10-K 1 syrg_10k-083114.htm FORM 10-K FOR THE FISCAL YEAR ENDED 8/31/2014
 
 
 UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K


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

For the fiscal year ended August 31, 2014

OR

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

For the transition period from _______________________ to _______________________

Commission file number:  001-35245

 SYNERGY RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
 
COLORADO
20-2835920
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
 
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.
 
 
1

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.
 
2

·
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.

3

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.
4

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.
 
5

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.
 
 
6


 

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 (Bbls1)
   
941,218
     
421,265
     
235,691
 
Gas (Mcf2)
   
3,747,074
     
2,107,603
     
1,109,057
 
BOE3
   
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.

 
 
7

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
 

               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.
 
8

 
    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.
 
 
9

 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.

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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.
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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.

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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.

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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.
 
14


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.

15

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.

16

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.

 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.

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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.”

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ITEM 1A.  RISK FACTORS

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

Risks Related to Our Business, Industry and Strategy
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.

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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.
 
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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.
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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.
 
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We face strong competition from larger oil and natural gas companies that may negatively affect our ability to carry on operations.
We operate in the highly competitive areas of oil and natural gas exploration, development and production. Factors that affect our ability to compete successfully in the marketplace include:
 
 
 
the availability of funds for, and information relating to, 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.
 
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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.
 
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 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.
 
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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
 
26

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:
 
27

 
 
 
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.
 
28


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.
 
29


ITEM 3.  LEGAL PROCEEDINGS

None.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

30

 
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.

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.

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.
31

 

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.

32

 

 

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.

 



 
33

 
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.
 
34

 
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.

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.

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
 

 
35

 
 
 
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.”

36

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.
 
37


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 (Bbls1)
   
941,218
     
421,265
 
Gas (Mcf2)
   
3,747,074
     
2,107,603
 
 
               
Total production in BOE3
   
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.


38

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.

39

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.
 
40

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 (Bbls1)
   
421,265
     
235,691
 
Gas (Mcf2)
   
2,107,603
     
1,109,057
 
 
               
Total production in BOE3
   
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.

41

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.

42

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.
 
43

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.

44

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.


45

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.
46


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 Contract1
 
$
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
 

1
 
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.


47


  
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.

48

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.

49

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.
 
 
50

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.

51

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.

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