect to the Excepted Liens, the Borrower owns the net interests in production attributable to the Hydrocarbon Interests as reflected in the most recently delivered Reserve Report, and the ownership of such Properties shall not in any material respect obligate the Borrower to bear the costs and expenses relating to the maintenance, development and operations of each such Property in an amount in excess of the working interest of each Property set forth in the most recently delivered Reserve Report that is not offset by a corresponding proportionate increase in the Borrower’s net revenue interest in such Property.

(b) All material leases and agreements necessary for the conduct of the business of the Borrower and its Subsidiaries are valid and subsisting, in full force and effect, and there exists no default or event or circumstance which with the giving of notice or the passage of time or both would give rise to a default under any such lease or leases, which could reasonably be expected to have a Material Adverse Effect.

(c) The rights and Properties presently owned, leased or licensed by the Borrower and its Subsidiaries including all easements and rights of way, include all rights and Properties necessary to permit the Borrower and its Subsidiaries to conduct their business in all material respects in the same manner as its business has been conducted prior to the date hereof.

(d) All of the material Properties of the Borrower and its Subsidiaries which are reasonably necessary for the operation of their businesses are in good working condition and are maintained in accordance with prudent business standards.

(e) The Borrower and each Subsidiary owns, or is licensed to use, all trademarks, tradenames, copyrights, patents and other intellectual Property material to its business, and the use thereof by the Borrower and its Subsidiaries does not and will not infringe upon the rights of any other Person, except for any such infringements that, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect. Each of the Borrower and its Subsidiaries either owns or has valid licenses or other rights to use all databases, geological data, geophysical data, engineering data, seismic data, maps, interpretations and other technical information used in its business as presently conducted, subject to the limitations contained in the agreements governing the use of the same, which limitations are customary for companies engaged in the business of the exploration and production of Hydrocarbons, with such exceptions as could not reasonably be expected to have a Material Adverse Effect.

Section 7.17 Maintenance of Properties . Except for such acts or failures to act as could not be reasonably expected to have a Material Adverse Effect, the Oil and Gas Properties (and Properties unitized therewith) of the Borrower and its Subsidiaries have been maintained, operated and developed in a good and workmanlike manner and in conformity with all Governmental Requirements and in conformity with the provisions of all leases, subleases or other contracts comprising a part of the Hydrocarbon Interests and other contracts and agreements forming a part of the Oil and Gas Properties of the Borrower and its Subsidiaries. Specifically in connection with the foregoing, except for those as could not be reasonably expected to have a Material Adverse Effect, (a) no Oil and Gas Property of the Borrower or its Subsidiaries is subject to having allowable production reduced below the full and regular allowable (including the maximum permissible tolerance) because of any overproduction (whether or not the same was permissible at the time) and (b) none of the wells comprising a part of the Oil and Gas Properties (or Properties unitized therewith) of the Borrower or its Subsidiaries is deviated from the vertical more than the maximum permitted by Governmental Requirements, and such wells are, in fact, bottomed under and are producing from, and the well bores are wholly within, the Oil and Gas Properties (or in the case of wells located on Properties unitized therewith, such unitized Properties) of the Borrower and its Subsidiaries. All pipelines, wells, gas processing plants, platforms and other material improvements, fixtures and equipment owned in whole or in part by the Borrower or its Subsidiaries that are necessary to conduct normal operations are being maintained in a state adequate to conduct normal operations, and in a manner consistent with the past practices of the Borrower and its Subsidiaries (other than those the failure of which to maintain in accordance with this Section 7.17 could not reasonably be expected to have a Material Adverse Effect).

Section 7.18 Gas Imbalances, Prepayments . Except as set forth on Schedule 7.18 or on the most recent certificate delivered pursuant to Section 8.12(b) , on a net basis there are no gas imbalances, take or pay or other prepayments which would require the Borrower or any Subsidiary to deliver Hydrocarbons produced from the Oil and Gas Properties of the Borrower or any Subsidiary at some future time without then or thereafter receiving full payment therefor exceeding two percent (2%) of the Borrower’s Proved Reserves of natural gas (on an mcf equivalent basis) in the aggregate.

Section 7.19 Marketing of Production . Except as set forth on Schedule 7.19 or on the most recent certificate delivered pursuant to Section 8.12(b) , neither the Borrower nor any Subsidiary a party to any material agreements which is not cancelable on sixty (60) days notice or less without penalty or detriment for the sale of production from the Borrower’s or any Subsidiary’s Hydrocarbons (including calls on or other rights to purchase, production, whether or not the same are currently being exercised) that (a) pertain to the sale of production at a fixed price and (b) have a maturity or expiry date of longer than six (6) months from the date thereof.

Section 7.20 Hedging Agreements . Schedule 7.20 , as of the date hereof, and after the date hereof, each report required to be delivered by the Borrower pursuant to Section 8.01(e) , sets forth, a true and complete list of all Hedging Agreements of the Borrower and each Subsidiary, the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), all credit support agreements relating thereto (including any margin required or supplied) and the counterparty to each such agreement.

Section 7.21 Use of Loans and Letters of Credit . The proceeds of the Loans and the Letters of Credit shall be used (a) to provide working capital for exploration and production operations, acquisition of oil and gas properties and general corporate purposes and (b) for Restricted Payments permitted under Section 9.04 . A portion of the Borrowing Base (not to exceed the LC Commitment) may be used for the issuance of Letters of Credit that shall expire prior to the Termination Date. The Borrower is not engaged principally, or as one of its important activities, in the business of extending credit for the purpose, whether immediate, incidental or ultimate, of buying or carrying margin stock (within the meaning of Regulation T, U or X of the Board). No part of the proceeds of any Loan or Letter of Credit will be used for any purpose which violates the provisions of Regulations T, U or X of the Board.

Section 7.22 Solvency . After giving effect to the transactions contemplated hereby, (a) the aggregate assets (after giving effect to amounts that could reasonably be received by reason of indemnity, offset, insurance or any similar arrangement), at a fair valuation, of the Borrower and the Guarantors will exceed the aggregate Debt of the Borrower and the Guarantors on a consolidated basis as the Debt becomes absolute and matures, (b) each of the Borrower and the Guarantors has not incurred and does not intend to incur, and does not believe that it will incur, Debt beyond its ability to pay such Debt (after taking into account the timing and amounts of cash to be received by each of the Borrower and the Guarantors and the amounts to be payable on or in respect of its liabilities, and giving effect to amounts that could reasonably be received by reason of indemnity, offset, insurance or any similar arrangement) as such Debt becomes absolute and matures and (c) the Borrower and the Guarantors will not have (and has no reason to believe that it will have thereafter) unreasonably small capital for the conduct of its business.

Section 7.23 Casualty Events . Since January 1, 2012, neither the business nor any Properties of the Borrower or any Subsidiary have been materially and adversely affected as a result of any fire, explosion, earthquake, flood, drought, windstorm, accident, strike or other labor disturbance, embargo, requisition or taking of property or cancellation of contracts, permits or concessions by any domestic or foreign Governmental Authority, riot, activities or armed forces or acts of God or of any public enemy.

Section 7.24 Material Agreements . Set forth on Schedule 7.24 hereto or as disclosed in writing to the Administrative Agent (which shall promptly furnish a copy to the Lenders), which shall be a supplement to Schedule 7.24 , is a complete and correct list of all material agreements and other instruments maintained by the Borrower and the Subsidiaries setting forth each counterparty thereto (other than the Loan Documents, exploration and/or development agreements and joint operating agreements to which the Borrower or any Subsidiary is a party) relating to the purchase, transportation by pipeline, gas processing, marketing, development, sale and supply of Hydrocarbons, farmout arrangements, contract operating agreements or other material contracts (excluding oil and gas leases of the Borrower or any Subsidiary and joint operating agreements to which the Borrower or any Subsidiary is a party) to which the Borrower or any Subsidiary is a party or by which its Properties are bound, in each case for which breach, nonperformance, cancellation or failure to renew could reasonably be expected to have a Material Adverse Effect (collectively “ Material Agreements ”) and copies of such documents have been provided to the Administrative Agent. All such agreements are in full force and effect and neither the Borrower nor any Subsidiary is in default thereunder, nor is there any uncured default by any Affiliate predecessor in interest to the Borrower or any Subsidiary or, to the Borrower’s knowledge, by any predecessor in interest to the Borrower or any Subsidiary (other than an Affiliate predecessor) or counterparty thereto, nor has the Borrower or any Subsidiary altered any material item of such agreements since the Effective Date without the prior written consent of the Lenders.

Section 7.25 No Brokers . No Person is entitled to any brokerage fee or finder’s fee or similar fee or commission in connection with arranging the Loans contemplated by this Agreement.

Section 7.26 Reliance . In connection with the negotiation of and the entering into this Agreement, the Borrower and each Subsidiary acknowledges and represents that none of the Lenders, the Administrative Agent or any representative of any of the foregoing is acting as a fiduciary or financial or investment advisor for it; it is not relying upon any representations (whether written or oral) of such Persons; it has consulted with its own legal, regulatory, tax, business investment, financial and accounting advisors to the extent it has deemed necessary, and it has made its own investment, hedging, and trading decisions based upon its own judgment and upon any advice from such advisors as it has deemed necessary and not upon any view expressed by any Lender, the Administrative Agent or any representative of any of the foregoing; it has not been given by any Lender, the Administrative Agent or any representative of any of the foregoing (directly or indirectly through any other Person) any advice, counsel, assurance, guarantee, or representation whatsoever as to the expected or projected success, profitability, return, performance, result, effect, consequence, or benefit (either legal, regulatory, tax, financial, accounting, or otherwise) of this Agreement or the transactions contemplated hereby; and it is entering into this Agreement and the other Loan Documents with a full understanding of all of the risks hereof and thereof (economic and otherwise), and it is capable of assuming and willing to assume (financially and otherwise) those risks.

Section 7.27 Payments by Purchasers of Production . All proceeds from the sale of the Borrower’s and each Subsidiary’s interests in Hydrocarbons from its Oil and Gas Properties are currently being paid in full by the purchaser thereof on a timely basis and at prices and terms comparable to market prices and terms generally available at the time such prices and terms were negotiated for oil and gas production from producing areas situated near such Oil and Gas Properties, and none of such proceeds are currently being held in suspense by such purchaser or any other Person.

Section 7.28 Existing Accounts Payable . As of the Effective Date, set forth on Schedule 7.28 hereto is a complete and correct list of all existing accounts payable of the Borrower and its Subsidiaries that are more than sixty (60) days past due.

Section 7.29 Foreign Corrupt Practices . Neither the Borrower, nor any of its Subsidiaries, nor any director, officer, agent, employee or Affiliate of the Borrower or any of its Subsidiaries is aware of or has taken any action, directly or indirectly, that would result in a material violation by such Persons of the FCPA, including making use of the mails or any means or instrumentality of interstate commerce corruptly in furtherance of an offer, payment, promise to pay or authorization of the payment of any money, or other property, gift, promise to give, or authorization of the giving of anything of value to any “foreign official” (as such term is defined in the FCPA) or any foreign political party or official thereof or any candidate for foreign political office, in contravention of the FCPA; and, the Borrower, its Subsidiaries and its and their Affiliates have conducted their business in material compliance with the FCPA and have instituted and maintained policies and procedures designed to ensure, and which are reasonably expected to continue to ensure, continued compliance therewith.

Section 7.30 Money Laundering . The operations of the Borrower and its Subsidiaries are and have been conducted at all times in material compliance with applicable financial recordkeeping and reporting requirements of the Money Laundering Laws, and no action, suit or proceeding by or before any court or governmental agency, authority or body or any arbitrator involving the Borrower or any of its Subsidiaries with respect to the Money Laundering Laws is pending or, to the best knowledge of the Borrower, threatened.

Section 7.31 OFAC . Neither the Borrower, its Subsidiaries, nor any director, officer, agent, employee or Affiliate of the Borrower or any of its Subsidiaries is currently subject to any material U.S. sanctions administered by OFAC, and neither the Borrower nor any Subsidiary will directly or indirectly use the proceeds from the Loans or lend, contribute or otherwise make available such proceeds to any joint venture partner or other Person, for the purpose of financing the activities of any Person currently subject to any U.S. sanctions administered by OFAC.

ARTICLE VIII
Affirmative Covenants

Until the Commitments have expired or been terminated and the principal of and interest on each Loan and all fees payable hereunder and all other amounts payable under the Loan Documents shall have been paid in full and all Letters of Credit shall have expired or terminated and all LC Disbursements shall have been reimbursed, the Borrower covenants and agrees with the Lenders that:

Section 8.01 Financial Statements; Other Information . The Borrower will furnish to the Administrative Agent and each Lender:

(a) Annual Financial Statements . As soon as available, but in any event in accordance with then applicable law and not later than (120) days after the end of each fiscal year of the Borrower, its audited consolidated balance sheet and related statements of operations (and, as the balance sheet and statements of operations, accompanied by consolidated schedules), shareholders’ equity and cash flows as of the end of and for such year, setting forth in each case in comparative form the figures for the previous fiscal year, all reported on by a firm of independent public accountants of recognized national or regional standing reasonably acceptable to the Administrative Agent (without a “ going concern ” or like qualification or exception and without any qualification or exception as to the scope of such audit), and certified by one of its Financial Officers, to the effect that such consolidated financial statements present fairly in all material respects the financial condition and results of operations of the Borrower and its Consolidated Subsidiaries on a consolidated basis in accordance with GAAP consistently applied.

(b) Quarterly Financial Statements . Within sixty (60) days after the end of each fiscal quarter of each fiscal year of the Borrower, a consolidated balance sheet, income statement and statement of the cumulative cash flows of the Borrower and its Consolidated Subsidiaries for the period from the beginning of the then current fiscal year to the end of such fiscal quarter, prepared by the Borrower and accompanied by a certification of a Responsible Officer of the Borrower, dated the date of the delivery of the financial statements to the Administrative Agent and each Lender, and further certifying that no Default exists under this Agreement and that such financial statements present fairly in all material respects the financial position and results of operations of the Borrower in accordance with GAAP, subject to normal year‑end adjustments and the absence of footnotes (other than those reasonably required to explain financial data).

(c) Certificate of Financial Officer – Compliance . Concurrently with any delivery of financial statements under Section 8.01(a) or Section 8.01(b) , a certificate of the a Financial Officer in substantially the form of Exhibit D attached hereto (i) certifying as to whether a Default has occurred and, if a Default has occurred, specifying the details thereof and any action taken or proposed to be taken with respect thereto, (ii) setting forth reasonably detailed calculations demonstrating compliance with Section 8.14 and Section 9.01 , (iii) stating whether any change in GAAP or in the application thereof has occurred since the date of the audited financial statements referred to in Section 7.04 and, if any such change has occurred, specifying the effect of such change on the financial statements accompanying such certificate, and (iv) if, at any time, the Borrower has any Consolidated Subsidiaries, setting forth consolidating spreadsheets that show all Consolidated Subsidiaries and eliminating entries, in such detail as would be provided to the auditors of the Borrower.

(d) Certificate of Accounting Firm – Defaults . Concurrently with any delivery of financial statements under Section 8.01(a) , a certificate of the accounting firm that reported on such financial statements stating whether they obtained knowledge during the course of their examination of such financial statements of any Default (which certificate may be limited to the extent required by accounting rules or guidelines).

(e) Certificate of Financial Officer – Hedging Agreements . Concurrently with any delivery of financial statements under Section 8.01(a) or Section 8.01(b) , a certificate of a Financial Officer, in substantially the form of Exhibit G attached hereto, setting forth as of the last Business Day of such fiscal quarter or fiscal year, as the case may be, a true and complete list of all Hedging Agreements of the Borrower, the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), the net mark‑to‑market value therefor, any new credit support agreements relating thereto not listed on Schedule 7.20 , any margin required or supplied under any credit support document, and the counterparty to each such agreement.

(f) Certificate of Insurer – Insurance Coverage . Promptly following any request therefor by the Administrative Agent or any Lender, a certificate of insurance coverage from each insurer with respect to the insurance required by Section 8.07 , in form and substance satisfactory to the Administrative Agent, and, if requested by the Administrative Agent or any Lender, all copies of the applicable policies.

(g) Other Accounting Reports . Promptly upon receipt thereof, a copy of each other report or letter (except standard and customary correspondence) submitted to the Borrower or any of its Subsidiaries by independent accountants in connection with any annual, interim or special audit made by them of the books of the Borrower or any such Subsidiary, and a copy of any response by the Borrower, or the board of directors of the Borrower, to such letter or report.

(a) SEC and Other Filings; Reports to Shareholders . Promptly after the same become publicly available, copies of all periodic and other reports, proxy statements and other materials filed by the Borrower or any Subsidiary with the SEC, or with any national securities exchange, or distributed by the Borrower to its shareholders generally, as the case may be.

(h) Notices Under Material Instruments . Promptly after the furnishing thereof, copies of any financial statement, report or notice furnished to or by any Person pursuant to the terms of any preferred stock designation, indenture, loan or credit or other similar agreement, other than this Agreement and not otherwise required to be furnished to the Lenders pursuant to any other provision of this Section 8.01 .

(i) Lists of Purchasers . Concurrently with the delivery of any Reserve Report to the Administrative Agent pursuant to Section 8.12 , a list of all Persons purchasing Hydrocarbons from the Borrower or any Subsidiary produced from the Oil and Gas Properties of the Borrower or its Subsidiaries included in the latest Reserve Report.

(j) Notice of Sales of Oil and Gas Properties . In the event the Borrower or any Subsidiary intends to sell, transfer, assign or otherwise dispose of any of its Oil or Gas Properties or any Equity Interests in the Borrower in accordance with Section 9.11 , prior written notice of such disposition, the price thereof and the anticipated date of closing and any other details thereof requested by the Administrative Agent or any Lender.

(k) Notice of Casualty Events . Prompt written notice, and in any event within three (3) Business Days of the occurrence of any Casualty Event or the commencement of any action or proceeding that could reasonably be expected to result in a Casualty Event.

(l) Information Regarding the Borrower and Guarantors . Prompt written notice (and in any event within ten Business Days prior thereto) of any change (i) in the Borrower’s or any Guarantor’s corporate name or in any trade name used to identify such Person in the conduct of its business or in the ownership of its Properties, (ii) in the location of the Borrower’s or any Guarantor’s chief executive office or principal place of business, (iii) in the Borrower’s or any Guarantor’s identity or corporate structure or in the jurisdiction in which such Person is organized or formed, (iv) in the Borrower’s or any Guarantor’s jurisdiction of organization or such Person’s organizational identification number in such jurisdiction of organization and (v) in the Borrower’s or any Guarantor’s federal taxpayer identification number.

(m) Other Reports . The Borrower shall prepare and provide the Lenders and Administrative Agent the following reports:

(i) concurrently with any delivery of financial statements under Section 8.01(a) , a 12 month budget for the Borrower and its Subsidiaries for the current fiscal year prepared by the management of the Borrower;

(ii) on a quarterly basis by the 45th day after the end of each fiscal quarter of the Borrower, an updated report setting forth the forecasted Capital Expenditure budget for the Borrower and its Subsidiaries for the following twelve (12) month period; and

(iii) such other information as the Administrative Agent may reasonably request, including each of the following to the extent available: an unaudited income statement, a consolidated balance sheet and a statement of cash flow (with such statement to show any variations from the budget previously delivered), copies of the Borrower’s and each Subsidiary’s bank account statements, statement of expenses for the preceding month, notice of any material changes with regard to oil and gas prices received, contracts or production expenses or any material litigation affecting the operation of the Oil and Gas Properties of the Borrower or its Subsidiaries.

(n) Notices of Certain Changes . Subject to Section 9.20 , promptly, but in any event within five (5) Business Days after the execution thereof, copies of any amendment, modification or supplement to the Organizational Documents, any preferred stock designation or any other organizational document of the Borrower or any Subsidiary.

(o) Notice of Purchase of Oil and Gas Properties . In the event the Borrower or any Subsidiary acquires Oil and Gas Properties having an acquisition cost in excess of $1,000,000 (which amount shall be applied on an acquisition by acquisition basis, but continuing as one acquisition any group of properties that are part of a single transaction or a series of related transactions), the Borrower shall deliver promptly, but in any event within forty‑five (45) days after the end of each fiscal quarter in which such acquisition occurred, to the Administrative Agent a list of all Oil and Gas Properties of the Borrower and its Subsidiaries (including each such newly acquired Oil and Gas Property) not subject to a Lien of the Security Instruments at the time of delivery of such list to the Administrative Agent, in substantially the form of Exhibit I attached hereto.

(p) Non‑Consent Election . Written notice of any non-consent election within five (5) Business Days after the Borrower’s or any Subsidiary’s election to withhold consent to participate in any wells located on any of the Oil and Gas Properties.

(q) Other Requested Information . Promptly following any request therefor, such other information regarding the operations, business affairs and financial condition of the Borrower compliance with the terms of this Agreement or any other Loan Document, in each case, as the Administrative Agent or any Lender may reasonably request.

Section 8.02 Notices of Material Events . The Borrower will furnish to the Administrative Agent and each Lender prompt written notice of the following:

(a) the occurrence of any Default or threatened Default under this Agreement or any of the other Loan Documents;

(b) the filing or commencement of, or the threat in writing of, any action, suit, proceeding, investigation or arbitration by or before any arbitrator or Governmental Authority against or affecting the Borrower, any Subsidiary or any Affiliate thereof not previously disclosed in writing to the Lenders or any material adverse development in any action, suit, proceeding, investigation or arbitration (whether or not previously disclosed to the Lenders) that, in either case, if adversely determined, could reasonably be expected to result in a Material Adverse Effect; and

Each notice delivered under this Section 8.02 shall be accompanied by a statement of a Responsible Officer setting forth the details of the event or development requiring such notice and any action taken or proposed to be taken with respect thereto.

Section 8.03 Existence; Conduct of Business . The Borrower will, and will cause each Subsidiary to, do or cause to be done all things necessary to preserve, renew and keep in full force and effect its legal existence and the rights, licenses, permits, privileges and franchises material to the conduct of its business and maintain, if necessary, its qualification to do business in each jurisdiction in which its Oil and Gas Properties are located or the ownership of its Properties requires such qualification, except where the failure to so qualify could not reasonably be expected to have a Material Adverse Effect; provided that the foregoing shall not prohibit any merger, consolidation, liquidation or dissolution permitted under Section 9.10 .

Section 8.04 Payment of Obligations . The Borrower will, and will cause each Subsidiary to, pay its obligations, including Tax liabilities and payables with rights to mechanic and materialman liens, before the same shall become delinquent or in default, except where (a) the validity or amount thereof is being contested in good faith by appropriate proceedings, (b) the Borrower or such Subsidiary has set aside on its books adequate reserves with respect thereto in accordance with GAAP and (c) the failure to make payment pending such contest could not reasonably be expected to result in a Material Adverse Effect or result in the seizure or levy of any Property of the Borrower or any Subsidiary.

Section 8.05 Performance of Obligations under Loan Documents . The Borrower will pay the Notes according to the reading, tenor and effect thereof, and the Borrower will, and will cause each Subsidiary to, do and perform every act and discharge all of the obligations to be performed and discharged by them under the Loan Documents, including this Agreement, at the time or times and in the manner specified.

Section 8.06 Operation and Maintenance of Properties . The Borrower, at its own expense, will, and will cause each Subsidiary to:

(a) operate its Oil and Gas Properties and other material Properties or cause such Oil and Gas Properties and other material Properties to be operated in a careful and efficient manner in accordance with the practices of the industry and in compliance with all applicable contracts and agreements and in compliance with all Governmental Requirements, including applicable proration requirements and Environmental Laws, and all applicable laws, rules and regulations of every other Governmental Authority from time to time constituted to regulate the development and operation of its Oil and Gas Properties and the production and sale of Hydrocarbons and other minerals therefrom, except, in each case, where the failure to comply could not reasonably be expected to have a Material Adverse Effect;

(b) keep, preserve and maintain all Property that is material to the conduct of its business in good working order and condition, ordinary wear and tear excepted, and preserve, maintain and keep in good repair, working order and efficiency (ordinary wear and tear excepted) all of its material Oil and Gas Properties and other material Properties, including all equipment, machinery and facilities;

(c) promptly pay and discharge, or make reasonable and customary efforts to cause to be paid and discharged, all delay rentals, royalties, expenses and indebtedness accruing under the leases or other agreements affecting or pertaining to its Oil and Gas Properties and will do all other things necessary, in accordance with customary industry standards, to keep unimpaired their rights with respect thereto and prevent any forfeiture thereof or default thereunder;

(d) promptly perform or make reasonable and customary efforts to cause to be performed, in accordance with industry standards, the obligations required by each and all of the assignments, deeds, leases, sub‑leases, contracts and agreements affecting its interests in its Oil and Gas Properties and other material Properties; and

(e) operate its Oil and Gas Properties and other material Properties or cause or make reasonable and customary efforts to cause such Oil and Gas Properties and other material Properties to be operated in accordance with the practices of the industry and in material compliance with all applicable contracts and agreements and in compliance in all material respects with all Governmental Requirements .

Section 8.07 Insurance . The Borrower will, and will cause each Subsidiary to, maintain, with financially sound and reputable insurance companies, insurance (a) in such amounts and against such risks as are customarily maintained by companies engaged in the same or similar businesses operating in the same or similar locations and (b) in accordance with all Governmental Requirements. The loss payable clauses or provisions in said insurance policy or policies insuring any of the collateral for the Loans shall be endorsed in favor of and made payable to the Administrative Agent as its interests may appear and such policies shall name the Administrative Agent and the Lenders as “additional insureds” and “loss payees”, as applicable, and provide that the insurer will endeavor to give at least thirty (30) days prior notice of any cancellation to the Administrative Agent.

Section 8.08 Books and Records; Inspection Rights . The Borrower will, and will cause each Subsidiary to, keep proper books of record and account in which full, true and correct entries are made of all dealings and transactions in relation to its business and activities. The Borrower will, and will cause each Subsidiary to, permit any representatives designated by the Administrative Agent or any Lender, upon reasonable prior notice, to visit and inspect its Properties, to examine and make extracts from its books and records, and to discuss its affairs, finances and condition with its officers and independent accountants, all at such reasonable times and as often as reasonably requested.

Section 8.09 Compliance with Laws . The Borrower will, and will cause each Subsidiary to, comply with all laws, rules, regulations and orders of any Governmental Authority applicable to it or its Property, except where the failure to do so, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect.

Section 8.10 Environmental Matters .

(a) The Borrower shall at its sole expense: (i) comply, and shall cause its Properties and operations and each Subsidiary and each Subsidiary’s Properties and operations to comply, with all applicable Environmental Laws, the breach of which could be reasonably expected to have a Material Adverse Effect; (ii) not Release or threaten to Release any Hazardous Material on, under, about or from such Property or any other property offsite from such Property to the extent caused by the Borrower’s or any Subsidiary’s operations except in

compliance with applicable Environmental Laws, the Release or threatened Release of which could reasonably be expected to have a Material Adverse Effect; (iii) timely obtain or file, and shall cause each Subsidiary to timely obtain or file, all Environmental Permits, if any, required under applicable Environmental Laws to be obtained or filed in connection with the operation or use of such Property, which failure to obtain or file could reasonably be expected to have a Material Adverse Effect; (iv) promptly commence and diligently prosecute to completion, and shall cause each Subsidiary to promptly commence and diligently prosecute to completion, any assessment, evaluation, investigation, monitoring, containment, cleanup, removal, repair, restoration, remediation or other remedial obligations (collectively, the “ Remedial Work ”) in the event any Remedial Work is required or reasonably necessary under applicable Environmental Laws because of or in connection with the actual or suspected past, present or future Release or threatened Release of any Hazardous Material on, under, about or from any of such Property, which failure to commence and diligently prosecute to completion could reasonably be expected to have a Material Adverse Effect; (v) conduct, and cause each Subsidiary to conduct, its operations and business in a manner that will not expose such Property or Person to Hazardous Materials that could reasonably be expected to form the basis for a claim for damages or compensation that could reasonably be expected to have a Material Adverse Effect; and (vi) establish and implement, and cause each Subsidiary to establish and implement, such procedures as may be necessary to continuously determine and assure that the Borrower’ obligations under this Section 8.10(a) are timely and fully satisfied, which failure to establish and implement could reasonably be expected to have a Material Adverse Effect.

(b) The Borrower will promptly, but in no event later than five (5) days of the occurrence of any of the following, notify the Administrative Agent and the Lenders in writing of any threatened action, investigation or inquiry by any Governmental Authority or any threatened demand or lawsuit by any Person against the Borrower or its Subsidiaries or their Properties of which the Borrower has knowledge in connection with any Environmental Laws if the Borrower reasonably anticipates that such action will result in liability (whether individually or in the aggregate) in excess of $200,000, not fully covered by insurance, subject to normal deductibles.

(c) The Borrower will, and will cause each Subsidiary to, undertake reasonable environmental assessments, audits and tests in accordance with the most current version of the American Society of Testing Materials standards upon request by the Administrative Agent and the Lenders (i) if the Administrative Agent reasonably believes (A) that there has been a Release of Hazardous Materials or (B) non‑compliance with an Environmental Law has occurred, and that such an event could reasonably be expected to cause a Material Adverse Effect (or as otherwise required to be obtained by the Administrative Agent or the Lenders by any Governmental Authority), in connection with any Oil and Gas Properties or other Properties of the Borrower and its Subsidiaries

(d) To the extent the Borrower is not the operator of any Property, the Borrower will use reasonable efforts to cause the operator to comply with this Section 8.10 .

Section 8.11 Further Assurances .

(a) The Borrower at its sole expense will, and will cause each Subsidiary to, promptly execute and deliver to the Administrative Agent all such other documents, agreements and instruments reasonably requested by the Administrative Agent to comply with, cure any defects or accomplish the conditions precedent, covenants and agreements of the Borrower or any Subsidiary, as the case may be, in the Loan Documents, including the Notes, if any, or to further evidence and more fully describe the collateral intended as security for the Indebtedness, or to correct any defect, error or inaccuracy in this Agreement or the Security Instruments, or to state more fully the obligations secured therein, or to perfect, protect or preserve any Liens created pursuant to this Agreement or any of the Security Instruments or the priority thereof, or to make any recordings, file any notices or obtain any consents, all as may be reasonably necessary or appropriate, in the sole discretion of the Administrative Agent, in connection therewith.

(b) The Borrower hereby authorizes the Administrative Agent to file one or more financing or continuation statements, and amendments thereto, relative to all or any part of the Mortgaged Properties without the signature of the Borrower or any Guarantor where permitted by law. A carbon, photographic or other reproduction of the Security Instruments or any financing statement covering the Mortgaged Property or any part thereof shall be sufficient as a financing statement where permitted by law. The Borrower acknowledges and agrees that any such financing statement may describe the collateral as “all assets” of the applicable party or words of similar effect as may be required by the Administrative Agent.

Section 8.12 Reserve Reports .

(a) Commencing on May 15, 2013 and on or before each November 15 and May 15 thereafter and in connection with any Interim Redetermination, the Borrower shall furnish to the Administrative Agent and the Lenders a Reserve Report (both in .pdf and Aries .mbd file format) evaluating the Oil and Gas Properties of the Borrower and its Subsidiaries as of the immediately preceding August 31st and February 28 ^th or the relevant date established for purposes of the Interim Redetermination, as applicable. The Reserve Report shall be prepared by one or more Approved Petroleum Engineers evaluating the Proved Developed Producing Reserves, Proved Developed Nonproducing Reserves and Proved Undeveloped Reserves for the Oil and Gas Properties of the Borrower and its Subsidiaries. In connection with each Reserve Report, the Borrower shall provide the Administrative Agent and the Lenders with (i) monthly lease operating statements (including production volumes, volumes sold, sales revenues and price per volume, ad valorem, severance and production taxes and lease operating expenses) for the 12-month period ending on the effective date of the Reserve Report and for all full calendar months ending after such effective date through the date the Reserve Report is delivered to the Administrative Agent and the Lenders, covering all Proved Developed Producing Reserves of the Borrower, and (ii) a statement identifying any Proved Developed Producing Reserves that are not included in the Reserve Report.

(b) With the delivery of each Reserve Report, the Borrower shall provide to the Administrative Agent and the Lenders a certificate from a Responsible Officer, in substantially the form of Exhibit H attached hereto, certifying that: (i) the data contained in the Reserve Report and any other information delivered in connection therewith is true and correct, (ii) the Borrower and its Subsidiaries own good and defensible title to the Hydrocarbon Interests in the Oil and Gas Properties evaluated in such Reserve Report and such Properties are free of all Liens except for Liens permitted by Section 9.03, (iii) except as set forth on an exhibit to the certificate, on a net basis there are no gas imbalances, take or pay or other prepayments in excess of the volume specified in Section 7.18 with respect to its Oil and Gas Properties evaluated in such Reserve Report which would require the Borrower or any Subsidiary to deliver Hydrocarbons either generally or produced from such Oil and Gas Properties at some future time without then or thereafter receiving full payment therefor, (iv) none of the Oil and Gas Properties have been sold since the date of the last Borrowing Base determination except as set forth on an exhibit to the certificate, which certificate shall list all of its Oil and Gas Properties sold and in such detail as reasonably required by the Administrative Agent, (v) attached to the certificate is a list of all marketing agreements entered into subsequent to the later of the Effective Date or the most recently delivered Reserve Report which the Borrower could reasonably be expected to have been obligated to list on Schedule 7.19 had such agreement been in effect on the Effective Date and (vi) attached thereto is a schedule of the proved Oil and Gas Properties of the Borrower and its Subsidiaries evaluated by such Reserve Report that are Mortgaged Properties and demonstrating the percentage of the Borrowing Base that the value (by NPV) of such Mortgaged Properties represent in compliance with Section 8.12(b) .

Section 8.13 Title Information .

(a) On or before the delivery to the Administrative Agent and the Lenders of each Reserve Report required by Section 8.12(a) , the Borrower will deliver title information in form and substance reasonably acceptable to the Administrative Agent covering enough of the Oil and Gas Properties evaluated by such Reserve Report that were not included in the immediately preceding Reserve Report, so that the Administrative Agent shall have received together with title information previously delivered to the Administrative Agent, reasonably satisfactory title information on at least 80% (by NPV) of the total Proved Reserves attributable to the Oil and Gas Properties evaluated in such Reserve Report, with such 80% first being satisfied from Proved Developed Producing Reserves, next from Proved Developed Nonproducing Reserves and thereafter from Proved Undeveloped Reserves.

(b) If the Borrower has provided title information for additional Properties under Section 8.13(a) , the Borrower shall, within forty‑five (45) days of notice from the Administrative Agent that title defects or exceptions exist with respect to such additional Properties, either (i) cure any such title defects or exceptions (including defects or exceptions as to priority) which are not permitted by Section 9.03 raised by such information, (ii) substitute acceptable Mortgaged Properties with no title defects or exceptions except for Excepted Liens (other than Excepted Liens described in clauses (e), (g) and (h) of such definition) having an equivalent value or (iii) deliver title information in form and substance acceptable to the Administrative Agent so that the Administrative Agent shall have received, together with title information previously delivered to the Administrative Agent, satisfactory title information on at least 80% (by NPV) of the Oil and Gas Properties evaluated by such Reserve Report.

(c) If the Borrower is unable to cure any title defect requested by the Administrative Agent or the Lenders to be cured within the 45‑day period or the Borrower does not comply with the requirements to provide acceptable title information covering 80% (by NPV) of the Oil and Gas Properties evaluated in the most recent Reserve Report, such default shall not be a Default, but instead the Administrative Agent and/or the Lenders shall have the right to exercise the following remedy in their sole discretion from time to time, and any failure to so exercise this remedy at any time shall not be a waiver as to future exercise of the remedy by the Administrative Agent or the Lenders. To the extent that the Administrative Agent or the Lenders are not satisfied with title to any Mortgaged Property after the 45‑day period has elapsed, such unacceptable Mortgaged Property shall not count towards the 80% requirement, and the Administrative Agent may send a notice to the Borrower and the Lenders that the then outstanding Borrowing Base shall be reduced by an amount as determined by the Lenders to cause the Borrower to be in compliance with the requirement to provide acceptable title information on 80% (by NPV) of the Oil and Gas Properties evaluated in the most recent Reserve Report. This new Borrowing Base shall become effective immediately after receipt of such notice.

Section 8.14 Additional Collateral ; Additional Guarantors .

(a) In connection with each redetermination of the Borrowing Base, the Borrower shall review the Reserve Report and the list of current Mortgaged Properties (as contemplated by Section 8.12(b) (vi) ) to ascertain whether the Mortgaged Properties represent at least 80% (by NPV) of the Oil and Gas Properties evaluated in the most recently completed Reserve Report, with such 80% first being satisfied from Proved Developed Producing, next from Proved Developed Nonproducing Reserves and thereafter from Proved Undeveloped Reserves. In the event that the Mortgaged Properties do not satisfy such 80% (by NPV), then the Borrower shall, and shall cause each Subsidiary to, grant, within forty‑five (45) days of delivery of the certificate required under Section 8.12(b) , to the Administrative Agent as security for the Indebtedness a first‑priority Lien interest ( provided that Excepted Liens of the type described in clauses (a) to (d) and (f) of the definition thereof may exist, but subject to the provisos at the end of such definition) on additional Oil and Gas Properties not already subject to a Lien of the Security Instruments such that after giving effect thereto, the Borrowing Base Properties will satisfy such 80% (by NPV). All such Liens will be created and perfected by and in accordance with the provisions of deeds of trust, security agreements and financing statements or other Security Instruments, all in form and substance reasonably satisfactory to the Administrative Agent and in sufficient executed (and acknowledged where necessary or appropriate) counterparts for recording purposes.

(b) In the event that the Borrower or any of its Subsidiary forms or acquires any Subsidiary, the Borrower or such Subsidiary shall promptly cause such new Subsidiary to guarantee the Indebtedness pursuant to the Guaranty Agreement. In connection with any such guaranty, the Borrower or such Subsidiary shall, or shall cause such new Subsidiary to, (i) execute and deliver a supplement to the Guaranty Agreement executed by such new Subsidiary, (ii) pledge all of the Equity Interests of such new Subsidiary (including, without limitation, delivery of original stock certificates evidencing the Equity Interests of such Subsidiary, together with an appropriate undated stock powers for each certificate duly executed in blank by the registered owner thereof) and (iii) execute and deliver such other additional closing documents, certificates and legal opinions as shall reasonably be requested by the Administrative Agent.

Section 8.15 ERISA Compliance . The Borrower will promptly furnish and will cause the Subsidiaries and any ERISA Affiliate to promptly furnish to the Administrative Agent promptly after the filing thereof with the United States Secretary of Labor, the Internal Revenue Service of the PBGC, copies of each annual and other report with respect to each Plan or any trust created thereunder, and immediately upon becoming aware of the occurrence of any “prohibited transaction” as described in section 406 of ERISA or in section 4975 of the Code, in connection with any Plan or any trust created thereunder, a written notice signed by the President or the principal Financial Officer, the Subsidiary or the ERISA Affiliate, as the case may be, specifying the nature thereof, what action the Borrower, the Subsidiary or the ERISA Affiliate is taking or proposes to take with respect thereto, and, when known, any action taken or proposed by the Internal Revenue Service, the Department of Labor or the PBGC with respect thereto.

Section 8.16 Marketing Activities . The Borrower will not, and will not permit any Subsidiary to, engage in marketing activities for any Hydrocarbons or enter into any contracts related thereto other than (a) contracts for the sale of Hydrocarbons scheduled or reasonably estimated to be produced from its proved Oil and Gas Properties during the period of such contract, (b) contracts for the sale of Hydrocarbons scheduled or reasonably estimated to be produced from proved Oil and Gas Properties of third parties during the period of such contract associated with the Oil and Gas Properties of the Borrower or any Subsidiary that the Borrower or any Subsidiary has the right to market pursuant to joint operating agreements, unitization agreements or other similar contracts that are usual and customary in the oil and gas business and (c) other contracts for the purchase and/or sale of Hydrocarbons of third parties (i) which have generally offsetting provisions (i.e. corresponding pricing mechanics, delivery dates and points and volumes) such that no “position” is taken and (ii) for which appropriate credit support has been taken to alleviate the material credit risks of the counterparty thereto.

Section 8.17 Hedging Agreements . Subject to Section 9.18 , during the term of this Agreement, Borrower shall maintain Hedging Agreements that satisfy the following requirements: (i) the Hedging Agreements shall be implemented pursuant to a hedging strategy satisfactory to the Administrative Agent, (ii) the Hedging Agreements shall be with an Approved Counterparty, and (iii) the Hedging Agreements shall, in the aggregate, cover at least forty-five percent (45%) of estimated Hydrocarbons to be produced during a rolling 24-month period from the Proved Developed Producing Reserves reflected in the most recent Reserve Report. Notwithstanding the foregoing, the Lenders and the Administrative Agent acknowledge that the Borrower does not maintain any Hedging Agreement as of the Effective Date and shall not be required to satisfy in full the requirements of this Section 8.17 until the expiration of the 120th day after the Effective Date; provided, however, that (i) within 30 days of the Effective Date the Borrower shall maintain Hedging Agreements coveting at least fifteen percent (15%) of estimated Hydrocarbons to be produced during a rolling 24-month period from the Proved Developed Producing Reserves reflected in the Initial Reserve Report, and (ii) 60 days of the Effective Date the Borrower shall maintain Hedging Agreements coveting at least thirty percent (30%) of estimated Hydrocarbons to be produced during a rolling 24-month period from the Proved Developed Producing Reserves reflected in the Initial Reserve Report.

Section 8.18 Operating Accounts . The Borrower will, and will cause each Subsidiary to, maintain all of its bank accounts with Administrative Agent. The Borrower and each Subsidiary will cause all of its receipts to be paid directly into one or more operating or other accounts maintained with the Adminstrative Agent by the payors thereof, including by instructing the first purchasers of production or the operators, as applicable, of the Borrower’s and each Subsidiary’s Properties to pay the proceeds of the sales of production from any and all of the Borrower’s and each Subsidiary’s Properties into such account and by agreeing with any and all counterparties to any Hedging Agreement with the Borrower or its Subsidiaries that any proceeds due the Borrower from such Hedging Agreement shall be deposited in such account.

ARTICLE IX
Negative Covenants

Until the Commitments have expired or terminated and the principal of and interest on each Loan and all fees payable hereunder and all other amounts payable under the Loan Documents have been paid in full and all Letters of Credit have expired or terminated and all LC Disbursements shall have been reimbursed, the Borrower covenants and agrees with the Lenders that:

Section 9.01 Financial Covenants .

(a) Total Funded Debt to EBITDAX . The Borrower will not, at any time, permit its ratio of Total Funded Debt as of such time to EBITDAX to be greater than or equal to 3.5 to 1.0, determined at the fiscal year ending August 31, 2012, and each fiscal quarter thereafter.

(b) Current Ratio . The Borrower will not permit, as of the last day of any fiscal quarter, its ratio of (i) current assets (excluding current assets resulting from requirements of ASC Topic 815) plus unused availability under the total Commitments (but only to the extent that the conditions to borrowing are able to be met at such time) to (ii) current liabilities (excluding the current portion of the sum of each Lender’s Commitment and current liabilities resulting from the requirements of ASC Topic 815), determined at the end of fiscal year ending August 31, 2012, and each quarter thereafter, to be less than 1.0 to 1.0.

(c) Ratio of EBITDAX to Interest and Fees . The Borrower will not permit, as of the last day of any fiscal quarter, its ratio of EBITDAX divided by 4 to the sum of interest expense for such fiscal quarter, to be less than or equal to 3.5 to 1.0, determined at the end of the fiscal year ending August 31, 2012, and each quarter thereafter.

(d) Ratio of Total Funded Debt to Total Capitalization . The Borrower will not permit, as of the last day of any fiscal quarter, its ratio of its Total Funded Debt as of such time to its Total Capitalization as of such time to be greater than or equal to 0.35 to 1.0.

Section 9.02 Debt . The Borrower will not, and will not permit any Subsidiary to, incur, create, assume or suffer to exist any Debt, except:

(a) the Notes or other Indebtedness arising under the Loan Documents or any guaranty of or suretyship arrangement for the Notes or other Indebtedness arising under the Loan Documents;

(b) endorsements of negotiable instruments for collection in the ordinary course of business;

(d) Debt associated with bonds or surety obligations required by Governmental Requirements in connection with the operation of, or provision for the abandonment and remediation of, the Oil and Gas Properties.

Section 9.03 Liens . The Borrower will not, and will not permit any Subsidiary to, create, incur, assume or permit to exist any Lien on any of its Property (now owned or hereafter acquired), except:

(a) Liens securing the payment of any Indebtedness; and

(b) Excepted Liens.

Section 9.04 Dividends and Distributions . The Borrower will not, and will not permit any Subsidiary to, declare or make, or agree to pay or make, directly or indirectly, any Restricted Payment, return any capital to its to its shareholders or make any distribution of its Property to its Equity Interest holders.

Section 9.05 Investments, Loans and Advances . The Borrower will not, and will not permit any Subsidiary to, make or permit to remain outstanding any Investments in or to any Person, except that the foregoing restriction shall not apply to:

(a) accounts receivable arising in the ordinary course of business;

(b) direct obligations of the United States or any agency thereof, or obligations guaranteed by the United States or any agency thereof, in each case maturing within one year from the date of acquisition thereof;

(c) commercial paper maturing within one year from the date of acquisition thereof rated in the highest grade by S&P or Moody’s;

(d) deposit accounts or deposits maturing within one year from the date of creation thereof with, including certificates of deposit issued by, any Lender or any other Person at any office located in the United States which is organized under the laws of the United States or any state thereof, has capital, surplus and undivided profits aggregating at least $100,000,000 (as of the date of such bank or trust company’s most recent financial reports) and has a short term deposit rating of no lower than A2 or P2, as such rating is set forth from time to time, by S&P or Moody’s, respectively;

(e) deposits in money market funds investing exclusively in Investments described in Section 9.05(b) , Section 9.05(c) or Section 9.05(d) ;

(f) investments in direct ownership interests in additional Oil and Gas Properties and gas gathering systems related thereto or related to farm‑out, farm‑in, joint operating, joint venture or area of mutual interest agreements, gathering systems, pipelines or other similar arrangements which are usual and customary in the oil and gas exploration and production business located within the onshore continental boundaries of the United States of America;

(g) investments in direct ownership interests in, or, subject to Section 9.15 , to acquire new Subsidiaries that own, additional Oil and Gas Properties and all other assets related to the business permitted under Section 9.06 ;

(h) investments made by any Guarantor in or to the Borrower or any other Guarantor;

(i) entry into operating agreements, working interests, royalty interests, mineral leases, processing agreements, farm-out agreements, contracts for the sale, transportation or exchange of oil and natural gas, unitization agreements, pooling arrangements, area of mutual interest agreements, production sharing agreements or other similar or customary agreements, transactions, properties, interests or arrangements, and Investments and expenditures in connection therewith or pursuant thereto, in each case made or entered into in the ordinary course of the oil and gas business, excluding, however, Investments in other Persons; provided, however, that none of the foregoing shall involve the incurrence of any Debt not permitted by Section 9.02 ; and

(j) other Investments not to exceed $200,000 in the aggregate at any time.

Section 9.06 Nature of Business . The Borrower will not allow any material change to be made in the character of its business as an independent oil and gas exploration and production company. From and after the date hereof, the Borrower and its Subsidiaries will not acquire or make any other expenditure (whether such expenditure is capital, operating or otherwise) in or related to, any Oil and Gas Properties not located within the onshore continental boundaries of the United States.

Section 9.07 Limitation on Leases . The Borrower will not, and will not permit any Subsidiary to, create, incur, assume or suffer to exist any obligation for the payment of rent or hire of Property of any kind whatsoever (real or personal but excluding leases of Hydrocarbon Interests), under leases or lease agreements which would cause the aggregate amount of all payments made by the Borrower and the Subsidiaries pursuant to all such leases or lease agreements, including any residual payments at the end of any lease, to exceed $100,000 in any period of twelve consecutive calendar months during the life of such leases.

Section 9.08 Proceeds of Notes . The Borrower will not, and will not permit any Subsidiary to, use the proceeds of the Notes for any purpose other than those permitted by Section 7.21 . Neither the Borrower nor any Person acting on behalf of the Borrower has taken or will take any action which might cause any of the Loan Documents to violate Regulations T, U or X or any other regulation of the Board or to violate section 7(a) of the Securities Exchange Act of 1934 or any rule or regulation thereunder, in each case as now in effect or as the same may hereinafter be in effect. If requested by the Administrative Agent, the Borrower will furnish to the Administrative Agent and each Lender a statement to the foregoing effect in conformity with the requirements of FR Form U‑1 or such other form referred to in Regulation U, Regulation T or Regulation X of the Board, as the case may be.

Section 9.09 ERISA Compliance . The Borrower will not, and will not permit any Subsidiary to, at any time:

(a) engage in, or permit any ERISA Affiliate to engage in, any transaction in connection with which the Borrower, a Subsidiary or any ERISA Affiliate could be subjected to either a civil penalty assessed pursuant to subsections (c), (i), (l) or (m) of section 502 of ERISA or a tax imposed by Chapter 43 of Subtitle D of the Code if such penalty or liability could reasonably be expected to result in a Material Adverse Effect.

(b) Fail to make, or permit any ERISA Affiliate to fail to make, full payment when due of all amounts which, under the provisions of any Plan, agreement relating thereto or applicable law, the Borrower, a Subsidairy or any ERISA Affiliate is required to pay as contributions thereto if such failure could reasonably be expected to result in a Material Adverse Effect.

(c) contribute to or assume an obligation to contribute to, or permit any ERISA Affiliate to contribute to or assume an obligation to contribute to (i) any employee welfare benefit plan, as defined in section 3(1) of ERISA, including any such plan maintained to provide benefits to former employees of such entities, that may not be terminated by such entities in their sole discretion at any time without any material liability, or (ii) any employee pension benefit plan, as defined in section 3(2) of ERISA, that is subject to Title IV of ERISA, section 302 of ERISA or section 412 of the Code.

Section 9.10 Mergers, Etc . The Borrower will not, and will not permit any Subsidiary to, merge into or with or consolidate with any other Person, or permit any other Person to merge into or consolidate with it, or sell, transfer, lease or otherwise dispose of (whether in one transaction or in a series of transactions) all or substantially all of its Property to any other Person (whether now owned or hereafter acquired), or liquidate or dissolve; provided that any Subsidiary may participate in a consolidation with (i) the Borrower so long as the Borrower shall be the continuing or surviving entity or (ii) any other Subsidiary (provided that if one of such Subsidiaries is a wholly-owned Subsidiary, then the surviving Person shall be a wholly-owned Subsidiary).

Section 9.11 Sale of Properties . The Borrower will not, and will not permit any Subsidiary to, sell, assign, farm‑out, convey or otherwise transfer (including through the sale of a production payment or overriding royalty interest) any of its Oil and Gas Properties except for (a) the sale of Hydrocarbons in the ordinary course of business; (b) farmouts or similar arrangements related to undeveloped acreage and assignments in connection with such farmouts or similar arrangements; provided that any farmouts or similar arrangements that relate to Oil and Gas Property included in the most recently delivered Reserve Report shall require the

approval of the Administrative Agent if such farmouts or similar arrangements over any rolling 12-month period relate to Oil and Gas Properties that have an NPV in excess of five percent (5%) of the Borrowing Base then in effect, but such consent shall only be required for those farmouts or similar arrangements in excess of such amount; (c) the sale or transfer of equipment that is no longer necessary for the business of the Borrower or any Subsidiary or that is replaced by equipment of at least comparable value and use; (d) the sale or other disposition (including Casualty Events and any indirect sale of properties by the sale of a Subsidiary) of any Oil and Gas Property or any interest therein; provided that (i) 100% of the consideration received in respect of such sale or other disposition shall be cash, (ii) the consideration received in respect of such sale or other disposition shall be equal to or greater than the fair market value of the Oil and Gas Property, interest therein subject to such sale or other disposition (as reasonably determined by the board of directors of the Borrower and, if requested by the Administrative Agent, the Borrower shall deliver a certificate of a Responsible Officer of the Borrower certifying to that effect), (iii) if such Oil and Gas Property was included in the most recently delivered Reserve Report and has a fair market value in excess of $200,000, individually or in the aggregate, the Borrowing Base shall automatically be reduced pursuant to Section 2.07(f)(ii) , by an amount equal to the value, if any, assigned such Oil and Gas Property in the most recently delivered Reserve Report and (iv) if any such sale or other disposition is of a Subsidiary owning Oil and Gas Properties, such sale or other disposition shall include all the Equity Interests of such Subsidiary; (e) the disposition of Oil and Gas Properties in exchange for fair consideration in the form of either (i) other Oil and Gas Properties of a similar use or purpose or (ii) an operator’s commitment to drill an oil or natural gas well; provided that in the case of each of subclauses (i) and (ii) above, the consideration received is of equivalent or greater fair market value as the properties being disposed of (as reasonably determined by the board of directors of the Borrower) and, to the extent applicable, the Borrower has delivered title information and mortgages covering the Oil and Gas Properties received by the Borrower as may be required pursuant to Section 8.13 and Section 8.14 ; and sales and other dispositions of Properties not regulated by Section 9.11 (a) to Section 9.11 (e) having a fair market value not to exceed five percent (5%) of the Borrowing Base then in effect during any twelve (12) month period. If following any Redetermination Date (and prior to the next Redetermination Date), the Borrower and its Subsidiaries, in the aggregate, directly or indirectly sells (whether through one or more transactions) Oil and Gas Properties having a borrowing base value equal to or in excess of ten percent (10%) of the aggregate borrowing base value of all Oil and Gas Properties of the Borrower and its Subsidiaries, as determined by the Administrative Agent based upon the most recent Reserve Report, the Required Lenders shall have the right to request an additional Borrowing Base determination in accordance with Section 2.07(b) . The Administrative Agent shall reasonably cooperate with Borrower, at Borrower’s cost and expense, to promptly provide a release of lien for any Oil and Gas Property that is being transferred or conveyed by the Borrower or its Subsidiaries in accordance with this Section 9.11 , provided that Borrower provides the Administrative Agent with any documents or certificates reasonably requested by the Administrative Agent to establish compliance with this Section 9.11 .

Section 9.12 Environmental Matters . The Borrower will not, and will not permit any Subsidiary to, cause or permit any of its Properties to be in violation of, or do anything or permit anything to be done which will subject any such Properties to a Release or threatened Release of Hazardous Materials, exposure to any Hazardous Materials, or to any Remedial Work under any Environmental Laws, assuming disclosure to the applicable Governmental Authority of all relevant facts, conditions and circumstances, if any, pertaining to such Property where such violations, Release or threatened Release, exposure, or Remedial work could reasonably be expected to have a Material Adverse Effect.

Section 9.13 Material Agreements . The Borrower will not, and will not permit any Subsidiary to, enter into or amend or otherwise modify any Material Agreement or any other contract or agreement that involves an individual commitment from such Person of more than $200,000 in the aggregate in any twelve (12) month period, except for contracts for the acquisition and/or development of Oil and Gas Properties .

Section 9.14 Transactions with Affiliates . The Borrower will not, and will not permit any Subsidiary to, enter into any transaction, including any purchase, sale, lease or exchange of Property or the rendering of any service or the making of any loan, with any Affiliate (other than a Guarantor) or shareholder of the Borrower unless such transactions are otherwise permitted under this Agreement and are upon terms no less favorable to it than it would obtain in a comparable arm’s length transaction with an independent third party.

Section 9.15 Subsidiaries . The Borrower shall not, and will not permit any Subsidiary to, create or acquire any Subsidiary without the prior written consent of the Administrative Agent, which consent shall not to be unreasonably withheld; provided that any such consent shall be conditioned on such amendments and conditions precedents as the Administrative Agent and the Required Lenders shall reasonably require, including, without limitation, that the Borrower, contemporaneously with the formation or acquisition of such Subsidiary, (a) cause such new Subsidiary to become a Guarantor to guarantee the Indebtedness and deliver to the Administrative Agent (x) an executed supplement or assumption agreement to the Guaranty Agreement in form and substance reasonably acceptable to the Administrative Agent, and (y) an executed supplement or assumption agreement to the Security Agreement, (b) pledge all of the Equity Interests of such new Subsidiary (including, without limitation, delivery of original stock certificates evidencing the Equity Interests of such new Subsidiary, together with an appropriate undated stock powers for each certificate duly executed in blank by the registered owner thereof) and (c) execute and deliver, or cause to be delivered, such other additional closing documents, certificates, tribal consents and legal opinions as shall be requested by the Administrative Agent.

Section 9.16 Negative Pledge Agreements . The Borrower will not, and will not permit any Subsidiary to, create, incur, assume or suffer to exist any contract, agreement or understanding (other than this Agreement, the Security Instruments, or Capital Leases creating Liens permitted by Section 9.03 ) which in any way prohibits or restricts the granting, conveying, creation or imposition of any Lien on any of its Properties in favor of the Administrative Agent and the Lenders or which requires the consent of or notice to other Persons in connection therewith.

Section 9.17 Gas Imbalances, Take‑or‑Pay or Other Prepayments . The Borrower will not, and will not permit any Subsidiary to, allow gas imbalances, take‑or‑pay or other prepayments with respect to the Oil and Gas Properties of the Borrower or any of its Subsidiaries that would require the Borrower or a Subsidiary to deliver Hydrocarbons at some future time without then or thereafter receiving full payment therefor to exceed two percent (2%) of the Borrower’s Proved Reserves of natural gas (on an mcf equivalent basis) in the aggregate.

Section 9.18 Hedging Agreements . The Borrower shall neither assign, terminate , unwind nor sell any Hedging Agreements listed on Schedule 7.20 . The Borrower shall not enter into Hedging Agreements in respect of commodities other than Hydrocarbons. In the case of Hydrocarbons, the Borrower shall not enter into Hedging Agreements if the effect thereof would be to cause the notional volumes of all Hedging Agreements and additional fixed price physical off take contracts, in the aggregate, to exceed (i) 85% of the projected production from the Borrower’s Proved Developed Producing Reserves reflected in the most recently completed Reserve Report for any month continuing through and including the date that is twelve (12) months following the effective date of each such Hedging Agreement, (ii) 70% of the projected production from the Borrower’s Proved Developed Producing Reserves for any month beginning at the expiration of the period in clause (i) and continuing through and including the date that is twelve (12) months following such date, (iii) 60% of the projected production from the Borrower’s Proved Developed Producing Reserves for any month beginning at the expiration of the period in clause (ii) and continuing through and including the date that is twelve (12) months following such date and (iv) 50% of the projected production from the Borrower’s Proved Developed Producing Reserves for any month beginning at the expiration of the period clause (iii) and continuing through and including the date that is twelve (12) months following such date (it being understood that any put contracts entered into for non speculative purposes shall not count against the above limitation). The Borrower shall not enter into Hedging Agreements converting interest rates. The Borrower shall not post any collateral to secure Hedging Agreements, except as contemplated by the Loan Documents in the case of a Secured Hedging Counterparty.

Section 9.19 Sale and Leasebacks . The Borrower will not, and will not permit any Subsidiary, to enter into any arrangement, directly or indirectly, with any Person whereby the Borrower or any Subsidiary shall sell or transfer any of its Property, whether now owned or hereafter acquired, and whereby Borrower shall then or thereafter rent or lease as lessee such Property or any part thereof or other Property which Borrower or any Subsidiary intends to use for substantially the same purpose or purposes as the Property sold or transferred.

Section 9.20 Amendments to Organizational Documents . Without the prior written consent of the Lenders, the Borrower will not amend, or permit to be amended, its Organizational Documents or waive any right or obligation of any Person thereunder except to the extent such amendment or waiver could not reasonably be expected to adversely affect the rights and benefits of the Administrative Agent, the Lenders and/or other secured parties under this Agreement or any other Loan Document.

ARTICLE X
Events of Default; Remedies

Section 10.01 Events of Default . One or more of the following events shall constitute an “ Event of Default ”:

(a) the Borrower shall fail to pay any principal of any Loan or any reimbursement obligation in respect of any LC Disbursement when and as the same shall become due and payable, whether at the due date thereof or at a date fixed for prepayment thereof, by acceleration or otherwise;

(b) the Borrower shall fail to pay any interest on any Loan or any fee or any other amount (other than an amount referred to in Section 10.01(a)) payable under any Loan Document, when and as the same shall become due and payable, and such failure shall continue unremedied for a period of five (5) Business Days;

(c) any representation or warranty made or deemed made by or on behalf of the Borrower in or in connection with any Loan Document or any amendment or modification of any Loan Document or waiver under such Loan Document or in any report, certificate, financial statement or other document furnished pursuant to or in connection with any Loan Document or any amendment or modification thereof or waiver thereunder, shall prove to have been incorrect in any material respect when made or deemed made;

(d) the Borrower shall fail to observe or perform any covenant, condition or agreement contained in the Loan Documents;

(e) the Borrower shall fail to make any payment (whether of principal or interest and regardless of amount) in respect of any Material Debt, beyond any period of grace provided with respect thereto;

(f) any event or condition occurs that results in any Material Debt becoming due prior to its scheduled maturity or that enables or permits the holder or holders of any Material Debt or any trustee or agent on its or their behalf to cause any Material Debt to become due (after taking into account any applicable period of grace with respect thereto), or to require the Redemption thereof or any offer to Redeem to be made in respect thereof, prior to its scheduled maturity or an event or condition requires the Borrower to make an offer in respect thereof;

(g) an involuntary proceeding shall be commenced or an involuntary petition shall be filed seeking (i) liquidation, reorganization or other relief in respect of the Borrower or its debts, or of a substantial part of its assets, under any Federal, state or foreign bankruptcy, insolvency, receivership or similar law now or hereafter in effect or (ii) the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for the Borrower or for a substantial part of its assets, and, in any such case, such proceeding or petition shall continue undismissed for forty‑five (45) days or an order or decree approving or ordering any of the foregoing shall be entered;

(h) the Borrower shall (i) voluntarily commence any proceeding or file any petition seeking liquidation, reorganization or other relief under any Federal, state or foreign bankruptcy, insolvency, receivership or similar law now or hereafter in effect, (ii) consent to the institution of, or fail to contest in a timely and appropriate manner, any proceeding or petition described in Section 10.01(g) , (iii) apply for or consent to the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for the Borrower for a substantial part of its assets, (iv) file an answer admitting the material allegations of a petition filed against it in any such proceeding, (v) make a general assignment for the benefit of creditors or (vi) take any action for the purpose of effecting any of the foregoing;

(i) the Borrower shall become unable, admit in writing its inability or fail generally to pay its debts as they become due;

(j) (i) one or more judgments for the payment of money in an aggregate amount in excess of $200,000 (to the extent not covered by independent third party insurance provided by insurers acceptable to the Administrative Agent as to which the insurer does not dispute coverage and is not subject to an insolvency proceeding) or (ii) any one or more non‑monetary judgments that have, or could reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect, shall be rendered against the Borrower, any Subsidiary or any combination thereof and, in either such case, the same shall remain undischarged for a period of forty‑five (45) consecutive days during which execution shall not be effectively stayed, or any action shall be legally taken by a judgment creditor to attach or levy upon any assets of the Borrower to enforce any such judgment;

(k) the Borrower or an ERISA Affiliate is not in compliance with all material respects with ERISA and, where applicable, the Code regarding each Plan, except to the extent the failure to do so could not reasonably be expected to result in a Material Adverse Effect;

(l) the Loan Documents after delivery thereof shall for any reason, except to the extent permitted by the terms thereof, cease to be in full force and effect and valid, binding and enforceable in accordance with their terms against the Borrower or shall be repudiated by any of them, or cease to create a valid and perfected Lien of the priority required thereby on any of the collateral purported to be covered thereby, except to the extent permitted by the terms of this Agreement, or the Borrower or its Affiliates shall so state in writing;

(m) a Change in Control shall occur;

(n) a failure to cure a Borrowing Base Deficiency as outlined in Section 3.04(c)(i) or (ii) ; and

(o) an “Event of Default”, “Termination Event” or “Additional Termination Event” (other than an “Event of Default”, “Termination Event” or “Additional Termination Event” associated with a breach thereof by a Lender) shall occur under any Hedging Agreement between the Borrower and any Lender or Affiliate of any Lender (in each case after giving effect to any applicable grace periods).

Section 10.02 Remedies .

(a) In the case of an Event of Default other than one described in Section 10.01(g) , Section 10.01(h) or Section 10.01(i) , at any time thereafter during the continuance of such Event of Default, the Administrative Agent may, and at the request of the Lenders, shall, by notice to the Borrower, take either or both of the following actions, at the same or different times: (i) terminate the Commitments, and thereupon the Commitments shall terminate immediately, and (ii) declare the Notes and the Loans then outstanding to be due and payable in whole (or in part, in which case any principal not so declared to be due and payable may thereafter be declared to be due and payable), and thereupon the principal of the Loans so declared to be due and payable, together with accrued interest thereon and all fees and other obligations of the Borrower and the Guarantors accrued hereunder and under the Notes and the other Loan Documents (including the payment of cash collateral to secure the LC Exposure as provided in Section 2.08(i) ), shall become due and payable immediately, without presentment, demand, protest, notice of intent to accelerate, notice of acceleration or other notice of any kind, all of which are hereby waived by the Borrower; and in case of an Event of Default described in Section 10.01(g) , Section 10.01(h) or Section 10.01(i) , the Commitments shall automatically terminate and such Notes and the principal of such Loans then outstanding, together with accrued interest thereon and all fees and the other obligations of the Borrower and the Guarantors accrued hereunder and under such Notes and the other Loan Documents (including the payment of cash collateral to secure the LC Exposure as provided in Section 2.08(i) ), shall automatically become due and payable, without presentment, demand, protest or other notice of any kind, all of which are hereby waived by the Borrower and each Guarantor.

(b) In the case of the occurrence of an Event of Default, the Administrative Agent and the Lenders will have all other rights and remedies available at law and equity.

(c) All proceeds realized from the liquidation or other disposition of collateral or otherwise received after maturity of the Notes, whether by acceleration or otherwise, shall be applied:

(i) first , to payment or reimbursement of that portion of the Indebtedness constituting fees, expenses and indemnities payable to the Administrative Agent in its capacity as such;

(ii) second , pro rata to payment or reimbursement of that portion of the Indebtedness constituting fees, expenses and indemnities payable to the Lenders;

(iii) third , pro rata to payment of accrued interest on the Loans;

(iv) fourth , pro rata to payment of all other Indebtedness;

(v) fifth , to serve as cash collateral to be held by the Administrative Agent to secure LC Exposure; and

(vi) sixth , any excess, after all of the Indebtedness shall have been indefeasibly paid in full in cash, shall be paid to the Borrower or as otherwise required by any Governmental Requirement.

Section 10.03 Limitation on Rights and Waivers . All rights, powers and remedies herein conferred shall be exercisable by Administrative Agent and any other Secured Party only to the extent not prohibited by applicable law; and all waivers and relinquishments of rights and similar matters shall only be effective to the extent such waivers or relinquishments are not prohibited by applicable law.

ARTICLE XI
The Administrative Agent

Section 11.01 Appointment; Powers . Each of the Lenders and each Issuing Bank hereby irrevocably (subject to Section 11.06 ) appoints the Administrative Agent as its agent and authorizes the Administrative Agent to take such actions on its behalf and to exercise such powers as are delegated to the Administrative Agent by the terms hereof and the other Loan Documents, together with such actions and powers as are reasonably incidental thereto.

Section 11.02 Duties and Obligations of Administrative Agent . The Administrative Agent shall not have any duties or obligations except those expressly set forth in the Loan Documents. Without limiting the generality of the foregoing, (a) the Administrative Agent shall not be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing (the use of the term “agent” herein and in the other Loan Documents with reference to the Administrative Agent is not intended to connote any fiduciary or other implied (or express) obligations arising under agency doctrine of any applicable law; rather, such term is used merely as a matter of market custom, and is intended to create or reflect only an administrative relationship between independent contracting parties), (b) the Administrative Agent shall have no duty to take any discretionary action or exercise any discretionary powers, except as provided in Section 11.03 , and (c) except as expressly set forth herein, the Administrative Agent shall not have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to the Borrower or any of its Subsidiaries that is communicated to or obtained by the bank serving as Administrative Agent or any of its Affiliates in any capacity. The Administrative Agent shall be deemed not to have knowledge of any Default unless and until written notice thereof is given to the Administrative Agent by the Borrower or a Lender, and shall not be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement or any other Loan Document, (ii) the contents of any certificate, report or other document delivered hereunder or under any other Loan Document or in connection herewith or therewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein or in any other Loan Document, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement, any other Loan Document or any other agreement, instrument or document, (v) the satisfaction of any condition set forth in Article VI or elsewhere herein, other than to confirm receipt of items expressly required to be delivered to the Administrative Agent or as to those conditions precedent expressly required to be to the Administrative Agent’s satisfaction, (vi) the existence, value, perfection or priority of any collateral security or the financial or other condition of the Borrower or any other obligor or guarantor, or (vii) any failure by the Borrower or any other Person (other than itself) to perform any of its obligations hereunder or under any other Loan Document or the performance or observance of any covenants, agreements or other terms or conditions set forth herein or therein. For purposes of determining compliance with the conditions specified in Article VI , each Lender shall be deemed to have consented to, approved or accepted or to be satisfied with, each document or other matter required thereunder to be consented to or approved by or acceptable or satisfactory to a Lender unless the Administrative Agent shall have received written notice from such Lender prior to the proposed closing date specifying its objection thereto.

Section 11.03 Action by Administrative Agent . The Administrative Agent shall have no duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby or by the other Loan Documents that the Administrative Agent is required to exercise in writing as directed by the Lenders and in all cases the Administrative Agent shall be fully justified in failing or refusing to act hereunder or under any other Loan Documents unless it shall (a) receive written instructions from the Lenders, as applicable, (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 12.02 ) specifying the action to be taken and (b) be indemnified to its satisfaction by the Lenders against any and all liability and expenses which may be incurred by it by reason of taking or continuing to take any such action. The instructions as aforesaid and any action taken or failure to act pursuant thereto by the Administrative Agent shall be binding on all of the Lenders. If a Default has occurred and is continuing, then the Administrative Agent shall take such action with respect to such Default as shall be directed by the requisite Lenders in the written instructions (with indemnities) described in this Section 11.03 , provided that, unless and until the Administrative Agent shall have received such directions, the Administrative Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default as it shall deem advisable in the best interests of the Lenders. In no event, however, shall the Administrative Agent be required to take any action which exposes the Administrative Agent to personal liability or which is contrary to this Agreement, the Loan Documents or applicable law. The Administrative Agent shall not be liable for any action taken or not taken by it with the consent or at the request of the Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 12.02 ), and otherwise the Administrative Agent shall not be liable for any action taken or not taken by it hereunder or under any other Loan Document or under any other document or instrument referred to or provided for herein or therein or in connection herewith or therewith INCLUDING ITS OWN ORDINARY NEGLIGENCE, except for its own gross negligence or willful misconduct.

Section 11.04 Reliance by Administrative Agent . The Administrative Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing believed by it to be genuine and to have been signed or sent by the proper Person. The Administrative Agent also may rely upon any statement made to it orally or by telephone and believed by it to be made by the proper Person, and shall not incur any liability for relying thereon and each of the Borrower, the Issuing Banks and the Lenders hereby waive the right to dispute the Administrative Agent’s record of such statement, except in the case of gross negligence or willful misconduct by the Administrative Agent. The Administrative Agent may consult with legal counsel (who may be counsel for the Borrower), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts. The Administrative Agent may deem and treat the payee of any Note as the holder thereof for all purposes hereof unless and until a written notice of the assignment or transfer thereof permitted hereunder shall have been filed with the Administrative Agent.

Section 11.05 Subagents . The Administrative Agent may perform any and all its duties and exercise its rights and powers by or through any one or more sub‑agents appointed by the Administrative Agent. The Administrative Agent and any such sub‑agent may perform any and all its duties and exercise its rights and powers through their respective Related Parties. The exculpatory provisions of the preceding Sections of this Article XI shall apply to any such sub‑agent and to the Related Parties of the Administrative Agent and any such sub‑agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Administrative Agent.

Section 11.06 Resignation or Removal of Administrative Agent . Subject to the appointment and acceptance of a successor Administrative Agent as provided in this Section 11.06 , the Administrative Agent may resign at any time by notifying the the Lenders and the Borrower, and the Administrative Agent may be removed at any time with or without cause by the Lenders. Upon any such resignation or removal, the Lenders shall have the right, in consultation with the Borrower (provided no Event of Default then exist), to appoint a successor. If no successor shall have been so appointed by the Lenders and shall have accepted such appointment within thirty (30) days after the retiring Administrative Agent gives notice of its resignation or removal of the retiring Administrative Agent, then the retiring Administrative Agent may, on behalf of the Issuing Banks and Lenders, appoint a successor Administrative Agent. Upon the acceptance of its appointment as Administrative Agent hereunder by a successor, such successor shall succeed to and become vested with all the rights, powers, privileges and duties of the retiring Administrative Agent, and the retiring Administrative Agent shall be discharged from its duties and obligations hereunder. The fees payable by the Borrower to a successor Administrative Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Borrower and such successor. After the Administrative Agent’s resignation hereunder, the provisions of this Article XI and Section 12.03 shall continue in effect for the benefit of such retiring Administrative Agent, its sub‑agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while it was acting as Administrative Agent.

Section 11.07 Administrative Agent as Lender . Each Person serving as an Administrative Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not an Administrative Agent, and such bank and its Affiliates may accept deposits from, lend money to and generally engage in any kind of business with the Borrower or any Subsidiary or other Affiliate thereof as if it were not an Administrative Agent hereunder.

Section 11.08 No Reliance . Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement and each other Loan Document to which it is a party. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any other Loan Document, any related agreement or any document furnished hereunder or thereunder. The Administrative Agent shall not be required to keep itself informed as to the performance or observance by the Borrower or any of its Subsidiaries of this Agreement, the Loan Documents or any other document referred to or provided for herein or to inspect the Properties or books of the Borrower or its Subsidiaries. Except for notices, reports and other documents and information expressly required to be furnished to the Lenders by the Administrative Agent hereunder, the Administrative Agent shall not have any duty or responsibility to provide any Lender with any credit or other information concerning the affairs, financial condition or business of the Borrower (or any of its Affiliates) which may come into the possession of such Agent or any of its Affiliates. In this regard, each Lender acknowledges that Faegre Baker Daniels is acting in this transaction as counsel to the Administrative Agent only, except to the extent otherwise expressly stated in any legal opinion or any Loan Document. Each other party hereto will consult with its own legal counsel to the extent that it deems necessary in connection with the Loan Documents and the matters contemplated therein.

Section 11.09 Administrative Agent May File Proofs of Claim . In case of the pendency of any receivership, insolvency, liquidation, bankruptcy, reorganization, arrangement, adjustment, composition or other judicial proceeding relative to the Borrower or any of its Subsidiaries, the Administrative Agent (irrespective of whether the principal of any Loan shall then be due and payable as herein expressed or by declaration or otherwise and irrespective of whether the Administrative Agent shall have made any demand on the Borrower) shall be entitled and empowered, by intervention in such proceeding or otherwise:

(a) to file and prove a claim for the whole amount of the principal and interest owing and unpaid in respect of the Loans and all other Indebtedness that are owing and unpaid and to file such other documents as may be necessary or advisable in order to have the claims of the Lenders and the Administrative Agent (including any claim for the reasonable compensation, expenses, disbursements and advances of the Lenders and the Administrative Agent and their respective agents and counsel and all other amounts due the Lenders and the Administrative Agent under Section 12.03 ) allowed in such judicial proceeding;

(b) to collect and receive any monies or other property payable or deliverable on any such claims and to distribute the same;

and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Lender to make such payments to the Administrative Agent and, in the event that the Administrative Agent shall consent to the making of such payments directly to the Lenders, to pay to the Administrative Agent any amount due for the reasonable compensation, expenses, disbursements and advances of the Administrative Agent and its agents and counsel, and any other amounts due the Administrative Agent under Section 12.03 .

Nothing contained herein shall be deemed to authorize the Administrative Agent to authorize or consent to or accept or adopt on behalf of any Lender any plan of reorganization, arrangement, adjustment or composition affecting the Indebtedness or the rights of any Lender or to authorize the Administrative Agent to vote in respect of the claim of any Lender in any such proceeding.

Section 11.10 Authority of Administrative Agent to Release Collateral and Liens . Each Lender and each Issuing Bank hereby authorizes the Administrative Agent to release any collateral that is permitted to be sold or released pursuant to the terms of the Loan Documents. Each Lender and each Issuing Bank hereby authorizes the Administrative Agent to execute and deliver to the Borrower, at the Borrower’s sole cost and expense, any and all releases of Liens, termination statements, assignments or other documents reasonably requested by the Borrower in connection with any sale or other disposition of Property to the extent such sale or other disposition is permitted by the terms of Section 9.11 or is otherwise authorized by the terms of the Loan Documents.

ARTICLE XII
Miscellaneous

Section 12.01 Notices .

(a) Except in the case of notices and other communications expressly permitted to be given by telephone (and subject to Section 12.01(b) ), all notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by facsimile transmission, as follows:

(i) if to the Borrower, to it at: Synergy Resources Corporation 20203 Highway 60 Platteville, CO 80651, Attention: Edward Holloway, CEO and Director (facsimile number 970-737-1073;

(ii) if to the Administrative Agent, to it at: Community Banks of Colorado, 3780 West 10th Street, Greeley, Colorado 80634, Attention: Sarah Burchett, Vice President (facsimile number 855-621-4025); and

(iii) if to any other Lender, to it at its address (or facsimile number) set forth on its signature page to this Agreement or, if applicable, any Assignment and Assumption.

(b) Notices sent by hand or overnight courier service, or mailed by certified or registered mail, shall be deemed to have been given when received. Notices sent by facsimile shall be deemed to have been given when sent (except that, if not sent during normal business hours for the recipient, shall be deemed to have been given at the opening of business on the next business day for the recipient). Notices delivered through electronic communications, to the extent provided in Section 12.01(c) , shall be effective as provided in Section 12.01(c) .

(c) Notices and other communications to the Lenders hereunder may be delivered or furnished by electronic communications pursuant to procedures approved by the Administrative Agent; provided that the foregoing shall not apply to notices pursuant to Article II , Article III , Article IV and Article V unless otherwise agreed by the Administrative Agent and the applicable Lender. The Administrative Agent or the Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

(d) Any party hereto may change its address or facsimile transmission number for notices and other communications hereunder by notice to the other parties hereto. All notices and other communications given to any party hereto in accordance with the provisions of this Agreement shall be deemed to have been given on the date of receipt.

Section 12.02 Waivers; Amendments .

(a) No failure on the part of the Administrative Agent, any Issuing Bank or any Lender to exercise and no delay in exercising, and no course of dealing with respect to, any right, power or privilege, or any abandonment or discontinuance of steps to enforce such right, power or privilege, under any of the Loan Documents shall operate as a waiver thereof, nor shall any single or partial exercise of any right, power or privilege under any of the Loan Documents preclude any other or further exercise thereof or the exercise of any other right, power or privilege. The rights and remedies of the Administrative Agent, the Issuing Banks and the Lenders hereunder and under the other Loan Documents are cumulative and are not exclusive of any rights or remedies that they would otherwise have. No waiver of any provision of this Agreement or any other Loan Document or consent to any departure by the Borrower therefrom shall in any event be effective unless the same shall be permitted by Section 12.02(b) , and then such waiver or consent shall be effective only in the specific instance and for the purpose for which given. Without limiting the generality of the foregoing, the making of a Loan or issuance of a Letter of Credit shall not be construed as a waiver of any Default, regardless of whether the Administrative Agent, any Issuing Bank or any Lender may have had notice or knowledge of such Default at the time.

(b) Neither this Agreement nor any provision hereof nor any Security Instrument nor any provision thereof may be waived, amended or modified except pursuant to an agreement or agreements in writing entered into by the Borrower and the Lenders or by the Borrower and the Administrative Agent with the consent of the Lenders; provided that no such agreement shall (i) increase the Commitment or the Maximum Credit Amount of any Lender without the written consent of such Lender, (ii) increase the Borrowing Base without the written consent of each Lender, decrease or maintain the Borrowing Base without the written consent of each Lender (other than any Defaulting Lender), or modify Section 2.07 in any manner without the consent of each Lender (other than any Defaulting Lender); provided that a Scheduled Redetermination may be postponed by the Lenders, (iii) reduce the principal amount of any Loan or LC Disbursement or reduce the rate of interest thereon, or reduce any fees payable hereunder, or reduce any other Indebtedness hereunder or under any other Loan Document, without the written consent of each Lender affected thereby, (iv) postpone the scheduled date of payment or prepayment of the principal amount of any Loan or LC Disbursement, or any interest thereon, or any fees payable hereunder, or any other Indebtedness hereunder or under any other Loan Document, or reduce the amount of, waive or excuse any such payment, or postpone or extend the Termination Date without the written consent of each Lender affected thereby, (v) change Section 4.01(b) or Section 4.01(c) in a manner that would alter the pro rata sharing of payments required thereby, without the written consent of each Lender, (vi) waive or amend Section 3.04(c) , Section 6.01 , Section 8.14 , Section 10.02(c) or Section 12.14 , without the written consent of each Lender (other than any Defaulting Lender), or (vii) change any of the provisions of this Section 12.02(b) or any other provision hereof specifying the number or percentage of Lenders required to waive, amend or modify any rights hereunder or under any other Loan Documents or make any determination or grant any consent hereunder or any other Loan Documents, without the written consent of each Lender (other than any Defaulting Lender); provided further that no such agreement shall amend, modify or otherwise affect the rights or duties of the Administrative Agent or any Issuing Bank hereunder or under any other Loan Document without the prior written consent of the Administrative Agent or such Issuing Bank, as the case may be. Notwithstanding the foregoing, any supplement to Schedule 7.24 (Material Agreements) shall be effective simply by delivering to the Administrative Agent a supplemental schedule clearly marked as such and, upon receipt, the Administrative Agent will promptly deliver a copy thereof to the Lenders.

Section 12.03 Expenses, Indemnity; Damage Waiver .

(a) The Borrower shall pay (i) all reasonable out‑of‑pocket expenses incurred by the Lenders, including the reasonable fees, charges and disbursements of counsel and other outside consultants for the Administrative Agent, the reasonable travel, photocopy, mailing, courier, telephone and other similar expenses, and the cost of environmental audits and surveys and appraisals, in connection with the credit facilities provided for herein, the investigation, preparation, negotiation, execution, delivery and administration (both before and after the execution hereof and including advice of counsel to the Administrative Agent as to the rights and duties of the Administrative Agent and the Lenders with respect thereto) of this Agreement and the other Loan Documents and any amendments, modifications or waivers of or consents related to the provisions hereof or thereof (whether or not the transactions contemplated hereby or thereby shall be consummated), (ii) all costs, expenses, Taxes, assessments and other charges incurred by the Administrative Agent or any Lender in connection with any filing, registration, recording or perfection of any security interest contemplated by this Agreement or any Security Instrument or any other document referred to therein, (iii) all reasonable out‑of‑pocket expenses incurred by the Administrative Agent and any Issuing Bank in connection with the issuance, amendment, renewal or extension of any Letter of Credit or any demand for payment thereunder, (iv) all reasonable out‑of‑pocket expenses incurred by any Administrative Agent, any Issuing Bank or any Lender, including the fees, charges and disbursements of any counsel for the Administrative Agent, any Issuing Bank or any Lender, in connection with the enforcement or protection of its rights in connection with this Agreement or any other Loan Document, including its rights under this Section 12.03 , or in connection with the Loans made or Letters of Credit issued hereunder, including all such out‑of‑pocket expenses incurred during any workout, restructuring or negotiations in respect of such Loans or Letters of Credit.

(b) THE BORROWER AND THE GUARANTORS SHALL INDEMNIFY THE ADMINISTRATIVE AGENT, EACH ISSUING BANK AND EACH LENDER, AND EACH RELATED PARTY OF ANY OF THE FOREGOING PERSONS (EACH SUCH PERSON BEING CALLED AN “ INDEMNITEE ”) AGAINST, AND DEFEND AND HOLD EACH INDEMNITEE HARMLESS FROM, ANY AND ALL LOSSES, CLAIMS, DAMAGES, PENALTIES, LIABILITIES AND RELATED EXPENSES, INCLUDING THE FEES, CHARGES AND DISBURSEMENTS OF ANY COUNSEL FOR ANY INDEMNITEE, INCURRED BY OR ASSERTED AGAINST ANY INDEMNITEE ARISING OUT OF, IN CONNECTION WITH, OR AS A RESULT OF (i) THE PERFORMANCE BY THE PARTIES HERETO OR THE PARTIES TO ANY OTHER LOAN DOCUMENT OF THEIR RESPECTIVE OBLIGATIONS HEREUNDER OR THEREUNDER OR THE CONSUMMATION OF THE TRANSACTIONS CONTEMPLATED HEREBY OR BY ANY OTHER LOAN DOCUMENT, (ii) THE FAILURE OF THE BORROWER OR ANY SUBSIDIARY TO COMPLY WITH THE TERMS OF ANY LOAN DOCUMENT, INCLUDING THIS AGREEMENT, OR WITH ANY GOVERNMENTAL REQUIREMENT, (iii) ANY INACCURACY OF ANY REPRESENTATION OR ANY BREACH OF

ANY WARRANTY OR COVENANT OF THE BORROWER OR ANY GUARANTOR SET FORTH IN ANY OF THE LOAN DOCUMENTS OR ANY INSTRUMENTS, DOCUMENTS OR CERTIFICATIONS DELIVERED IN CONNECTION THEREWITH, (iv) ANY LOAN OR LETTER OF CREDIT OR THE USE OF THE PROCEEDS THEREFROM, INCLUDING (A) ANY REFUSAL BY ANY ISSUING BANK TO HONOR A DEMAND FOR PAYMENT UNDER A LETTER OF CREDIT ISSUED BY SUCH ISSUING BANK IF THE DOCUMENTS PRESENTED IN CONNECTION WITH SUCH DEMAND DO NOT STRICTLY COMPLY WITH THE TERMS OF SUCH LETTER OF CREDIT, OR (B) THE PAYMENT OF A DRAWING UNDER ANY LETTER OF CREDIT NOTWITHSTANDING THE NON‑COMPLIANCE, NON‑DELIVERY OR OTHER IMPROPER PRESENTATION OF THE DOCUMENTS PRESENTED IN CONNECTION THEREWITH, (v) ANY OTHER ASPECT OF THE LOAN DOCUMENTS, (vi) THE OPERATIONS OF THE BUSINESS OF THE BORROWER AND ITS SUBSIDIARIES BY THE BORROWER AND ITS SUBSIDIARIES, (vii) ANY ASSERTION THAT THE LENDERS WERE NOT ENTITLED TO RECEIVE THE PROCEEDS RECEIVED PURSUANT TO THE SECURITY INSTRUMENTS, (viii) ANY ENVIRONMENTAL LAW APPLICABLE TO THE BORROWER OR ANY SUBSIDIARY OR ANY OF THEIR PROPERTIES OR OPERATIONS, INCLUDING THE PRESENCE, GENERATION, STORAGE, RELEASE, THREATENED RELEASE, USE, TRANSPORT, DISPOSAL, ARRANGEMENT OF DISPOSAL OR TREATMENT OF OIL, OIL AND GAS WASTES, SOLID WASTES OR HAZARDOUS MATERIALS ON OR AT ANY OF THEIR PROPERTIES, (ix) THE BREACH OR NON‑COMPLIANCE BY THE BORROWER OR ANY SUBSIDIARY WITH ANY ENVIRONMENTAL LAW APPLICABLE TO THE BORROWER OR ANY SUBSIDIARY, (x) THE PAST OWNERSHIP BY THE BORROWER OR ANY SUBSIDARY OF ANY OF THEIR PROPERTIES OR PAST ACTIVITY ON ANY OF THEIR PROPERTIES WHICH, THOUGH LAWFUL AND FULLY PERMISSIBLE AT THE TIME, COULD RESULT IN PRESENT LIABILITY, (xi) THE PRESENCE, USE, RELEASE, STORAGE, TREATMENT, DISPOSAL, GENERATION, THREATENED RELEASE, TRANSPORT, ARRANGEMENT FOR TRANSPORT OR ARRANGEMENT FOR DISPOSAL OF OIL, OIL AND GAS WASTES, SOLID WASTES OR HAZARDOUS MATERIALS ON OR AT ANY OF THE PROPERTIES OWNED OR OPERATED BY THE BORROWER OR ANY SUBSIDIARY OR ANY ACTUAL OR ALLEGED PRESENCE OR RELEASE OF HAZARDOUS MATERIALS ON OR FROM ANY PROPERTY OWNED OR OPERATED BY THE BORROWER OR ANY OF ITS SUBSIDIARIES, (xii) ANY ENVIRONMENTAL LIABILITY RELATED IN ANY WAY TO THE BORROWER OR ANY OF IT SUBSIDIARIES, OR (xiii) ANY OTHER ENVIRONMENTAL, HEALTH OR SAFETY CONDITION IN CONNECTION WITH THE LOAN DOCUMENTS, OR (xiv) ANY ACTUAL OR PROSPECTIVE CLAIM, LITIGATION, INVESTIGATION OR PROCEEDING RELATING TO ANY OF THE FOREGOING, WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY AND REGARDLESS OF WHETHER ANY INDEMNITEE IS A PARTY THERETO, AND SUCH INDEMNITY SHALL EXTEND TO EACH INDEMNITEE NOTWITHSTANDING THE SOLE OR CONCURRENT NEGLIGENCE OF EVERY KIND OR CHARACTER WHATSOEVER, WHETHER ACTIVE OR PASSIVE, WHETHER AN AFFIRMATIVE ACT OR AN OMISSION, INCLUDING ALL TYPES OF NEGLIGENT CONDUCT IDENTIFIED IN THE RESTATEMENT (SECOND) OF TORTS OF ONE OR MORE OF THE INDEMNITEES OR BY REASON OF STRICT LIABILITY IMPOSED WITHOUT FAULT

ON ANY ONE OR MORE OF THE INDEMNITEES; PROVIDED THAT SUCH INDEMNITY SHALL NOT, AS TO ANY INDEMNITEE, BE AVAILABLE TO THE EXTENT THAT SUCH LOSSES, CLAIMS, DAMAGES, LIABILITIES OR RELATED EXPENSES ARE DETERMINED BY A COURT OF COMPETENT JURISDICTION BY FINAL AND NONAPPEALABLE JUDGMENT TO HAVE RESULTED FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF SUCH INDEMNITEE.

(c) To the extent that the Borrower fails to pay any amount required to be paid by it to the Administrative Agent or any Issuing Bank under Section 12.03(a) or (b) , each Lender severally agrees to pay to the Administrative Agent or such Issuing Bank, as the case may be, such Lender’s Applicable Percentage (determined as of the time that the applicable unreimbursed expense or indemnity payment is sought) of such unpaid amount; provided that the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the case may be, was incurred by or asserted against the Administrative Agent or such Issuing Bank in its capacity as such.

(d) To the extent permitted by applicable law, the Borrower shall not assert, and hereby waives, any claim against any Indemnitee, on any theory of liability, for special, indirect, consequential or punitive damages (as opposed to direct or actual damages) arising out of, in connection with, or as a result of, this Agreement, any other Loan Document or any agreement or instrument contemplated hereby or thereby, the Transactions, any Loan or Letter of Credit or the use of the proceeds thereof.

(e) All amounts due under this Section 12.03 shall be payable promptly after written demand therefor.

Section 12.04 Successors and Assigns .

(a) The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby (including any Affiliate of any Issuing Bank that issues any Letter of Credit), except that (i) the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of each Lender (and any attempted assignment or transfer by the Borrower without such consent shall be null and void) and (ii) no Lender may assign or otherwise transfer its rights or obligations hereunder except in accordance with this Section 12.04 . Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby (including any Affiliate of any Issuing Bank that issues any Letter of Credit), Participants (to the extent provided in Section 12.04(c) ) and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent, the Issuing Banks and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

(b) (i) Subject to the conditions set forth in Section 12.04(b)(ii) , any Lender may assign to one or more assignees all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment and the Loans at the time owing to it) with the prior written consent (such consent not to be unreasonably withheld) of:

(A) the Borrower, provided that no consent of the Borrower shall be required if such assignment is to a Lender, an Affiliate of a Lender or, if an Event of Default has occurred and is continuing, is to any other assignee; and

(B) the Administrative Agent and Issuing Bank, provided that no consent of the Administrative Agent or Issuing Bank shall be required for an assignment to an assignee that is a Lender immediately prior to giving effect to such assignment.

(ii) Assignments shall be subject to the following additional conditions:

(A) except in the case of an assignment to a Lender or an Affiliate of a Lender or an assignment of the entire remaining amount of the assigning Lender’s Commitment or Loans, the amount of the Commitment or Loans of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent) shall not be less than $5,000,000 unless each of the Borrower, the Administrative Agent and the Issuing Banks otherwise consent, provided that no such consent of the Borrower shall be required if an Event of Default has occurred and is continuing;

(B) each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement;

(C) the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing fee of $3,500; and

(D) the assignee, if it shall not be a Lender, shall deliver to the Administrative Agent any information reasonably requested by the Administrative Agent in connection with its duties hereunder.

(iii) Subject to Section 12.04(b)(iv) and the acceptance thereof, from and after the effective date specified in each Assignment and Assumption the assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Section 5.01 , Section 5.02 , Section 5.03 and Section 12.03 ). Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 12.04 shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with Section 12.04(c) .

(iv) The Administrative Agent, acting for this purpose as an agent of the Borrower, shall maintain at its office a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Maximum Credit Amount of, and principal amount of the Loans and LC Disbursements owing to, each Lender pursuant to the terms hereof from time to time (the “ Register ”). The entries in the Register shall be conclusive, and the Borrower, the Administrative Agent, each Issuing Bank and the Lenders may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower, any Issuing Bank and any Lender, at any reasonable time and from time to time upon reasonable prior notice. In connection with any changes to the Register, if necessary, the Administrative Agent will reflect the revisions on Annex I and forward a copy of such revised Annex I to the Borrower, each Issuing Bank and each Lender.

(v) Upon its receipt of a duly completed Assignment and Assumption executed by an assigning Lender and an assignee, the assignee’s providing any information reasonably requested by the Administrative Agent in connection with its duties hereunder, the processing and recordation fee referred to in Section 12.04(b) and any written consent to such assignment required by this Section 12.04(b) , the Administrative Agent shall accept such Assignment and Assumption and record the information contained therein in the Register. No assignment shall be effective for purposes of this Agreement unless it has been recorded in the Register as provided in this Section 12.04(b) .

(c) (i) Any Lender may, without the consent of the Borrower, or the Administrative Agent or any Issuing Bank, sell participations to one or more banks or other entities (a “ Participant ”) in all or a portion of such Lender’s rights and obligations under this Agreement (including all or a portion of its Commitment and the Loans owing to it); provided that (A) such Lender’s obligations under this Agreement shall remain unchanged, (B) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (C) the Borrower, the Administrative Agent, the Issuing Banks and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in the proviso to Section 12.02 that affects such Participant. In addition such agreement must provide that the Participant be bound by the provisions of Section 12.03 . Subject to Section 12.04(c)(ii) , the Borrower agrees that each Participant shall be entitled to the benefits of Section 5.01 , Section 5.02 and Section 5.03 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to Section 12.04 . To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 12.08 as though it were a Lender, provided such Participant agrees to be subject to Section 4.01(c) as though it were a Lender. Each Lender that sells a participation shall, acting solely for this purpose as an agent of the Borrower, maintain a register on which it enters the name and address of each Participant and the principal amounts (and stated interest) of each Participant’s interest in the Loans or other obligations under the Loan Documents (the “ Participant Register ”); provided that no Lender shall have any obligation to disclose all or any portion of the Participant Register (including the identity of any Participant or any information relating to a Participant's interest in any commitments, loans, letters of credit or its other obligations under any Loan Document) to any Person except to the extent that such disclosure is necessary to establish that such commitment, loan, letter of credit or other obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations. The entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary. For the avoidance of doubt, the Administrative Agent (in its capacity as Administrative Agent) shall have no responsibility for maintaining a Participant Register.

(ii) A Participant shall not be entitled to receive any greater payment under Section 5.01 or Section 5.03 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrower’s prior written consent.

(d) Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement, including to a trustee or other pledgee, to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank, and this Section 12.04(d) shall not apply to any such pledge or assignment of a security interest; provided that no such pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

(e) Notwithstanding any other provisions of this Section 12.04 , no transfer or assignment of the interests or obligations of any Lender or any grant of participations therein shall be permitted if such transfer, assignment or grant would require the Borrower and the Guarantors to file a registration statement with the SEC or to qualify the Loans under the “ Blue Sky ” laws of any state, or to meet the requirements of any exemption to such registration or qualification requirements.

(f) Notwithstanding any other provisions of this Section 12.04 , no transfer or assignment of the interests or obligations of any Lender or any grant of participations therein shall be permitted if such transfer, assignment or grant would be to an Affiliate of the Borrower.

Section 12.05 Survival; Revival; Reinstatement .

(a) All covenants, agreements, representations and warranties made by the Borrower herein and in the certificates or other instruments delivered in connection with or pursuant to this Agreement or any other Loan Document shall be considered to have been relied upon by the other parties hereto and shall survive the execution and delivery of this Agreement and the making of any Loans and issuance of any Letters of Credit, regardless of any investigation made by any such other party or on its behalf and notwithstanding that the Administrative Agent, any Issuing Bank or any Lender may have had notice or knowledge of any Default or incorrect representation or warranty at the time any credit is extended hereunder, and shall continue in full force and effect as long as the principal of or any accrued interest on any Loan or any fee or any other amount payable under this Agreement is outstanding and unpaid or any Letter of Credit is outstanding and so long as the Commitments have not expired or terminated. The provisions of Section 5.01 , Section 5.02 , Section 5.03 and Section 12.03 and Article XI shall survive and remain in full force and effect regardless of the consummation of the transactions contemplated hereby, the repayment of the Loans, the expiration or termination of the Letters of Credit and the Commitments or the termination of this Agreement, any other Loan Document or any provision hereof or thereof.

(b) To the extent that any payments on the Indebtedness or proceeds of any collateral are subsequently invalidated, declared to be fraudulent or preferential, set aside or required to be repaid to a trustee, debtor in possession, receiver or other Person under any bankruptcy law, common law or equitable cause, then to such extent, the Indebtedness so satisfied shall be revived and continue as if such payment or proceeds had not been received and the Administrative Agent’s and the Lenders’ Liens, security interests, rights, powers and remedies under this Agreement and each Loan Document shall continue in full force and effect. In such event, each Loan Document shall be automatically reinstated and the Borrower shall take such action as may be reasonably requested by the Administrative Agent and the Lenders to effect such reinstatement.

Section 12.06 Counterparts; Integration; Effectiveness .

(a) This Agreement may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract.

(b) This Agreement and the other Loan Documents constitute the entire contract among the parties relating to the subject matter hereof and thereof and supersede any and all previous agreements and understandings, oral or written, relating to the subject matter hereof and thereof. THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES HERETO AND THERETO AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

(c) Except as provided in Section 6.01 , this Agreement shall become effective when it shall have been executed by the Administrative Agent and when the Administrative Agent shall have received counterparts hereof which, when taken together, bear the signatures of each of the other parties hereto, and thereafter shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns. Delivery of an executed counterpart of a signature page of this Agreement or any other Loan Document by facsimile transmission or electronic transmission shall be effective as delivery of a manually executed counterpart thereof.

Section 12.07 Severability . Any provision of this Agreement or any other Loan Document held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof or thereof, and the remaining provisions hereof and thereof shall remain in full force and effect and shall be liberally construed to carry out the provisions and intent hereof and thereof; provided, that if any one or more of the provisions contained in this Agreement or any other Loan Document shall be determined or held to be invalid or unenforceable because such provision is overly broad as to duration, geographic scope, activity, subject or otherwise, such provision shall be deemed amended (and any court or other tribunal is hereby authorized to reform this Agreement accordingly) by limiting and reducing it to the minimum extent necessary to make such provision valid and enforceable; provided further, that the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.

Section 12.08 Right of Setoff . If an Event of Default shall have occurred and be continuing, each Lender and each of its Affiliates is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other obligations (of whatsoever kind, including obligations under Hedging Agreements) at any time owing by such Lender or Affiliate to or for the credit or the account of the Borrower or any Subsidiary against any of and all the obligations of the Borrower or any Subsidiary owed to such Lender now or hereafter existing under this Agreement or any other Loan Document, irrespective of whether or not such Lender shall have made any demand under this Agreement or any other Loan Document and although such obligations may be unmatured. The rights of each Lender under this Section 12.08 are in addition to other rights and remedies (including other rights of setoff) which such Lender or its Affiliates may have.

Section 12.09 Governing Law; Jurisdiction; Consent to Service of Process .

(a) THIS AGREEMENT AND THE NOTES SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF COLORADO EXCEPT TO THE EXTENT THAT UNITED STATES FEDERAL LAW PERMITS ANY LENDER TO CONTRACT FOR, CHARGE, RECEIVE, RESERVE OR TAKE INTEREST AT THE RATE ALLOWED BY THE LAWS OF THE STATE WHERE SUCH LENDER IS LOCATED.

(b) ANY LEGAL ACTION OR PROCEEDING WITH RESPECT TO THE LOAN DOCUMENTS SHALL BE BROUGHT IN THE COURTS OF THE STATE OF COLORADO LOCATED IN THE COUNTY OF DENVER OR THE COLORADO DISTRICT COURT FOR THE UNITED STATES OF AMERICA, AND, BY EXECUTION AND DELIVERY OF THIS AGREEMENT, EACH PARTY HEREBY ACCEPTS FOR ITSELF AND (TO THE EXTENT PERMITTED BY LAW) IN RESPECT OF ITS PROPERTY, GENERALLY AND UNCONDITIONALLY, THE JURISDICTION OF THE AFORESAID COURTS. EACH PARTY HEREBY IRREVOCABLY WAIVES ANY OBJECTION, INCLUDING ANY OBJECTION TO THE LAYING OF VENUE OR BASED ON THE GROUNDS OF FORUM NON CONVENIENS, WHICH IT MAY NOW OR HEREAFTER HAVE TO THE BRINGING OF ANY SUCH ACTION OR PROCEEDING IN SUCH RESPECTIVE JURISDICTIONS. THIS SUBMISSION TO JURISDICTION IS NON‑EXCLUSIVE AND DOES NOT PRECLUDE A PARTY FROM OBTAINING JURISDICTION OVER ANOTHER PARTY IN ANY COURT OTHERWISE HAVING JURISDICTION.

(c) EACH PARTY IRREVOCABLY CONSENTS TO THE SERVICE OF PROCESS OF ANY OF THE AFOREMENTIONED COURTS IN ANY SUCH ACTION OR PROCEEDING BY THE MAILING OF COPIES THEREOF BY REGISTERED OR CERTIFIED MAIL, POSTAGE PREPAID, TO IT AT THE ADDRESS SPECIFIED IN SECTION 12.01 OR SUCH OTHER ADDRESS AS IS SPECIFIED PURSUANT TO SECTION 12.01 (OR ITS ASSIGNMENT AND ASSUMPTION), SUCH SERVICE TO BECOME EFFECTIVE THIRTY (30) DAYS AFTER SUCH MAILING. NOTHING HEREIN SHALL AFFECT THE RIGHT OF A PARTY OR ANY HOLDER OF A NOTE TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY LAW OR TO COMMENCE LEGAL PROCEEDINGS OR OTHERWISE PROCEED AGAINST ANOTHER PARTY IN ANY OTHER JURISDICTION.

(d) EACH PARTY HEREBY (I) IRREVOCABLY AND UNCONDITIONALLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, TRIAL BY JURY IN ANY LEGAL ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT AND FOR ANY COUNTERCLAIM THEREIN; (II) IRREVOCABLY WAIVES, TO THE MAXIMUM EXTENT NOT PROHIBITED BY LAW, ANY RIGHT IT MAY HAVE TO CLAIM OR RECOVER IN ANY SUCH LITIGATION ANY SPECIAL, EXEMPLARY, PUNITIVE OR CONSEQUENTIAL DAMAGES, OR DAMAGES OTHER THAN, OR IN ADDITION TO, ACTUAL DAMAGES; (III) CERTIFIES THAT NO PARTY HERETO NOR ANY REPRESENTATIVE, AGENT OR COUNSEL FOR ANY PARTY HERETO HAS REPRESENTED, EXPRESSLY OR OTHERWISE, OR IMPLIED THAT SUCH PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVERS, AND (IV) ACKNOWLEDGES THAT IT HAS BEEN INDUCED TO ENTER INTO THIS AGREEMENT, THE LOAN DOCUMENTS AND THE TRANSACTIONS CONTEMPLATED HEREBY AND THEREBY BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS CONTAINED IN THIS SECTION 12.09 .

Section 12.10 Headings . Article and Section headings and the Table of Contents used herein are for convenience of reference only, are not part of this Agreement and shall not affect the construction of, or be taken into consideration in interpreting, this Agreement.

Section 12.11 Confidentiality . Each of the Administrative Agent, the Issuing Banks and the Lenders agrees to maintain the confidentiality of the Information (as defined below), except that Information may be disclosed (a) to its and its Affiliates’ directors, officers, employees and agents, including accountants, legal counsel and other advisors (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Information and instructed to keep such Information confidential), (b) to potential investors, rating agencies, and secured parties, including accountants, legal counsel and other advisors (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Information and instructed to keep such Information confidential), (c) to the extent requested by any regulatory authority, (d) to the extent required by applicable laws or regulations or by any subpoena or similar legal process, (e) to any other party to this

Agreement or any other Loan Document, (f) in connection with the exercise of any remedies hereunder or under any other Loan Document or any suit, action or proceeding relating to this Agreement or any other Loan Document or the enforcement of rights hereunder or thereunder, (g) subject to an agreement containing provisions substantially the same as those of this Section 12.11 , to (i) any assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights or obligations under this Agreement or (ii) any actual or prospective counterparty (or its advisors) to any Hedging Agreement relating to the Borrower and its obligations, (h) with the consent of the Borrower or (i) to the extent such Information (i) becomes publicly available other than as a result of a breach of this Section 12.11 or (ii) becomes available to the Administrative Agent, any Issuing Bank or any Lender on a non‑confidential basis from a source other than the Borrower. For the purposes of this Section 12.11 , “ Information ” means all information received from the Borrower relating to the Borrower and its business, other than any such information that is available to the Administrative Agent, any Issuing Bank or any Lender on a non‑confidential basis prior to disclosure by the Borrower; provided that, in the case of information received from the Borrower after the date hereof, such information is clearly identified at the time of delivery as confidential. Any Person required to maintain the confidentiality of Information as provided in this Section 12.11 shall be considered to have complied with its obligation to do so if such Person has exercised the same degree of care to maintain the confidentiality of such Information as such Person would accord to its own confidential information (assuming such Person’s degree of care in maintaining the confidentiality of its own confidential information is reasonable).

Section 12.12 Interest Rate Limitation . It is the intention of the parties hereto that each Lender shall conform strictly to usury laws applicable to it. Accordingly, if the transactions contemplated hereby would be usurious as to any Lender under laws applicable to it (including the laws of the United States of America and the State of Colorado or any other jurisdiction whose laws may be mandatorily applicable to such Lender notwithstanding the other provisions of this Agreement), then, in that event, notwithstanding anything to the contrary in any of the Loan Documents or any agreement entered into in connection with or as security for the Notes, it is agreed as follows: (a) the aggregate of all consideration which constitutes interest under law applicable to any Lender that is contracted for, taken, reserved, charged or received by such Lender under any of the Loan Documents or agreements or otherwise in connection with the Notes shall under no circumstances exceed the maximum amount allowed by such applicable law, and any excess shall be canceled automatically and if theretofore paid shall be credited by such Lender on the principal amount of the Indebtedness (or, to the extent that the principal amount of the Indebtedness shall have been or would thereby be paid in full, refunded by such Lender to the Borrower); and (b) in the event that the maturity of the Notes is accelerated by reason of an election of the holder thereof resulting from any Event of Default under this Agreement or otherwise, or in the event of any required or permitted prepayment, then such consideration that constitutes interest under law applicable to any Lender may never include more than the maximum amount allowed by such applicable law, and excess interest, if any, provided for in this Agreement or otherwise shall be canceled automatically by such Lender as of the date of such acceleration or prepayment and, if theretofore paid, shall be credited by such Lender on the principal amount of the Indebtedness (or, to the extent that the principal amount of the Indebtedness shall have been or would thereby be paid in full, refunded by such Lender to the Borrower). All sums paid or agreed to be paid to any Lender for the use, forbearance or detention of sums due hereunder shall, to the extent permitted by law applicable to such Lender, be amortized, prorated, allocated and spread throughout the stated term of the Loans evidenced by the Notes until payment in full so that the rate or amount of interest on account of any Loans hereunder does not exceed the maximum amount allowed by such applicable law. If at any time and from time to time (i) the amount of interest payable to any Lender on any date shall be computed at the Highest Lawful Rate applicable to such Lender pursuant to this Section 12.12 and (ii) in respect of any subsequent interest computation period the amount of interest otherwise payable to such Lender would be less than the amount of interest payable to such Lender computed at the Highest Lawful Rate applicable to such Lender, then, to the extent permitted by applicable law, the amount of interest payable to such Lender in respect of such subsequent interest computation period shall continue to be computed at the Highest Lawful Rate applicable to such Lender until the total amount of interest payable to such Lender shall equal the total amount of interest which would have been payable to such Lender if the total amount of interest had been computed without giving effect to this Section 12.12 .

Section 12.13 Exculpation Provisions . EACH OF THE PARTIES HERETO SPECIFICALLY AGREES THAT IT HAS A DUTY TO READ THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS AND AGREES THAT IT IS CHARGED WITH NOTICE AND KNOWLEDGE OF THE TERMS OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS; THAT IT HAS IN FACT READ THIS AGREEMENT AND IS FULLY INFORMED AND HAS FULL NOTICE AND KNOWLEDGE OF THE TERMS, CONDITIONS AND EFFECTS OF THIS AGREEMENT; THAT IT HAS BEEN REPRESENTED BY INDEPENDENT LEGAL COUNSEL OF ITS CHOICE THROUGHOUT THE NEGOTIATIONS PRECEDING ITS EXECUTION OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS; AND HAS RECEIVED THE ADVICE OF ITS ATTORNEY IN ENTERING INTO THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS; AND THAT IT RECOGNIZES THAT CERTAIN OF THE TERMS OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS RESULT IN ONE PARTY ASSUMING THE LIABILITY INHERENT IN SOME ASPECTS OF THE TRANSACTION AND RELIEVING THE OTHER PARTY OF ITS RESPONSIBILITY FOR SUCH LIABILITY. EACH PARTY HERETO AGREES AND COVENANTS THAT IT WILL NOT CONTEST THE VALIDITY OR ENFORCEABILITY OF ANY EXCULPATORY PROVISION OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS ON THE BASIS THAT THE PARTY HAD NO NOTICE OR KNOWLEDGE OF SUCH PROVISION OR THAT THE PROVISION IS NOT “CONSPICUOUS.”

Section 12.14 Collateral Matters; Hedging Agreements . The benefit of the Security Instruments and of the provisions of this Agreement relating to any collateral securing the Indebtedness shall also extend to and be available to any Secured Hedging Agreement on a pro rata basis in respect of any obligations of the Borrower.

Section 12.15 No Third Party Beneficiaries . This Agreement, the other Loan Documents, and the agreement of the Lenders to make Loans and the Issuing Banks to issue, amend, renew or extend Letters of Credit hereunder are solely for the benefit of the Borrower, and no other Person (including any Subsidiary of the Borrower, any obligor, contractor, subcontractor, supplier or materialsman) shall have any rights, claims, remedies or privileges hereunder or under any other Loan Document (except to the extent it is a party thereto) against the Administrative Agent, any Issuing Bank or any Lender for any reason whatsoever. There are no third party beneficiaries other than Secured Hedging Counterparties.

Section 12.16 USA Patriot Act Notice . Each Lender hereby notifies the Borrower that pursuant to the requirements of the USA Patriot Act (Title III of Pub. L. 107‑56 (signed into law October 26, 2001)) (the “ Patriot Act ”), it is required to obtain, verify and record information that identifies the Borrower, which information includes the name and address of the Borrower and other information that will allow such Lender to identify the Borrower in accordance with the Patriot Act.

Section 12.17 Existing Credit Agreement . This Agreement amends and restates the Existing Credit Agreement in its entirety. On the date of the initial funding of Loans hereunder, all amounts outstanding under the Existing Credit Agreement shall be paid in full with the proceeds of such Loans and the “Commitments” (as defined in the Existing Credit Agreement) thereunder shall be terminated. Each Lender that was a party to the Existing Credit Agreement hereby agrees to return to the Borrower, with reasonable promptness, any note delivered by the Borrower to such Lender in connection with the Existing Credit Agreement upon receipt of its new Note, if any, delivered pursuant to this Agreement.

[SIGNATURE PAGES FOLLOW]

The parties hereto have caused this Agreement to be duly executed as of the day and year first above written.

BORROWER:

SYNERGY RESOURCES CORPORATION

By: /s/ Edward Holloway
Name: Ed ward Holloway
Title: Chief Executive Officer

Signature Page to Amended and Restated Credit Agreement

ADMINISTRATIVE AGENT:

COMMUNITY BANKS OF COLORADO ,
as Administrative Agent

By: /s/ Sarah Burchett

Name: Sarah Burchett
Title: Vice President

Signature Page to Amended and Restated Credit Agreement

LENDERS:

COMMUNITY BANKS OF COLORADO ,
as a Lender

By: /s/ Sarah Burchett

Name: Sarah Burchett
Title: Vice President

Signature Page to Amended and Restated Credit Agreement

COBIZ BANK, A COLORADO CORPORATION, DBA COLORADO BUSINESS BANK ,
as a Lender

By: /s/ Dougls K. Derks _
Name: Douglas K. Derks
Title: Senior Vice President

Address:

Colorado Business Bank

Attn: Douglas Derks/Diane Bowen

15710 W. Colfax Ave.

Golden, CO 80401

Signature Page to Amended and Restated Credit Agreement

AMEGY BANK NATIONAL ASSOCIATION,
as a Lender

By: /s/ Kevin Donaldson
Name: Kevin Donaldson
Title: Senior Vice President

Address:

Amegy Bank National Association

4400 Post Oak Parkway

Houston, Texas 77027

Signature Page to Amended and Restated Credit Agreement

ANNEX I
LIST OF MAXIMUM CREDIT AMOUNTS

Aggregate Maximum Credit Amounts

Name of Lender	Applicable Percentage	Maximum Credit Amount	Amount of Commitment on the Effective Date
Community Banks of Colorado	46.8085%	$70,212,750	$22,000,000
CoBiz Bank, a Colorado corporation, dba Colorado Business Bank	21.2766%	$31,914,900	$ 10,000,000
Amegy Bank National Association	31.9149%	$47,872,350	$15,000,000
TOTAL	100.0000%	$150,000,000	$47,000,000

EXHIBIT A
FORM OF NOTE

FOR VALUE RECEIVED, Synergy Resources Corporation, a Colorado corporation (the “ Borrower ”), hereby promises to pay to [ ] (the “ Lender ”), or its assigns, at the principal office of Community Banks of Colorado, a division of NBH Bank (the “ Administrative Agent ”), at [_____], the principal sum of [_______________] dollars ($[____________]) (or such lesser amount as shall equal the aggregate unpaid principal amount of the Loans made by the Lender to the Borrower under the Credit Agreement, as hereinafter defined), in lawful money of the United States of America and in immediately available funds, on the dates and in the principal amounts provided in the Credit Agreement, and to pay interest on the unpaid principal amount of each such Loan, at such office, in like money and funds, for the period commencing on the date of such Loan until such Loan shall be paid in full, at the rates per annum and on the dates provided in the Credit Agreement.

The date, amount, Type, interest rate, Interest Period and maturity of each Loan made by the Lender to the Borrower, and each payment made on account of the principal thereof, shall be recorded by the Lender on its books and, prior to any transfer of this Note, may be endorsed by the Lender on the schedules attached hereto or any continuation thereof or on any separate record maintained by the Lender. Failure to make any such notation or to attach a schedule shall not affect any Lender’s or the Borrower’s rights or obligations in respect of such Loans or affect the validity of such transfer by any Lender of this Note.

This Note is one of the Notes referred to in the Amended and Restated Credit Agreement dated as of November 28, 2012 among the Borrower, the Administrative Agent, and the other lenders signatory thereto (including the Lender), and evidences Loans made by the Lender thereunder (such Credit Agreement as the same may be amended, supplemented or restated from time to time, the “ Credit Agreement ”). Capitalized terms used in this Note have the respective meanings assigned to them in the Credit Agreement.

This Note (a) is issued pursuant to, and is subject to the terms and conditions set forth in, the Credit Agreement and is entitled to the benefits provided for in the Credit Agreement and the other Loan Documents, and (b) is secured by and entitled to the benefits of certain Security Instruments (as identified and defined in the Credit Agreement). The Credit Agreement provides for the acceleration of the maturity of this Note upon the occurrence of certain events, for prepayments of Loans upon the terms and conditions specified therein and other provisions relevant to this Note.

If this Note is placed in the hands of an attorney for collection after default, or if all or any part of the indebtedness represented hereby is proved, established or collected in any court or in any bankruptcy, receivership, debtor relief, probate or other court proceedings, the Borrower agrees to pay reasonable attorneys’ fees and collection costs to the holder hereof in addition to the principal and interest payable hereunder.

The Borrower and all endorsers, sureties and guarantors of this Note hereby severally waive demand, presentment, notice of demand and of dishonor and nonpayment of this Note, protest, notice of protest, notice of intention to accelerate the maturity of this Note, declaration or notice of acceleration of the maturity of this Note, diligence in collecting, the bringing of any suit against any party and any notice of or defense on account of any extensions, renewals, partial payments or changes in any manner of or in this Note or in any of its terms, provisions and covenants, or any releases or substitutions of any security, or any delay, indulgence or other act of any trustee or any holder hereof, whether before or after maturity.

In no event shall the interest payable under this Note, whether before or after maturity, exceed the maximum amount of interest which, under applicable law, may be contracted for, charged, or received on this Note, and this Note is expressly made subject to the provisions of the Credit Agreement which more fully set out the limitations on how interest accrues hereon.

THIS NOTE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF COLORADO.

SYNERGY RESOURCES CORPORATION

By: _______________________________________________
Name:
Title:

EXHIBIT B
FORM OF BORROWING REQUEST

Synergy Resources Corporation, a Colorado corporation (the “ Borrower ”), pursuant to Section 2.03 of the Amended and Restated Credit Agreement dated as of November 28, 2012 (together with all amendments, restatements, supplements or other modifications thereto, the “ Credit Agreement ”) among the Borrower, Community Banks of Colorado, a division of NBH Bank, N.A., as Administrative Agent and the other lenders (the “ Lenders ”) which are or become parties thereto (unless otherwise defined herein, each capitalized term used herein is defined in the Credit Agreement), hereby requests a Borrowing as follows:

(i) Aggregate amount of the requested Borrowing is $[____________];

(ii) Date of such Borrowing is [________________], 201[__];

(iii) Requested Borrowing is to be [an ABR Borrowing] [a Eurodollar Borrowing];

(iv) In the case of a Eurodollar Borrowing, the initial Interest Period applicable thereto is [______________];

(v) Amount of Borrowing Base in effect on the date hereof (or Aggregate Maximum Credit Amounts, if such amount is less than the Borrowing Base in effect on the date hereof) is $[_______________];

(vi) Total Revolving Credit Exposures on the date hereof (i.e., outstanding principal amount of Loans and total LC Exposure) is $[_____________]; and

(vii) Pro forma total Revolving Credit Exposures (giving effect to the requested Borrowing) is $[________________]; and

(viii) Location and number of the Borrower’s account to which funds are to be disbursed, which shall comply with the requirements of Section 2.05 of the Credit Agreement, is as follows:

[________________________ ]

(ix) The Borrower hereby warrants and represents to Administrative Agent and the Lenders that the following statements are true and correct as of the date of this Borrowing Request:

a. Each of the documents previously delivered to Administrative Agent pursuant to Section 6.01 and Section 6.02 of the Credit Agreement, as applicable, are in full force and effect and have not been terminated, amended or modified except in accordance with the Credit Agreement;

b. The representations and warranties of the Borrower set forth in the Credit Agreement and in the other Loan Documents are true and correct in all material respects, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, on and as of the date of the requested Borrowing, such representations and warranties shall continue to be true and correct in all material respects as of such specified earlier date;

c. Except as set forth in Exhibit A , attached hereto, there is and, after giving effect to the requested Borrowing, there will be no Default or any event which with notice or the passage of time would become an Event of Default under the Credit Agreement or any of the other Loan Documents;

d. At the time of and immediately after giving effect to this Borrowing, no Material Adverse Effect shall have occurred;

e. To the knowledge of the Borrower, the making of this Borrowing would not conflict with, or cause Administrative Agent or any Lender to violate or exceed, any applicable Governmental Requirement, and no change in law shall have occurred;

f. No litigation shall be pending or threatened, which does or, seeks to, enjoin, prohibit or restrain, the making or repayment of any Borrowing or any participations therein or the consummation of the transactions contemplated by the Credit Agreement or any other Loan Document; and

g. The amount of the Borrowing requested exceeds [minimum amount of one hundred thousand dollars ($1,000,000)] except to the extent a lesser amount remains available under the Credit Agreement.

The undersigned certifies that he/she is the [ ] of the Borrower, and that as such he/she is authorized to execute this certificate on behalf of the Borrower. The undersigned further certifies, represents and warrants in such capacity and on behalf of the Borrower that the Borrower is entitled to receive the requested Borrowing under the terms and conditions of the Credit Agreement.

SYNERGY RESOURCES CORPORATION

By: _______________________________
Name:
Title:

By: _______________________________

EXHIBIT C
FORM OF INTEREST ELECTION REQUEST

Synergy Resources Corporation, a Colorado corporation (the “ Borrower ”), pursuant to Section 2.04 of the Amended and Restated Credit Agreement dated as of November 28, 2012 (together with all amendments, restatements, supplements or other modifications thereto, the “ Credit Agreement ”) among the Borrower, Community Banks of Colorado, a division of NBH Bank, N.A., as Administrative Agent and the lenders referenced therein (the “ Lenders ”) (unless otherwise defined herein, each capitalized term used herein is defined in the Credit Agreement), hereby makes an Interest Election Request as follows:

(i) The Borrowing to which this Interest Election Request applies, and if different options are being elected with respect to different portions thereof, the portions thereof to be allocated to each resulting Borrowing (in which case the information specified pursuant to (iii) and (iv) below shall be specified for each resulting Borrowing) is [____________];

(ii) The effective date of the election made pursuant to this Interest Election Request is [____________], 201[__];[and]

(iii) The resulting Borrowing is to be [an ABR Borrowing] [a Eurodollar Borrowing][; and]

[(iv) [If the resulting Borrowing is a Eurodollar Borrowing] The Interest Period applicable to the resulting Borrowing after giving effect to such election is [___________]].

The undersigned certifies that he/she is the [_____________] of the Borrower, and that as such he/she is authorized to execute this certificate on behalf of the Borrower. The undersigned further certifies, represents and warrants in such capacity and on behalf of the Borrower that the Borrower is entitled to receive the requested continuation or conversion under the terms and conditions of the Credit Agreement.

SYNERGY RESOURCES CORPORATION

By: _______________________________________________
Name:
Title:

EXHIBIT D
FORM OF
COMPLIANCE CERTIFICATE

The undersigned officer executing this certificate on behalf of Synergy Resources Corporation, a Colorado corporation (the “ Borrower ”), certifies that he/she is the [ ] of the Borrower and that as such he/she is authorized to execute this certificate. Reference is made to that certain Amended and Restated Credit Agreement dated as of November 28, 2012 (together with all amendments, restatements, supplements or other modifications thereto being the “ Credit Agreement ”) among the Borrower, Community Banks of Colorado, as Administrative Agent, and the lenders referenced therein (the “ Lenders ”). Terms used but not defined herein shall have the meanings given them in the Credit Agreement and all section references herein refer to sections of the Credit Agreement. This certificate is being delivered pursuant to Section 8.01(c) of the Credit Agreement. The Borrower hereby certifies that:

(a) The representations and warranties of the Borrower contained in Article VII of the Credit Agreement and in the Loan Documents and otherwise made in writing by or on behalf of the Borrower pursuant to the Credit Agreement and the Loan Documents were true and correct when made, and are repeated at and as of the time of delivery hereof and are true and correct in all material respects at and as of the time of delivery hereof, except to the extent such representations and warranties are expressly limited to an earlier date or the Lenders have expressly consented in writing to the contrary.

(b) The Borrower has performed and complied with all agreements and conditions contained in the Credit Agreement and in the Loan Documents required to be performed or complied with by it prior to or at the time of delivery hereof [or specify default and describe].

(c) Since the date of the Credit Agreement, no change has occurred, either in any case or in the aggregate, in the condition, financial or otherwise, of the Borrower which could reasonably be expected to have a Material Adverse Effect [or specify event].

(d) There exists no Default or Event of Default [or specify Default and describe].

(e) Attached hereto are the detailed computations necessary to determine whether the Borrower is in compliance with Section 9.01 and Section 8.14(a) as of the end of the [fiscal quarter][fiscal year] ending [____________].

EXECUTED AND DELIVERED this [______] day of [_______________].

SYNERGY RESOURCES CORPORATION

By: __________________________________________________
Name:
Title: Chief Financial Officer

EXHIBIT E
SECURITY INSTRUMENTS

1.	Amended and Restated Pledge and Security Agreement, dated November 28, 2012, executed by Synergy Resources Corporation and Community Banks of Colorado, as Administrative Agent.

Amended and Restated Deed of Trust, Mortgage, Fixture Filing, Assignment of As-Extracted Collateral, Security Agreement and Financing Statement dated November 28, 2012, from Synergy Resources Corporation to the Public Trustee of Weld County, Colorado, the Public Trustee of Boulder County, Colorado and Community Banks of Colorado, as Administrative Agent.

3.	UCC-1 Financing Statement filed by Community Banks of Colorado, as Administrative Agent.

4.	Amendment to UCC-1 filed with the Colorado Secretary of State on December 1, 2011, at reception number 20112043646.

5.	Amendment to UCC-1 filed with the Colorado Secretary of State on December 1, 2011, reception number 20112043647.

EXHIBIT F
FORM OF ASSIGNMENT AND ASSUMPTION

This Assignment and Assumption (the “ Assignment and Assumption ”) is dated as of the Effective Date set forth below and is entered into by and between [Insert name of Assignor] (the “ Assignor ”) and [Insert name of Assignee] (the “ Assignee ”). Capitalized terms used but not defined herein shall have the meanings given to them in the Credit Agreement identified below (as amended, the “ Credit Agreement ”), receipt of a copy of which is hereby acknowledged by the Assignee. The Standard Terms and Conditions set forth in Annex 1 attached hereto are hereby agreed to and incorporated herein by reference and made a part of this Assignment and Assumption as if set forth herein in full.

For an agreed consideration, the Assignor hereby irrevocably sells and assigns to the Assignee, and the Assignee hereby irrevocably purchases and assumes from the Assignor, subject to and in accordance with the Standard Terms and Conditions and the Credit Agreement, as of the Effective Date inserted by the Administrative Agent as contemplated below (i) all of the Assignor’s rights and obligations in its capacity as a Lender under the Credit Agreement and any other documents or instruments delivered pursuant thereto to the extent related to the amount and percentage interest identified below of all of such outstanding rights and obligations of the Assignor under the respective facilities identified below (including any letters of credit and guarantees included in such facilities) and (ii) to the extent permitted to be assigned under applicable law, all claims, suits, causes of action and any other right of the Assignor (in its capacity as a Lender) against any Person, whether known or unknown, arising under or in connection with the Credit Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby or in any way based on or related to any of the foregoing, including contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity related to the rights and obligations sold and assigned pursuant to clause (i) above (the rights and obligations sold and assigned pursuant to clauses (i) and (ii) above being referred to herein collectively as the “ Assigned Interest ”). Such sale and assignment is without recourse to the Assignor and, except as expressly provided in this Assignment and Assumption, without representation or warranty by the Assignor.

1.	Assignor: ______________________________

2.	Assignee: ______________________________ [and is an Affiliate/Approved Fund of [identify Lender]]

3.	Borrower: ______________________________

4.	Administrative Agent: Community Banks of Colorado, as the Administrative Agent under the Credit Agreement

5.	Credit Agreement: The Amended and Restated Credit Agreement dated as of November 28, 2012 among Synergy Resources Corporation, the Lenders parties thereto, Community Banks of Colorado, as Administrative Agent, and the lenders referenced therein.

6.	Assigned Interest:

Commitment Assigned	Aggregate Amount of Commitment/Loans for all Lenders	Amount of Commitment/Loans Assigned	Percentage Assigned of Commitment/Loans ²
	$	$	%
	$	$	%
	$	$	%

Effective Date: _____________ ___, 201__ [TO BE INSERTED BY ADMINISTRATIVE AGENT AND WHICH SHALL BE THE EFFECTIVE DATE OF RECORDATION OF TRANSFER IN THE REGISTER THEREFOR.]

The terms set forth in this Assignment and Assumption are hereby agreed to:

ASSIGNOR

[NAME OF ASSIGNOR]

By: ______________________________
Name:
Title:

ASSIGNEE

[NAME OF ASSIGNEE]

By: ______________________________
Name:
Title:

Address of Assignee:

____________________________________
____________________________________
____________________________________

2 Set forth, to at least 9 decimals, as a percentage of the Commitment/Loans of all Lenders thereunder.

Consented to and Accepted:

Community Banks of Colorado,
as Administrative Agent

By: _________________________________________________
Name:
Title:

Consented to:

Synergy Resources Corporation

By: _________________________________________________
Name:
Title:

Synergy Resources Corporation Amended and Restated Credit Agreement

STANDARD TERMS AND CONDITIONS FOR
ASSIGNMENT AND ASSUMPTION

1. Representations and Warranties .

1.1 Assignor . The Assignor (a) represents and warrants that (i) it is the legal and beneficial owner of the Assigned Interest, (ii) the Assigned Interest is free and clear of any lien, encumbrance or other adverse claim and (iii) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby; and (b) assumes no responsibility with respect to (i) any statements, warranties or representations made in or in connection with the Amended and Restated Credit Agreement or any other Loan Document, (ii) the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan Documents or any collateral thereunder, (iii) the financial condition of the Borrower, any of its Affiliates or any other Person obligated in respect of any Loan Document or (iv) the performance or observance by the Borrower, any of its Affiliates or any other Person of any of their respective obligations under any Loan Document.

1.2. Assignee . The Assignee (a) represents and warrants that (i) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and to become a Lender under the Credit Agreement, (ii) it satisfies the requirements, if any, specified in the Credit Agreement that are required to be satisfied by it in order to acquire the Assigned Interest and become a Lender, (iii) from and after the Effective Date, it shall be bound by the provisions of the Credit Agreement as a Lender thereunder and, to the extent of the Assigned Interest, shall have the obligations of a Lender thereunder, (iv) it has received a copy of the Credit Agreement, together with copies of the most recent financial statements delivered pursuant to Section 8.01 thereof, as applicable, and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Assignment and Assumption and to purchase the Assigned Interest on the basis of which it has made such analysis and decision independently and without reliance on the Administrative Agent or any other Lender, and (v) if it is a Foreign Lender, attached to the Assignment and Assumption is any documentation required to be delivered by it pursuant to the terms of the Credit Agreement, duly completed and executed by the Assignee; and (b) agrees that (i) it will, independently and without reliance on the Administrative Agent, the Assignor or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents, and (ii) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender.

2. Payments . From and after the Effective Date, the Administrative Agent shall make all payments in respect of the Assigned Interest (including payments of principal, interest, fees and other amounts) to the Assignor for amounts which have accrued to but excluding the Effective Date and to the Assignee for amounts which have accrued from and after the Effective Date.

3. General Provisions . This Assignment and Assumption shall be binding upon, and inure to the benefit of, the parties hereto and their respective successors and assigns. This Assignment and Assumption may be executed in any number of counterparts, which together shall constitute one instrument. Delivery of an executed counterpart of a signature page of this Assignment and Assumption by facsimile transmission shall be effective as delivery of a manually executed counterpart of this Assignment and Assumption. This Assignment and Assumption shall be governed by, and construed in accordance with, the law of the State of Colorado.

EXHIBIT G
FORM OF HEDGING AGREEMENTS CERTIFICATE

The undersigned officer executing this certificate on behalf of Synergy Resources Corporation, a Colorado corporation (the “ Borrower ”), certifies that he/she is the Chief Financial Officer of the Borrower, and that as such he/she is authorized to execute this certificate. Reference is made to that certain Amended and Restated Credit Agreement dated as of November 28, 2012 (together with all amendments, restatements, supplements or other modifications thereto being the “ Credit Agreement ”) among the Borrower, Community Banks of Colorado, as Administrative Agent, and the lenders referenced therein (the “ Lenders ”). Terms used but not defined herein shall have the meanings given them in the Credit Agreement and all section references herein refer to sections of the Credit Agreement. This certificate is being delivered pursuant to Section 8.01(e) of the Credit Agreement. The Borrower hereby certifies that set forth on Schedule 1 attached hereto is a true and complete list of all Hedging Agreements of the Borrower, including the type, term, effective date, termination date, notional amounts or volumes and any other material terms for each such Hedging Agreement.

EXECUTED AND DELIVERED this [__] day of ___________, 201[_].

SYNERGY RESOURCES CORPORATION

By: ___________________________________________________
Name:
Title: Chief Financial Officer

Schedule 1
Hedging Agreements Certificate

	Type	Term	Effective Date	Termination Date	Notional Amount or Volumes	Comments/Other
1.
2.
3.
4.
5.

EXHIBIT H
FORM OF RESERVE REPORT CERTIFICATE

The undersigned officer executing this certificate on behalf of Synergy Resources Corporation, a Colorado corporation (the “ Borrower ”), certifies that he/she is the [ ] of the Borrower, and that as such he/she is authorized to execute this certificate. Reference is made to that certain Amended and Restated Credit Agreement dated as of November 28, 2012 (together with all amendments, restatements, supplements or other modifications thereto being the “ Credit Agreement ”) among the Borrower, Colorado Community Banks, a division of NBH Bank, N.A., as Administrative Agent, and the lenders referenced therein (the “ Lenders ”). Terms used but not defined herein shall have the meanings given them in the Credit Agreement and all section references herein refer to sections of the Credit Agreement. This certificate is being delivered pursuant to Section 8.12(b) of the Credit Agreement. The Borrower hereby certifies that:

(a) The Borrower did not provide any statements or conclusions in the preparation of the [Initial] ³ Reserve Report which were based upon or include misleading information or failed to take into account material information regarding the matters reported therein, it being understood that projections concerning volumes attributable to the Oil and Gas Properties and production and cost estimates contained in the [Initial] Reserve Report are necessarily based upon professional opinions, estimates and projections and that the Borrower does not warrant that such opinions, estimates and projections will ultimately prove to have been accurate.

(b) The Borrower owns good and defensible title to the Hydrocarbon Interests in the Oil and Gas Properties evaluated in the Reserve Report delivered herewith and such Properties are free of all Liens except for Liens permitted by Section 9.03 of the Credit Agreement.

[(c) The Oil and Gas Properties to be mortgaged on the date hereof in connection with the Credit Agreement comply with the requirements of Section 8.12(b) .] ²

[(c) Except as set forth on Schedule 1 attached hereto, on a net basis there are no gas imbalances, take or pay or other prepayments in excess of the volume specified in Section 7.18 .

(d) Except as set forth on Schedule 1 attached hereto, no Oil and Gas Properties have been sold since the date of the last Borrowing Base determination.

(e) Set forth on Schedule 1 attached hereto is a list of all marketing agreements effective on the date hereof.

(f) Attached hereto is as Exhibit A is a list of the Oil and Gas Properties of the Borrower evaluated in the Reserve Report delivered herewith that are Mortgaged Properties which demonstrates compliance with Section 8.14(a) ]

1 Use bracketed language for certificate delivered on Effective Date only.

2 Use this subsection (c) for certificate delivered on Effective Date only and delete for subsequent delivery of this and use subsections (c) to (f).

EXECUTED AND DELIVERED this [__] day of ___________, 201[_].

SYNERGY RESOURCES CORPORATION

By:      ________________________________________________
Name: ______________________________________________
Title:       ______________________________________________

Schedule 1
Reserve Report Certificate

Oil and Gas Properties Sold

Marketing Agreements

Exhibit A
Reserve Report Certificate

List of Mortgaged Properties

Reserve Report Effective Date:

Date Prepared:

PROPERTY DESCRIPTION

STATUS

RES RPT NPV10

TITLE

COMMENTS

Per Review

Per Reserve Report

Per Mortgage

Date Added

Date Removed

Other

State

County

Location

Field

Lease

Well No.

Res Rpt

Currently

LIST OF UNMORTGAGED PROPERTIES

Reserve Report Effective Date:
Date Prepared:

PROPERTY DESCRIPTION						STATUS		OWNERSHIP		COMMENTS
PROPERTY DESCRIPTION						PDP/PDNP/PUD	If PDP, Avg Daily Rate	Per Review
State	County	Location	Field	Lease	Well No.	PDP/PDNP/PUD	If PDP, Avg Daily Rate	WI	NI

SCHEDULE 7.05
LITIGATION

SCHEDULE 7.18
GAS IMBALANCES

SCHEDULE 7.19
MARKETING CONTRACTS

SCHEDULE 7.20
HEDGING AGREEMENTS

SCHEDULE 7.24
MATERIAL AGREEMENTS

1. Purchase and Sale Agreement between Orr Energy, LLC, a Colorado limited liability company, as seller and Synergy Energy Resources, a Colorado corporation, as purchaser, dated October 23, 2012.

SCHEDULE 7.28
EXISTING ACCOUNTS PAYABLE

FIRST AMENDMENT TO CREDIT AGREEMENT

This First Amendment to Credit Agreement (this “ Amendment ”) is made and entered into effective as of February 12, 2013 (the “ Effective Date ”), by and between Synergy Resources Corporation, a Colorado corporation (“ Borrower ”), each of the Lenders party to the Credit Agreement (as defined below) (“ Lenders ”), and Community Banks of Colorado, a division of NBH Bank, N.A., as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “ Administrative Agent ”), and is as follows:

Preliminary Statements

A. Lenders, the Administrative Agent and Borrower are parties to a Credit Agreement dated as of November 28, 2012 (the “ Credit Agreement ”). Capitalized terms which are used, but not defined, in this Amendment will have the meanings given to them in the Credit Agreement.

B. The parties desire to make certain amendments to the Credit Agreement, all as more particularly set forth herein.

Statement of Amendment

In consideration of the mutual covenants and agreements set forth in this Amendment, and for other good and valuable consideration, Lenders, the Administrative Agent and Borrower hereby agree as follows:

1. Amendments to Credit Agreement . Subject to the terms and provisions of this Amendment, the Credit Agreement is hereby amended as follows:

(a) The number set forth in clause (ii) of the definition of “LC Commitment” in Section 1.01 of the Credit Agreement is hereby amended to be “$15,000,000.”

(b) Section 2.04(e) of the Credit Agreement (including the heading thereto) is hereby amended and restated in its entirety as follows:

“(e) Effect of Events of Default on Interest Election . Notwithstanding any contrary provision hereof, if an Event of Default has occurred and is continuing: (i) no outstanding Borrowing may be converted to or continued as a Eurodollar Borrowing (and any Interest Election Request that requests the conversion of any Borrowing to, or continuation of any Borrowing as, a Eurodollar Borrowing shall be ineffective) and (ii) unless repaid, each Eurodollar Borrowing shall be converted to an ABR Borrowing at the end of the Interest Period applicable thereto.”

2. Reaffirmation of Security . Borrower, Lenders and the Administrative Agent hereby expressly intend that this Amendment shall not in any manner (a) constitute the refinancing, refunding, payment or extinguishment of the Obligations evidenced by the existing Loan Documents; (b) be deemed to evidence a novation of the outstanding balance of the Obligations; or (c) replace, impair, or extinguish the creation, attachment, perfection or priority of the Liens on the Borrowing Base Properties. Borrower ratifies and reaffirms any and all grants of Liens to Lenders and the Administrative Agent on the Borrowing Base Properties as security for the Obligations, and Borrower acknowledges and confirms that the grants of the Liens to Lenders and the Administrative Agent on the Borrowing Base Properties: (i) represent continuing Liens on all of the Borrowing Base Properties, (ii) secure all of the Obligations, and (iii) represent valid, first and best Liens on all of the Borrowing Base Properties except to the extent of any Permitted Liens.

3. Representations . In connection with this Amendment, Borrower hereby represents and warrants to Lenders and the Administrative Agent as follows:

(a) Power and Authority . Borrower has full power and authority to enter into, and to perform its obligations under this Amendment, and the execution and delivery of, and the performance of its obligations under and arising out of, this Amendment have been duly authorized by all necessary corporate action.

(b) Legal, Valid and Binding Obligation . This Amendment constitutes the legal, valid and binding obligation of Borrower enforceable in accordance with its terms, except as such enforceability may be limited by bankruptcy, insolvency, reorganization or similar laws affecting creditors’ rights generally.

(c) Continued Representations and Warranties . After giving effect to the amendments contained in this Amendment, Borrower’s representations and warranties contained in the Loan Documents are complete and correct as of the date of this Amendment with the same effect as though these representations and warranties had been made again on and as of the date of this Amendment, subject to those changes as are not prohibited by, or do not constitute Events of Default under, the Credit Agreement.

(d) No Events of Default . No Event of Default has occurred and is continuing.

4. Continuing Effect of Credit Agreement; Reaffirmation of Loan Documents . Except as expressly amended hereby, all of the provisions of the Credit Agreement are ratified and confirmed and remain in full force and effect. The existing Loan Documents, except as amended by this Amendment, shall remain in full force and effect, and each of them is hereby ratified and confirmed by Borrower, Lenders and the Administrative Agent.

5. One Agreement; References; Fax Signature . The Credit Agreement, as amended by this Amendment, will be construed as one agreement. All references in any of the Loan Documents to the Credit Agreement will be deemed to be references to the Credit Agreement as amended by this Amendment. This Amendment may be signed by facsimile signatures or other electronic delivery of an image file reflecting the execution hereof, and if so signed, (i) may be relied on by each party as if the document were a manually signed original and (ii) will be binding on each party for all purposes.

6. Captions . The headings to the Sections of this Amendment have been inserted for convenience of reference only and shall in no way modify or restrict any provisions hereof or be used to construe any such provisions.

7. Counterparts . This Amendment may be executed in multiple counterparts, each of which shall be an original but all of which together shall constitute one and the same instrument.

8. Entire Agreement . This Amendment sets forth the entire agreement of the parties with respect to the subject matter of this Amendment and supersedes all previous understandings, written or oral, in respect of this Amendment. At no time shall the prior or subsequent course of conduct by Borrower, Lenders or the Administrative Agent directly or indirectly limit, impair or otherwise adversely affect any of the parties’ rights or remedies in connection with this Amendment or any of the documents, instruments and agreements executed in connection herewith, as Lenders, the Administrative Agent and Borrower agree that this Amendment shall only be amended by written instruments executed by Lenders, the Administrative Agent and Borrower. Except to the extent that the Loan Documents are expressly amended by this Amendment, if there is any conflict, ambiguity, or inconsistency, in the Administrative Agent’s judgment, between the terms of this Amendment and any of the other Loan Documents, then the applicable terms and provisions, in the Administrative Agent’s judgment, providing Lenders and the Administrative Agent with greater rights, remedies, powers, privileges, or benefits will control.

9. Governing Law; Severability . This Amendment shall be governed by and construed in accordance with the internal laws of the State of Colorado (without regard to its conflicts of law principles). If any term of this Amendment is found invalid under Colorado law or laws of mandatory application by a court of competent jurisdiction, the invalid term will be considered excluded from this Amendment and will not invalidate the remaining terms of this Amendment.

10. WAIVER OF JURY TRIAL . BORROWER, LENDERS AND THE ADMINISTRATIVE AGENT EACH WAIVE TRIAL BY JURY WITH RESPECT TO ANY ACTION, CLAIM, SUIT OR PROCEEDING IN RESPECT OF OR ARISING OUT OF THIS AMENDMENT, ANY OF THE OTHER LOAN DOCUMENTS, OR THE TRANSACTIONS CONTEMPLATED HEREBY.

[ Signature Page Follow s]

IN WITNESS WHEREOF, Borrower, Lenders and the Administrative Agent have executed this Amendment by their duly authorized officers on the Effective Date.

BORROWER:

SYNERGY RESOURCES CORPORATION

By: /s/ Edward Holloway

Edward Holloway, Chief Executive Officer

ADMINISTRATIVE AGENT:

COMMUNITY BANKS OF COLORADO

By: /s/ Sarah Burchett

Sarah Burchett, Vice President

LENDERS:

COMMUNITY BANKS OF COLORADO

By: /s/ Sarah Burchett

Sarah Burchett, Vice President

COBIZ BANK, A COLORADO CORPORATION

DBA COLORADO BUSINESS BANK

By: /s/ Douglas K. Derks

Douglas K. Derks, Senior Vice President

AMEGY NATIONAL BANK ASSOCIATION

By: /s/ Kevin Donaldson

Kevin Donaldson, Senior Vice President

SECOND AMENDMENT TO CREDIT AGREEMENT

This Second Amendment to Credit Agreement (this “ Amendment ”) is made and entered into effective as of June [●], 2013 (the “ Effective Date ”), by and between Synergy Resources Corporation, a Colorado corporation (“ Borrower ”), each of the Lenders party to the Credit Agreement (as defined below) (“ Lenders ”), Texas Capital Bank, N.A. (“ Texas Capital ”) and Community Banks of Colorado, a division of NBH Bank, N.A., individually, as Issuing Bank and as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “ Administrative Agent ”), and is as follows:

Preliminary Statements

A. Lenders, the Administrative Agent and Borrower are parties to an Amended and Restated Credit Agreement dated as of November 28, 2012, as amended by that First Amendment dated as of February ___, 2013 (as amended, the “ Credit Agreement ”). Capitalized terms which are used, but not defined, in this Amendment will have the meanings given to them in the Credit Agreement.

B. Borrower has requested that Lenders and the Administrative Agent make certain amendments to the Credit Agreement, all as more particularly set forth herein.

C. Lenders and the Administrative Agent are willing to consent to such requests and so amend the Credit Agreement to reflect such modifications, all on the terms of this Amendment.

Statement of Amendment

In consideration of the mutual covenants and agreements set forth in this Amendment, and for other good and valuable consideration, Lenders, the Administrative Agent, Texas Capital and Borrower hereby agree as follows:

1. Amendments to Credit Agreement . Subject to the terms and provisions of this Amendment, the Credit Agreement is hereby amended as follows:

(a) Section 1.01 of the Credit Agreement is hereby amended by the addition of the following new definitions, in their proper alphabetical order, to provide in their respective entireties as follows:

“ Interest Expense ” means, as to any period of determination, all accrued interest for such period, whether or not for GAAP purposes such interest is expensed for such period or capitalized by the Borrower.

(b) The following definitions in Section 1.01 of the Credit Agreement are hereby amended in their entireties by substituting the following in their respective places:

“ LC Commitment ” means $5,000,000.

Ratio of EBITDAX to Interest and Fees . The Borrower will not permit, as of the last day of any fiscal quarter, its ratio of EBITDAX divided by 4 to the sum of Interest Expense for such quarter, to be less than or equal to 3.5 to 1.0, determined as of the fiscal quarter ending August 31, 2012 and each quarter thereafter.

(d) Section 9.01(d) of the Credit Agreement is hereby amended and restated in its entirety as follows:

Ratio of Total Funded Debt to Total Capitalization . The Borrower will not permit, as of the last day of any fiscal quarter, its ratio of Total Funded Debt as of such time to its Total Capitalization as of such time to be greater than or equal to 0.50.

(e) Section 12.02(b) o the Credit Agreement is hereby amended and restated in its entirety as follows:

Neither this Agreement nor any provision hereof nor any Security Instrument nor any provision thereof may be waived, amended or modified except pursuant to an agreement or agreements in writing entered into by the Borrower and the Lenders or by the Borrower and the Administrative Agent with the consent of the Lenders; provided that no such agreement shall (i) increase the Commitment or the Maximum Credit Amount of any Lender without the written consent of such Lender, (ii) increase the Borrowing Base without the written consent of each Lender, (iii) decrease or maintain the Borrowing Base without the written consent of the Required Lenders (other than any Defaulting Lender), or modify Section 2.07 in any manner without the consent of each Lender (other than any Defaulting Lender); provided that a Scheduled Redetermination may be postponed by the Lenders, (iv) reduce the principal amount of any Loan or LC Disbursement or reduce the rate of interest thereon, or reduce any fees payable hereunder, or reduce any other Indebtedness hereunder or under any other Loan Document, without the written consent of each Lender affected thereby, (v) postpone the scheduled date of payment or prepayment of the principal amount of any Loan or LC Disbursement, or any interest thereon, or any fees payable hereunder, or any other Indebtedness hereunder or under any other Loan Document, or reduce the amount of, waive or excuse any such payment, or postpone or extend the Termination Date without the written consent of each Lender affected thereby, (vi) change Section 4.01(b) or Section 4.01(c) in a manner that would alter the pro rata sharing of payments required thereby, without the written consent of each Lender, (vii) waive or amend Section 3.04(c) , Section 6.01 , Section 8.14 , Section 10.02(c) or Section 12.14 , without the written consent of each Lender (other than any Defaulting Lender), or (viii) change any of the provisions of this Section 12.02(b) or any other provision hereof specifying the number or percentage of Lenders required to waive, amend or modify any rights hereunder or under any other Loan Documents or make any determination or grant any consent hereunder or any other Loan Documents, without the written consent of each Lender (other than any Defaulting Lender); provided further that no such agreement shall amend, modify or otherwise affect the rights or duties of the Administrative Agent or any Issuing Bank hereunder or under any other Loan Document without the prior written consent of the Administrative Agent or such Issuing Bank, as the case may be. Notwithstanding the foregoing, any supplement to Schedule 7.24 (Material Agreements) shall be effective simply by delivering to the Administrative Agent a supplemental schedule clearly marked as such and, upon receipt, the Administrative Agent will promptly deliver a copy thereof to the Lenders.

(f) Annex I to the Credit Agreement is hereby amended and restated in its entirety to conform to Annex I attached hereto. The adjustment to each Lender’s Applicable Percentage as set forth on Annex I attached hereto shall be effective as of the Increase Date (defined below) and each Lender’s Applicable Percentage prior to the Increase Date shall be as set forth in Annex I to the Credit Agreement.

2. Eligible Lenders . The parties to this Amendment agree that Texas Capital is an Eligible Lender. Texas Capital hereby agrees that upon the execution of this Amendment, it shall become a party to the Credit Agreement and shall be fully bound by, and subject to, all of the covenants, terms and conditions of the Credit Agreement as though an original party thereto. From and after the date hereof, all references in the Credit Agreement and in all other Loan Documents to the “Lenders” shall be deemed to include Texas Capital.

3. Conditions Precedent . This Amendment will not become effective until the date on which each of the following conditions is satisfied.

(a) The Borrower shall execute and deliver to the Administrative Agent the Promissory Notes attached hereto as Exhibit A (the “ Amendment Notes ”). These Amendment Notes, to the extent that they are for the benefit of Lenders other than Texas Capital, are issued in substitution for and replacement of, but not repayment of, those certain Promissory Notes issued by the Borrower in favor of those Lenders in connection with the Credit Agreement. The Amendment Notes shall constitute a “Note” as defined and described in the Credit Agreement. From and after the date hereof, all references in the Credit Agreement and in all other Loan Documents to the “Notes” shall be deemed to be references to the Amendment Notes.

4. Borrowing Base . In connection with the first Scheduled Redetermination contemplated by Section 2.07 of the Credit Agreement, the Administrative Agent, the Lenders and the Borrower have agreed that the Borrowing Base shall be increased to $75,000,000, which Borrowing Base adjustment shall be effective as of the latter of [●], 2013, or the satisfaction of the conditions set forth in Section 3 (the “ Increase Date ”).

5. Reaffirmation of Security . Borrower, Lenders and the Administrative Agent hereby expressly intend that this Amendment shall not in any manner (a) constitute the refinancing, refunding, payment or extinguishment of the Obligations evidenced by the existing Loan Documents; (b) be deemed to evidence a novation of the outstanding balance of the Obligations; or (c) replace, impair, or extinguish the creation, attachment, perfection or priority of the Liens on the Borrowing Base Properties. Borrower ratifies and reaffirms any and all grants of Liens to Lenders and the Administrative Agent on the Borrowing Base Properties as security for the Obligations, and Borrower acknowledges and confirms that the grants of the Liens to Lenders and the Administrative Agent on the Borrowing Base Properties: (i) represent continuing Liens on all of the Borrowing Base Properties, (ii) secure all of the Obligations, and (iii) represent valid, first and best Liens on all of the Borrowing Base Properties except to the extent of any Permitted Liens.

6. Representations . To induce Lenders and the Administrative Agent to accept this Amendment, Borrower hereby represents and warrants to Lenders and the Administrative Agent as follows:

(a) Power and Authority . Borrower has full power and authority to enter into, and to perform its obligations under, this Amendment, and the execution and delivery of, and the performance of its obligations under and arising out of, this Amendment have been duly authorized by all necessary corporate action.

(d) No Events of Default . No Event of Default has occurred and is continuing.

7. Fees, Costs and Expenses . As a condition of this Amendment, Borrower will (i) in connection with the execution and delivery of this Amendment, pay to the Administrative Agent (A) for the account of Texas Capital, a commitment fee of $85,000, (B) for the account of Community Banks of Colorado, a threshold commitment fee of $11,250, (C) for the account of Amegy Bank National Association, a threshold commitment fee of $30,000, and (D) for the account of the Administrative Agent, an Administrative Fee of $9,753, representing a prorated annual fee of $20,000, and (ii) reimburse the Administrative Agent’s for all out of pocket expenses (including reasonable attorneys’ fees) incurred in connection with this Amendment.

8. Release . Borrower, on its behalf and, as applicable, on behalf of Borrower’s officers, directors, shareholders, Affiliates, Subsidiaries, successors and assigns (collectively, the “ Releasing Parties ”), hereby represents and warrants that such Releasing Parties have no claims, counterclaims, setoffs, actions or causes of action, damages or liabilities of any kind or nature whatsoever, whether in law or in equity, in contract or in tort, whether now accrued or hereafter maturing (collectively, “ Claims ”) against Lenders or the Administrative Agent, their direct or indirect Affiliates, or any of the foregoing’s respective directors, officers, employees, attorneys and legal representatives, or the heirs, administrators, successors or assigns of any of them (collectively, “ Lender Parties ”) to the extent that any such Claim directly or indirectly arises out of, is based upon or is in any manner connected with, any Prior Related Event. Borrower, on its behalf and, as applicable, on behalf of the other Releasing Parties, voluntarily releases and forever discharges all Lender Parties from any and all Claims, whether known or unknown, to the extent that any such Claim directly or indirectly arises out of, is based upon or is in any manner connected with any Prior Related Event. “ Prior Related Event ” means any transaction, event, circumstance, action, failure to act, occurrence of any type or sort, whether known or unknown, which occurred, existed, was taken, was permitted or begun in accordance with, pursuant to or by virtue of: (a) any of the terms of any Loan Document or this Amendment, (b) any actions, transactions, matters or circumstances related hereto or to any Loan Document, (c) the conduct of the relationship between any Lender Party and Borrower and its Subsidiaries, or (d) any other actions or inactions by any Lender Party, in each case on or prior to the Effective Date.

9. Continuing Effect of Credit Agreement; Reaffirmation of Loan Documents . Except as expressly amended hereby, all of the provisions of the Credit Agreement are ratified and confirmed and remain in full force and effect. The existing Loan Documents, except as amended by this Amendment, shall remain in full force and effect, and each of them is hereby ratified and confirmed by Borrower, Lenders and the Administrative Agent.

10. One Agreement; References; Fax Signature . The Credit Agreement, as amended by this Amendment, will be construed as one agreement. All references in any of the Loan Documents to the Credit Agreement will be deemed to be references to the Credit Agreement as amended by this Amendment. This Amendment may be signed by facsimile signatures or other electronic delivery of an image file reflecting the execution hereof, and if so signed, (a) may be relied on by each party as if the document were a manually signed original and (b) will be binding on each party for all purposes.

11. Captions . The headings to the Sections of this Amendment have been inserted for convenience of reference only and shall in no way modify or restrict any provisions hereof or be used to construe any such provisions.

12. Counterparts . This Amendment may be executed in multiple counterparts, each of which shall be an original but all of which together shall constitute one and the same instrument.

13. Entire Agreement . This Amendment sets forth the entire agreement of the parties with respect to the subject matter of this Amendment and supersedes all previous understandings, written or oral, in respect of this Amendment. At no time shall the prior or subsequent course of conduct by Borrower, Lenders or the Administrative Agent directly or indirectly limit, impair or otherwise adversely affect any of the parties’ rights or remedies in connection with this Amendment or any of the documents, instruments and agreements executed in connection herewith, as Lenders, the Administrative Agent and Borrower agree that this Amendment shall only be amended by written instruments executed by Lenders, the Administrative Agent and Borrower. Except to the extent that the Loan Documents are expressly amended by this Amendment, if there is any conflict, ambiguity, or inconsistency, in the Administrative Agent’s judgment, between the terms of this Amendment and any of the other Loan Documents, then the applicable terms and provisions, in the Administrative Agent’s judgment, providing Lenders and the Administrative Agent with greater rights, remedies, powers, privileges, or benefits will control.

14. Governing Law; Severability . This Amendment shall be governed by and construed in accordance with the internal laws of the State of Colorado (without regard to its conflicts of law principles). If any term of this Amendment is found invalid under Colorado law or laws of mandatory application by a court of competent jurisdiction, the invalid term will be considered excluded from this Amendment and will not invalidate the remaining terms of this Amendment.

15. WAIVER OF JURY TRIAL . BORROWER, LENDERS AND THE ADMINISTRATIVE AGENT EACH WAIVE TRIAL BY JURY WITH RESPECT TO ANY ACTION, CLAIM, SUIT OR PROCEEDING IN RESPECT OF OR ARISING OUT OF THIS AMENDMENT, ANY OF THE OTHER LOAN DOCUMENTS, OR THE TRANSACTIONS CONTEMPLATED HEREBY.

[ signature page follows ]

The parties have caused this Amendment to be duly executed and delivered as of the day and year first above written.

BORROWER:

SYNERGY RESOURCES CORPORATION

By: /s/ Edward Holloway
Name: Edward Holloway
Title: Chief Executive Officer

ADMINISTRATIVE AGENT:

COMMUNITY BANKS OF COLORADO ,
as Administrative Agent

By: /s/ Sarah Burchett
Name: Sarah Burchett
Title: Vice President

LENDERS:

COMMUNITY BANKS OF COLORADO ,
as a Lender

By: /s/ Sarah Burchett
Name: Sarah Burchett
Title: Vice President

COBIZ BANK, A COLORADO CORPORATION, DBA COLORADO BUSINESS BANK ,
as a Lender

By: /s/ Douglas K. Derks
Name: Douglas K. Derks
Title: Senior Vice President

[Signature Page to Second Amendment to Credit Agreement]

AMEGY BANK NATIONAL ASSOCIATION,
as a Lender

By:              /s/ Kevin Donaldson
Name:              Kevin Donaldson
Title:              Senior Vice President

TEXAS CAPITAL BANK , N.A.

as a Lender

By: /s/ Kelly Graham
Name: Kelly Graham
Title: Vice President

[Signature Page to Second Amendment to Credit Agreement]

ANNEX I
LIST OF MAXIMUM CREDIT AMOUNTS

Aggregate Maximum Credit Amounts

Name of Lender	Applicable Percentage	Maximum Credit Amount	Amount of Commitment on the Effective Date
Community Banks of Colorado	33.333333333%	$ 50,000,000	$ 25, 000, 000
CoBiz Bank, a Colorado corporation, dba Colorado Business Bank	13.333333333%	$ 20,000,000	$ 10, 000, 000
Amegy Bank National Association	30.666666667%	$ 46,000,000	$ 23,000,000
Texas Capital Bank	22.666666667%	$ 34,000,000	$ 17,000,000
TOTAL	100.000000000%	$ 150, 000, 000	$ 75, 000, 000

EXHIBIT A

[see attached]

THIRD AMENDMENT TO CREDIT AGREEMENT

This Third Amendment to Credit Agreement (this “ Amendment ”) is made and entered into effective as of December 20, 2013 (the “ Effective Date ”), by and between Synergy Resources Corporation, a Colorado corporation (the “ Borrower ”), each of the Lenders party to the Credit Agreement (as defined below) (“ Lenders ”), SunTrust Bank (“ SunTrust ”), KeyBank National Association (“ Key Bank ”), and Community Banks of Colorado, a division of NBH Bank, N.A., individually, as Issuing Bank and as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “ Administrative Agent ”), and is as follows:

Preliminary Statements

A. Lenders, the Administrative Agent and the Borrower are parties to an Amended and Restated Credit Agreement dated as of November 28, 2012, as amended by that First Amendment dated as of February 12, 2013 (the “ First Amendment ”) and that Second Amendment (the “ Second Amendment ”) dated as of June 28, 2013 (as amended, the “ Credit Agreement ”). Capitalized terms which are used, but not defined, in this Amendment will have the meanings given to them in the Credit Agreement.

B. The Borrower has requested that Lenders and the Administrative Agent make certain amendments to the Credit Agreement, all as more particularly set forth herein.

C. Lenders and the Administrative Agent are willing to consent to such requests and so amend the Credit Agreement to reflect such modifications, all on the terms of this Amendment.

Statement of Amendment

In consideration of the mutual covenants and agreements set forth in this Amendment, and for other good and valuable consideration, Lenders, the Administrative Agent, SunTrust, Key Bank and the Borrower hereby agree as follows:

1. Amendments to Credit Agreement . Subject to the terms and provisions of this Amendment, the Credit Agreement is hereby amended as follows:

(a) Section 1.01 of the Credit Agreement is hereby amended to add thereto in alphabetical order the following definitions which shall read in full as follows:

“ Commodity Exchange Act ” means the Commodity Exchange Act (7 U.S.C. § 1 et seq.), as amended from time to time, and any successor statute, and any regulations promulgated thereunder.

“ Excluded Swap Obligations ” means, with respect to any Guarantor, any Swap Obligation if, and to the extent that, all or a portion of the guarantee of such Guarantor of, or the grant by such Guarantor of a security interest to secure, such Swap Obligation (or any guarantee thereof) is or becomes illegal under the Commodity Exchange Act or any rule, regulation or order of the Commodity Futures Trading Commission (or the application or official interpretation of any thereof) by virtue of such Guarantor’s failure for any reason to constitute an “eligible contract participant” as defined in the Commodity Exchange Act and the regulations thereunder at the time the guarantee of such Guarantor or the grant of such security interest becomes effective with respect to such Swap Obligation. If a Swap Obligation arises under a master agreement governing more than one swap, such exclusion shall apply only to the portion of such Swap Obligation that is attributable to swaps for which such guarantee or security interest is or becomes illegal.

“ Qualified ECP Guarantor ” means, in respect of any Swap Obligation, each Guarantor that (a) has total assets exceeding $10,000,000 at the time any guaranty of obligations under such Swap Obligation or grant of the relevant security interest becomes effective or (b) otherwise constitutes an “eligible contract participant” under the Commodity Exchange Act and can cause another Person to qualify as an “eligible contract participant” at such time by entering into a keepwell under Section 1a(18)(A)(v)(II) of the Commodity Exchange Act.

“ Swap Obligation ” means, with respect to any Guarantor, any obligation to pay or perform under any agreement, contract or transaction that constitutes a “swap” within the meaning of section 1a(47) of the Commodity Exchange Act.

(b) The following definitions in Section 1.01 of the Credit Agreement are hereby amended and restated in their entirety as follows:

“ Approved Counterparty ” means (a) any Lender or any Affiliate of a Lender, or (b) any other Person whose (y) credit rating assigned by Moody’s or S&P (or their equivalent) to its unsecured long-term indebtedness is not lower than Baa3 or BBB-, respectively, or (z) obligations under any Hedging Agreement with the Borrower are guaranteed by an entity whose credit rating assigned by Moody’s or S&P (or their equivalent) to its unsecured long-term indebtedness is not lower than Baa3 or BBB-, respectively.

“ Excepted Liens ” means: (a) Liens for Taxes, assessments or other governmental charges or levies which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (b) Liens in connection with workers’ compensation, unemployment insurance or other social security, old age pension or public liability obligations which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (c) statutory landlord’s liens, operators’, vendors’, carriers’, warehousemen’s, repairmen’s, mechanics’, suppliers’, workers’, materialmen’s, construction or other like Liens arising by operation of law in the ordinary course of business or incident to the exploration, development, operation and maintenance of Oil and Gas Properties each of which is in respect of obligations that are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (d) contractual Liens which arise in the ordinary course of

business under operating agreements, joint venture agreements, oil and gas partnership agreements, oil and gas leases, farm‑out agreements, division orders, contracts for the sale, transportation or exchange of oil and natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements, royalty agreements, overriding royalty agreements, marketing agreements, processing agreements, net profits agreements, development agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or other geophysical permits or agreements and other agreements which are usual and customary in the oil and gas business and are for claims which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP, provided that any such Lien referred to in this clause does not materially impair the use of the Property covered by such Lien for the purposes for which such Property is held by the Borrower or any Subsidiary or materially impair the value of such Property subject thereto; (e) Liens arising solely by virtue of any statutory or common law provision relating to banker’s liens, rights of set‑off or similar rights and remedies and burdening only deposit accounts or other funds maintained with a creditor depository institution, provided that no such deposit account is a dedicated cash collateral account or is subject to restrictions against access by the depositor in excess of those set forth by regulations promulgated by the Board and no such deposit account is intended by the Borrower or any of its Subsidiaries to provide collateral to the depository institution; (f) easements, restrictions, servitudes, permits, conditions, covenants, exceptions or reservations in any Property of the Borrower or any Subsidiary for the purpose of roads, pipelines, transmission lines, transportation lines, distribution lines for the removal of gas, oil, coal or other minerals or timber, and other like purposes, or for the joint or common use of real estate, rights of way, facilities and equipment, and Liens related to surface leases and surface operations, that do not secure any monetary obligations and which in the aggregate do not materially impair the use of such Property for the purposes of which such Property is held by the Borrower or any Subsidiary or materially impair the value of such Property subject thereto; (g) Liens on cash or securities pledged to secure performance of tenders, surety and appeal bonds, government contracts, performance and return of money bonds, bids, trade contracts, leases, statutory obligations, regulatory obligations and other obligations of a like nature incurred in the o rdinary course of business; (h) judgment and attachment Liens not giving rise to an Event of Default; and (i) Liens arising from the debt associated with Secured Hedging Agreement, provided that any appropriate legal proceedings which may have been duly initiated for the review of such judgment shall not have been finally terminated or the period within which such proceeding may be initiated shall not have expired and no action to enforce such Lien has been commenced; provided, further that Liens described in clauses (a) through (e) shall remain “ Excepted Liens ” only for so long as no action to enforce such Lien has been commenced and no intention to subordinate the first priority Lien granted in favor of the Administrative Agent and the Lenders is to be hereby implied or expressed by the permitted existence of such Excepted Liens.

“ Fee Letter ” means that that letter agreement dated October 11, 2012, by and between the Borrower and the Administrative Agent, related to, among other things, the payment of certain fees by the Borrower, as amended by that letter agreement dated as of December 20, 2013, by and between the Borrower and the Administrative Agent.

“ Required Lenders ” means Lenders holding, in the aggregate, at least sixty-six and two-thirds percent (66 2/3%) of the outstanding Revolving Credit Exposure, unless there is no outstanding Revolving Credit Exposure at such time, and in such case, then Lenders holding, in the aggregate, at least sixty-six and two-thirds percent (66 2/3%) of the existing Commitments at such time; provided, however, that under if any one Lender holds 66 2/3% of the outstanding Revolving Credit Exposure or of the existing Commitments, as applicable, then the Required Lenders shall mean such Lender and at least one other Lender.

(c) Section 2.06(c) of the Credit Agreement is hereby amended by increasing the amount in clause (ii) from $150,000,000 to $300,000,000.

(d) Clause (i) of Section 2.07(f) of the Credit Agreement is hereby amended and restated in its entirety as follows:

“(i) If the Borrower or any Subsidiary novates, sells, assigns, unwinds, terminates, restructures, modifies, amends or otherwise affects (“ Unwinds ”) any Borrowing Base Hedging Agreement, the Borrower shall promptly provide the Administrative Agent with written notice of such Unwind and the Borrowing Base then in effect shall automatically be reduced by an amount equal to the mark-to-market value (as determined by the Administrative Agent) of such Borrowing Base Hedging Agreement as of the date of such Unwind, if any, resulting from such event (which right shall be in addition to the Administrative Agent’s right to request Interim Redetermination between each Scheduled Redetermination).”

(e) Clause (b) of Section 5.01 of the Credit Agreement is hereby amended and restated in its entirety as follows:

“(b) Capital Requirements . If any Change in Law regarding capital or liquidity requirements has the effect of reducing the rate of return on a Lender’s or Issuing Bank’s capital or on the capital of such Lender’s or Issuing Bank’s holding company, if any, as a consequence of this Agreement or the Loans made by, or participations in Letters of Credit held by, such Lender, or the Letters of Credit issued by any Issuing Bank, to a level below that which such Lender or Issuing Bank or such Lender’s or Issuing Bank’s holding company could have achieved but for such Change in Law (taking into consideration such Lender’s or Issuing Bank’s policies and the policies of such Lender’s or Issuing Bank’s holding company with respect to capital adequacy), then from time to time the Borrower will pay to such Lender or Issuing Bank, as the case may be, such additional amount or amounts as will compensate such Lender or Issuing Bank or such Lender’s or Issuing Bank’s holding company for any such reduction suffered.”

(f) A new Section 8.19 of the Credit Agreement shall be added to Article VIII of the Credit Agreement in appropriate numerical order to read in full as follows:

“Section 8.19 Commodity Exchange Act Keepwell Provisions . The Borrower hereby guarantees the payment and performance of all Indebtedness of each Guarantor and absolutely, unconditionally and irrevocably undertakes to provide such funds or other support as may be needed from time to time by each Guarantor in order for such Guarantor to honor its obligations under its respective guaranty agreement including obligations with respect to Swap Obligations (provided, however, that the Borrower shall only be liable under this Section 8.19 for the maximum amount of such liability that can be hereby incurred without rendering its obligations under this Section 8.19 , or otherwise under this Agreement or any Loan Document, as it relates to such other Guarantor, voidable under applicable law relating to fraudulent conveyance or fraudulent transfer, and not for any greater amount). The obligations of the Borrower under this Section 8.19 shall remain in full force and effect until all Indebtedness is paid in full to the Lenders, the Administrative Agent and all other Secured Parties, and all of the Lenders’ Commitments are terminated. The Borrower intends that this Section 8.19 constitute, and this Section 8.19 shall be deemed to constitute, a “keepwell, support, or other agreement” for the benefit of each other Guarantor for all purposes of Section 1a(18)(A)(v)(II) of the Commodity Exchange Act.”

(g) Section 9.18 of the Credit Agreement is hereby amended and restated in its entirety as follows:

“Section 9.18 Hedging Agreements .

(a) The Borrower shall neither assign, terminate , unwind nor sell any Hedging Agreements listed on Schedule 7.20 . The Borrower shall not enter into Hedging Agreements in respect of commodities other than Hydrocarbons. In the case of Hydrocarbons, the Borrower shall not enter into Hedging Agreements if the effect thereof would be to cause the notional volumes of all Hedging Agreements and additional fixed‑price physical off‑take contracts, in the aggregate, to exceed (i) 85% of the projected production from the Borrower’s Proved Developed Producing Reserves reflected in the most recently completed Reserve Report for any month continuing through and including the date that is twelve (12) months following the effective date of each such Hedging Agreement, (ii) 70% of the projected production from the Borrower’s Proved Developed Producing Reserves for any month beginning at the expiration of the period in clause (i) and continuing through and including the date that is twelve (12) months following such date, (iii) 60% of the projected production from the Borrower’s Proved Developed Producing Reserves for any month beginning at the expiration of the period in clause (ii) and continuing through and including the date that is twelve (12) months following such date and (iv) 50% of the projected production from the Borrower’s Proved Developed Producing Reserves for any month beginning at the expiration of the period clause (iii) and continuing through and including the date that is twelve (12) months following such date (it being understood that any put contracts entered into for non speculative purposes shall not count against the above limitation). The Borrower shall not enter into Hedging Agreements converting interest rates. The Borrower shall not post any collateral to secure Hedging Agreements, except as contemplated by the Loan Documents in the case of a Secured Hedging Counterparty.

(b) In addition to the Hedging Agreements permitted under Section 9.18(a) , if after the date of the latest Reserve Report the Borrower converts any of its Oil and Gas Properties (through drilling operations or otherwise) from Proved Developed Nonproducing Reserves or Proved Undeveloped Reserves (in each case, as shown in the latest Reserve Report) to Proved Developed Producing Reserves (such converted reserves being referred to herein as “ Additional Proved Producing Reserves ”), the Borrower may, but shall not be obligated to, provide the Administrative Agent with the Borrower’s good faith estimated production forecast (which forecast shall be prepared showing monthly production numbers, a “ Production Forecast ”) for the Additional Proved Producing Reserves. If the Borrower provides a Production Forecast to the Administrative Agent, the Borrower shall also provide the Administrative Agent with any other information requested by the Administrative Agent with respect to such Additional Proved Producing Reserves. Unless the Administrative Agent notifies the Borrower in writing within five Business Days of its receipt of a Production Forecast that the Administrative Agent is rejecting the Borrower’s treatment of such reserves as Additional Proved Producing Reserves or is otherwise modifying the Borrower’s production estimates set forth in the Production Forecast, the Borrower shall be permitted to enter into Hedging Agreements for up to 70% of the projected production from such Additional Proved Producing Reserves, but only with respect to that production that is forecasted in the Production Forecast to occur during the 12 month period beginning with the first month after the expiration of such 5-day period. The Additional Proved Producing Reserves shall be included in the next Reserve Report prepared in accordance with Section 8.12 and, at such time, the Borrower shall be subject to the limitations on Hedging Agreements contemplated by Section 9.18 with respect to such Additional Proved Producing Reserves.

(c) The limitations on Hedging Agreements set forth in this Section 9.18 shall be calculated based upon barrels of oil or cubic feet of natural gas, as the case may be, as set forth in the relevant Reserve Report (in the case of Section 9.18(a) ) or the Production Forecast (in the case of Section 9.18(b) ) and shall not be based on barrel of oil equivalent (or BOE) computations.”

(h) Clause (c) of Section 10.02 of the Credit Agreement is hereby amended by inserting the following language immediately following clause (c), which shall read in its entirety as follows:

“Notwithstanding the foregoing, amounts received from the Borrower or any Guarantor that is not an “eligible contract participant” under the Commodity Exchange Act shall not be applied to any Excluded Swap Obligations (it being understood, that in the event that any amount is applied to Indebtedness other than Excluded Swap Obligations as a result of this this clause, the Administrative Agent shall make such adjustments as it determines are appropriate to distributions pursuant to clause fourth above from amounts received from “eligible contract participants” under the Commodity Exchange Act to ensure, as nearly as possible, that the proportional aggregate recoveries with respect to Indebtedness described in clause fourth above by the holders of any Excluded Swap Obligations are the same as the proportional aggregate recoveries with respect to other Indebtedness pursuant to clause fourth above).”

(i) Clause (b) of Section 12.02 of the Credit Agreement is hereby amended and restated in its entirety as follows:

“(b) Neither this Agreement nor any provision hereof nor any Security Instrument nor any provision thereof may be waived, amended or modified except pursuant to an agreement or agreements in writing entered into by the Borrower and the Lenders or by the Borrower and the Administrative Agent with the consent of the Lenders; provided that no such agreement shall (i) increase the Commitment or the Maximum Credit Amount of any Lender without the written consent of such Lender, (ii) increase the Borrowing Base without the written consent of each Lender, decrease or maintain the Borrowing Base without the written consent of each Lender (other than any Defaulting Lender), or modify Section 2.07 in any manner without the consent of each Lender (other than any Defaulting Lender); provided that a Scheduled Redetermination may be postponed by the Lenders, (iii) reduce the principal amount of any Loan or LC Disbursement or reduce the rate of interest thereon, or reduce any fees payable hereunder, or reduce any other Indebtedness hereunder or under any other Loan Document, without the written consent of each Lender affected thereby, (iv) postpone the scheduled date of payment or prepayment of the principal amount of any Loan or LC Disbursement, or any interest thereon, or any fees payable hereunder, or any other Indebtedness hereunder or under any other Loan Document, or reduce the amount of, waive or excuse any such payment, or postpone or extend the Termination Date without the written consent of each Lender affected thereby, (v) change Section 4.01(b) or Section 4.01(c) in a manner that would alter the pro rata sharing of payments required thereby, without the written consent of each Lender, (vi) waive or amend Section 3.04(c) , Section 6.01 , Section 8.14 , Section 10.02(c) or Section 12.14 , without the written consent of each Lender (other than any Defaulting Lender),(vii) release any Guarantor from its obligations under any guaranty agreement that relates to the Indebtedness, without the written consent of each Lender (other than any Defaulting Lender), (viii) release the Liens contemplated by any Security Instrument on all or substantially all of the collateral covered thereby (other than a release of Liens related to Oil and Gas Properties transferred in accordance with Section 9.11 ),

without the written consent of each Lender (other than any Defaulting Lender) or (ix) change any of the provisions of this Section 12.02(b) or any other provision hereof specifying the number or percentage of Lenders required to waive, amend or modify any rights hereunder or under any other Loan Documents or make any determination or grant any consent hereunder or any other Loan Documents, without the written consent of each Lender (other than any Defaulting Lender); provided further that no such agreement shall amend, modify or otherwise affect the rights or duties of the Administrative Agent or any Issuing Bank hereunder or under any other Loan Document without the prior written consent of the Administrative Agent or such Issuing Bank, as the case may be. Notwithstanding the foregoing, any supplement to Schedule 7.24 (Material Agreements) shall be effective simply by delivering to the Administrative Agent a supplemental schedule clearly marked as such and, upon receipt, the Administrative Agent will promptly deliver a copy thereof to the Lenders.

(j) Annex I to the Credit Agreement is hereby amended and restated in its entirety to conform to Annex I attached hereto. The adjustment to each Lender’s Applicable Percentage as set forth on Annex I attached hereto shall be effective as of the Increase Date (defined below) and each Lender’s Applicable Percentage prior to the Increase Date shall be as set forth in Annex I to the Credit Agreement.

2. Eligible Lenders . The parties to this Amendment agree that SunTrust and Key Bank are Eligible Lenders. Each of SunTrust and Key Bank hereby agrees that upon the execution of this Amendment, it shall become a party to the Credit Agreement and shall be fully bound by, and subject to, all of the covenants, terms and conditions of the Credit Agreement as though an original party thereto. From and after the date hereof, all references in the Credit Agreement and in all other Loan Documents to the “Lenders” shall be deemed to include SunTrust and Key Bank.

3. Adjustments . On the Effective Date, the Borrower shall, in coordination with the Administrative Agent, repay the outstanding Loans of certain Lenders, and incur additional Loans from certain other Lenders, in each case to the extent necessary so that all of the Lenders participate in the Borrowings ratably on the basis of their respective Commitments (after giving effect to any adjustments contemplated by Section 1(j) hereof).

4. Borrowing Base . In connection with the second Scheduled Redetermination contemplated by Section 2.07 of the Credit Agreement, the Administrative Agent, the Lenders and the Borrower have agreed that the Borrowing Base shall be increased to $90,000,000, which Borrowing Base adjustment shall be effective as of the later of December 20, 2013, or the satisfaction of the conditions set forth in Section 7 hereof (the “ Increase Date ”).

5. Reaffirmation of Security . The Borrower, Lenders and the Administrative Agent hereby expressly intend that this Amendment shall not in any manner (a) constitute the refinancing, refunding, payment or extinguishment of the Indebtedness evidenced by the existing Loan Documents; (b) be deemed to evidence a novation of the outstanding balance of the Indebtedness; or (c) replace, impair, or extinguish the creation, attachment, perfection or priority of the Liens on the Borrowing Base Properties. The Borrower ratifies and reaffirms any and all grants of Liens to Lenders and the Administrative Agent on the Borrowing Base Properties as security for the Indebtedness, and the Borrower acknowledges and confirms that the grants of the Liens to Lenders and the Administrative Agent on the Borrowing Base Properties: (i) represent continuing Liens on all of the Borrowing Base Properties, (ii) secure all of the Indebtedness, and (iii) represent valid, first and best Liens on all of the Borrowing Base Properties except to the extent of any Permitted Liens

6. Collateral Agent . The Borrower, Lenders and the Administrative Agent hereby expressly authorize Community Banks of Colorado to serve as collateral agent (the “ Collateral Agent ”) under any of the Security Instruments for the ratable benefits of Lenders, the Administrative Agent, any Secured Hedging Counterparties and the Collateral Agent and agree that any Lien granted to the Collateral Agent by the Borrower or any Guarantor to secure the Indebtedness shall be held by the Collateral Agent for the ratable benefit of Lenders, the Administrative Agent, any Secured Hedging Counterparties and the Collateral Agent. Community Banks of Colorado is further authorized to cause any Liens granted to it under the Security Instruments in its capacity as Administrative Agent to be transferred and conveyed to it in its capacity as Collateral Agent.

7. Conditions Precedent . This Amendment will not become effective until the date on which each of the following conditions is satisfied:

(a) The Borrower shall have executed and delivered to the Administrative Agent the Promissory Notes attached hereto as Exhibit A (the “ Amendment Notes ”). These Amendment Notes, to the extent that they are for the benefit of Lenders other than SunTrust and Key Bank, are issued in substitution for and replacement of, but not repayment of (i) those certain Amended and Restated Promissory Notes, dated as of June 28, 2013, issued by the Borrower in favor of those Lenders in connection with the Second Amendment, and (ii) that Promissory Note, dated as of June 28, 2013, issued by the Borrower in favor of Texas Capital Bank, N.A. in connection with the Second Amendment. The Amendment Notes shall constitute a “Note” as defined and described in the Credit Agreement. From and after the date hereof, all references in the Credit Agreement and in all other Loan Documents to the “Notes” shall be deemed to be references to the Amendment Notes.

(b) The Administrative Agent shall have received counterparts of this Amendment from the Borrower and each of the Lenders.

(c) The Administrative Agent shall have received all fees and other amounts due and payable on or prior to the effective date of this Amendment.

(d) The Administrative Agent shall have received title information satisfactory to it on at least 80% (by NPV) of the total Proved Reserves attributable to the Oil and Gas Properties evaluated in such Reserve Report, with such 80% first being satisfied from Proved Developed Producing Reserves, next from Proved Developed Nonproducing Reserves and thereafter from Proved Undeveloped Reserves.

(e) The Administrative Agent shall have received information and evidence satisfactory to it that the Mortgaged Properties represent at least 80% (by NPV) of the Oil and Gas Properties evaluated in the most recently completed Reserve Report, with such 80% first being satisfied from Proved Developed Producing, next from Proved Developed Nonproducing Reserves and thereafter from Proved Undeveloped Reserves.

(f) No Default or Event of Default shall have occurred that is continuing.

(g) The Administrative Agent shall have received such other documents as the Administrative Agent or counsel to the Administrative Agent may reasonably request.

The Administrative Agent shall notify the Borrower and the Lenders of the effectiveness of this Amendment, and such notice shall be conclusive and binding.

8. Representations . To induce Lenders and the Administrative Agent to accept this Amendment, the Borrower hereby represents and warrants to Lenders and the Administrative Agent as follows:

(a) Power and Authority . The Borrower has full power and authority to enter into, and to perform its obligations under, this Amendment, and the execution and delivery of, and the performance of its obligations under and arising out of, this Amendment have been duly authorized by all necessary corporate action.

(b) Legal, Valid and Binding Obligation . This Amendment constitutes the legal, valid and binding obligation of the Borrower enforceable in accordance with its terms, except as such enforceability may be limited by bankruptcy, insolvency, reorganization or similar laws affecting creditors’ rights generally.

(c) Continued Representations and Warranties . After giving effect to the amendments contained in this Amendment, the Borrower’s representations and warranties contained in the Loan Documents are complete and correct as of the date of this Amendment with the same effect as though these representations and warranties had been made again on and as of the date of this Amendment, subject to those changes as are not prohibited by, or do not constitute Events of Default under, the Credit Agreement.

(d) No Defenses . The Borrower has no defenses to payment, counterclaims, or right of set-off with respect to any Indebtedness existing as of the Effective Date.

(e) No Events of Default . No Event of Default has occurred and is continuing.

(f) Material Adverse Effect . The Borrower hereby affirms that no Material Adverse Effect has occurred

9. First Amendment . The parties acknowledge and agree that the First Amendment was dated as of February 12, 2013 and that such date shall be the Effective Date (as such term is used in the First Amendment) for all purposes related to the First Amendment.

10. Fees, Costs and Expenses . As a condition of this Amendment, the Borrower will (i) in connection with the execution and delivery of this Amendment, pay to the Administrative Agent (A) for the account of SunTrust, a commitment fee of $37,500, (B) for the account of Key Bank, a commitment fee of $37,500, and (C) for the account of the Administrative Agent, an Administrative Fee of $19,644.26, and (ii) reimburse the Administrative Agent’s for all out of pocket expenses (including reasonable attorneys’ fees) incurred in connection with this Amendment.

11. Release . The Borrower, on its behalf and, as applicable, on behalf of the Borrower’s officers, directors, shareholders, Affiliates, Subsidiaries, successors and assigns (collectively, the “ Releasing Parties ”), hereby represents and warrants that such Releasing Parties have no claims, counterclaims, setoffs, actions or causes of action, damages or liabilities of any kind or nature whatsoever, whether in law or in equity, in contract or in tort, whether now accrued or hereafter maturing (collectively, “ Claims ”) against Lenders or the Administrative Agent, their direct or indirect Affiliates, or any of the foregoing’s respective directors, officers, employees, attorneys and legal representatives, or the heirs, administrators, successors or assigns of any of them (collectively, “ Lender Parties ”) to the extent that any such Claim directly or indirectly arises out of, is based upon or is in any manner connected with, any Prior Related Event. The Borrower, on its behalf and, as applicable, on behalf of the other Releasing Parties, voluntarily releases and forever discharges all Lender Parties from any and all Claims, whether known or unknown, to the extent that any such Claim directly or indirectly arises out of, is based upon or is in any manner connected with any Prior Related Event. “ Prior Related Event ” means any transaction, event, circumstance, action, failure to act, occurrence of any type or sort, whether known or unknown, which occurred, existed, was taken, was permitted or begun in accordance with, pursuant to or by virtue of: (a) any of the terms of any Loan Document or this Amendment, (b) any actions, transactions, matters or circumstances related hereto or to any Loan Document, (c) the conduct of the relationship between any Lender Party and the Borrower and its Subsidiaries, or (d) any other actions or inactions by any Lender Party, in each case on or prior to the Effective Date.

12. Continuing Effect of Credit Agreement; Reaffirmation of Loan Documents . The provisions of the Credit Agreement (as amended by this Amendment) shall remain in full force and effect in accordance with its terms following the effectiveness of this Amendment. Except as expressly amended hereby, all of the provisions of the Credit Agreement are ratified and confirmed. The existing Loan Documents, except as amended by this Amendment, shall remain in full force and effect, and each of them is hereby ratified and confirmed by the Borrower, Lenders and the Administrative Agent.

13. One Agreement; References; Fax Signature . The Credit Agreement, as amended by this Amendment, will be construed as one agreement. Each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof”, “herein”, or words of like import shall mean and be a reference to the Credit Agreement as amended hereby, and each reference to the Credit Agreement in any Loan Document or any other document, instrument or agreement executed and/or delivered in connection with the Credit Agreement shall mean and be a reference to the Credit Agreement as amended hereby. This Amendment may be signed by facsimile signatures or other electronic delivery of an image file reflecting the execution hereof, and if so signed, (a) may be relied on by each party as if the document were a manually signed original and (b) will be binding on each party for all purposes.

14. No Implied Consent or Waiver . This Amendment shall not be construed as consent to the departure from, or a waiver of the terms and conditions of, the Credit Agreement except as expressly set forth herein.

15. Captions . The headings to the Sections of this Amendment have been inserted for convenience of reference only and shall in no way modify or restrict any provisions hereof or be used to construe any such provisions.

16. Counterparts . This Amendment may be executed in multiple counterparts, each of which shall be an original but all of which together shall constitute one and the same instrument.

17. Entire Agreement . This Amendment sets forth the entire agreement of the parties with respect to the subject matter of this Amendment and supersedes all previous understandings, written or oral, in respect of this Amendment. At no time shall the prior or subsequent course of conduct by the Borrower, Lenders or the Administrative Agent directly or indirectly limit, impair or otherwise adversely affect any of the parties’ rights or remedies in connection with this Amendment or any of the documents, instruments and agreements executed in connection herewith, as Lenders, the Administrative Agent and the Borrower agree that this Amendment shall only be amended by written instruments executed by Lenders, the Administrative Agent and the Borrower. Except to the extent that the Loan Documents are expressly amended by this Amendment, if there is any conflict, ambiguity, or inconsistency, in the Administrative Agent’s judgment, between the terms of this Amendment and any of the other Loan Documents, then the applicable terms and provisions, in the Administrative Agent’s judgment, providing Lenders and the Administrative Agent with greater rights, remedies, powers, privileges, or benefits will control.

18. Governing Law; Severability . This Amendment shall be governed by and construed in accordance with the internal laws of the State of Colorado (without regard to its conflicts of law principles). If any term of this Amendment is found invalid under Colorado law or laws of mandatory application by a court of competent jurisdiction, the invalid term will be considered excluded from this Amendment and will not invalidate the remaining terms of this Amendment.

19. WAIVER OF JURY TRIAL . THE BORROWER, LENDERS AND THE ADMINISTRATIVE AGENT EACH WAIVE TRIAL BY JURY WITH RESPECT TO ANY ACTION, CLAIM, SUIT OR PROCEEDING IN RESPECT OF OR ARISING OUT OF THIS AMENDMENT, ANY OF THE OTHER LOAN DOCUMENTS, OR THE TRANSACTIONS CONTEMPLATED HEREBY.

[ signature page follows ]

The parties have caused this Amendment to be duly executed and delivered as of the day and year first above written.

BORROWER:

SYNERGY RESOURCES CORPORATION

By: /s/ Frank Jennings
Name: Frank Jennings
Title: Chief Financial Officer

ADMINISTRATIVE AGENT:

COMMUNITY BANKS OF COLORADO ,
as Administrative Agent

By: /s/ Sarah Burchett
Name: Sarah Burchett
Title: Vice President

LENDERS:

COMMUNITY BANKS OF COLORADO ,
as a Lender

By: /s/ Sarah Burchett
Name: Sarah Burchett
Title: Vice President

COBIZ BANK, A COLORADO CORPORATION, DBA COLORADO BUSINESS BANK ,
as a Lender

By: /s/ Douglas K. Derks
Name: Douglas K. Derks
Title: Senior Vice President

[Signature Page to Third Amendment to Credit Agreement]

AMEGY BANK NATIONAL ASSOCIATION ,
as a Lender

By:              /s/ Kevin Donaldson
Name:              Kevin Donaldson
Title:              Senior Vice President

TEXAS CAPITAL BANK , N.A. ,

as a Lender

By: /s/ W. David McCarver IV
Name: W. David McCarver IV
Title: Senior Vice President

SUNTRUST BANK ,

as a Lender

By:              /s/ Scott Mackey
Name:              Scott Mackey
Title:              Director

KEYBANK NATIONAL ASSOCIATION ,

as a Lender

By:              /s/ Paul J. Pace
Name:              Paul J. Pace
Title:              Senior Vice President

[Signature Page to Third Amendment to Credit Agreement]

ANNEX I
LIST OF MAXIMUM CREDIT AMOUNTS

Aggregate Maximum Credit Amounts

Name of Lender	Applicable Percentage	Maximum Credit Amount	Amount of Commitment on the Effective Date
Community Banks of Colorado	27.7777777778%	$ 83,333,333.33	$ 25, 000, 000.00
Amegy Bank National Association	25.5555555556%	$ 76,666,666.67	$ 23,000,000.00
Texas Capital Bank, N.A.	18.8888888889%	$ 56,666,666.67	$ 17,000,000.00
CoBiz Bank, a Colorado corporation, dba Colorado Business Bank	11.1111111111%	$ 33,333,333.33	$ 10, 000, 000.00
SunTrust Bank, Inc.	8.3333333334%	$ 25,000,000.00	$ 7,500,000.00
Key Bank National Association	8.3333333334%	$ 25,000,000.00	$ 7,500,000.00
TOTAL	100.0000000000%	$ 300, 000, 000.00	$ 90, 000, 000.00

EXHIBIT A

[see attached]

FOURTH AMENDMENT TO CREDIT AGREEMENT

This Fourth Amendment to Credit Agreement (this “ Amendment ”) is made and entered into effective as of June 3, 2014 (the “ Effective Date ”), by and between Synergy Resources Corporation, a Colorado corporation (the “ Borrower ”), each of the Lenders party to the Credit Agreement (as defined below) (“ Lenders ”), and Community Banks of Colorado, a division of NBH Bank, N.A., individually, as Issuing Bank and as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “ Administrative Agent ”), and is as follows:

Preliminary Statements

A. Lenders, the Administrative Agent and the Borrower are parties to an Amended and Restated Credit Agreement dated as of November 28, 2012, as amended by that First Amendment dated as of February 12, 2013 (the “ First Amendment ”), that Second Amendment (the “ Second Amendment ”) dated as of June 28, 2013 (as amended, the “ Credit Agreement ”) and that Third Amendment (the “ Third Amendment ”) dated as of December 20, 2013. Capitalized terms which are used, but not defined, in this Amendment will have the meanings given to them in the Credit Agreement.

B. The Borrower has requested that Lenders and the Administrative Agent make certain amendments to the Credit Agreement, all as more particularly set forth herein.

C. Lenders and the Administrative Agent are willing to consent to such requests and so amend the Credit Agreement to reflect such modifications, all on the terms of this Amendment.

Statement of Amendment

1. Amendments to Credit Agreement . Subject to the terms and provisions of this Amendment, the Credit Agreement is hereby amended as follows:

(a) The following definitions in Section 1.01 of the Credit Agreement are hereby amended and restated in their entirety as follows:

Borrowing Base Utilization	Libor Margin	Abr Margin
≥ 90%	275 bps	150 bps
≥ 75% and < 90%	250 bps	125 bps
≥ 50% and < 75%	225 bps	100 bps
≥ 25% and < 50%	200 bps	75 bps
< 25%	175 bps	50 bps

“ Termination Date ” means the earlier to occur of (i) May 29, 2019 or (ii) the date that the Aggregate Maximum Credit Amount is sooner terminated pursuant to Section 2.06 or Section 10.02 .”

(b) The first sentence of Section 3.05(e) of the Credit Agreement is hereby amended and restated in its entirety as follows:

“The Borrower agrees to pay to the Administrative Agent for the account of each Lender an unused commitment fee equal to (i) if the Borrowing Base Utilization Percentage is less than 50%, 0.375% per annum and (ii) if the Borrowing Base Utilization Percentage is equal to or greater than 50%, 0.50% per annum, in each case calculated on the average daily amount of the unused Commitment of such lender during the period from and including the date of this Agreement to but excluding the later of the date of termination of the Commitments.”

“(ii) on a quarterly basis by the 45th day after the end of each fiscal quarter of the Borrower, an updated report setting forth the forecasted Capital Expenditure budget for the Borrower and its Subsidiaries for the remainder of the Borrower’s fiscal year; provided, however, that in the case of the report delivered during the fourth quarter of each fiscal year, such report shall set forth the forecasted Capital Expenditure budget for the Borrower and its Subsidiaries for the following fiscal year; and”

(d) Section 9.01(a) of the Credit Agreement is hereby amended and restated in its entirety as follows:

“(a) Total Funded Debt to EBITDAX . The Borrower will not, at any time, permit its ratio of Total Funded Debt as of such time to EBITDAX to be greater than or equal to 4.0 to 1.0, determined at the fiscal year ending August 31, 2012, and each fiscal quarter thereafter.”

(e) Section 9.01(c) and Section 9.01(d) of the Credit Agreement are hereby deleted and removed from the Credit Agreement.

2. Adjustments . On the Effective Date, Texas Capital Bank, N.A. will be paid off and will no longer be a Lender under the Credit Agreement. The Borrower shall, in coordination with the Administrative Agent, repay the outstanding Loans of Texas Capital Bank, N.A., and incur additional Loans from the Lenders, in each case to the extent necessary so that Texas Capital Bank, N.A. is paid in full with respect to its Loans and all of the Lenders participate in the Borrowings ratably on the basis of their respective Commitments (after giving effect to any adjustments contemplated by Section 1 (j) hereof).

3. Borrowing Base . In connection with the third Scheduled Redetermination contemplated by Section 2.07 of the Credit Agreement, the Administrative Agent, the Lenders and the Borrower have agreed that the Borrowing Base shall be increased to $110,000,000, which Borrowing Base adjustment shall be effective as of the later of June 3, 2014, or the satisfaction of the conditions set forth in Section 7 hereof (the “ Increase Date ”).

4. Reaffirmation of Security . The Borrower, Lenders and the Administrative Agent hereby expressly intend that this Amendment shall not in any manner (a) constitute the refinancing, refunding, payment or extinguishment of the Indebtedness evidenced by the existing Loan Documents; (b) be deemed to evidence a novation of the outstanding balance of the Indebtedness; or (c) replace, impair, or extinguish the creation, attachment, perfection or priority of the Liens on the Borrowing Base Properties. The Borrower ratifies and reaffirms any and all grants of Liens to Lenders and the Administrative Agent on the Borrowing Base Properties as security for the Indebtedness, and the Borrower acknowledges and confirms that the grants of the Liens to Lenders and the Administrative Agent on the Borrowing Base Properties: (i) represent continuing Liens on all of the Borrowing Base Properties, (ii) secure all of the Indebtedness, and (iii) represent valid, first and best Liens on all of the Borrowing Base Properties except to the extent of any Permitted Liens

5. Conditions Precedent . This Amendment will not become effective until the date on which each of the following conditions is satisfied:

(a) The Borrower shall have executed and delivered to the Administrative Agent the Promissory Notes attached hereto as Exhibit A (the “ Amendment Notes ”). These Amendment Notes are issued in substitution for and replacement of, but not repayment of (i) those certain Promissory Notes, dated as of December 20, 2013, issued by the Borrower in favor of the Lenders in connection with the Third Amendment. The Amendment Notes shall constitute a “Note” as defined and described in the Credit Agreement. From and after the date hereof, all references in the Credit Agreement and in all other Loan Documents to the “Notes” shall be deemed to be references to the Amendment Notes.

(b) The Administrative Agent shall have received counterparts of this Amendment from the Borrower and each of the Lenders.

(c) The Administrative Agent shall have received all fees and other amounts due and payable on or prior to the effective date of this Amendment.

(f) No Default or Event of Default shall have occurred that is continuing.

(g) The Administrative Agent shall have received such other documents as the Administrative Agent or counsel to the Administrative Agent may reasonably request.

The Administrative Agent shall notify the Borrower and the Lenders of the effectiveness of this Amendment, and such notice shall be conclusive and binding.

6. Representations . To induce Lenders and the Administrative Agent to accept this Amendment, the Borrower hereby represents and warrants to Lenders and the Administrative Agent as follows:

(d) No Defenses . The Borrower has no defenses to payment, counterclaims, or right of set-off with respect to any Indebtedness existing as of the Effective Date.

(e) No Events of Default . No Event of Default has occurred and is continuing.

(f) Material Adverse Effect . The Borrower hereby affirms that no Material Adverse Effect has occurred

7. Fees, Costs and Expenses . As a condition of this Amendment, the Borrower will (i) in connection with the execution and delivery of this Amendment, pay to the Administrative Agent for the account of each Lender (A) a fee equal 0.25% of the such Lender’s Commitment as in effect prior to this Amendment, and(B) a fee equal 0.375% of the increase in such Lender’s Commitment as a result of this Amendment, and (ii) reimburse the Administrative Agent’s for all out of pocket expenses (including reasonable attorneys’ fees) incurred in connection with this Amendment.

8. Release . The Borrower, on its behalf and, as applicable, on behalf of the Borrower’s officers, directors, shareholders, Affiliates, Subsidiaries, successors and assigns (collectively, the “ Releasing Parties ”), hereby represents and warrants that such Releasing Parties have no claims, counterclaims, setoffs, actions or causes of action, damages or liabilities of any kind or nature whatsoever, whether in law or in equity, in contract or in tort, whether now accrued or hereafter maturing (collectively, “ Claims ”) against Lenders or the Administrative Agent, their direct or indirect Affiliates, or any of the foregoing’s respective directors, officers, employees, attorneys and legal representatives, or the heirs, administrators, successors or assigns of any of them (collectively, “ Lender Parties ”) to the extent that any such Claim directly or indirectly arises out of, is based upon or is in any manner connected with, any Prior Related Event. The Borrower, on its behalf and, as applicable, on behalf of the other Releasing Parties, voluntarily releases and forever discharges all Lender Parties from any and all Claims, whether known or unknown, to the extent that any such Claim directly or indirectly arises out of, is based upon or is in any manner connected with any Prior Related Event. “ Prior Related Event ” means any transaction, event, circumstance, action, failure to act, occurrence of any type or sort, whether known or unknown, which occurred, existed, was taken, was permitted or begun in accordance with, pursuant to or by virtue of: (a) any of the terms of any Loan Document or this Amendment, (b) any actions, transactions, matters or circumstances related hereto or to any Loan Document, (c) the conduct of the relationship between any Lender Party and the Borrower and its Subsidiaries, or (d) any other actions or inactions by any Lender Party, in each case on or prior to the Effective Date.

9. Continuing Effect of Credit Agreement; Reaffirmation of Loan Documents . The provisions of the Credit Agreement (as amended by this Amendment) shall remain in full force and effect in accordance with its terms following the effectiveness of this Amendment. Except as expressly amended hereby, all of the provisions of the Credit Agreement are ratified and confirmed. The existing Loan Documents, except as amended by this Amendment, shall remain in full force and effect, and each of them is hereby ratified and confirmed by the Borrower, Lenders and the Administrative Agent.

10. One Agreement; References; Fax Signature . The Credit Agreement, as amended by this Amendment, will be construed as one agreement. Each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof”, “herein”, or words of like import shall mean and be a reference to the Credit Agreement as amended hereby, and each reference to the Credit Agreement in any Loan Document or any other document, instrument or agreement executed and/or delivered in connection with the Credit Agreement shall mean and be a reference to the Credit Agreement as amended hereby. This Amendment may be signed by facsimile signatures or other electronic delivery of an image file reflecting the execution hereof, and if so signed, (a) may be relied on by each party as if the document were a manually signed original and (b) will be binding on each party for all purposes.

11. No Implied Consent or Waiver . This Amendment shall not be construed as consent to the departure from, or a waiver of the terms and conditions of, the Credit Agreement except as expressly set forth herein.

12. Captions . The headings to the Sections of this Amendment have been inserted for convenience of reference only and shall in no way modify or restrict any provisions hereof or be used to construe any such provisions.

13. Counterparts . This Amendment may be executed in multiple counterparts, each of which shall be an original but all of which together shall constitute one and the same instrument.

14. Entire Agreement . This Amendment sets forth the entire agreement of the parties with respect to the subject matter of this Amendment and supersedes all previous understandings, written or oral, in respect of this Amendment. At no time shall the prior or subsequent course of conduct by the Borrower, Lenders or the Administrative Agent directly or indirectly limit, impair or otherwise adversely affect any of the parties’ rights or remedies in connection with this Amendment or any of the documents, instruments and agreements executed in connection herewith, as Lenders, the Administrative Agent and the Borrower agree that this Amendment shall only be amended by written instruments executed by Lenders, the Administrative Agent and the Borrower. Except to the extent that the Loan Documents are expressly amended by this Amendment, if there is any conflict, ambiguity, or inconsistency, in the Administrative Agent’s judgment, between the terms of this Amendment and any of the other Loan Documents, then the applicable terms and provisions, in the Administrative Agent’s judgment, providing Lenders and the Administrative Agent with greater rights, remedies, powers, privileges, or benefits will control.

15. Governing Law; Severability . This Amendment shall be governed by and construed in accordance with the internal laws of the State of Colorado (without regard to its conflicts of law principles). If any term of this Amendment is found invalid under Colorado law or laws of mandatory application by a court of competent jurisdiction, the invalid term will be considered excluded from this Amendment and will not invalidate the remaining terms of this Amendment.

16. WAIVER OF JURY TRIAL . THE BORROWER, LENDERS AND THE ADMINISTRATIVE AGENT EACH WAIVE TRIAL BY JURY WITH RESPECT TO ANY ACTION, CLAIM, SUIT OR PROCEEDING IN RESPECT OF OR ARISING OUT OF THIS AMENDMENT, ANY OF THE OTHER LOAN DOCUMENTS, OR THE TRANSACTIONS CONTEMPLATED HEREBY.

[ signature page follows ]

The parties have caused this Amendment to be duly executed and delivered as of the day and year first above written.

BORROWER:

SYNERGY RESOURCES CORPORATION

By: /s/ Frank Jennings
Name: Frank Jennings
Title: Chief Financial Officer

ADMINISTRATIVE AGENT:

COMMUNITY BANKS OF COLORADO ,
as Administrative Agent

By: /s/ Sarah Burchett
Name: Sarah Burchett
Title: Vice President

LENDERS:

COMMUNITY BANKS OF COLORADO ,
as a Lender

By: /s/ Sarah Burchett
Name: Sarah Burchett
Title: Vice President

COBIZ BANK, A COLORADO CORPORATION, DBA COLORADO BUSINESS BANK ,
as a Lender

By: /s/ Douglas K. Derks
Name: Douglas K. Derks
Title: Senior Vice President

[Signature Page to Fourth Amendment to Credit Agreement]

AMEGY BANK NATIONAL ASSOCIATION ,
as a Lender

By:              /s/ Kevin Donaldson
Name:              Kevin Donaldson
Title:              Senior Vice President

SUNTRUST BANK ,

as a Lender

By:              /s/ Chulley Bogle
Name:              Chulley Bogle
Title:              Vice President

KEYBANK NATIONAL ASSOCIATION ,

as a Lender

By:              /s/ George E. McKean
Name:              George E. McKean
Title:              Senior Vice President

[Signature Page to Fourth Amendment to Credit Agreement]

ANNEX I
LIST OF MAXIMUM CREDIT AMOUNTS

Aggregate Maximum Credit Amounts

Name of Lender	Applicable Percentage	Maximum Credit Amount	Amount of Commitment on the Effective Date
Community Banks of Colorado	26.36363636%	$79,090,909.09	$29,000,000.00
Amegy Bank National Association	23.63636364%	$70,909,090.91	$26,000,000.00
CoBiz Bank, a Colorado corporation, dba Colorado Business Bank	9.09090909%	$27,272,727.27	$10,000,000.00
SunTrust Bank	20.45454545%	$61,363,636.36	$22,500,000.00
Key Bank National Association	20.45454545%	$61,363,636.36	$22,500,000.00
TOTAL	100.0000000000%	$ 300, 000, 000.00	$ 110, 000, 000.00

October 9, 2014

Synergy Resources Corporation

20203 Highway 60

Platteville, Colorado 80651

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of Synergy Resources Corporation (Synergy) as of August 31, 2014. The subject properties are located in the state of Colorado. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on October 9, 2014 and presented herein, was prepared for public disclosure by Synergy in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of Synergy as of August 31, 2014.

The estimated reserves and future net income amounts presented in this report, as of August 31, 2014, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the "as of date" of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Synergy Resources Corporation

As of August 31, 2014

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Remaining Reserves
Oil/Condensate – Barrels		4,537,061		2,079,421		9,708,471		16,324,953
Gas – MCF		25,921,459		12,240,142		57,016,746		95,178,347

Income Data
Future Gross Revenue	$	511,251,988	$	234,452,154	$	1,094,283,479	$	1,839,987,621
Deductions		141,144,536		78,393,622		587,999,147		807,537,305
Future Net Income (FNI)	$	370,107,452	$	156,058,532	$	506,284,332	$	1,032,450,316

Discounted FNI @ 10%	$	250,749,027	$	76,592,530	$	206,356,515	$	533,698,072

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an "as sold" basis expressed in thousands of cubic feet (MCF) at the official temperature and pressure bases of Colorado, which are 60°F and 14.73 psia, respectively.

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants, L.C. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 75 percent and gas reserves account for the remaining 25 percent of total future gross revenue from the proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at five other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income
	As of August 31, 2014
Discount Rate		Total
Percent		Proved

5		$723,176,782
8		$599,341,284
12		$478,361,223
15		$410,358,357
20		$325,705,710

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulations Part 210.4-10 (a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled "Petroleum Reserves Definitions" is included as an attachment to this report.

The various reserve status categories are defined under the attachment entitled "Petroleum Reserves Status Definitions and Guidelines" in this report. The proved developed non-producing reserves included herein consist of the shut in, behind pipe and temporarily abandoned categories. The refrac cases are included as the behind pipe-rf category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are "estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations." All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Synergy's request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are "those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward." The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a "high degree of confidence that the quantities will be recovered."

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that "as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease." Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Synergy's operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Synergy owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission's Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the "quantities actually recovered are much more likely than not to be achieved." The SEC states that "probable reserves are those additional 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." The SEC states that "possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves." All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods or by analogy. Approximately 100 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by the performance methods. These performance methods include decline curve analysis which utilized extrapolations of historical production and pressure data available through August, 2014 in those cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by Synergy or obtained from public data sources and were considered sufficient for the purpose thereof.

Approximately 100 percent of the proved developed non-producing and undeveloped reserves included herein were estimated by the analogy method. The analogy method utilized pertinent well data supplied to Ryder Scott by Synergy or which we have obtained from public data sources that were available through August, 2014. The data utilized in this analysis were considered sufficient for purposes thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Synergy has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Synergy with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, product prices based on the SEC regulations and adjustments or differentials to product prices. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Synergy. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the "SEC Regulations." In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Offset analogies and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Synergy. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the "as of date" of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Ryder Scott determined the above mentioned average prices in effect on August 31, 2014. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the "benchmark prices" and "price reference" used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as "differentials." The differentials used in the preparation of this report were furnished to us by Synergy. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Synergy to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the "average realized prices." The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
Colorado	Oil/Condensate	WTI Cushing	$100.05/Bbl	$89.48/Bbl
	Gas	Henry Hub	$4.20/MMBTU	$5.03/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by Synergy and are based on the operating expense reports of Synergy and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished by Synergy were reviewed by us for their reasonableness using information supplied by Synergy for this purpose. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Synergy and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Synergy were reviewed by us for their reasonableness using information supplied by Synergy for this purpose. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by Synergy were accepted without independent verification. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Synergy's estimate.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Synergy's plans to develop these reserves as of August 31, 2014. The implementation of Synergy's development plans as presented to us and incorporated herein is subject to the approval process adopted by Synergy's management. As the result of our inquires during the course of preparing this report, Synergy has informed us that the development activities included herein have been subjected to and received the internal approvals required by Synergy's management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Synergy. Additionally, Synergy has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Synergy were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer's license or a registered or certified professional geoscientist's license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Synergy. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for reviewing and approving the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Synergy.

Synergy makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Synergy has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 of Synergy of the references to our name as well as to the references to our third party report for Synergy which appears in the August 31, 2014 annual report on Form 10-K of Synergy. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Synergy.

We have provided Synergy with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Synergy and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

		Very truly yours, RYDER SCOTT COMPANY, L.P. TBPE Firm Registration No. F-1580

	[Seal]	\s\ James L. Baird James L. Baird, P.E. Colorado License No. 41521 Managing Senior Vice President

	[Seal]	\s\ Thomas E. Venglar Thomas E. Venglar, P.E. Colorado License No. 28846 Senior Petroleum Engineer

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. James Larry Baird was the primary technical person responsible for overseeing the estimate of the reserves.

Mr. Baird, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President and also serves as Manager of the Denver office, responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Baird served in a number of engineering positions with Gulf Oil Corporation (1970-1973), Northern Natural Gas (1973-1975) and Questar Exploration & Production (1975-2006). For more information regarding Mr. Baird's geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees .

Mr. Baird earned a Bachelor of Science degree in Petroleum Engineering from the University of Missouri at Rolla in 1970 and is a registered Professional Engineer in the States of Colorado and Utah. He is also a member of the Society of Petroleum Engineers.

In addition to gaining experience and competency through prior work experience, the Colorado and Utah Board of Professional Engineers recommend continuing education annually, including at least one hour in the area of professional ethics, which Mr. Baird fulfills. As part of his 2011 continuing education hours, Mr. Baird attended an internally presented sixteen hours of formalized training as well as an eight hour public forum. Mr. Baird attended the 2010 and 2011 RSC Reserves Conference and various professional society presentations specifically on the new SEC regulations relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Baird attended an additional sixteen hours of formalized in-house and external training during 2011, 2012 and 2013 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, reserve reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves, procedures and software and ethics for consultants. Mr. Baird was a keynote speaker, presenting the Changing Landscape of the SEC Reporting, at the 2009 Unconventional Gas International Conference held in Fort Worth, Texas.

Based on his educational background, professional training and more than 43 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Baird has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the Society of Petroleum Engineers as of February 19, 2007.