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

FORM 10-Q
(Mark One)

QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended February 28, 2015

TRANSITION REPORT UNDER 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, Colorado  80651
(Address of Principal Executive Offices)  (Zip Code)

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

N/A
Former name, former address, and former fiscal year, if changed since last report

Indicate by check mark whether the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 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 ☒     No ☐

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

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 definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
 
Large accelerated filer 
Accelerated filer    
 
Non-accelerated filer 
Smaller reporting company

Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ☐     No ☒
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:  104,066,892 shares outstanding as of April 7, 2015.

SYNERGY RESOURCES CORPORATION

Index

 
Page
Part I – FINANCIAL INFORMATION
   
     
Item 1.
Financial Statements
 
     
 
Balance Sheets as of February 28, 2015 (unaudited)
 and August 31, 2014
2
       
 
Statements of Operations for the three and six months ended
February 28, 2015 and February 28, 2014 (unaudited)
3
       
 
Statements of Cash Flows for the six months ended
February 28, 2015 and February 28, 2014 (unaudited)
4
       
 
Notes to Financial Statements (unaudited)
5
       
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
28
       
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
50
     
Item 4.
Controls and Procedures
51
       
Part II - OTHER INFORMATION
   
       
Item 1A. Risk Factors 52
 
Item 6.
Exhibits
53
       
SIGNATURES
54
 
1

 
SYNERGY RESOURCES CORPORATION
BALANCE SHEETS
(in thousands, except share data)
 
ASSETS
 
February 28,
2015
   
August 31,
2014
 
    
(unaudited)
     
Current assets:
       
Cash and cash equivalents
 
$
218,470
   
$
34,753
 
Accounts receivable:
               
Oil and gas sales
   
11,523
     
16,974
 
Joint interest billing and other
   
27,751
     
15,398
 
Commodity derivative
   
10,387
     
365
 
Other current assets
   
1,432
     
750
 
Total current assets
   
269,563
     
68,240
 
                 
Oil and gas properties, full cost method:
               
Proved properties
   
333,995
     
275,018
 
Unproved properties and properties under development, not being amortized
   
213,704
     
95,278
 
Other property and equipment
   
4,812
     
9,104
 
Property and equipment, net
   
552,511
     
379,400
 
                 
Commodity derivative
   
6,798
     
54
 
Other assets
   
2,971
     
848
 
                 
Total assets
 
$
831,843
   
$
448,542
 
                 
LIABILITIES AND SHAREHOLDERS' EQUITY
               
                 
Current liabilities:
               
Trade accounts payable
 
$
538
   
$
1,747
 
Well costs payable
   
30,598
     
71,849
 
Revenue payable
   
23,671
     
14,487
 
Production taxes payable
   
21,523
     
14,376
 
Other accrued expenses
   
950
     
817
 
Commodity derivative
   
-
     
302
 
Total current liabilities
   
77,280
     
103,578
 
                 
Revolving credit facility
   
146,000
     
37,000
 
Commodity derivative
   
-
     
307
 
Deferred tax liability, net
   
36,504
     
21,437
 
Asset retirement obligations
   
7,189
     
4,730
 
Total liabilities
   
266,973
     
167,052
 
Commitments and contingencies (See Note 13)
               
                 
Shareholders' equity:
               
Preferred stock - $0.01 par value, 10,000,000 shares authorized:
               
no shares issued and outstanding
   
-
     
-
 
Common stock - $0.001 par value, 200,000,000 shares authorized:
               
    104,066,892 and 77,999,082 shares issued and outstanding, respectively
   
104
     
78
 
Additional paid-in capital
   
523,344
     
265,793
 
Retained earnings
   
41,422
     
15,619
 
Total shareholders' equity
   
564,870
     
281,490
 
                 
Total liabilities and shareholders' equity
 
$
831,843
   
$
448,542
 
 
 
The accompanying notes are an integral part of these financial statements.
2



SYNERGY RESOURCES CORPORATION
STATEMENTS OF OPERATIONS
 (unaudited; in thousands, except share and per share data)
 

                 
    
Three Months Ended
February 28,
   
Six Months Ended
February 28,
 
   
2015
   
2014
   
2015
   
2014
 
                 
Oil and gas revenues
 
$
23,713
   
$
23,028
   
$
66,251
   
$
42,294
 
                                 
Expenses
                               
Lease operating expenses
   
3,689
     
1,806
     
6,730
     
3,079
 
Production taxes
   
2,143
     
2,255
     
6,321
     
4,271
 
Depletion, depreciation
                               
   amortization and accretion
   
15,506
     
7,719
     
31,960
     
13,310
 
General and administrative
   
4,079
     
1,770
     
8,189
     
4,938
 
Total expenses
   
25,417
     
13,550
     
53,200
     
25,598
 
                                 
Operating income (loss)
   
(1,704
)
   
9,478
     
13,051
     
16,696
 
                                 
Other income (expense)
                               
Commodity derivative realized gain (loss)
   
12,367
     
(191
)
   
13,799
     
(589
)
Commodity derivative unrealized (loss) gain
   
(2,832
)
   
(1,805
)
   
13,876
     
831
 
Interest income
   
28
     
17
     
28
     
48
 
Total other income (expense)
   
9,563
     
(1,979
)
   
27,703
     
290
 
                                 
Income before income taxes
   
7,859
     
7,499
     
40,754
     
16,986
 
                                 
Income tax provision
   
3,207
     
2,338
     
14,951
     
5,725
 
Net income
 
$
4,652
   
$
5,161
   
$
25,803
   
$
11,261
 
                                 
Net income per common share:
                               
Basic
 
$
0.05
   
$
0.07
   
$
0.31
   
$
0.15
 
Diluted
 
$
0.05
   
$
0.07
   
$
0.30
   
$
0.15
 
                                 
Weighted–average shares outstanding:
                               
Basic
   
89,903,288
     
76,203,938
     
84,396,143
     
74,934,940
 
Diluted
   
90,636,107
     
77,990,416
     
85,145,431
     
76,843,593
 


The accompanying notes are an integral part of these financial statements.
3


SYNERGY RESOURCES CORPORATION
 STATEMENTS OF CASH FLOWS
 (unaudited, in thousands)
 
 
   
Six Months Ended
February 28,
 
   
2015
   
2014
 
Cash flows from operating activities        
Net income
 
$
25,803
   
$
11,261
 
Adjustments to reconcile net income to net
               
cash provided by operating activities:
               
Depletion, depreciation and amortization
   
31,960
     
13,310
 
Provision for deferred taxes
   
14,951
     
5,725
 
Stock-based compensation
   
1,929
     
867
 
Valuation increase in commodity derivatives
   
(13,876
)
   
(831
)
Changes in operating assets and liabilities:
               
Accounts receivable
               
    Oil and gas sales
   
5,451
     
(4,620
)
    Joint interest billing and other
   
(12,353
)
   
(996
)
Premiums paid for derivatives
   
(3,498
)
   
-
 
Inventory
   
-
     
(312
)
Accounts payable
               
    Trade
   
(1,210
)
   
(553
)
    Revenue
   
9,183
     
3,163
 
    Production taxes
   
7,147
     
5,709
 
    Accrued expenses
   
133
     
35
 
Other
   
(505
)
   
596
 
Total adjustments
   
39,312
     
22,093
 
Net cash provided by operating activities
   
65,115
     
33,354
 
                 
Cash flows from investing activities:                
Acquisition of property and equipment
   
(197,530
)
   
(87,497
)
Short-term investments
   
-
     
39,990
 
Net proceeds from sales of oil and gas properties
   
3,696
     
-
 
Net cash used in investing activities
   
(193,834
)
   
(47,507
)
                 
Cash flows from financing activities:                
Cash proceeds from sale of stock
   
200,100
     
-
 
Stock offering costs
   
(9,255
)
   
-
 
Proceeds from exercise of warrants
   
15,367
     
29,104
 
Gross proceeds from revolving credit facility
   
109,000
     
-
 
Finance fee for revolving credit facility
   
(2,300
)
       
Shares withheld for payment of employee payroll taxes
   
(476
)
   
(34
)
Net cash provided by financing activities
   
312,436
     
29,070
 
                 
Net increase in cash and cash equivalents    
183,717
     
14,917
 
                 
Cash and cash equivalents at beginning of period    
34,753
     
19,463
 
                 
Cash and cash equivalents at end of period  
$
218,470
   
$
34,380
 
                 
               
Supplemental Cash Flow Information (See Note 14)
 
 
The accompanying notes are an integral part of these financial statements.
 
4

SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
February 28, 2015
(unaudited)


1.
Organization and Summary of Significant Accounting Policies

Organization:    Synergy Resources Corporation ("the Company”) is engaged in oil and gas acquisition, exploration, development and production activities, primarily in the Denver-Julesburg Basin ("D-J Basin") of Colorado.  The Company’s common stock is listed and traded on the NYSE MKT under the symbol “SYRG.”

Basis of Presentation:    The Company has adopted August 31st as the end of its fiscal year.  The Company does not utilize any special purpose entities.  The Company operates in one business segment and all of its operations are located in the United States of America.

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

Interim Financial Information:    The interim financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the SEC as promulgated in Rule 10-01 of Regulation S-X.  The balance sheet as of August 31, 2014 was derived from the Company’s Annual Report on Form 10-K for the year ended August 31, 2014.  Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been condensed or omitted pursuant to such SEC rules and regulations.  The Company believes that the disclosures included are adequate to make the information presented not misleading, and recommends that these financial statements be read in conjunction with the audited financial statements and notes thereto for the year ended August 31, 2014.

In management’s opinion, the unaudited financial statements contained herein reflect all adjustments, consisting solely of normal recurring items, which are necessary for the fair presentation of the Company’s financial position, results of operations, and cash flows on a basis consistent with that of its prior audited financial statements.  However, the results of operations for interim periods may not be indicative of results to be expected for the full fiscal year.

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

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

Cash and Cash Equivalents:    The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents.
 
5

 

Oil and Gas Properties:    The Company uses the full cost method of accounting for costs related to its oil and gas properties.  Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool.  These costs include land acquisition costs, geological and geophysical expenses, 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 units-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 unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs.  If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Wells in progress represent the costs associated with the drilling of oil and gas wells that have yet to be completed as of February 28, 2015.  Since the wells had not been completed as of February 28, 2015, they were classified within unproved oil and gas properties and were withheld from the depletion calculation and ceiling test.  The costs for these wells will be transferred into proved property when the wells commence production and will become subject to depletion and the ceiling test calculation in subsequent periods.

Under the full cost method of accounting, a ceiling test is performed each quarter.  The full cost ceiling test is an impairment test prescribed by SEC regulations.  The ceiling test determines a limit on the book value of oil and gas properties.  The capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion, depreciation, and amortization, and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, less future cash outflows associated with asset retirement obligations that have been accrued, plus the cost of unproved properties not being amortized, plus the lower of cost or estimated fair value of unproven properties being amortized.  Prices are held constant for the productive life of each well.  Net cash flows are discounted at 10%.  If net capitalized costs exceed this limit, the excess is charged to expense and reflected as additional accumulated depletion, depreciation and amortization.  The calculation of future net cash flows assumes continuation of current economic conditions.  Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount.  No provision for impairment was required for the three and six months ended February 28, 2015 and 2014.

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

Oil and Gas Reserves:    Oil and gas reserves represent theoretical, estimated quantities of crude oil and natural gas which geological and engineering data estimate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.
 
6

 

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

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

Capitalized Overhead:    A portion of the Company’s overhead expenses are directly attributable to acquisition and development activities.  Under the full cost method of accounting, these expenses in the amounts shown in the table below were capitalized in the full cost pool (in thousands):
 
   
Three Months Ended
February 28,
   
Six Months Ended
February 28,
 
   
2015
   
2014
   
2015
   
2014
 
Capitalized Overhead
 
$
634
   
$
304
   
$
1,137
   
$
621
 
 
Well Costs Payable:    The costs of wells in progress are recorded as incurred, generally based upon invoiced amounts or joint interest billings (“JIB”).  For those instances in which an invoice or JIB is not received on a timely basis, estimated costs are accrued to oil and gas properties, generally based on the authorization for expenditure.

Other Property and Equipment:  Support equipment (including such items as vehicles, well servicing equipment, and office furniture and equipment) is stated at the lower of cost or market.  Depreciation of support equipment is computed using primarily the straight-line method over periods ranging from five to seven years.

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

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

Oil and Gas Sales:    The Company derives revenue primarily from the sale of crude oil and natural gas produced on its properties.  Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest.  Revenues are reported on a gross basis for the amounts received before taking into account production taxes and lease operating costs, which are reported as separate expenses.  Revenue is recorded and receivables are accrued 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.
 
7

 

Major Customers :    The Company sells production to a small number of customers, as is customary in the industry.  As a result, during the three and six month periods ended February 28, 2015 and 2014, certain of our customers represented 10% or more of our oil and gas revenue (“major customers”).  For the three months ended February 28, 2015, the Company had three major customers, which represented 58%, 15% and 13% of our revenue during the period. For the three months ended February 28, 2014, the Company had three major customers, which represented 32%, 20% and 18% of our revenue during the period. For the six months ended February 28, 2015, the Company had three major customers, which represented 64%, 12% and 10% of our revenue during the period. For the six months ended February 28, 2014, the Company had three major customers, which represented 51%, 15% and 10% of our revenue during the period

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

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

Purchasers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table:

Major Customers
 
As of
February 28, 2015
   
As of
August 31, 2014
 
Company A
   
15%
 
   
37%
 
Company B
   
10%
 
    (1)
 
Company C
     (1)
 
     (1) 
 

(1) Balance was less than 10% of total receivable balances during the period.

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

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

Income Tax:    Income taxes are computed using the asset and liability method.  Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, their respective tax bases as well as the effect of net operating losses, tax credits and tax credit carry-forwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.
 
8


No significant uncertain tax positions were identified as of any date on or before February 28, 2015.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of February 28, 2015, the Company has not recognized any interest or penalties related to uncertain tax benefits.

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

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

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

Commodity Derivative Instruments:    The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or “no premium” collars to reduce the effect of price changes on a portion of its future oil and gas production.  The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the statement of operations. The Company values its derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors, as well as other relevant economic measures.  The Company compares the valuations calculated by it to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 7.
 
9


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

The following table sets forth the share calculation of diluted earnings per share:
 
   
Three Months Ended
February 28,
   
Six Months Ended
February 28,
 
   
2015
   
2014
   
2015
   
2014
 
                 
Weighted-average shares outstanding-basic
   
89,903,288
     
76,203,938
     
84,396,143
     
74,934,940
 
Potentially dilutive common shares from:
                               
Stock options
   
732,819
     
512,399
     
749,288
     
532,095
 
Warrants
   
-
     
1,274,079
     
-
     
1,376,558
 
     
732,819
     
1,786,478
     
749,288
     
1,908,653
 
Weighted-average shares outstanding - diluted
   
90,636,107
     
77,990,416
     
85,145,431
     
76,843,593
 
 
 
The following potentially dilutive securities outstanding for the periods presented were not included in the respective earnings per share calculation above; as such securities had an anti-dilutive effect on earnings per share:

   
Three Months Ended
February 28,
   
Six Months Ended
February 28,
 
   
2015
   
2014
   
2015
   
2014
 
                 
Employee stock options
   
858,000
     
886,333
     
858,000
     
829,160
 
 

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 January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2015-01, “Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items” (“ASU 2015-01”), which eliminates from US GAAP the concept of extraordinary items, while retaining certain presentation and disclosure guidance for items that are unusual in nature or occur infrequently.  The standard is effective prospectively for fiscal years and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted provided the guidance is applied from the beginning of the fiscal year of adoption.  Adoption of ASU 2015-01 is not expected to have a material effect on the Company’s financial position, results of operations, or cash flows.

In November 2014, the FASB issued Accounting Standards Update 2014-16, “Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity” (“ASU 2014-16”), which clarifies how to evaluate the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share.  Specifically, ASU 2014-16 requires that an entity consider all relevant terms and features in evaluating the nature of the host contract and clarifies that the nature of the host contract depends upon the economic characteristics and the risks of the entire hybrid financial instrument.  An entity should assess the substance of the relevant terms and features, including the relative strength of the debt-like or equity-like terms and features given the facts and circumstances, when considering how to weight those terms and features.  ASU 2014-16 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted. The Company is currently evaluating the impact of the adoption of this standard on its consolidated financial statements.
 
10


In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. ASU 2014-09 allows for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, 2016 including interim periods within that period. 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.

There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on the Company's reported financial position, results of operations or cash flows.
 
11

 
 
2.
Property and Equipment

The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
 
   
As of
   
As of
 
   
February 28, 2015
   
August 31, 2014
 
Oil and gas properties, full cost method:
       
   Unproved properties, not subject to amortization:
       
      Lease acquisition and other costs
 
$
146,891
   
$
41,531
 
      Properties under development
   
66,813
     
53,747
 
         Subtotal
   
213,704
     
95,278
 
                 
   Proved producing and non-producing properties
   
420,895
     
329,926
 
         Total capitalized costs
   
634,599
     
425,204
 
      Less, accumulated depletion
   
(86,900
)
   
(54,908
)
           Oil and gas properties, net
   
547,699
     
370,296
 
                 
Land
   
4,478
     
3,898
 
Other property and equipment
   
828
     
5,961
 
Less, accumulated depreciation
   
(494
)
   
(755
)
            Other property and equipment, net
   
4,812
     
9,104
 
                 
Total property and equipment, net
 
$
552,511
   
$
379,400
 
 
    The Company periodically reviews its unproved properties to determine if the carrying value of such assets exceeds estimated fair value. The reviews for the three months and six months ended February 28, 2015 and 2014 indicated that estimated fair values of such assets exceeded carrying values, thus revealing no impairment in either period.  Similarly, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs.  The ceiling tests performed for the three months and six months ended February 28, 2015 and 2014 revealed no impairments.

During the six months ended February 28, 2015, certain amounts previously recorded were reclassified from one category to another without changing the total amounts recorded as property and equipment.  Specifically, costs associated with the disposal well and related equipment were reclassified from other property and equipment into producing oil and gas properties to more closely reflect use of the disposal well as an integral part of oil and gas operations.  Similarly, accumulated depreciation associated with the disposal well was reclassified from accumulated depreciation to accumulated depletion.  The updated classification for the disposal well, related equipment, and accumulated depreciation did not require a change to previously reported depletion, depreciation, and amortization expense (“DDA”).  Future calculations of DDA for the full cost pool will include costs of the disposal well. Secondly, as discussed in Note 3, the analysis of assets acquired in the 2014 business combination transactions with Apollo and Trilogy was completed and fair values associated with probable horizontal well development were reclassified from proved properties into unproved properties.
 
12

 

3.
Acquisitions

During the six months ended February 28, 2015 and 2014, we acquired certain oil and gas and other assets, as described below.

Bayswater transaction

On December 15, 2014, the Company completed the acquisition of certain assets from three independent oil and gas companies (collectively known as “Bayswater”) for a total purchase price of $122.5 million, net of customary closing adjustments.  The purchase price was composed of $74.0 million in cash and $48.4 million in restricted common stock.

The Bayswater acquisition encompasses 5,040 gross (4,053 net) acres with rights to the Codell and Niobrara formations, and 2,400 gross (1,739 net) acres with rights to other formations including the Sussex, Shannon and J-Sand.  Additionally, the Company acquired non-operated working interests in 17 horizontal wells, all of which have been completed and are in the early phase of production, and 73 operated vertical wells as well as working interests in 11 non-operated vertical wells.  The working interests in the horizontal wells ranges from 6% to 40% while the working interests in the vertical wells ranges from 5% to 100%.

The following allocation of the purchase price is preliminary and includes significant use of estimates.  The fair values of the assets acquired and liabilities assumed are preliminary and are subject to revision as the Company continues to evaluate the fair value of this acquisition.  Accordingly, the allocation will change as additional information becomes available and is assessed by us, and the impact of such changes may be material.  The following table summarizes the preliminary purchase price and preliminary estimated fair values of assets acquired and liabilities assumed (in thousands):
 
 
Purchase Price
 
December 15, 2014
 
Consideration Given
   
Cash
 
$
74,048
 
Synergy Resources Corp. Common Stock *
   
48,434
 
         
Total consideration given
 
$
122,482
 
         
Allocation of Purchase Price
       
Proved oil and gas properties
 
$
44,513
 
Unproved oil and gas properties
 
$
80,834
 
Total fair value of oil and gas properties acquired
   
125,347
 
         
Asset retirement obligation
 
$
(1,913
)
Other adjustments
   
(952
)
         
Fair value of net assets acquired
 
$
122,482
 
 
*
The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of December 15, 2014. (4,648,136 shares at $10.42 per share)
 

13

The following table presents the pro forma combined results of operations for the three and six months ended February 28, 2015 as if the Bayswater transaction had occurred on September 1, 2013, the first day of our 2014 fiscal year.  The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock and debt, additional depreciation expense, costs directly attributable to the acquisition and operating costs incurred as a result of the assets acquired.  The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired.  The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

   
Three Months Ended
February 28,
   
Six Months ended
February 28,
 
   
2015
   
2014
   
2015
   
2014
 
                 
Oil and Gas Revenues
 
$
23,713
   
$
24,189
   
$
73,124
   
$
44,783
 
Net income
 
$
4,652
   
$
4,868
   
$
27,583
   
$
10,796
 
                                 
Earnings per common share
                               
  Basic
 
$
0.05
   
$
0.06
   
$
0.31
   
$
0.14
 
  Diluted
 
$
0.05
   
$
0.06
   
$
0.31
   
$
0.14
 

Apollo and Trilogy transactions

During the year ended August 31, 2014, the Company closed on two transactions that qualified as Business Combinations under ASC 805.  The initial accounting treatment of the transactions was based upon the preliminary analysis of the assets acquired.  During the first fiscal quarter of 2015, the Company completed its analysis and finalized the allocation of purchase price to the assets acquired.  The following tables present the final fair values.

On September 16, 2013, the Company entered into a definitive purchase and sale agreement with Trilogy Resources, LLC (“Trilogy”), for its interests in 21 producing oil and gas wells and approximately 800 net mineral acres (the “Trilogy Assets”). On November 12, 2013, the Company closed the transaction for a combination of cash and stock.  Trilogy received 301,339 shares of our common stock valued at $2.9 million and cash consideration of approximately $15.9 million.  No material transaction costs were incurred in connection with this acquisition.
 
14


The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of November 12, 2013.  The following table summarizes the final purchase price and the final fair values of assets acquired and liabilities assumed (in thousands):
 
Purchase Price
 
November 12,
2013
 
Consideration Given
   
Cash
 
$
15,902
 
Synergy Resources Corp. Common Stock *
   
2,896
 
         
Total consideration given
 
$
18,798
 
         
Allocation of Purchase Price
       
Proved oil and gas properties
 
$
11,514
 
Unproved oil and gas properties
 
$
7,725
 
Total fair value of oil and gas properties acquired
   
19,239
 
         
Working capital
 
$
(83
)
Asset retirement obligation
   
(358
)
         
Fair value of net assets acquired
 
$
18,798
 
         
Working capital acquired was estimated as follows:
       
Accounts receivable
   
536
 
Accrued liabilities and expenses
   
(619
)
         
Total working capital
 
$
(83
)
 
*
The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of November 12, 2013. (301,339 shares at $9.61 per share)
 
On August 27, 2013, the Company entered into a definitive purchase and sale agreement (“the Agreement”), with Apollo Operating, LLC (“Apollo”), for its interests in 38 producing oil and gas wells, partial interest (25%) in one water disposal well (the “Disposal Well”), and approximately 3,639 gross (1,000 net) mineral acres (“the Apollo Operating Assets”). On November 13, 2013, the Company closed the transaction for a combination of cash and stock.  Apollo received cash consideration of approximately $11.0 million and 550,518 shares of our common stock valued at $5.2 million.  Following our acquisition of the Apollo Operating Assets, we acquired all other remaining interests in the Disposal Well (the “Related Interests”) through several transactions with the individual owners of such interests. We acquired the Related Interests for approximately $3.7 million in cash consideration and 20,626 shares of our common stock, valued at $0.2 million.  No material transaction costs were incurred in connection with this acquisition.
 
15


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

Purchase Price
 
November 13,
2013
 
Consideration Given
   
Cash
 
$
14,688
 
Synergy Resources Corp. Common Stock *
   
5,432
 
         
Total consideration given
 
$
20,120
 
         
Allocation of Purchase Price
       
Proved oil and gas properties
 
$
13,284
 
Unproved oil and gas properties
 
$
7,577
 
Total fair value of oil and gas properties acquired
   
20,861
 
         
Working capital
 
$
(507
)
Asset retirement obligation
   
(234
)
         
Fair value of net assets acquired
 
$
20,120
 
         
Working capital acquired was estimated as follows:
       
Accounts receivable
   
662
 
Accrued liabilities and expenses
   
(1,169
)
         
Total working capital
 
$
(507
)
 
*
The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock prices on the measurement dates (including 550,518 shares at $9.49 per share on November 13, 2013 plus 20,626 shares at various measurement dates at an average per share price of $10.08).
 
The motivation for both the Trilogy and Apollo acquisitions was the expectation that each was accretive to cash flow and earnings per share.  The acquisitions qualify as a business combination, and as such, the Company estimated the fair value of each property as of the acquisition date (the date on which the Company obtained control of the properties). Fair value measurements utilize assumptions of market participants. To determine the fair value of the oil and gas assets, the Company used an income approach based on a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. The Company determined the appropriate discount rates used for the discounted cash flow analyses by using a weighted-average cost of capital from a market participant perspective plus property-specific risk premiums for the assets acquired. The Company estimated property-specific risk premiums taking into consideration the Gas to Oil Ratio (“GOR”) of the related reserves, among other items.  Given the unobservable nature of the significant inputs, they are deemed to be Level 3 in the fair value hierarchy. The working capital assets acquired were determined to be at fair value due to their short-term nature.

The preliminary analysis and allocation of the purchase price focused on the values inherent in the proved producing wells and the associated proved undeveloped reserves.  All of the producing wells acquired in the transactions were vertical wells and the initial estimates allocated 100% of the fair value to proved properties associated with vertical well development.  The final analysis also considered the additional value provided by the virtue of the ability to drill horizontal wells in the acquired acreage.  Adding horizontal wells to the development plan required a further evaluation as to the classification of the horizontal reserves, as reserves classified as proved under a vertical well drilling plan may be classified differently under a horizontal drilling plan.  In the subject acres, the horizontal well reserves are classified as unproved even though the vertical well reserves are proved.  Thus, the final analysis attributed $15.3 million of fair value to unproved horizontal properties and $24.8 million of fair value to proved properties.
 
16


Differences between the preliminary allocation and final allocation of acquired fair value have been treated as a change in accounting estimate, and no retroactive adjustments were made to the previously reported financial statements.  Furthermore, since the reclassification of $15.3 million from proved properties subject to amortization to unproved properties not subject to amortization represents approximately 2% of the full cost amortization base, no prior period adjustment was recorded during the current year.

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

Depletion, depreciation and amortization consisted of the following (in thousands):
 
   
Three Months Ended
February 28,
   
Six Months ended
February 28,
 
   
2015
   
2014
   
2015
   
2014
 
Depletion
 
$
15,345
   
$
7,491
   
$
31,649
   
$
12,981
 
Depreciation and amortization
   
161
     
228
     
311
     
329
 
Total DDA Expense
 
$
15,506
   
$
7,719
   
$
31,960
   
$
13,310
 
 
Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter.  For the three months ended February 28, 2015, production of 697,069 barrels of oil equivalent (“BOE”) represented 2.1% of the estimated total proved reserves.  For the six months ended February 28, 2015, production of 1,450,381 BOE represented 4.4% of the estimated total proved reserves.

5.
Asset Retirement Obligations

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

     
For The Six Months Ended
February 28,
     
2015
 
2014
Inflation rate
 
3.90%
 
 3.9 - 4.0%
Estimated asset life
 
 25.0 - 39.0 years
 
 20.0 - 40.0 years
Credit adjusted risk free interest rate
 
8.0%
 
8.0%
 
 
17


The following table summarizes the change in asset retirement obligations associated with the Company’s oil and gas properties (in thousands):

Asset retirement obligations, August 31, 2014
 
$
4,730
 
  Liabilities incurred
   
318
 
  Liabilities assumed
   
1,913
 
  Accretion expense
   
228
 
Asset retirement obligations, February 28, 2015
 
$
7,189
 

6.
Revolving Credit Facility

On December 15, 2014, simultaneously with the completion of the acquisition of certain oil and gas assets from Bayswater Exploration and Development, LLC, et. al., the Company amended its revolving credit facility (“LOC”).  Under the amendment, the maximum loan commitment was increased to $500 million from $300 million and the borrowing base was increased to $230 million from $110 million.  The number of banks participating in the LOC increased to eight with SunTrust Bank as the Joint Lead Arranger / Administrative Agent and KeyBank, National Association as the Joint Lead Arranger / Syndication Agent.  The maturity date of the facility was extended to December 15, 2019.

Concurrent with the amendment, the Company increased its borrowings to approximately $146 million.  Proceeds from the additional borrowings were used to fund the Bayswater acquisition.

Interest under the LOC is payable monthly and accrues at a variable rate, subject to a minimum rate of 2.5%.  For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or the London Interbank Offered Rate (“LIBOR”) plus a margin.  The interest rate margin, as well as other bank fees, varies with utilization of the LOC.  The average annual interest rate for borrowings during the three months and six months ended February 28, 2015, was 2.5%.

Certain of the Company’s assets, including substantially all of our producing wells and developed oil and gas leases, have been designated as collateral under the arrangement.  The borrowing commitment is subject to adjustment based upon a borrowing base calculation that includes the value of oil and gas reserves.  The borrowing base limitation is subject to scheduled redeterminations on a semi-annual basis.  In certain events, and at the discretion of the bank syndicate, an unscheduled redetermination could be prepared.  Certain events occurring after December 15, 2014, caused reductions to the borrowing base.  Those events included the equity financing event discussed in Note 10 and the early liquidation of “in-the-money” hedge positions.  As of April 2, 2015, based upon a borrowing base of $192 million and an outstanding principal balance of $146 million, the unused borrowing base available for future borrowing totaled approximately $46 million.  The next semi-annual redetermination is scheduled for May 2015.

The arrangement contains covenants that, among other things, restrict the payment of dividends.  In addition, the LOC generally requires an overall hedge position that covers a rolling 24 months of estimated future production with a minimum position of no less than 45% and a maximum position of no more than 85% of hydrocarbon production as projected in the semi-annual reserve report.
 
 
18


Furthermore, the LOC requires the Company to maintain certain financial ratio compliance covenants.  Under the requirements, on a quarterly basis, the Company must (a) not, at any time, permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0; and (b) not, as of the last day of the fiscal quarter, permit its adjusted current ratio, as defined, to be less than 1.0 to 1.0.  As of February 28, 2015, the most recent compliance date, the Company was in compliance with all loan covenants.

7.
Commodity Derivative Instruments

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

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

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

The Company’s valuation estimate takes into consideration the counterparty’s creditworthiness, the Company’s creditworthiness, and the time value of money.  The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view.  Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.
 
19


The Company’s commodity derivative contracts as of February 28, 2015 are summarized below:
 
Settlement Period
Derivative
Instrument
 
Average Volumes
(BBls/MMBtu
per month)
   
Average
Fixed
Price
   
Floor
Price
   
Celing
Price
 
Crude Oil - NYMEX WTI
                 
Mar 1, 2015 - Jun 30, 2015
Collar
   
7,000
     
-
   
$
80.00
   
$
92.50
 
Mar 1, 2015 - Jun 30, 2015
Collar
   
2,500
     
-
   
$
80.00
   
$
95.75
 
Jul  1, 2015  - Dec 31, 2015
Collar
   
9,000
     
-
   
$
80.00
   
$
92.25
 
Mar 1, 2015 - Dec 31, 2015
Collar
   
4,500
     
-
   
$
80.00
   
$
99.40
 
Mar 1, 2015 - Dec 31, 2015
Collar
   
6,000
     
-
   
$
85.00
   
$
101.30
 
Mar 1, 2015 - Oct 31, 2015
Swap
 (1)  
12,000
   
$
78.65
     
-
     
-
 
Mar 1, 2015 - Dec 31, 2015
Put
   
40,000
     
-
   
$
50.00
     
-
 
Mar 1, 2015 - Oct 31, 2015
Put
   
8,750
     
-
   
$
50.00
     
-
 
                                   
Jan 1, 2016 - May 31, 2016
Collar
   
10,000
     
-
   
$
75.00
   
$
96.00
 
Jan 1, 2016 - May 31, 2016
Collar
   
5,000
     
-
   
$
80.00
   
$
100.75
 
Jun 1, 2016 - Aug 31, 2016
Collar
   
15,000
     
-
   
$
80.00
   
$
100.05
 
Jan 1, 2016  - Aug 31, 2016
Swap
   
5,000
   
$
88.55
     
-
     
-
 
Sep 1, 2016 - Dec 31, 2016
Swap
   
20,000
   
$
88.10
     
-
     
-
 
Jan 1, 2016  - Oct 31, 2016
Swap
   
6,400
   
$
78.96
     
-
     
-
 
Jan 1, 2016 - Dec 31, 2016
Put
   
25,000
     
-
   
$
50.00
     
-
 
                                   
Jan 1, 2017 - Dec 31, 2017
Put
   
20,000
     
-
   
$
50.00
     
-
 
                                   
Natural Gas - NYMEX Henry Hub
                               
Mar 1, 2015 - Dec 31, 2015
Collar
   
72,000
     
-
   
$
4.15
   
$
4.49
 
Jan 1, 2016 - May 31, 2016
Collar
   
60,000
     
-
   
$
4.05
   
$
4.54
 
Jun 1, 2016 - Aug 31, 2016
Collar
   
60,000
           
$
3.90
   
$
4.14
 
                                   
Natural Gas - CIG Rocky Mountain
                               
Apr 1, 2015 - Dec 31, 2015
Collar
   
100,000
     
-
   
$
2.20
   
$
3.05
 
Jan 1, 2016 - Dec 31, 2016
Collar
   
100,000
     
-
   
$
2.65
   
$
3.10
 
Jan 1, 2017 - Apr 30, 2017
Collar
   
100,000
     
-
   
$
2.80
   
$
3.95
 
 
(1) 
Subsequent to February 28, 2015, the Company liquidated this position for net proceeds of $2.1 million.
 
Offsetting of Derivative Assets and Liabilities

As of February 28, 2015 and 2014, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions.  In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at election of both parties, for transactions that occur on the same date and in the same currency.  The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty.  The Company’s accounting policy is to offset these positions in its accompanying balance sheets.
 
 
20


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

      
As of February 28, 2015  
 
Underlying Commodity
Balance Sheet Location
 
Gross Amounts of Recognized Assets and Liabilities
   
Gross Amounts Offset in the Balance Sheet
   
Net Amounts of Assets and Liabilities Presented in the Balance Sheet
 
Derivative contracts
Current assets
 
$
10,602
   
$
(215
)
 
$
10,387
 
Derivative contracts
Noncurrent assets
 
$
7,257
   
$
(459
)
 
$
6,798
 
Derivative contracts
Current liabilities
 
$
215
   
$
(215
)
 
$
-
 
Derivative contracts
Noncurrent liabilities
 
$
459
   
$
(459
)
 
$
-
 

      
As of August 31, 2014   
 
Underlying Commodity
Balance Sheet Location
 
Gross Amounts of Recognized Assets and Liabilities
   
Gross Amounts Offset in the Balance Sheet
   
Net Amounts of Assets and Liabilities Presented in the Balance Sheet
 
Derivative contracts
Current assets
 
$
903
   
$
(538
)
 
$
365
 
Derivative contracts
Noncurrent assets
 
$
718
   
$
(664
)
 
$
54
 
Derivative contracts
Current liabilities
 
$
840
   
$
(538
)
 
$
302
 
Derivative contracts
Noncurrent liabilities
 
$
971
   
$
(664
)
 
$
307
 
 
The amount of gain (loss) recognized in the statements of operations related to derivative financial instruments was as follows (in thousands):

   
Three Months Ended
February 28,
   
Six Months ended
February 28,
 
   
2015
   
2014
   
2015
   
2014
 
Realized gain (loss) on commodity derivatives
 
$
12,367
   
$
(191
)
 
$
13,799
   
$
(589
)
Unrealized gain (loss) on commodity derivatives
   
(2,832
)
   
(1,805
)
   
13,876
     
831
 
Total gain (loss)
 
$
9,535
   
$
(1,996
)
 
$
27,675
   
$
242
 


Realized gains and losses include cash received from the monthly settlement of hedge contracts at their scheduled maturity date along with the proceeds from early liquidation of in-the-money hedge contracts.  During the second quarter of 2015, the Company liquidated oil swaps with an average price of $89.81 and covering 173,000 barrels and received cash settlements of approximately $6.3 million.  The following table summarizes hedge realized gains and losses during the periods presented:
 
   
Three Months Ended
February 28,
   
Six Months ended
February 28,
 
   
2015
   
2014
   
2015
   
2014
 
Monthly settlement
 
$
6,086
   
$
(191
)
 
$
7,518
   
$
(589
)
Early liquidation
   
6,281
     
-
     
6,281
     
-
 
Total realized gain (loss)
 
$
12,367
   
$
(191
)
 
$
13,799
   
$
(589
)


21


Credit-Related Contingent Features

During the three and six months ended February 28, 2015, the Company added a fourth counterparty to its derivative transactions.  The additional counterparty is a member of the Company’s credit facility syndicate and the Company’s obligations under its credit facility and derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties.

8.
Fair Value Measurements

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

·
Level 1: Quoted prices available in active markets for identical assets or liabilities;
·
Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;
·
Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models.

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

The Company’s non-recurring fair value measurements include asset retirement obligations and purchase price allocations for the fair value of assets and liabilities acquired through business combinations.

The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.  See Note 5 for additional information.

The acquisition of a group of assets in a business combination transaction requires fair value estimates for assets acquired and liabilities assumed.  The fair value of assets and liabilities acquired through business combinations is calculated using a discounted cash flow approach using primarily unobservable inputs.  Inputs are reviewed by management on an annual basis. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices and operating costs. See Note 3 for additional information.
 
22

 

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of February 28, 2015 and August 31, 2014 by level within the fair value hierarchy (in thousands):
 
   
Fair Value Measurements at February 28, 2015   
 
   
Level 1
   
Level 2
   
Level 3
   
Total
 
Financial assets and liabilities:
               
    Commodity derivative asset
 
$
-
   
$
17,185
   
$
-
   
$
17,185
 
    Commodity derivative liability
 
$
-
   
$
-
   
$
-
   
$
-
 

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

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments.  Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At February 28, 2015, derivative instruments utilized by the Company consist of puts, “no premium” collars and swaps. The crude oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors including public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Fair Value of Financial Instruments

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

23


9.
Interest Expense

The components of interest expense are (in thousands):
 
   
Three Months Ended
February 28,
   
Six Months Ended
February 28,
 
   
2015
   
2014
   
2015
   
2014
 
Revolving credit facility
 
$
898
   
$
246
   
$
1,276
   
$
497
 
Amortization of debt issuance costs
   
218
     
100
     
355
     
194
 
Less, interest capitalized
   
(1,116
)
   
(346
)
   
(1,631
)
   
(691
)
Interest expense, net
 
$
-
   
$
-
   
$
-
   
$
-
 
 
10.
Shareholders’ Equity

The Company’s classes of stock are summarized as follows:
 
   
As of February 28,
   
As of August 31,
 
   
2015
   
2014
 
Preferred stock, shares authorized
   
10,000,000
     
10,000,000
 
Preferred stock, par value
 
$
0.01
   
$
0.01
 
Preferred stock, shares issued and outstanding
 
nil
   
nil
 
Common stock, shares authorized
   
200,000,000
     
200,000,000
 
Common stock, par value
 
$
0.001
   
$
0.001
 
Common stock, shares issued and outstanding
   
104,066,892
     
77,999,082
 

Stock Offering

During the three months ended February 28, 2015, the Company completed a public offering of 18,613,952 shares of its common stock at a price to the public of $10.75 per share.  On February 2, 2015, the Company received net proceeds of approximately $190.8 million after deducting underwriting discounts, commissions and other offering expenses.

Common Stock Issued for Acquisition of Mineral Property Interests

During the six months ended February 28, 2015 the Company issued shares of common stock in exchange for mineral property interests.  The value of each transaction was determined using the market price of the Company’s common stock on the date of each transaction.

   
For the six months ended
 February 28, 2015
 
Number of common shares issued for mineral property leases
   
157,957
 
Number of common shares issued for acquisitions
   
4,648,136
 
Total common shares issued
   
4,806,093
 
         
Average price per common share
 
$
10.47
 
Aggregate value of shares issued (in thousands)
 
$
50,330
 


24

Common Stock Warrants

During the six months ended February 28, 2015, holders exercised outstanding warrants to purchase 2,562,473 shares of common stock.  The Company received cash proceeds of $15.4 million.  The following table summarizes activity for common stock warrants for the six month period ended February 28, 2015:
 
   
Number of
Warrants
   
Weighted-Average
Exercise Price
 
Outstanding, August 31, 2014
   
2,562,473
   
$
6.00
 
Granted
   
-
   
$
-
 
Exercised
   
(2,562,473
)
 
$
6.00
 
Expired
   
-
   
$
-
 
Outstanding, February 28, 2015
   
-
   
$
-
 
 

11.
Stock-Based Compensation

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

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

   
Three Months Ended
February 28,
   
Six Months Ended
February 28,
 
   
2015
   
2014
   
2015
   
2014
 
Stock options
 
$
577
   
$
447
   
$
1,077
   
$
867
 
Employee stock grants
   
559
     
-
     
852
     
-
 
   
$
1,136
   
$
447
   
$
1,929
   
$
867
 
 
 
25


During the three and six months ended February 28, 2015 and 2014, the Company granted the following employee stock options:
 
   
Three Months Ended
February 28,
   
Six Months Ended
February 28,
 
   
2015
   
2014
   
2015
   
2014
 
Number of options to purchase common shares
   
335,000
     
113,000
     
410,000
     
263,000
 
Weighted-average exercise price
 
$
12.11
   
$
9.38
   
$
12.25
   
$
9.72
 
Term (in years)
   
10.0
     
10.0
     
10.0
     
10.0
 
Vesting Period (in years)
   
5
     
5
     
5
     
5
 
Fair Value (in thousands)
 
$
1,960
   
$
711
   
$
2,599
   
$
1,725
 
 
The assumptions used in valuing stock options granted during each of the six months presented were as follows:

   
Six Months Ended
February 28,
 
   
2015
   
2014
 
Expected term
 
6.45 years
   
6.5 years
 
Expected volatility
   
52
%
   
74
%
Risk free rate
   
1.71
%
   
1.97
%
Expected dividend yield
   
0.00
%
   
0.00
%
Forfeiture rate
   
0.35
%
   
0.00
%

The following table summarizes activity for stock options for the six months ended February 28, 2015:

   
Number
of Shares
   
Weighted-Average Exercise Price
 
Outstanding, August 31, 2014
   
2,167,000
   
 
$5.94
 
Granted
   
410,000
   
 
$12.25
 
Exercised
   
(133,000
)
 
 
$3.84
 
Forfeited
   
-
     
-
 
Outstanding, February 28, 2015
   
2,444,000
   
 
$7.12
 

The following table summarizes information about issued and outstanding stock options as of February 28, 2015:

   
Outstanding Options
   
Vested
Options
 
Number of shares
   
2,444,000
     
888,100
 
Weighted-average remaining contractual life
 
7.9 years
   
7.0 years
 
Weighted-average exercise price
 
 
$7.12
   
 
$5.03
 
Aggregate intrinsic value (in thousands)
 
 
$12,034
   
 
$6,149
 

The estimated unrecognized compensation cost from unvested stock options as of February 28, 2015, which will be recognized ratably over the remaining vesting phase, is as follows:

   
Unvested Options at February 28, 2015
Unrecognized compensation expense (in thousands)
 
$6,899
Remaining vesting phase
 
3.5 years

26


12.
Related Party Transactions

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

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

   
Three Months Ended
February 28,
   
Six Months Ended
February 28,
 
   
2015
   
2014
   
2015
   
2014
 
Rent expense
 
$
45
   
$
45
   
$
90
   
$
90
 

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


   
Three Months Ended
February 28,
   
Six Months Ended
February 28,
 
   
2015
   
2014
   
2015
   
2014
 
Total Royalty Payments
 
$
28
   
$
51
   
$
81
   
$
133
 

13.
Other Commitments and Contingencies

During the six months ended February 28, 2015, the Company fulfilled its contract drilling obligations with Ensign United States Drilling, Inc.  Two of the three rigs under contract were released, and one rig was contracted to continue drilling on a day-rate pricing basis.  The new contract has a term of less than one year.

From time to time, the Company receives notice from other operators of their intent to drill and operate a well in which the Company owns a working interest (a “non-operated well”).  The Company has the option to participate in the well and assume the obligation for its pro-rata share of the costs.  As of February 28, 2015, the Company was participating in the drilling and completion of 9 gross (1.1 net) new horizontal wells, with aggregate costs to its interest estimated at $5.6 million.  It is the Company’s policy to accrue costs on a non-operated well when it receives notice that active drilling operations have commenced.  Accordingly, the February 28, 2015 financial statements include accrued costs of $4.6 million for these wells.

14.
Supplemental Schedule of Information to the Statements of Cash Flows

The following table supplements the cash flow information presented in the financial statements for the six months ended February 28, 2015 and 2014 (in thousands):

   
Six Months Ended
 
   
February 28,
 
   
2015
   
2014
 
Supplemental cash flow information:
       
    Interest paid
 
$
1,284
   
$
501
 
    Income taxes paid
   
110
     
-
 
                 
Non-cash investing and financing activities:
               
Accrued well costs
 
$
30,598
   
$
17,966
 
Assets acquired in exchange for common stock
   
50,330
     
10,122
 
Asset retirement costs and obligations
   
2,231
     
1,000
 

 
27



Item 2.  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 provide certain details regarding our financial condition as of February 28, 2015, and the results of our operations for the three and six months ended February 28, 2015 and 2014. It should be read in conjunction with the unaudited financial statements and notes thereto contained in this report as well as the audited financial statements included in our Form 10-K for the fiscal year ended August 31, 2014.

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, Colorado, and is considered one of the premier oil and gas resource plays in the United States.  The area has produced oil and gas for over fifty years and benefits from a relatively low development cost structure.

Substantially all of our producing wells are either in or adjacent to the Wattenberg Field.  We operate over 90% of our proved reserves and 97% of our fiscal 2015 capital budget is focused on the Wattenberg Field.  This gives us both operational focus and development flexibility to maximize returns on our leasehold position.

As of February 28, 2015, we hold approximately 446,000 gross acres and 323,000 net acres under lease.   We currently hold approximately 75,000 net acres in the “Greater Wattenberg Area.”  This position consists of approximately 36,600 net acres in the “core Wattenberg Area” and 38,400 net acres in what we call the North East Extension Area.  In addition, we hold approximately 184,600 net acres in Southwest Nebraska, a conventional oil-prone prospect, and approximately 63,500 net acres in far eastern Colorado, an existing shallow dry-gas field.

Since commencing active operations in September 2008, we have undergone significant growth.  From inception through February 28, 2015, we have completed, acquired, or participated in 554 gross (371 net) successful oil and gas wells.  Our early development efforts were focused on drilling vertical wells into the Niobrara, Codell, and J-Sand formations but, in May 2013, we shifted our efforts to horizontal well development.  Horizontal wells, while taking longer to drill and complete and costing significantly more than vertical wells, have provided superior returns on our capital.

28

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

Vertical Wells
                         
Operated Wells
   
Non- Operated Wells
   
Totals
 
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
 
382
     
309
     
36
     
12
     
418
     
321
 
                                             
 
Horizontal Wells
                               
Operated Wells
   
Non- Operated Wells
   
 Totals
 
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
 
39
     
35
     
97
     
15
     
136
     
50
 

In addition to the producing wells summarized in the preceding table, as of February 28, 2015, we were the operator of 40 wells in progress and we were participating as a non-operating working interest owner in 9 wells in progress.

During the first six months of fiscal 2015 crude oil prices have declined by approximately 50%.  Price declines, especially of this magnitude, can impact many aspects of our operations.  For a more complete deliberation concerning the potential impacts from declining commodity prices, please see our discussions in “Drilling and Completion Operations”, “Market Conditions”, “Oil and Gas Commodity Contracts”, and “Trends and Outlook”.

Strategy

Our basic strategy encompasses the continuation of horizontal drilling within our Wattenberg leasehold as well as targeting asset acquisitions in well-defined, lower-risk areas that can provide significant cash flows and rapid returns on capital.  Drilling in lower-risk areas, maintaining high operating interests, and focusing on cost control enables us to achieve attractive well economics in most commodity price environments.  Our drilling efforts have been, and for the foreseeable future will continue to be, focused on the Wattenberg Field as its geologic and economic characteristics best fit our strategic goals.

We believe the most important aspect of our business that we can control is the cost associated with finding and developing our reserves, and that our cost-focused strategy is prudent irrespective of the prevailing commodity price environment.  Historically, we have been one of the most cost efficient producers in the Wattenberg Field, enabling us to provide attractive returns on capital.  Management’s experience in the Wattenberg Field has shown that in times of lower commodity prices, cost optimization and control is critical if the reserves are to be developed economically.  Our profitability, and ultimately the return on our assets and equity, is driven by how well we can manage costs relative to the prices we receive for our crude oil and natural gas.

In addition to our focus on cost optimization and low-risk development drilling, our strategy includes the use of commodity derivative contracts to mitigate a portion of the Company’s exposure to potentially adverse market changes in commodity prices and the associated impact on our expected future cash flows.  We do not however, utilize commodity derivative contracts for speculative purposes.  For more information, see “Oil and Gas Commodity Contracts.”

Historically, our cash flow from operations has not been sufficient to fund our rapid growth plans and we supplemented our capital resources with proceeds from the sale of equity and convertible securities.  We also arranged for a bank credit facility to fund additional capital needs.  During the three and six month periods ended February 28, 2015, the primary sources of our capital resources were cash on hand at the beginning of the year, cash flow from operations, cash proceeds from the early liquidation of in-the-money commodity contracts, proceeds from our revolving credit facility, proceeds from the exercise of outstanding warrants and proceeds from our recent equity issuance.  In the future, we plan 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.”
 
29


Significant Developments

Acquisition of Mineral Assets from Bayswater on December 15, 2014

On December 15, 2014, the Company completed the acquisition of certain assets from three independent oil and gas companies (collectively known as “Bayswater”).  Consideration paid to Bayswater, after customary closing and post-closing adjustments, consisted of approximately $74.0 million in cash and $48.4 million in stock.

The Bayswater acquisition encompasses 5,040 gross (4,053 net) acres with rights to the Codell and Niobrara formations, and 2,400 gross (1,739 net) acres with rights to other formations including the Sussex, Shannon and J-Sand.  Additionally, we acquired working interests in 17 non-operated horizontal wells, 73 operated vertical wells, and 11 non-operated vertical wells.  

The acquisition’s current production is coming from a relatively small portion of the total acreage, but these assets significantly increase the Company’s exposure to the southern portion of the Wattenberg Field where infrastructure and gathering line pressures have been more favorable for reliable production.  In addition, the non-operated horizontal wells have given the Company the opportunity to work with one of the largest and most respected operators in the area and initial production results from their extended-reach horizontal wells is highly encouraging.

While we do not have any drilling commitments relative to this leasehold, and importantly all leases are held by production, we are evaluating the economic return potential for future development efforts on this leasehold.  The leasehold and geology is conducive to mid- and extended-reach horizontal laterals, which are exhibiting shallower decline curves in the area, and we believe could generate higher overall returns on capital.  In addition, there are numerous offset Codell horizontal wells near our acreage with attractive production profiles.  We anticipate this acreage will provide a multi-year drilling inventory and, when fully developed, expect these assets to be accretive to cash flow and earnings per share.

Fifth Amendment to Revolving Credit Facility (“LOC”) on December 15, 2014

We continue to improve our borrowing arrangements to complement our growth strategy.  On December 15, 2014, the Company amended its LOC.  The title of the most recent amendment is the Fifth Amendment to Amended and Restated Credit Agreement (“Fifth Amendment”) and expanded the bank syndicate to eight members.  SunTrust Bank is the Administrative Agent while KeyBank National Association is the Syndication Agent.  The Fifth Amendment increased the loan commitment from $300 million to $500 million and increased our borrowing base from $110 million to $230 million. The LOC, as amended, expires on December 15, 2019 and establishes a minimum interest rate on borrowings of 2.5%.  Actual interest rates will vary depending upon utilization.

Amounts borrowed from the banks will be used to develop oil and gas properties, acquire new oil and gas properties, and for working capital and other general corporate purposes. 


30

Completion of Public Stock Offering on January 28, 2015

During the three months ended February 28, 2015, the Company completed a public offering of 18,613,952 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to the public of $10.75 per share.  On February 2, 2015, we received net proceeds of approximately $190.7 million after deducting underwriting discounts, commissions and other offering expenses.  The Company intends to use the net proceeds to fund additional asset acquisitions in the Wattenberg Field, to pay down outstanding indebtedness under our revolving credit facility and for general corporate purposes, including working capital.  For more information, see “Liquidity and Capital Resources.”

Increased Working Interest in Greenhorn AMI

On February 12, 2015, we agreed with Vecta Oil & Gas, Ltd. (“Vecta”) to amend our Joint Exploration Agreement dated March 1, 2013.  The transaction is expected to close in April of this year.  Under the amendment, Vecta will convey assignments to us for an undivided 30% working interest in the DJ Basin Greenhorn Area of Mutual Interest (AMI).  In consideration, we agreed to pay Vecta $250 per net mineral acre payable in Synergy’s restricted common stock.  The transaction will increase our working interest in the AMI from 35% to 65%.  The transaction will convey approximately 10,000 net acres to us, increasing our position in the North East Wattenberg Extension Area to over 38,000 net acres.

Early Liquidation of In-The-Money Commodity Contracts

During the quarter ended February 28, 2015, we liquidated a portion of our deep in-the-money commodity contracts while increasing the absolute barrels under contract by purchasing crude oil puts with $50/bbl strike prices.  These transactions allowed us to monetize what would have otherwise been unrealized gains, thereby increasing cash flow, while at the same time hedge a greater portion of our expected future production from further commodity price weakness.  In addition to working with our existing counterparties, we purchased a portion of the put contracts on the Chicago Mercantile Exchange, which we believe will enhance the liquidity of our overall position.

Drilling and Completion operations

Our drilling and completion schedule has a material impact on our production forecast and a corresponding impact on our expected future cash flows.
 
As commodity prices have fallen over the preceding two fiscal quarters, we have been able to reduce drilling and completion costs by approximately 25%. We think we can achieve even lower costs in the future, but believe at current drilling and completion cost levels and with current prevailing commodity prices, we can achieve reasonable well-level rates of return going forward.  
 
As of the end of our second fiscal quarter, we have no plans to curtail any activities.  However, should commodity prices weaken further, our operational flexibility will allow us to adjust the completion schedule of many of our wells-in-progress and reduce further drilling activities if prudent.  If management believes the well-level internal rate of return will be at or below our weighted-average cost of capital, we can choose to delay completions and/or forego drilling altogether.
 

31

Drilling Activity

During our fiscal 2015 second quarter ended February 28, 2015, we concluded drilling operations on our Weis pad and commenced drilling operations on our Cannon pad.  The Cannon pad will consist of six Codell and five Niobrara wells.  All 11 wells are permitted to be standard-length laterals with a range of 18 to 24 frac stages per well utilizing sliding sleeves, unless geologic conditions necessitate plug-and-perforate completions.  The six Codell wells are expected to utilize slickwater fluids, while the five Niobrara wells are designed to utilize hybrid gel fluids.  Total drilling and completion costs are expected to be between $3.1 to $3.3 million per well for the Codell wells and $3.3 to $3.5 million per well for the Niobrara wells.  We have a 100% working interest in the Cannon prospect and the pad is located in the western area of the Company’s Wattenberg leasehold where line pressures have been lower and more favorable for reliable production.  Drilling on the Cannon pad is expected to conclude in May with completion operations expected to begin in June.

As it relates to our North East Extension Area, we continue to expect to spud our first horizontal Greenhorn prospect in May.  We are finalizing the well design and are in the process of identifying the appropriate rig to utilize.  Given the step-out nature of the prospect, we anticipate the well will take longer and cost more than a comparable standard length, horizontal Niobrara well.   We currently expect initial results to be available either late this fiscal year or early next fiscal year.

Completion Activity

Subsequent to the end of our fiscal second quarter, we began completion operations on our 13 well Kiehn/Weis pad.  This pad comprises eight wells on the Kiehn portion and five wells on the Weis portion of the pad. The 13 wells consist of seven Niobrara and six Codell wells.  Five of the 13 will utilize plug-and-perf completion designs while the balance will utilize sliding sleeves.  This pad is also located on the western flank of the Wattenberg Field where infrastructure and lower line pressures have been more advantageous than the northern area of the Wattenberg Field.  We anticipate the Kiehn/Weis pad completion operations will be finished by late April with first production expected in May.

The balance of our drilled but not yet completed wells consists of eight wells at our Geis pad and eight wells at our Weideman pad, which includes four Extended Reach Lateral (ERL) wells.  The four ERL Weideman wells will take longer and cost more to complete than our standard length lateral wells.  We continue to anticipate the Geis wells and the Weideman wells will begin production during our fourth fiscal quarter.  While these pads are located in the more northern area of the Wattenberg Field, we anticipate midstream operating conditions will improve with the startup of DCP Midstream’s Lucerne II plant in May.

Other operations

The Company continues to be opportunistic as it relates to acquisition and divestiture efforts.  We continue to enter into land and working interest swaps to increase our overall leasehold control.  For example, in December 2014, while maintaining operational control of 40 vertical wells, we divested approximately 600 net acres for approximately $3.7 million.  This divestiture allowed us to not only increase cash on hand, but also avoid participating in the drilling of several wells we deemed non-economic given the expected costs relative to the then current commodity prices.

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

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

Production
 
Our production from producing wells decreased from 8,278 barrels of oil equivalent (“BOE”) per day for the fiscal quarter ending November 30, 2014 to 7,745 BOE per day for the fiscal quarter ending February 28, 2015.  The additional production volumes contributed by the producing wells acquired in the Bayswater transaction since the closing date of December 15, 2014 was not sufficient to offset the natural decline curve of our wells. 

32

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 Reference Price (derived from average NYMEX prices weighted to reflect monthly sales volumes) as well as the differential between the Reference Price and the wellhead prices realized by us.
 
   
Three Months Ended
   
Six Months Ended
 
   
February 28, 
   
February 28,
 
Oil (NYMEX WTI)
 
2015
   
2014
   
2015
   
2014
 
Reference Price
 
$
53.66
   
$
97.69
   
$
69.93
   
$
98.96
 
Realized Price
 
$
43.51
   
$
86.82
   
$
59.53
   
$
89.64
 
Differential
 
$
(10.15
)
 
$
(10.87
)
 
$
(10.40
)
 
$
(9.32
)
                                 
Gas (NYMEX Henry Hub)
                               
Reference Price
 
$
3.11
   
$
4.98
   
$
3.53
   
$
4.31
 
Realized Price
 
$
3.38
   
$
5.93
   
$
4.06
   
$
5.44
 
Differential
 
$
0.27
   
$
0.95
   
$
0.53
   
$
1.13
 
 
 
Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX.  The negative differential between the prices actually received by us at the wellhead and the published indices reflects deductions imposed upon us by the purchasers for location and quality adjustments.  We continue to negotiate with crude oil purchasers to obtain better differentials.  With regard to the sale of natural gas and liquids, we are able to sell production at prices greater than the prices posted for dry gas, primarily because prices we receive include payment for the natural gas liquids produced with the gas.

There has been a significant decline in the price of oil since the summer of 2014.  As reflected in published data, the price for West Texas Intermediate (WTI) oil settled at $95.96/bbl on Friday, August 29, 2014, the last trading day of our 2014 fiscal year.  The price of WTI settled at $66.15 per barrel on Friday November 28, 2014, which equates to an approximate 31% decline in oil prices during our fiscal first quarter.  The price of oil settled at $49.76/bbl on Friday, February 27, 2015, which equates to an approximate 48% decline during the first six months of our fiscal year.  Our revenues, results of operations, profitability and future growth, and the carrying value of our oil and natural gas properties depend primarily on the prices we receive for our oil and natural gas production.

A decline in oil and natural gas prices will adversely affect our financial condition and results of operations.  Furthermore, low oil and natural gas prices affect the value of our properties and the calculation of the “ceiling test” required under the accounting principles for companies following the “full cost” method of accounting.  We review our oil and gas properties for impairment at each quarterly reporting period.  For the second quarter, the ceiling test indicated that no impairment had occurred.  However, continued low prices will further lower the calculated ceiling, and future impairments may occur.
 
 
33


RESULTS OF OPERATIONS

For the three months ended February 28, 2015, compared to the three months ended February 28, 2014

For the three months ended February 28, 2015, we reported net income of $4.7 million compared to $5.2 million during the three months ended February 28, 2014.  Earnings were $0.05 per basic and diluted share for the three months ended February 28, 2015 compared to $0.07 per basic and diluted share for the three months ended February 28, 2014.  The following discussion expands upon significant items of inflow and outflow that affected results of operations.

Oil and Gas Production and Revenues – For the three months ended February 28, 2015 we recorded total oil and gas revenues of $23.7 million compared to $23.0 million for the three months ended February 28, 2014, an increase of $0.7 million or 3.0%.

Year over year, we added 35 net horizontal wells, including 4 (net) Bayswater horizontal wells, increasing our reserves, producing wells and daily production totals.  However, although the three months ended February 28, 2015 yielded almost twice as much BOE production compared to the three months ended February 28, 2014, our revenues during the 2015 quarter increased only modestly as a result of declining oil prices.

Net oil and gas production for the three months ended February 28, 2015 averaged 7,745 BOE per day. For the three months ended February 28, 2014, production averaged 3,917 BOE per day, a year-over-year increase of 98%.  As a further comparison, average BOE production was 8,278 per day during the quarter ended November 30, 2014, a quarter-over-quarter decrease of 6.4%.  Over the last twelve months, the daily production increase reflects the increased number of wells owned by us.  However, in the most recent quarter, production from new wells was not sufficient to offset the natural decline curve for our wells.    

Our revenues are sensitive to changes in commodity prices.  As shown in the following table, there has been a decrease of nearly 50% in average realized prices between the periods presented.  This decline in average sales prices mostly offset the effects of increased production.

The following table presents actual realized prices, without the effect of hedge transactions.  The impact of hedge transactions is presented later in this discussion.

Key production information is summarized in the following table:

   
Three Months Ended February 28,
 
   
2015
   
2014
   
Change
 
Production:
           
Oil (Bbls1)
   
412,469
     
204,622
     
102
%
Gas (Mcf2)
   
1,707,598
     
887,494
     
92
%
                         
Total production in BOE3
   
697,069
     
352,537
     
98
%
                         
Revenues (in thousands):
                 
Oil
 
$
17,948
   
$
17,765
     
1
%
Gas
   
5,765
     
5,263
     
10
%
   
$
23,713
   
$
23,028
     
3
%
Average sales price:
                       
Oil
 
$
43.51
   
$
86.82
     
-50
%
Gas
 
$
3.38
   
$
5.93
     
-43
%
BOE
 
$
34.02
   
$
65.32
     
-48
%


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


Lease Operating Expenses (“LOE”) – Direct operating costs of producing oil and natural gas are reported as follows (in thousands):
 
   
Three Months Ended
 
   
February 28,
 
   
2015
   
2014
 
Production Costs
 
$
3,659
   
$
1,797
 
Workover
   
30
     
9
 
Total LOE
 
$
3,689
   
$
1,806
 
                 
Per BOE:
               
Production costs
 
$
5.25
   
$
5.10
 
Workover
   
0.04
     
0.03
 
Total LOE
 
$
5.29
   
$
5.13
 
 
 
Lease operating and workover costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas.  During the second quarter of fiscal 2015, we continued to experience elevated production cost per BOE in connection with additional costs to operate horizontal wells.  Production from certain wells was intermittently restricted during the quarter as midstream infrastructure providers struggled to increase the efficiency and capacity of the gas gathering system.  We continue to work diligently to mitigate production difficulties within the Wattenberg Field.
 
34


Production taxes – During the three months ended February 28, 2015, production taxes were $2.1 million, or $3.08 per BOE, compared to $2.3 million, or $6.40 per BOE, during the three months ended February 28, 2014.  Taxes tend to increase or decrease primarily based on the value of oil and gas sold.  As a percent of revenues, taxes were 9.0% and 9.8% for the three months ended February 28, 2015 and 2014, respectively.

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

 
Three Months Ended
 
 
February 28,
 
(in thousands)
2015
 
2014
 
Depletion
 
15,345
 
 
7,491
 
Depreciation and amortization
   
161
     
228
 
Total DDA
 
15,506
 
 
7,719
 
                 
DDA expense per BOE
 
22.24
 
 
21.90
 
 
For the three months ended February 28, 2015, depletion of oil and gas properties was $22.24 per BOE compared to $21.90 for the three months ended February 28, 2014.  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 proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning-of-quarter estimated total reserves determine the depletion rate.  For the three months ended February 28, 2015, production represented 2.1% of the reserve base compared to 1.9% for the three months ended February 28, 2014.  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 initial 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.

In addition to a change in the ratio of production to reserves, our DDA rate was affected by the increasing costs of mineral leases and the increasing costs to drill and complete horizontal wells.

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

 
  
Three Months Ended
 
  
February 28,
(in thousands)
2015
 
2014
 
G&A costs incurred
 
4,713
 
 
2,074
 
Capitalized costs
   
(634
)
   
(304
)
Total G&A
 
4,079
 
 
1,770
 
                 
G&A expense per BOE
 
5.85
 
 
5.02
 


 
35


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

Although G&A costs have increased as we grow the business, we strive to maintain an efficient overhead structure.  For the quarter ended February 28, 2015, G&A was $5.85 per BOE compared to $5.02 for the quarter ended February 28, 2014.

Our G&A expense for the quarter ended February 28, 2015 includes stock-based compensation of $1.1 million compared to $0.4 million for the quarter ended February 28, 2014.  Stock-based compensation includes a calculated value for stock options or shares of common stock that we grant for compensatory purposes.  It is a non-cash charge, which, for stock options, is calculated using the Black-Scholes-Merton option pricing model to estimate the fair value of options.  Amounts are pro-rated over the vesting terms of the option agreements, which are generally three to five years.

Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the development of properties.  Those costs are reclassified from G&A expenses and capitalized into the full cost pool.  The increase in capitalized costs from 2014 to 2015 reflects our increasing activities to acquire leases and develop the properties.

Commodity derivative gains (losses) – As more fully described in the paragraphs titled “Oil and Gas Commodity Contracts” 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.  For the quarter ended February 28, 2015, we realized a cash settlement gain of $12.4 million, including gains of $6.1 million from the settlement of contracts at their scheduled maturity dates and gains of $6.3 million from the early liquidation of “in-the-money” contracts.  For the prior year quarter ended February 28, 2014, we realized a loss of $191,000.

In addition, for the quarter ended February 28, 2015, we recorded an unrealized loss of $2.8 million to recognize the mark-to-market change in fair value of our commodity contracts for the quarter ended February 28, 2015.  In comparison, in the quarter ended February 28, 2014, we reported an unrealized gain of $1.8 million.  Unrealized gains and losses are non-cash items.

Income taxes – We reported income tax expense of $3.2 million for the three months ended February 28, 2015, calculated at an effective tax rate of 40.8%.  During the comparable prior year period, we reported income tax expense of $2.3 million, calculated at an effective tax rate of 31.2%.  For both periods, we anticipate that the tax liability will be substantially deferred into future years. During fiscal year 2015, we estimate that the effective tax rate will differ from the federal and state statutory rate by the impact of deductions for percentage depletion.

For the six months ended February 28, 2015, compared to the six months ended February 28, 2014

For the six months ended February 28, 2015, we reported net income of $25.8 million compared to $11.3 million during the six months ended February 28, 2014.  Earnings were $0.31 per basic and $0.30 per diluted share for the six months ended February 28, 2015 compared to $0.15 per basic and diluted share for the six months ended February 28, 2014.  Significant differences between the two periods are the result of rapid growth in reserves, producing wells and daily production totals, as discussed previously, as well as the impact of changing prices on our commodity hedge positions.  As of February 28, 2015, we had 554 gross producing wells, compared to 376 gross producing wells as of February 28, 2014. However, although our production more than doubled during the comparative periods, our revenues during the 2015 period increased only 57% as a result of declining oil and gas prices. The following discussion expands upon significant items of inflow and outflow that affected results of operations. 
36

Oil and Gas Production and Revenues – For the six months ended February 28, 2015 we recorded total oil and gas revenues of $66.3 million compared to $42.3 million for the six months ended February 28, 2014, an increase of $24.0 million or 56.6%.

During the six months ended February 28, 2015, our BOE production was 125% higher than during the same period in 2014, largely as a result of increases in the number of gross producing wells.  However, our revenues are sensitive to changes in commodity prices.  As shown in the following table, there has been a decrease of approximately 30% in average realized prices between the periods presented.  These price declines have had a direct impact on the amount of revenue we have been able to achieve, despite our production growth.

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:

   
Six Months Ended February 28,
     
   
2015
   
2014
   
Change
 
Production:
           
Oil (Bbls1)
   
879,125
     
372,900
     
136
%
Gas (Mcf2)
   
3,427,536
     
1,629,249
     
110
%
                         
Total production in BOE3
   
1,450,381
     
644,441
     
125
%
                         
Revenues (in thousands):
                 
Oil
 
$
52,334
   
$
33,425
     
57
%
Gas
   
13,917
     
8,869
     
57
%
   
$
66,251
   
$
42,294
     
57
%
Average sales price:
                       
Oil
 
$
59.53
   
$
89.64
     
-34
%
Gas
 
$
4.06
   
$
5.44
     
-25
%
BOE
 
$
45.68
   
$
65.63
     
-30
%


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.


37

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

   
Six Months Ended  
 
   
February 28,
 
   
2015
   
2014
 
Production Costs
 
$
6,694
   
$
3,000
 
Workover
   
36
     
79
 
Total LOE
 
$
6,730
   
$
3,079
 
                 
Per BOE:
               
Production costs
 
$
4.62
   
$
4.66
 
Workover
   
0.02
     
0.12
 
Total LOE
 
$
4.64
   
$
4.78
 
 
Lease operating and workover costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas.

During the first six months of fiscal 2015, we continued to experience elevated production cost per BOE in connection with additional costs to operate horizontal wells.  Production from certain wells was intermittently restricted during the period as midstream infrastructure providers struggled to increase the efficiency and capacity of the gas gathering system.  We continue to work diligently to mitigate production difficulties within the Wattenberg Field.

Production taxes – During the six months ended February 28, 2015, production taxes were $6.3 million, or $4.36 per BOE, compared to $4.3 million, or $6.63 per BOE, during the six months ended February 28, 2014.  Taxes tend to increase or decrease primarily based on the value of oil and gas sold.  As a percent of revenues, taxes were approximately 10% for the six months ended February 28, 2015 and 2014.

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

   
Six Months Ended
 
   
February 28,
 
(in thousands)
 
2015
   
2014
 
Depletion
 
$
31,649
   
$
12,981
 
Depreciation and amortization
   
311
     
329
 
Total DDA
 
$
31,960
   
$
13,310
 
                 
DDA expense per BOE
 
$
22.04
   
$
20.65
 
 
For the six months ended February 28, 2015, depletion of oil and gas properties was $22.04 per BOE compared to $20.65 for the six months ended February 28, 2014.  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 proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning-of-quarter estimated total reserves determine the depletion rate.  For the six months ended February 28, 2015, production represented 4.4% of the reserve base compared to 3.5% for the six months ended February 28, 2014.  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 initial 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.
 
38


In addition to a change in the ratio of production to reserves, our DDA rate was affected by the increasing costs of mineral leases and the increasing costs to drill and complete horizontal wells.

General and Administrative (“G&A”) –The following table summarizes G&A expenses incurred and capitalized during the periods presented:
 
  
Six Months Ended
 
  
February 28,
 
(in thousands)
2015
 
2014
 
G&A costs incurred
 
$
9,326
   
$
5,559
 
Capitalized costs
   
(1,137
)
   
(621
)
Total G&A
 
$
8,189
   
$
4,938
 
                 
G&A expense per BOE
 
$
5.65
   
$
7.66
 

Our G&A expense for the six months ended February 28, 2015 includes stock-based compensation of $1.9 million compared to $0.9 million for the six months ended February 28, 2014.  As discussed previously, stock-based compensation is a non-cash charge related to options we grant for compensatory purposes and is based on a calculated value using the Black-Scholes-Merton option pricing model. See also Note 11 to our financial statements.

As discussed previously, pursuant to the full cost accounting method for oil and gas properties, we capitalize into the full cost pool all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the development of properties.  The increase in capitalized costs between the 2014 and 2015 periods reflects our increasing activities to acquire leases and develop the properties.

Commodity derivative gains (losses) – As more fully described in the paragraphs titled “Oil and Gas Commodity Contracts” 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.  For the six months ended February 28, 2015, we realized a cash settlement gain of $13.8 million, including gains of $7.5 million from the settlement of contracts at their scheduled maturity dates and gains of $6.3 million from the early liquidation of “in-the-money” contracts.   In comparison, in the six months ended February 28, 2014, we realized a loss of $0.6 million.

In addition, for the six months ended February 28, 2015, we recorded an unrealized gain of $13.9 million to recognize the mark-to-market change in fair value of our commodity contracts for the period.   In comparison, in the six months ended February 28, 2014, we reported an unrealized gain of $0.8 million.  Unrealized gains and losses are non-cash items.

Income taxes – We reported income tax expense of $15.0 million for the six months ended February 28, 2015, calculated at an effective tax rate of 36.7%.  During the comparable prior year period, we reported income tax expense of $5.7 million, calculated at an effective tax rate of 34.2%.  For both periods, it appears that the tax liability will be substantially deferred into future years. During fiscal year 2015, we estimate that the effective tax rate will approximate the federal and state statutory rate.
 
39


For tax purposes, we have a net operating loss (“NOL”) carryover of $33.2 million, which is available to offset future taxable income.  The NOL will begin to expire, if not used, in 2031.

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

LIQUIDITY AND CAPITAL RESOURCES

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

We believe our capital resources, including $218.5 million of cash on hand, $46.0 million available under our revolving credit facility, and cash flow from operating activities, will be sufficient to fund our planned capital expenditures and operating expenses for the next twelve months.  To the extent actual operating results differ from our anticipated results, or available borrowings under our credit facility are reduced, or we experience other unfavorable events, our liquidity could be adversely impacted.  Terms of future financings may be unfavorable and we cannot assure investors that funding will be available on acceptable terms.

Sources and Uses

Our sources and uses of capital are heavily influenced by the prices we receive for our production.  Over the past four years, the NYMEX—WTI oil price ranged from a high of $113.93 per Bbl to a recent low of $46.39 per Bbl, while the NYMEX—Henry Hub natural gas price ranged from a high of $6.01 per MMBtu to a low of $1.91 per MMBtu. These markets will likely continue to be volatile in the future.  To deal with the volatility in commodity prices, we maintain a flexible capital investment program and seek to maintain a high operating interest in our leaseholds with limited long-term capital commitments.  This enables us to accelerate or decelerate our activities quickly in response to changing industry environments.  Additionally, we believe our conservative use of leverage and corresponding strong balance sheet helps mitigate the potentially negative impact from lower commodity prices.

At February 28, 2015, we had cash and cash equivalents of $218.5 million and an outstanding balance of $146.0 million under our revolving credit facility.  Our sources and (uses) of funds for the six months ended February 28, 2015 and 2014 are summarized below (in thousands):
 
   
Six Months Ended
 
   
February 28,
 
   
2015
   
2014
 
Cash provided by operations
 
$
65,115
   
$
33,354
 
Net acquisition of oil and gas properties and equipment
   
(193,834
)
   
(87,497
)
Proceeds from short-term investments
   
-
     
39,990
 
Equity financing activities
   
205,736
     
29,070
 
Net borrowings
   
106,700
     
-
 
Net increase in cash and cash equivalents
 
$
183,717
   
$
14,917
 
 
40

 
Net cash provided by operating activities was $65.1 million and $33.4 million for the six months ended February 28, 2015 and 2014, respectively.  The significant improvement in cash from operating activities reflects the operating contribution from new wells that were drilled and producing wells that were acquired.

During the six months ended February 28, 2015, we received cash proceeds of $15.4 million from the exercise of Series C warrants.  As of February 28, 2015, all Series C warrants had been exercised.

During our second fiscal quarter, we also received cash proceeds of approximately $190.7 million (after underwriting discounts, commissions and expenses) from our public offering of 18,613,952 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to the public of $10.75 per share.  We plan to use these proceeds to fund additional asset acquisitions in the Wattenberg Field which may become available from time to time, to pay down outstanding indebtedness under our revolving credit facility and for corporate purposes, including working capital.

During the six month period ending February 28, 2015, we drew net proceeds of $106.7 million under our revolving credit facility, including $66.2 million drawn concurrently with the December 15, 2014 Bayswater acquisition.

Credit Arrangements

We maintain a borrowing arrangement with a banking syndicate.  The arrangement, in the form of a revolving credit facility, was most recently amended on December 15, 2014.  Under the amendment, the maximum loan commitment is $500 million; however, the maximum amount the Company can borrow at any one time is subject to a borrowing base limitation, which stipulates that the Company may borrow up to the lesser of the maximum loan commitment or the borrowing base.  The borrowing base can increase or decrease based upon the value of the collateral, which secures any amounts borrowed under the line of credit.  For the most part, the value of the collateral will be derived utilizing estimated future cash flows from the Company’s proved oil and gas reserves, discounted by 10%.  Amounts borrowed under the facility are secured by substantially all of the Company’s producing wells and developed oil and gas leases. 

Under the amendment, the initial borrowing base was set at $230 million, including a “non-conforming” component of $30 million.  On January 28, 2015, upon the successful completion of our follow-on public offering, our borrowing base was adjusted to eliminate the “non-conforming” amount.  Subsequently, our borrowing base was further reduced by the gains realized from the early liquidation of in-the-money commodity contracts.  As of April 2, 2015, our borrowing base was $192 million and we had $146 million outstanding under the facility.  The maturity date of the borrowing arrangement is December 15, 2019.

Interest on our revolving line of credit accrues at a variable rate, which will equal or exceed the minimum rate of 2.5%.  The interest rate pricing grid contains a graduated escalation in applicable margin for increased utilization.

41

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 $204.8 million and $91.2 million for the six months ended February 28, 2015 and 2014, respectively.  A reconciliation of the differences between cash payments and the “all-inclusive” amounts is summarized in the following table (in thousands):

   
Six Months Ended
 
   
February 28, 
 
   
2015
   
2014
 
Cash payments for capital expenditures
 
$
197,530
   
$
87,497
 
Accrued costs, beginning of period
   
(71,849
)
   
(25,491
)
Accrued costs, end of period
   
30,598
     
17,966
 
Non-cash acquisitions, common stock
   
50,330
     
10,122
 
Other
   
(1,767
)
   
1,112
 
All inclusive capital expenditures
 
$
204,842
   
$
91,206
 


Capital Expenditures

The majority of capital expenditures during the six months ended February 28, 2015, were associated with the acquisition of the Bayswater assets and drilling activities on operated wells.  As of February 28, 2015, there were 29 wells that had been drilled but not completed.  In addition, we had initiated drilling activities on the Cannon pad.  With respect to our ownership interest in wells operated by other companies, we participated in drilling and completion activities on 50 gross (5.8 net) non-operated wells.

As of February 28, 2015, there were 49 wells in progress (38.5 net) with accrued capital expenditures of $30.6 million.  Other expenditures included $9.2 million for the acquisition of lands, leases and other mineral assets.
 
Capital Requirements
 
Our primary need for cash will be to fund our drilling and acquisition programs for the remainder of the fiscal year ending August 31, 2015.  Our cash requirements have increased significantly as we implement our horizontal drilling program.  Standard length horizontal wells we drilled early in the fiscal year are estimated to cost between $3.5 million and $3.8 million each.  However, as commodity prices have dropped we have negotiated lower costs from our service providers and revised our completion design and we are now budgeting that the remaining standard length lateral wells to be drilled this fiscal year will cost between $3.1 million and $3.5 million each.  In order to maximize the efficient use of our capital we have reduced the amount of non-operated working interests in wells operated by others, either by swapping interests when appropriate or by outright selling of interests. 

Our fiscal 2015 plan still anticipates drilling and completing 46 gross operated wells and participating in 3 to 4 (net) non-operated wells.  Our fiscal 2015 budget remains $190 million to $195 million for drilling and leasing activities.  Our actual capital expenditures for the first six months of fiscal year 2015 approximated $80.5 million.

As has been our historical practice, we regularly review capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service costs and drilling success.  Our level of exploration, development and acreage expenditures is largely discretionary and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among other factors.


42


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.  We typically enter into contracts covering between 45% and 85% of anticipated production from our proved developed producing reserves, as projected in our most recent semi-annual reserve report, for a period of 24 months.  At February 28, 2015, we had open positions covering 1.5 million barrels of oil and 3.7 million mcf of natural gas.  We do not use derivative instruments for speculative purposes.

Our commodity derivative instruments may include but are not limited to “collars”, “swaps”, and “put” positions. Our hedging strategy, including how much anticipated production we hedge, whether we hedge oil and/or natural gas, and at what prices we hedge, is based in part on our view of expected future market conditions and our analysis of well-level economic return potential.  In addition, our use of hedging contracts is subject to stipulations set forth in our credit facility as amended.

During periods of significant price declines, for settled contracts structured as “collars”, we will receive settlement payments from the contracts’ counterparties for the difference between the contracted “floor” price and the average posted price for the contract period.  For settled “swaps”, we will receive the difference between the contracted swap price and the average posted price for the contract period.  For settled “put” contracts, we will receive the difference between the put’s strike price and the average posted price for the contract period.  If we decide to liquidate an “in-the-money” position prior to settlement date, we will receive the approximate fair value of the contract at that time.  These realized gains increase our reported net income for the period in which they are recognized.

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

The fair values of our open, not yet settled, derivative contracts are estimated by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors, as well as other relevant economic measures. The Company compares the valuations calculated by it 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 the Company, as appropriate.

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

43

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.

At February 28, 2015, we estimated that the fair value of our various commodity derivative contracts was a net asset of $17.2 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 February 28, 2015 may differ significantly from the realized values at their respective settlement dates.

Non-GAAP Financial Measures

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

Adjusted EBITDA

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

We define adjusted EBITDA as net income adjusted to exclude the impact of interest expense, interest income, income tax expense, DDA (depletion, depreciation 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. 

44

The following table presents a reconciliation of adjusted EBITDA, a non-GAAP financial measure, to net income, its nearest GAAP measure:
 
   
Three Months Ended
February 28,
   
Six Months Ended
February 28,
 
(in thousands)
 
2015
   
2014
   
2015
   
2014
 
Adjusted EBITDA:
               
   Net income
  $
4,652
    $
5,161
    $
25,803
    $
11,261
 
   Depletion, depreciation and amortization
   
15,506
     
7,719
     
31,960
     
13,310
 
   Provision for income tax
   
3,207
     
2,338
     
14,951
     
5,725
 
   Stock-based compensation
   
1,136
     
448
     
1,929
     
867
 
   Commodity derivative hedge
   
2,832
     
1,805
     
(13,876
)
   
(831
)
   Interest income
   
(28
)
   
(17
)
   
(28
)
   
(48
)
       Adjusted EBITDA
  $
27,305
    $
17,454
    $
60,739
    $
30,284
 
 
 
TRENDS AND OUTLOOK

Oil prices traded as high as $107/bbl in June 2014, and have since declined more than 50%.  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 returns, (iv) may cause us to allow leases to expire based upon the value of potential oil and gas reserves in relation to the costs of exploration,  (v) may result in marginally productive oil and gas wells being abandoned as non-commercial, and (vi) may cause a ceiling test impairment.   However, price declines reduce the competition for oil and gas properties and correspondingly reduce the prices paid for leases and prospects.

Other factors that will most significantly affect our results of operations include (i) activities on properties that we operate, (ii) the marketability of our production, (iii) our ability to satisfy our substantial capital requirements, (iv) completion of acquisitions of additional properties and reserves, and (v) competition from larger companies.  Our revenues will also be significantly impacted by our ability to maintain or increase oil or gas production through exploration and development activities.
 
Horizontal well development within the field is still relatively new and the geology is enabling operators to utilize higher density drilling within designated spacing units.  We are currently spacing our well bores to allow for up to 24 wells per 640 acre section 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, utilizing different amounts of proppant per hydraulic fractionation stage, employing different completion fluids and comparing “plug-and-perf” completions to “sliding-sleeve” completions in order to determine the most cost efficient well designs for the formations we are developing.

The recent decline in commodity prices has led to a corresponding decline in service costs, which directly relate to our drilling and completion costs.  On average, we have been able to reduce drilling and completion costs by approximately 25% over the first two quarters of fiscal 2015, due to a combination of optimizing well designs, moving to day-rate drilling, lower contract rates for drilling rigs, and lower completion costs.  This focus on cost reduction has supported well-level economics in spite of the severe price drop in crude oil and natural gas.  We believe at current drilling and completion cost levels and with current prevailing commodity prices, we can achieve reasonable well-level rates of return going forward.

45

Our production continues to be adversely impacted by high natural gas gathering line pressures, especially in the northern area of the Wattenberg Field.  This problem 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 gathering pipelines.  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.  

We are continuing our efforts to mitigate the adverse impact of high line pressures.  Where it is cost effective, we install wellhead compression to enhance our ability to inject gas into the gathering system.  Additionally, along with our midstream service provider, we are evaluating and in some instances installing larger gathering pipelines to our operated pads.

Over the longer term, midstream companies that operate the gas gathering pipelines have continued to make significant capital investments to increase system capacity.  As publicly disclosed, DCP Midstream Partners (“DCP”), the principal third-party provider that we employ to gather production from our wells, brought online a 160 MMcf/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.  DCP has also announced the building of the Lucerne II plant, northeast of Greeley in Weld County, with a maximum capacity of approximately 200 MMcf/d.  The Lucerne II plant is estimated to begin operations in May of 2015.  We believe this additional processing capacity will help lower line pressures in the northern area of the Wattenberg Field where we have several operated pads and anticipate further completion activity in the near future.  However, we do not know if this new capacity will completely mitigate the problem and does not help alleviate increasing line pressures in the west and/or south portions of the field.

The success of horizontal drilling techniques in the D-J Basin has also significantly increased quantities of oil produced in the region.  Local crude oil refineries do not have sufficient capacity to process all of the oil available and the imbalance of supply and demand is increasing the transportation of oil out of the D-J Basin via pipeline and rail.  This imbalance has also impacted the prices paid by oil purchasers in the basin, leading to generally wider differentials between the wellhead prices we realize and the crude oil prices posted on NYMEX.  However, as commodity prices have contracted and transportation options have increased, we anticipate price differentials may narrow in the coming quarters and we continue to explore various alternatives with other oil purchasers to ensure we realize the highest net prices available.  In all cases, we believe we will continue to have sufficient take-away capacity for all of our oil production.  Further details regarding posted prices and average realized prices are discussed in the section entitled “Market Conditions,” presented in this Item 2. 
 
Other than the foregoing, we do not know of any trends, events or uncertainties that will have had or are reasonably expected to have a material impact on our sales, revenues, expenses or liquidity and capital resources.

46


CRITICAL ACCOUNTING POLICIES

We prepare our financial statements and the accompanying notes in conformity with US GAAP, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection, and disclosure of each of the critical accounting policies.

During the second quarter ended February 28, 2015, there was a significant decline in the price of oil.  The commodity price decline continued into the third quarter, and there are no indications that it will reverse in the near future.  The declines are the most significant price volatility experienced during the last three years.  Accordingly, the description of certain critical accounting policies was updated to reflect the potential impact of these changing commodity prices on our financial statements.  The goal of this disclosure is to highlight some areas where increased price volatility and updated economic assumptions will interact with existing accounting policies.  Please note that there have been no changes in the underlying accounting policies since August 31, 2014, our fiscal year end.  

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

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

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

47

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

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

Companies that use full cost accounting perform a ceiling test each quarter.  The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10.  The test compares capitalized costs in the full cost pool, less accumulated DDA and related deferred income taxes, to a calculated ceiling amount.  The calculated ceiling amount is equal to the sum of the present value (using a 10% discount factor) of future net revenues, plus unproved property costs and pre-production costs not being amortized, plus the lower of cost or estimated fair value of unproved properties included in costs being amortized, less related income tax effects.  If the net capitalized costs exceed the ceiling amount, the excess must be charged to expense in recognition of the impairment.

Under the ceiling test, the estimate of future revenues is calculated using a current price (as defined in the SEC rules to include data points over a trailing 12 month period).  Thus, the full impact of a sudden price decline is not recognized immediately.  We anticipate that the price declines during the second quarter will have a significant negative impact on the ceiling test calculation for future quarters.  Furthermore, as prices decline, the economic performance of certain properties in the reserve estimate may deteriorate to the point that they are removed from the proved reserve category, thus reducing the quantity and value of proved reserves.  Again, the use of a twelve month average will tend to spread the impact of the change on the financial statements over several reporting periods.

The ceiling test performed for the quarter ended February 28, 2015, did not result in impairment recognition.  However, a decline of 7% or more in the value of the ceiling limitation would have resulted in an impairment.

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

Commodity Derivative Instruments: Our use of commodity derivative instruments helps us mitigate the cash flow impact of short-term commodity price volatility.  We typically enter into contracts covering a portion of our expected oil and gas production over 24 months.  We record realized gains and losses for contracts that settle during the reporting periods.  Contracts either settle at their scheduled maturity date or settle prior to their scheduled maturity date as a result of our decision to early liquidate an open position.  Realized gains and losses represent cash transactions.  Under our hedge strategy we typically receive cash payments when the posted price for the settlement period is less than the hedge price.  Conversely, when the posted price for the settlement period is greater than the hedge price, we typically disburse a cash payment to the counterparty.  Thus, realized gains and losses tend to offset increases or decreases in our revenue stream that are caused by changing prices.
48


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

With the current downward trend in commodity prices, we expect to report reduced oil and gas revenues and to report partially offsetting realized gains in our hedge transactions.  During any reporting period in which the commodity prices decline, we expect to report unrealized gains on our open commodity derivative contracts.  However, during any period in which the downward trend reverses, we expect to report unrealized losses.  Looking forward, we expect current contracts to be settled or liquidated over the next 24 months.  We expect to periodically enter into new hedges at then current prices.  Newer hedges at lower prices will reduce the amount of future cash flow risk mitigation provided by the contracts.

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.
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Item 3.  Quantitative and Qualitative Disclosures About Market Risks

Commodity Price Risk - Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas.  The volatility of oil prices affects our results to a greater degree than the volatility of gas prices, as approximately 79% of our revenue during the first six months of fiscal 2015 was from the sale of oil.  A $10 per barrel change in our realized oil price would have resulted in a $4.1 million change in revenues during our second fiscal quarter, while a $0.50 per mcf change in our realized gas price would have resulted in a $0.8 million change in our natural gas revenues in our second fiscal quarter.

During the last few months, the price of oil has declined significantly.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil, the global supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, the strength of the U.S. dollar compared to other currencies, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources.

We attempt to mitigate fluctuations in short-term cash flow resulting from changes in commodity prices by entering into derivative positions on a portion of our expected oil and gas production.  We use derivative contracts to cover no less than 45% and no more than 85% of expected proved developed producing production as projected in our semi-annual reserve report, generally over a period of two years.  We do not enter into derivative contracts for speculative or trading purposes.  As of February 28, 2015, we had open crude oil derivatives in a net asset position with a fair value of $17.2 million.  A hypothetical upward shift of 10% in the NYMEX forward curve of crude oil and natural gas prices would reduce the fair value of our position by $4.7 million.  A hypothetical downward shift of 10% in the NYMEX forward curve of crude oil and natural gas prices would increase the fair value of our position by $4.8 million.

Interest Rate Risk - At February 28, 2015, we had debt outstanding under our bank credit facility totaling $146.0 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”) plus an applicable margin.  At February, 2015, we were incurring interest at a rate of 2.5%.  We are exposed to interest rate risk on the bank credit facility if the variable reference rates increase.  A decrease in the variable interest rates would not have a significant impact on us, as the bank credit facility has a minimum interest rate of 2.5%.  If interest rates increase, our monthly interest payments would increase and our available cash flow would decrease.  We estimate that if market interest rates increase by 1% to an annual percentage rate of 3.5%, our interest payments would increase by approximately $1.5 million per year.

Under current market conditions, we do not anticipate significant changes in prevailing interest rates for the next year and we have not undertaken any activities to mitigate potential interest rate risk.  There was no material change in interest rate risk during the quarter ended February 28, 2015.

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

Our exposure to counterparty risk has increased during the last few months as the amounts due to us from counterparties has increased.

Item 4.  Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our 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-Q (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 our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II

Item 1A. Risk Factors.

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we will receive for our oil and natural gas will significantly affect our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. For example, over the past four years, the NYMEX—WTI oil price ranged from a high of $113.93 per Bbl to a recent low of $46.39 per Bbl, while the NYMEX—Henry Hub natural gas price ranged from a high of $6.01 per MMBtu to a low of $1.91 per MMBtu. These markets will likely continue to be volatile in the future. The prices we will receive for our production, and the levels of our production, will depend on numerous factors beyond our control. These factors include the following:
 
 
 
worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;
 
 
 
the actions of the Organization of Petroleum Exporting Countries, or OPEC;
 
 
 
the price and quantity of imports of foreign oil and natural gas;
 
 
 
political conditions in or hostilities in oil-producing and natural gas-producing regions and related sanctions, including current conflicts in the Middle East and conditions in Africa, South America, Russia and Ukraine;
 
 
 
the level of global oil and domestic natural gas exploration and production;
 
 
 
the level of global oil and domestic natural gas inventories;
 
 
 
prevailing prices on local oil and natural gas price indexes in the areas in which we operate;
 
 
 
localized supply and demand fundamentals and gathering, processing and transportation availability;
 
 
 
weather conditions and natural disasters;
 
 
 
domestic and foreign governmental regulations;
 
 
 
authorization of exports from the United States of liquefied natural gas or oil;
 
 
 
speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
 
 
 
price and availability of competitors’ supplies of oil and natural gas;
 
 
 
technological advances affecting energy consumption; and
 
 
 
the price and availability of alternative fuels.
 
 
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Lower oil and natural gas prices will reduce our cash flows and our borrowing ability. Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms in the future, which may in turn limit our ability to develop our exploration and production plans. Lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and may cause the value of our estimated proved reserves at future reporting dates to decline compared to our estimated proved reserves at August 31, 2014, our most recent fiscal year end. Specifically, a decline in the value of our reserves may reduce the borrowing base available to us under the Facility, and, should the value of our reserves decline below our recorded costs as measured by the ceiling test, we would be required to record a non-cash impairment charge in our financial statements. Additionally, an extended decline in commodity prices could lead us to reduce our capital expenditure budget and scale back our drilling and development plans.

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.
 
Item 6.  Exhibits

a.  Exhibits

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

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

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

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

101 INSXBRL Instance Document

101 SCHXBRL Schema Document

101 CALXBRL Calculation Linkbase Document

101 DEFXBRL Definition Linkbase Document.

101 LABXBRL Label Linkbase Document

101 PREXBRL
Presentation Linkbase Document
 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 
SYNERGY RESOURCES CORPORATION
 
       
Date:  April 9, 2015
By:
/s/ Ed Holloway  
    Ed Holloway, Co-Chief Executive Officer  
    (Principal Executive Officer)  
       

 
 
 
       
Date:  April 9, 2015
By:
/s/ William Scaff, Jr.  
    William Scaff, Jr., Co-Chief Executive Officer  
   
(Principal Executive Officer)
 
       
 
 
 
 
       
Date:  April 9, 2015
By:
/s/ Frank L. Jennings  
    Frank L. Jennings, Chief Financial Officer  
   
(Principal Financial Officer)
 
       

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