10-Q 1 syrg_10q-053115.htm FORM 10-Q FOR THE PERIOD ENDED 5/31/2015
 


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 May 31, 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: 105,025,453 shares outstanding as of July 6, 2015.

 
SYNERGY RESOURCES CORPORATION

Index

 
Page
   
     
 
     
 
       
 
       
 
       
 
       
       
     
       
   
       
Item 1. Legal Proceedings 54
 
 
       
       

 
1

 
SYNERGY RESOURCES CORPORATION
BALANCE SHEETS
(in thousands, except share data)
 
 
ASSETS
 
May 31,
2015
   
August 31,
2014
 
     
(unaudited)
     
Current assets:
       
Cash and cash equivalents
 
$
190,205
   
$
34,753
 
Accounts receivable:
               
Oil and gas sales
   
14,781
     
16,974
 
Joint interest billing and other
   
18,487
     
15,398
 
Commodity derivative
   
4,268
     
365
 
Other current assets
   
1,311
     
750
 
Total current assets
   
229,052
     
68,240
 
                 
Oil and gas properties, full cost method:
               
Proved properties, net
   
407,576
     
275,018
 
Unproved properties and properties under development, not being amortized
   
170,639
     
95,278
 
Other property and equipment, net
   
4,811
     
9,104
 
Property and equipment, net
   
583,026
     
379,400
 
                 
Commodity derivative
   
4,615
     
54
 
Other assets
   
2,767
     
848
 
                 
Total assets
 
$
819,460
   
$
448,542
 
                 
LIABILITIES AND SHAREHOLDERS' EQUITY
               
                 
Current liabilities:
               
Trade accounts payable
 
$
1,027
   
$
1,747
 
Well costs payable
   
26,491
     
71,849
 
Revenue payable
   
18,786
     
14,487
 
Production taxes payable
   
17,120
     
14,376
 
Other accrued expenses
   
457
     
817
 
Commodity derivative
   
-
     
302
 
Total current liabilities
   
63,881
     
103,578
 
                 
Revolving credit facility
   
141,000
     
37,000
 
Commodity derivative
   
-
     
307
 
Deferred tax liability, net
   
34,670
     
21,437
 
Asset retirement obligations
   
7,772
     
4,730
 
Total liabilities
   
247,323
     
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:
               
105,025,453 and 77,999,082 shares issued and outstanding, respectively
   
105
     
78
 
Additional paid-in capital
   
533,091
     
265,793
 
Retained earnings
   
38,941
     
15,619
 
Total shareholders' equity
   
572,137
     
281,490
 
                 
Total liabilities and shareholders' equity
 
$
819,460
   
$
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
May 31,
   
Nine Months Ended
May 31,
 
   
2015
   
2014
   
2015
   
2014
 
                 
Oil and gas revenues
 
$
26,033
   
$
25,672
   
$
92,284
   
$
67,966
 
                                 
Expenses
                               
Lease operating expenses
   
3,570
     
2,303
     
10,300
     
5,382
 
Production taxes
   
2,249
     
2,376
     
8,570
     
6,647
 
Depletion, depreciation
                               
   amortization and accretion
   
16,397
     
7,796
     
48,357
     
21,106
 
Full cost ceiling impairment
   
3,000
     
-
     
3,000
     
-
 
General and administrative
   
3,886
     
1,938
     
12,075
     
6,876
 
Total expenses
   
29,102
     
14,413
     
82,302
     
40,011
 
                                 
Operating income (loss)
   
(3,069
)
   
11,259
     
9,982
     
27,955
 
                                 
Other income (expense)
                               
Commodity derivative realized gain (loss)
   
7,136
     
(826
)
   
20,935
     
(1,415
)
Commodity derivative unrealized (loss) gain
   
(8,298
)
   
(179
)
   
5,578
     
652
 
Interest expense
   
(116
)
   
-
     
(116
)
   
-
 
Interest income
   
33
     
22
     
61
     
70
 
Total other income (expense)
   
(1,245
)
   
(983
)
   
26,458
     
(693
)
                                 
Income (loss) before income taxes
   
(4,314
)
   
10,276
     
36,440
     
27,262
 
                                 
Income tax provision (benefit)
   
(1,833
)
   
3,116
     
13,118
     
8,841
 
Net income (loss)
 
$
(2,481
)
 
$
7,160
   
$
23,322
   
$
18,421
 
                                 
Net income (loss) per common share:
                               
Basic
 
$
(0.02
)
 
$
0.09
   
$
0.26
   
$
0.24
 
Diluted
 
$
(0.02
)
 
$
0.09
   
$
0.25
   
$
0.24
 
                                 
Weighted-average shares outstanding:
                               
Basic
   
104,234,519
     
77,176,420
     
91,105,035
     
75,689,903
 
Diluted
   
104,234,519
     
79,008,619
     
91,804,253
     
77,299,456
 

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


 
SYNERGY RESOURCES CORPORATION
 STATEMENTS OF CASH FLOWS
 (unaudited, in thousands)
 
   
Nine Months Ended
May 31,
 
   
2015
   
2014
 
Cash flows from operating activities:
       
Net income
 
$
23,322
   
$
18,421
 
Adjustments to reconcile net income to net
               
cash provided by operating activities:
               
Depletion, depreciation and amortization
   
48,357
     
21,106
 
Full cost ceiling impairment
   
3,000
     
-
 
Provision for deferred taxes
   
13,118
     
8,841
 
Stock-based compensation
   
3,330
     
1,569
 
Valuation increase in commodity derivatives
   
(5,578
)
   
(652
)
Changes in operating assets and liabilities:
               
Accounts receivable
               
    Oil and gas sales
   
2,193
     
(7,505
)
    Joint interest billing and other
   
(3,089
)
   
(4,037
)
Unamortized premiums paid for derivatives
   
(3,494
)
   
-
 
Inventory
   
-
     
(211
)
Accounts payable
               
    Trade
   
(720
)
   
188
 
    Revenue
   
4,299
     
3,448
 
    Production taxes
   
2,744
     
4,707
 
    Accrued expenses
   
(360
)
   
49
 
Other
   
(180
)
   
821
 
Total adjustments
   
63,620
     
28,324
 
Net cash provided by operating activities
   
86,942
     
46,745
 
                 
Cash flows from investing activities:
               
Acquisition of property and equipment
   
(241,903
)
   
(112,155
)
Short-term investments
   
-
     
60,018
 
Net proceeds from sales of oil and gas properties
   
3,696
     
704
 
Net cash used in investing activities
   
(238,207
)
   
(51,433
)
                 
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
     
33,380
 
Gross proceeds from revolving credit facility
   
104,000
     
-
 
Finance fee for revolving credit facility
   
(2,300
)
   
-
 
Shares withheld for payment of employee payroll taxes
   
(1,195
)
   
(176
)
Net cash provided by financing activities
   
306,717
     
33,204
 
                 
Net increase in cash and cash equivalents
   
155,452
     
28,516
 
                 
Cash and cash equivalents at beginning of period
   
34,753
     
19,463
 
                 
Cash and cash equivalents at end of period
 
$
190,205
   
$
47,979
 
                 
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
May 31, 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 goodwill, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain.  Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.  Estimates and assumptions are revised periodically and the effects of revisions are reflected in the financial statements in the period 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.

Properties under development represent the costs associated with the development of oil and gas properties that have yet to be proved as of May 31, 2015.  Since the properties were not classified as proved as of May 31, 2015, they were classified within unproved oil and gas properties and were withheld from the depletion calculation and ceiling test.  The costs for these properties will be transferred into proved properties when they are proved 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.  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.

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
May 31,
   
Nine Months Ended
May 31,
 
   
2015
   
2014
   
2015
   
2014
 
Capitalized Overhead
 
$
486
   
$
300
   
$
1,623
   
$
921
 
 
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.
 
7

 

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

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 nine month periods ended May 31, 2015 and 2014, certain of the Company's customers represented 10% or more of its oil and gas revenue ("major customers").  For the three months ended May 31, 2015, the Company had three major customers, which represented 58%, 15% and 10% of its revenue during the period. For the three months ended May 31, 2014, the Company had four major customers, which represented 45%, 13%, 12% and 12% of its revenue during the period. For the nine months ended May 31, 2015, the Company had two major customers, which represented 62% and 11% of its revenue during the period. For the nine months ended May 31, 2014, the Company had three major customers, which represented 45%, 15% and 10% of its 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.

Customers 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
May 31, 2015
 
As of
August 31, 2014
Company A
29%
 
37%
Company B
12%
 
(1)

(1) Balance was less than 10% of total receivable balances during the period.
 
 
8

 
 

 
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.

No significant uncertain tax positions were identified as of any date on or before May 31, 2015.  The Company's policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of May 31, 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. 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
May 31,
   
Nine Months Ended
May 31,
 
   
2015
   
2014
   
2015
   
2014
 
                 
Weighted-average shares outstanding-basic
   
104,234,519
     
77,176,420
     
91,105,035
     
75,689,903
 
Potentially dilutive common shares from:
                               
Stock options
 
Anti-dilutive
     
515,530
     
699,218
     
432,170
 
Warrants
   
-
     
1,316,669
     
-
     
1,177,383
 
     
-
     
1,832,199
     
699,218
     
1,609,553
 
Weighted-average shares outstanding - diluted
   
104,234,519
     
79,008,619
     
91,804,253
     
77,299,456
 
 
As a result of the net loss reported for the three months ended May 31, 2015, the calculation of basic and diluted Earnings per Share used the same number of weighted-average common shares outstanding in the denominator, as the inclusion of common share equivalents was anti-dilutive.

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
May 31,
   
Nine Months Ended
May 31,
 
   
2015
   
2014
   
2015
   
2014
 
                 
Employee stock options
   
4,101,500
     
478,000
     
2,710,500
     
503,000
 
 
Recent Accounting Pronouncements:    We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new pronouncements on US GAAP and the impact on us.

In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2015-03, "Simplifying the Presentation of Debt Issuance Costs" ("ASU 2015-03"), which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. For public business entities, the ASU is effective for financial statements issued for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years.  Entities should apply the new guidance on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance.  Upon transition, entities are required to comply with the applicable disclosures for a change in an accounting principle.  The Company is currently evaluating the impact of the adoption of this standard on its consolidated financial statements.
 
10

 
 

 
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.

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 and Full Cost Ceiling Impairment

The capitalized costs related to the Company's oil and gas producing activities were as follows (in thousands):
 
   
As of
   
As of
 
   
May 31, 2015
   
August 31, 2014
 
Oil and gas properties, full cost method:
       
   Unproved properties, not subject to amortization:
       
      Lease acquisition and other costs
 
$
139,012
   
$
41,531
 
      Properties under development
   
31,627
     
53,747
 
         Subtotal
   
170,639
     
95,278
 
                 
   Proved producing and non-producing properties
   
513,677
     
329,926
 
         Total capitalized costs
   
684,316
     
425,204
 
      Less, accumulated depletion
   
(103,101
)
   
(54,908
)
      Less, full cost ceiling impairment
   
(3,000
)
   
-
 
           Oil and gas properties, net
   
578,215
     
370,296
 
                 
Land
   
4,478
     
3,898
 
Other property and equipment
   
867
     
5,961
 
Less, accumulated depreciation
   
(534
)
   
(755
)
            Other property and equipment, net
   
4,811
     
9,104
 
                 
Total property and equipment, net
 
$
583,026
   
$
379,400
 

The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value.

For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs.  Under the ceiling test, the value of the Company's reserves are calculated using the average of the published spot prices for West Texas Intermediate (WTI) oil (per barrel) as of the first day of each of the previous twelve months, as well as the average of the published spot prices for Henry Hub (per MMBtu) as of the first day of each of the previous twelve months, each adjusted by lease or field for quality, transportation fees and regional price differentials.  The ceiling test used realized prices of $64.26 per barrel and $4.14 per MMBtu.  The prices used at May 31, 2015, were approximately 16% lower than the prices used at February 28, 2015.

Using these prices, the Company's net capitalized costs of oil and natural gas properties exceeded the ceiling amount by $3.0 million at May 31, 2015, resulting in immediate recognition of a ceiling test impairment.

The Company also reviews the fair value of its unproved properties.  The reviews for the three months and nine months ended May 31, 2015 and 2014 indicated that estimated fair values of such assets exceeded carrying values, thus revealing no impairment in either period.

In addition, during the nine months ended May 31, 2015, certain amounts previously recorded were reclassified from one category to another without changing the total amounts recorded as property and equipment.  Specifically, costs associated with 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 to process flow-back water from oil and gas operations.  Similarly, accumulated depreciation associated with the disposal well was reclassified from accumulated depreciation to accumulated depletion.  The updated classification for the disposal well, related equipment, and accumulated depreciation did not require a change to previously reported depletion, depreciation, and amortization expense ("DDA").  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 nine months ended May 31, 2015 and 2014, the Company 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 $125.1 million, net of customary closing adjustments.  The purchase price was composed of $74.2 million in cash and $48.4 million in restricted common stock plus the assumption of certain liabilities.

The Bayswater acquisition encompassed 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 and 73 operated vertical wells as well as working interests in 11 non-operated vertical wells.  The working interests in the horizontal wells range from 6% to 40% while the working interests in the vertical wells range from 5% to 100%.

The following allocation of the purchase price is preliminary and includes significant use of estimates.  The fair values of the assets acquired and liabilities assumed are preliminary and are subject to revision as the Company continues to evaluate the fair value of this acquisition.  Accordingly, the allocation will change as additional information becomes available and is assessed and the impact of such changes may be material.  The following table summarizes the preliminary purchase price and preliminary estimated fair values of assets acquired and liabilities assumed (in thousands):
 
Purchase Price
 
December 15, 2014
 
Consideration Given
   
Cash
 
$
74,221
 
Synergy Resources Corp. Common Stock (1)
   
48,434
 
Liabilities assumed, including asset retirement obligations
   
2,467
 
Total consideration given
 
$
125,122
 
         
Allocation of Purchase Price
       
Proved oil and gas properties (2)
 
$
51,400
 
Unproved oil and gas properties
   
73,722
 
Total fair value of oil and gas properties acquired
 
$
125,122
 
 
(1) The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of December 15, 2014 (4,648,136 shares at $10.42 per share).

(2) Proved oil and gas properties were measured primarily using an income approach.  The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement.  The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of 10%, and assumptions on the timing and amount of future development and operating costs.

13

 
 

 
The following table presents the pro forma combined results of operations for the three and nine months ended May 31, 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 cash, additional depreciation expense, costs directly attributable to the acquisition and operating costs incurred as a result of the assets acquired.  The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired.  The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.
 
   
Three Months Ended
May 31,
   
Nine Months ended
May 31,
 
   
2015
   
2014
   
2015
   
2014
 
                 
Oil and Gas Revenues
 
$
26,033
   
$
26,766
   
$
99,157
   
$
71,550
 
Net income
 
$
(2,481
)
 
$
6,889
   
$
25,102
   
$
17,997
 
                                 
Earnings per common share
                               
  Basic
 
$
(0.02
)
 
$
0.08
   
$
0.26
   
$
0.22
 
  Diluted
 
$
(0.02
)
 
$
0.08
   
$
0.26
   
$
0.22
 
 
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 the Company's common stock valued at $2.9 million and cash consideration of approximately $15.9 million.  No material transaction costs were incurred in connection with this acquisition.
 
 
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 the Company's common stock valued at $5.2 million.  Following the acquisition of the Apollo Operating Assets, the Company acquired all other remaining interests in the Disposal Well (the "Related Interests") through several transactions with the individual owners of such interests. The Company acquired the Related Interests for approximately $3.7 million in cash consideration and 20,626 shares of the Company's common stock, valued at $0.2 million.  No material transaction costs were incurred in connection with this acquisition.
 
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.
 
16

 

 
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.

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
May 31,
   
Nine Months ended
May 31,
 
   
2015
   
2014
   
2015
   
2014
 
Depletion
 
$
16,200
   
$
7,569
   
$
47,849
   
$
20,550
 
Depreciation and amortization
   
197
     
227
     
508
     
556
 
Total DDA Expense
 
$
16,397
   
$
7,796
   
$
48,357
   
$
21,106
 
 
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 May 31, 2015, production of 738,357 barrels of oil equivalent ("BOE") represented 1.7% of the estimated total proved reserves.  For the nine months ended May 31, 2015, production of 2,188,737 BOE represented 4.9% of the estimated total proved reserves.
 
 
17


 

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 Nine Months Ended
May 31,
   
2015
 
2014
Inflation rate
 
3.9%
 
 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%

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
   
744
 
  Liabilities assumed
   
1,913
 
  Accretion expense
   
385
 
Asset retirement obligations, May 31, 2015
 
$
7,772
 
 

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.

On June 2, 2015, the LOC was further amended in connection with the regularly scheduled semi-annual redetermination.  The borrowing base was reduced to $175 million and the covenant requiring maintenance of a minimum current ratio was replaced with a covenant requiring the maintenance of a minimum liquidity amount of $25,000,000.  On June 11, 2015, the Company reduced its outstanding borrowings under the LOC to $87 million.
 
18

 

 
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 nine months ended May 31, 2015 was 2.5%.

Certain of the Company's assets, including substantially all of the 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.  As of July 1, 2015, based upon a borrowing base of $175 million and an outstanding principal balance of $87 million, the unused borrowing base available for future borrowing totaled approximately $88 million.  The next semi-annual redetermination is scheduled for November 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.

Furthermore, the LOC requires the Company to maintain certain financial and liquidity ratio compliance covenants.  Under the requirements, as most recently amended, the Company, on a quarterly basis, must (a) not, at any time, permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0; and (b) maintain a minimum liquidity, defined as cash and cash equivalents plus the unused availability under the total commitments, of not less than $25 million.  As of May 31, 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 May 31, 2015 are summarized below:

Settlement Period
Derivative
Instrument
 
Average Volumes
(BBls/MMBtu
per month)
   
Average
Fixed
Price
   

Floor
Price
   
Ceiling
Price
 
Crude Oil - NYMEX WTI
                 
Jun 1, 2015 - Jun 30, 2015
Collar
   
2,500
     
-
   
$
80.00
   
$
95.75
 
Jun 1, 2015 - Dec 31, 2015
Put
   
40,000
     
-
   
$
50.00
     
-
 
Jun 1, 2015 - Oct 31, 2015
Put
   
5,200
     
-
   
$
50.00
     
-
 
Jun 1, 2015 - Dec 31, 2015
Put
   
10,000
     
-
   
$
55.00
     
-
 
                                   
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 - Apr 30, 2017
Put
   
20,000
     
-
   
$
50.00
     
-
 
May 1, 2017 - Aug 31, 2017
Put
   
20,000
     
-
   
$
55.00
      -  
                                   
Natural Gas - NYMEX Henry Hub
                               
Jun 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
                               
Jun 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
 
May 1 2017 - Aug 31, 2017
Collar
   
110,000
      -    
$
2.50
   
$
3.05
 


20




Offsetting of Derivative Assets and Liabilities

As of May 31, 2015 and 2014, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions.  In general, the terms of the Company's agreements provide for offsetting of amounts payable or receivable between 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.

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 May 31, 2015
 
Underlying Commodity
Balance Sheet Location
 
Gross Amounts of Recognized Assets and Liabilities
   
Gross Amounts Offset in the Balance Sheet
   
Net Amounts of Assets and Liabilities Presented in the Balance Sheet
 
Derivative contracts
Current assets
 
$
4,487
   
$
(219
)
 
$
4,268
 
Derivative contracts
Noncurrent assets
 
$
4,994
   
$
(379
)
 
$
4,615
 
Derivative contracts
Current liabilities
 
$
219
   
$
(219
)
 
$
-
 
Derivative contracts
Noncurrent liabilities
 
$
379
   
$
(379
)
 
$
-
 
 
 
                       
 
 
 
 
   
   
 
 
  
 
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
May 31,
   
Nine Months ended
May 31,
 
   
2015
   
2014
   
2015
   
2014
 
Realized gain (loss) on commodity derivatives
 
$
7,136
   
$
(826
)
 
$
20,935
   
$
(1,415
)
Unrealized gain (loss) on commodity derivatives
   
(8,298
)
   
(179
)
   
5,578
     
652
 
Total gain (loss)
 
$
(1,162
)
 
$
(1,005
)
 
$
26,513
   
$
(763
)


21

 
 

 
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 third quarter of 2015, the Company liquidated oil hedges with an average price of $80.61 and covering 188,500 barrels and received cash settlements of approximately $5.0 million.  The following table summarizes hedge realized gains and losses during the periods presented (in thousands):
 
   
Three Months Ended
May 31,
   
Nine Months ended
May 31,
 
   
2015
   
2014
   
2015
   
2014
 
Monthly settlement
 
$
2,100
   
$
(826
)
 
$
9,618
   
$
(1,415
)
Early liquidation
   
5,036
     
-
     
11,317
     
-
 
Total realized gain (loss)
 
$
7,136
   
$
(826
)
 
$
20,935
   
$
(1,415
)

Credit-Related Contingent Features

During the nine months ended May 31, 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 May 31, 2015 and August 31, 2014 by level within the fair value hierarchy (in thousands):
 
   
Fair Value Measurements at May 31, 2015 
 
   
Level 1
   
Level 2
   
Level 3
   
Total
 
Financial assets and liabilities:
               
    Commodity derivative asset
 
$
-
   
$
8,883
   
$
-
   
$
8,883
 
    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 the counterparty to be of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At May 31, 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
May 31,
   
Nine Months Ended
May 31,
 
 
 
2015
   
2014
   
2015
   
2014
 
Revolving credit facility
 
$
915
   
$
252
   
$
2,191
   
$
749
 
Amortization of debt issuance costs
   
252
     
118
     
607
     
312
 
Less, interest capitalized
   
(1,051
)
   
(370
)
   
(2,682
)
   
(1,061
)
Interest expense, net
 
$
116
   
$
-
   
$
116
   
$
-
 


10. Shareholders' Equity

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

   
As of May 31,
   
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
   
105,025,453
     
77,999,082
 

Stock Offering

During the nine months ended May 31, 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 nine months ended May 31, 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 nine months ended
May 31, 2015
 
Number of common shares issued for mineral property leases
   
995,672
 
Number of common shares issued for acquisitions
   
4,648,136
 
Total common shares issued
   
5,643,808
 
         
Average price per common share
 
$
10.45
 
Aggregate value of shares issued (in thousands)
 
$
58,968
 

24

 

 

Common stock warrants

During the nine months ended May 31, 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 nine month period ended May 31, 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, May 31, 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
May 31,
   
Nine Months Ended
May 31,
 
   
2015
   
2014
   
2015
   
2014
 
Stock options
 
$
715
   
$
445
   
$
1,792
   
$
1,312
 
Employee stock grants
   
686
     
257
     
1,538
     
257
 
   
$
1,401
   
$
702
   
$
3,330
   
$
1,569
 
 
 
25

 
 
 

 
During the three and nine months ended May 31, 2015 and 2014, the Company granted the following employee stock options:
 
   
Three Months Ended
May 31,
   
Nine Months Ended
May 31,
 
   
2015
   
2014
   
2015
   
2014
 
Number of options to purchase common shares
   
1,892,500
     
90,000
     
2,302,500
     
353,000
 
Weighted-average exercise price
 
$
11.57
   
$
10.51
   
$
11.64
   
$
9.92
 
Term (in years)
   
10.0
     
10.0
     
10.0
     
10.0
 
Vesting Period (in years)
   
5
     
5
     
5
     
5
 
Fair Value (in thousands)
 
$
10,500
   
$
633
   
$
12,940
   
$
2,362
 
 
The assumptions used in valuing stock options granted during each of the nine months presented were as follows:

   
Nine Months Ended
May 31,
 
   
2015
   
2014
 
Expected term
 
6.5 years
   
6.5 years
 
Expected volatility
   
47
%
   
73
%
Risk free rate
   
1.77
%
   
1.97% - 2.02
%
Expected dividend yield
   
0.00
%
   
0.00
%
Forfeiture rate
   
3.3
%
   
0.00
%

The following table summarizes activity for stock options for the nine months ended May 31, 2015:

   
Number
of Shares
   
Weighted-Average
Exercise Price
 
Outstanding, August 31, 2014
   
2,167,000
   
$
5.94
 
Granted
   
2,302,500
   
$
11.64
 
Exercised
   
(258,000
)
 
$
3.81
 
Forfeited
   
(110,000
)
  $
(4.97
)
Outstanding, May 31, 2015
   
4,101,500
   
$
9.30
 

The following table summarizes information about issued and outstanding stock options as of May 31, 2015:

   
Outstanding
Options
   
Vested
Options
 
Number of shares
   
4,101,500
     
888,100
 
Weighted-average remaining contractual life
 
   8.8 years
   
   6.9 years
 
Weighted-average exercise price
 
 
$9.30
   
 
$5.34
 
Aggregate intrinsic value (in thousands)
 
 
$9,547
   
 
$5,480
 

The estimated unrecognized compensation cost from unvested stock options as of May 31, 2015, which will be recognized ratably over the remaining vesting phase, is as follows:

   
Unvested Options at May 31, 2015
Unrecognized compensation expense (in thousands)
 
$15,038
Remaining vesting phase
 
4.3 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
May 31,
   
Nine Months Ended
May 31,
 
   
2015
   
2014
   
2015
   
2014
 
Rent expense
 
$
45
   
$
45
   
$
135
   
$
135
 

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
May 31,
   
Nine Months Ended
May 31,
 
   
2015
   
2014
   
2015
   
2014
 
Total Royalty Payments
 
$
14
   
$
58
   
$
95
   
$
191
 

13. Other Commitments and Contingencies

From time to time, the Company is a party to various commercial and regulatory claims, pending or threatened legal action, and other proceedings that arise in the ordinary course of business.  It is the opinion of management that none of the current matters of contention are reasonably likely to have a material adverse impact on its business, financial position, results of operations or cash flows.

During the nine months ended May 31, 2015, the Company modified its contract drilling obligations with Ensign United States Drilling, Inc.  Two of the three rigs under contract fulfilled the terms of their contracts and 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 May 31, 2015, the Company was participating in the drilling and completion of 12 gross (0.7 net) new horizontal wells.  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 May 31, 2015 financial statements include recorded costs of $3.6 million for these wells.
 
 
 
27

 
 

 
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 nine months ended May 31, 2015 and 2014 (in thousands):
 
   
Nine Months Ended
 
   
May 31,
 
   
2015
   
2014
 
Supplemental cash flow information:
       
    Interest paid
 
$
2,200
   
$
750
 
    Income taxes paid
   
110
     
-
 
                 
Non-cash investing and financing activities:
               
Accrued well costs
 
$
26,491
   
$
47,489
 
Assets acquired in exchange for common stock
   
58,968
     
11,185
 
Asset retirement costs and obligations
   
2,657
     
1,367
 

 
15. Subsequent Events

Subsequent to May 31, 2015, the Company repaid $54 million in outstanding borrowings, bringing the total outstanding principal balance on its LOC from $141 million at May 31, 2015 to $87 million at July 1, 2015.

28


 
 
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 May 31, 2015, and the results of our operations for the three and nine months ended May 31, 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 May 31, 2015, we hold approximately 452,000 gross acres and 345,000 net acres under lease.   We currently hold approximately 89,000 net acres in the "Greater Wattenberg Area."  This position consists of approximately 35,000 net acres in the "core Wattenberg Area" and 54,000 net acres in what we call the "North East Extension Area."  In addition, we hold approximately 185,000 net acres in Southwest Nebraska, a conventional oil-prone prospect, and approximately 65,000 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 May 31, 2015, we have completed, acquired, or participated in 558 gross (385 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.
 
29

 

 
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
 
 
344
     
301
     
74
     
22
     
418
     
323
 
                                             
Horizontal Wells
 
Operated Wells
   
Non- Operated Wells
   
Totals
 
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
 
52
     
50
     
88
     
12
     
140
     
62
 
 
In addition to the producing wells summarized in the preceding table, as of May 31, 2015, we were the operator of 28 wells in progress and we were participating as a non-operating working interest owner in 12 wells in progress.

During the first nine months of fiscal 2015, crude oil prices have declined by approximately 37%.  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  our 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."
 
30

 

 
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 nine month periods ended May 31, 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 February 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."

Significant Developments
 
Impairment of full cost pool

Each quarter, we perform a ceiling test as prescribed by SEC regulations for entities following the full cost method of accounting.  This test determines a limit on the book value of oil and gas properties using a formula to estimate future net cash flows from oil and gas reserves.  This formula is dependent on several factors and assumes future oil and natural gas prices to be equal to an unweighted arithmetic average of oil and natural gas prices derived from each the 12 months prior to the reporting period.  As of May 31, 2015, this calculation indicated that the ceiling amount had declined, largely from the recent decline in oil and natural gas prices.  Since the ceiling amount was $3.0 million less than the net book value of oil and gas properties, we immediately recorded a ceiling test impairment.  This full cost ceiling impairment is recognized as a charge to earnings and may not be reversed in future periods, even if oil and natural gas prices subsequently increase.
 
Because the ceiling calculation requires rolling twelve month average commodity prices, the effect of lower quarter-over-quarter prices in 2015 compared to 2014 will be a lower ceiling amount each quarter.  This will result in ongoing impairments until prices stabilize or improve over a twelve month period.  At May 31, 2015, our ceiling test formula was calculated based upon SEC pricing of $64.26 per barrel and $4.14 per MMBtu.  Current pricing trends indicate that the formula for August 31, 2015, will be based upon SEC pricing that is approximately 15% less.  The decline in SEC pricing will likely result in a ceiling test impairment in the fourth quarter.
 
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 $74.2 million in cash and $48.4 million in stock plus the assumption of certain liabilities.

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.  

While we do not have any drilling commitments relative to the properties acquired from Bayswater, 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.

For accounting purposes, the Bayswater acquisition was treated as a business combination and the assets acquired will be recorded at fair value.  We expect to complete our evaluation of fair value during our fourth fiscal quarter.  In these interim financial statements for May 31, 2015, we recorded our preliminary estimates.  Final amounts may vary from the preliminary estimates.
 
Fifth and Sixth Amendments to Revolving Credit Facility ("LOC") on December 15, 2014 and June 2, 2015, respectively

On December 15, 2014, we closed on the Fifth Amendment to Amended and Restated Credit Agreement ("Fifth Amendment").  The terms of the Fifth Amendment included an expansion of the bank syndicate to eight members,  an increase in the loan commitment from $300 million to $500 million, and an increase in our borrowing base from $110 million to $230 million.  On June 2, 2015, we closed on the Sixth Amendment in connection with the regular semi-annual redetermination.  The Sixth Amendment provides for a borrowing base of $175 million.  The facility continues to bear a minimum interest rate on borrowings of 2.5%, with the effective rate varying with utilization, and expires on December 15, 2019.

Amounts borrowed 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. 
 
31

 
 
Completion of Public Stock Offering on February 2, 2015

During our second fiscal quarter, we completed a public offering of 18,613,952 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to the public of $10.75 per share.  On February 2, 2015, we received net proceeds of approximately $190.8 million after deducting underwriting discounts, commissions and other offering expenses.  We intend 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 and May 22, 2015

On February 12, 2015, we agreed with Vecta Oil & Gas, Ltd. ("Vecta") to amend our Joint Exploration Agreement dated March 1, 2013.  Under the amendment, Vecta conveyed to us assignments for an undivided 30% working interest in the DJ Basin Greenhorn Area of Mutual Interest (AMI) covering approximately 13,530 net acres.  In consideration, we agreed to pay Vecta the equivalent of $250 per net mineral acre.  Total consideration of $3.4 million was paid in the form of 287,642 restricted shares of our common stock based on a per share price of $11.76.  On May 22, 2015, we agreed to purchase the 35% working interest in the DJ Basin Greenhorn AMI owned by Vecta's affiliate, Foreland Investments LP (Foreland).  The consideration for 15,789 net acres conveyed by Foreland was $250 per net mineral acre.  Total consideration of $3.95 million was paid in the form of 323,745 restricted shares of our common stock based on a per share price of $12.19.  Successfully closing both transactions provided us with a 100% working interest in the DJ Basin Greenhorn AMI of approximately 56,000 net acres in the NE Wattenberg Extension Area.

Early Liquidation of In-The-Money Commodity Contracts

During the three and nine months ended May 31, 2015, we liquidated a portion of our deep in-the-money commodity contracts and purchased crude oil put contracts with $50/bbl and $55/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 maintaining a hedge on a greater portion of our expected future production.  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 three 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 May 31, 2015, we have no plans to curtail any activities.  However, should commodity prices weaken, our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent.    If management believes the well-level internal rate of return will be at or below our weighted-average cost of capital, we can choose to delay completions and/or forego drilling altogether.
 
 
32

 

 
Drilling Activity

During our fiscal third quarter ended May 31, 2015, we completed drilling operations on our Cannon pad and began drilling our Conrad well, our first horizontal well targeting the Greenhorn formation in our North East Extension Area.  After successfully completing the drilling of the Conrad well in June, ahead of schedule and on budget, we moved our contracted rig to the Bestway pad.  This pad is expected to consist of four mid-length (7,000 foot) lateral wells including one targeting the Codell formation, one targeting the Niobrara C formation, one targeting the Niobrara B formation, and one targeting the Niobrara A formation.  Drilling operations on the Bestway pad are expected to conclude in August and we anticipate moving our contracted rig to the southern portion of the Wattenberg Field to begin our fiscal 2016 drilling program in September.

Completion Activity

During the three months ended May 31, 2015, we began completion operations on our 13-well Kiehn/Weis pad and all the wells were brought online. The 13 wells consist of six Niobrara C, one Niobrara A, and six Codell wells. Eight of the wells are oriented south-to-north on the Kiehn portion of the pad, while the five wells on the Weis portion of the pad are oriented east-to-west. All the wells are exhibiting low gas-to-oil ratio characteristics.  We estimate the average Drill and Completion (D&C) cost of the thirteen wells will be approximately $3.5 million per well.

Completion activities on our eight-well Gies pad began in late fiscal 3rd quarter.  All eight wells are utilizing sliding sleeve completion designs with four using Halliburton's "Access (Biovert) Frac" fluids and the others using hybrid gel and slickwater fluids.  The Gies wells commenced production subsequent to May 31, 2015.

Completion activities on the 11-well Cannon pad began in June with first production expected in late July.  This pad consists of six Codell and five Niobrara C wells, and is oriented east-to-west.  Total D&C costs are expected to be between $2.9 million to $3.3 million per well.

Completion activities on our Wiedeman pad, which includes four Extended Reach Lateral (ERL) wells, have been delayed by a legal dispute over ownership issues and by remediation of an existing offset vertical well within the spacing unit owned by a third party.
 
For the Conrad well targeting the Greenhorn formation, our engineers are finalizing the completion design and completion activities are scheduled to occur during the fourth quarter.

Other Operations

We continue 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.  Likewise, during the three months ended May 31, 2015, we consummated several asset and acreage swaps, resulting in a higher working interest in several of our operated pads as well as a higher working interest in yet-to-be-developed leaseholds.  While these transactions lowered our expected non-operated production volumes in the quarter, they also resulted in an estimated $14 million reduction in our non-operated capital expenditures.  We anticipate the net result will be a higher ultimate return on our capital employed.
 
33

 

 
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 increased from 7,745 barrels of oil equivalent ("BOE") per day for the fiscal quarter ending February 28, 2015 to 8,026 BOE per day for the fiscal quarter ending May 31, 2015.    The additional production volumes from recently completed wells more than offset the natural decline of our existing wells and the loss of non-operated production due to asset swaps. The increase was achieved despite continuing mid-stream constraints, high line pressures in the northern portion of the Wattenberg Field, and the loss of production from shut-in wells due to offset operator completion activities.

Market Conditions

Market prices for our products significantly impact our revenues, net income, and cash flow.  The market prices for crude oil and natural gas are inherently volatile.  To provide historical perspective, the following table presents the average annual 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
   
Nine Months Ended
 
   
May 31,
   
May 31,
 
Oil (NYMEX WTI)
 
2015
   
2014
   
2015
   
2014
 
Reference Price
 
$
55.23
   
$
101.44
   
$
64.97
   
$
99.79
 
Realized Price
 
$
45.77
   
$
90.91
   
$
54.88
   
$
90.13
 
Differential
 
$
(9.46
)
 
$
(10.53
)
 
$
(10.09
)
 
$
(9.66
)
                                 
Gas (NYMEX Henry Hub)
                               
Reference Price
 
$
2.90
   
$
4.71
   
$
3.32
   
$
4.45
 
Realized Price
 
$
3.16
   
$
5.15
   
$
3.76
   
$
5.34
 
Differential
 
$
0.26
   
$
0.44
   
$
0.44
   
$
0.89
 
 
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.
34


 
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 then declined 48% during the first six months of our fiscal year, settling at $49.76/bbl on Friday, February 27, 2015.  The price of oil settled at $60.30/bbl on Friday, May 29, 2015, signaling a modest price recovery during our third fiscal quarter.  The third quarter price remains approximately 37% below the benchmark price at the start of our 2015 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 can result in an impairment of the value of our properties and the calculation of the "ceiling test" required under the accounting principles for companies following the "full cost" method of accounting.  We review our oil and gas properties for impairment at each quarterly reporting period.  For the third quarter, the ceiling test resulted in an impairment of $3.0 million, and future impairments may occur.

RESULTS OF OPERATIONS

For the three months ended May 31, 2015, compared to the three months ended May 31, 2014

For the three months ended May 31, 2015, we reported a net loss of $2.5 million compared to net income of $7.2 million during the three months ended May 31, 2014, driven in part by a $3.0 million full cost ceiling impairment, as discussed previously under the heading "Significant Developments."  Loss per basic and diluted share was $0.02 for the three months ended May 31, 2015 compared to net income of $0.09 per basic and diluted share for the three months ended May 31, 2014.  Other significant differences between the two periods include the rapid growth in reserves, producing wells and daily production totals, as well as the impact of changing prices on our revenues and our commodity hedge positions.  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 May 31, 2015 we recorded total oil and gas revenues of $26.0 million compared to $25.7 million for the three months ended May 31, 2014, an increase of $0.3 million or 1.4%.

Year over year, we added 36 net horizontal wells, including 3 (net) Bayswater horizontal wells, increasing our reserves, producing wells and daily production totals.  Although the three months ended May 31, 2015 yielded almost twice as much BOE production compared to the three months ended May 31, 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 May 31, 2015 averaged 8,026 BOE per day. For the three months ended May 31, 2014, production averaged 4,120 BOE per day, a year-over-year increase of 95%.  As a further comparison, average BOE production was 7,745 per day during the quarter ended February 28, 2015, a quarter-over-quarter increase of 4%.  When the price of oil declined in 2014, we temporarily postponed the final completion of certain wells under development.  The majority of the temporarily delayed wells has either commenced production or is expected to commence production during the third and fourth quarters.    

Our revenues are sensitive to changes in commodity prices.  As shown in the following table, there has been a decrease of nearly 48% in average realized prices between the periods presented.  This decline in average sales prices mostly offset the effects of increased production.
 
35

 

 
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 May 31,
     
   
2015
   
2014
   
Change 
Production:
           
Oil (Bbls1)
   
448,906
     
232,571
     
93
%
Gas (Mcf2)
   
1,736,702
     
879,062
     
98
%
                         
Total production in BOE3
   
738,357
     
379,081
     
95
%
                         
Revenues (in thousands):
                       
Oil
 
$
20,546
   
$
21,143
     
-3
%
Gas
   
5,487
     
4,529
     
21
%
   
$
26,033
   
$
25,672
     
1
%
Average sales price:
                       
Oil
 
$
45.77
   
$
90.91
     
-50
%
Gas
 
$
3.16
   
$
5.15
     
-39
%
BOE
 
$
35.26
   
$
67.72
     
-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
 
   
May 31,
 
   
2015
   
2014
 
Production Costs
 
$
3,533
   
$
2,252
 
Workover
   
37
     
51
 
Total LOE
 
$
3,570
   
$
2,303
 
                 
Per BOE:
               
Production costs
 
$
4.79
   
$
5.94
 
Workover
   
0.05
     
0.13
 
Total LOE
 
$
4.84
   
$
6.07
 
 
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 third 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.
 
36

 

 
Production taxes – During the three months ended May 31, 2015, production taxes were $2.2 million, or $3.04 per BOE, compared to $2.4 million, or $6.27 per BOE, during the three months ended May 31, 2014.  Taxes tend to increase or decrease primarily based on the value of oil and gas sold.  As a percent of revenues, taxes were 8.6% and 9.3% for the three months ended May 31, 2015 and 2014, respectively.

Depletion, Depreciation, and Amortization ("DDA") – The following table summarizes the components of DDA:
 
    
Three Months Ended
 
   
May 31,
 
(in thousands)
 
2015
   
2014
 
Depletion
 
$
16,200
   
$
7,569
 
Depreciation and amortization
   
197
     
227
 
Total DDA
 
$
16,397
   
$
7,796
 
                 
DDA expense per BOE
 
$
22.21
   
$
20.57
 
 
For the three months ended May 31, 2015, depletion of oil and gas properties was $22.21 per BOE compared to $20.57 per BOE for the three months ended May 31, 2014.  The increase in the DDA rate was the result of an increase in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves.  Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning-of-quarter estimated total reserves determine the depletion rate.  For both 2015 and 2014, production represented 1.7% of the reserve base.  Since DDA expense represents amortization of historical costs, our recently implemented reductions in well costs are not fully reflected in the rate.

Full cost ceiling impairment – During the three months ended May 31, 2015, we recognized an impairment of $3.0 million, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling.  See "Oil and Gas Properties, including Ceiling Test," included in the discussion of Critical Accounting Policies below.
 
37

 

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

  
 
Three Months Ended
 
 
 
May 31,
 
(in thousands)
 
2015
   
2014
 
G&A costs incurred
 
$
4,372
   
$
2,238
 
Capitalized costs
   
(486
)
   
(300
)
Total G&A
 
$
3,886
   
$
1,938
 
 
               
G&A Expense per BOE
 
$
5.26
   
$
5.11
 
 
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 May 31, 2015, G&A was $5.26 per BOE compared to $5.11 per BOE for the quarter ended May 31, 2014.

Our G&A expense for the quarter ended May 31, 2015 includes stock-based compensation of $1.4 million compared to $0.7 million for the quarter ended May 31, 2014.  Stock-based compensation includes a calculated value for stock options or shares of common stock that we grant for compensatory purposes.  It is a non-cash charge, which, for stock options, is calculated using the Black-Scholes-Merton option pricing model to estimate the fair value of options.  Amounts are pro-rated over the vesting terms of the option agreements, which are generally three to five years.

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

Commodity derivative gains (losses) – As more fully described in the paragraphs titled "Oil and Gas Commodity Contracts" 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 May 31, 2015, we realized a cash settlement gain of $7.1 million, including gains of $2.1 million from the settlement of contracts at their scheduled maturity dates and gains of $5.0 million from the early liquidation of "in-the-money" contracts.  For the prior year quarter ended May 31, 2014, we realized a cash settlement loss of $826,000.

In addition, for the quarter ended May 31, 2015, we recorded an unrealized loss of $8.3 million to recognize the mark-to-market change in fair value of our commodity contracts for the quarter ended May 31, 2015.  In comparison, in the quarter ended May 31, 2014, we reported an unrealized loss of $179,000.  Unrealized gains and losses are non-cash items.
Income taxes – We reported income tax benefit of $1.8 million for the three months ended May 31, 2015, calculated at an effective tax rate of 42%.  During the comparable prior year period, we reported income tax expense of $3.0 million, calculated at an effective tax rate of 30%.  For both periods, we anticipate that the tax liability will be substantially deferred into future years. During both fiscal years the effective tax rate differed from the federal and state statutory rate primarily by the impact of deductions for percentage depletion.

38

 

 

For the nine months ended May 31, 2015, compared to the nine months ended May 31, 2014

For the nine months ended May 31, 2015, we reported net income of $23.3 million compared to net income of $18.4 million during the nine months ended May 31, 2014.  Net income per basic and diluted share were $0.26 and $0.25, respectively, for the nine months ended May 31, 2015 compared to earnings per share of $0.24 per basic and diluted share for the nine months ended May 31, 2014.    Revenues increased $24.3 million during the nine months ended May 31, 2015 compared to the comparable period ended May 31, 2014 due to rapid growth in reserves, producing wells and daily production totals, as discussed previously.  As of May 31, 2015, we had 558 gross producing wells, compared to 388 gross producing wells as of May 31, 2014.  However, although our production more than doubled during the comparable periods, our revenues during the 2015 period increased only 35.8% as a result of declining oil and gas prices. The impact of changing prices on our commodity hedge positions also drove significant differences in our results of operations between the two periods.

The following discussion expands upon significant items of inflow and outflow that affected results of operations.

Oil and Gas Production and Revenues – For the nine months ended May 31, 2015, we recorded total oil and gas revenues of $92.3 million compared to $68.0 million for the nine months ended May 31, 2014, an increase of $24.3 million or 35.8%.

During the nine months ended May 31, 2015, our BOE production was 114% 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 37% in average realized BOE 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.
 
 
39

 
 

 
Key production information is summarized in the following table:
 
    
Nine Months Ended May 31,
     
   
2015
   
2014
   
Change 
Production:
           
Oil (Bbls1)
   
1,328,031
     
605,471
     
119
%
Gas (Mcf2)
   
5,164,238
     
2,508,311
     
106
%
                         
Total production in BOE3
   
2,188,737
     
1,023,523
     
114
%
                         
Revenues (in thousands):
                 
 Oil
 
$
72,880
   
$
54,569
     
34
%
 Gas
   
19,404
     
13,397
     
45
%
    
$
92,284
   
$
67,966
     
36
%
Average sales price:
                       
 Oil
 
$
54.88
   
$
90.13
     
-39
%
 Gas
 
$
3.76
   
$
5.34
     
-30
%
 BOE
 
$
42.16
   
$
66.40
     
-37
%
 
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):

    
Nine Months Ended
 
   
May 31,
 
   
2015
   
2014
 
Production Costs
 
$
10,227
   
$
5,252
 
Workover
   
73
     
130
 
Total LOE
 
$
10,300
   
$
5,382
 
                 
Per BOE:
               
Production costs
 
$
4.68
   
$
5.13
 
Workover
   
0.03
     
0.14
 
Total LOE
 
$
4.71
   
$
5.27
 

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 nine 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.
 
 
40

 
 
 

 
Production taxes – During the nine months ended May 31, 2015, production taxes were $8.6 million, or $3.92 per BOE, compared to $6.6 million, or $6.49 per BOE, during the nine months ended May 31, 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 9.3% and 9.8% for the nine months ended May 31, 2015 and 2014, respectively.

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

    
Nine Months Ended
 
   
May 31,
 
(in thousands)
 
2015
   
2014
 
Depletion
 
$
47,849
   
$
20,550
 
Depreciation and amortization
   
508
     
556
 
Total DDA
 
$
48,357
   
$
21,106
 
                 
DDA expense per BOE
 
$