10-Q 1 syrg_10q-q114.htm FORM 10-Q FOR THE PERIOD ENDED 11/30/2014
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
(Mark One)

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

For the quarterly period ended November 30, 2014

o 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 x     No o

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 x     No o

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 
x
Accelerated filer
o
 
Non-accelerated filer 
o
Smaller reporting company
o
 
 
 
 
 
Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
 Yes o   No x
 
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:  85,327,715 shares outstanding as of January 7, 2015.

SYNERGY RESOURCES CORPORATION

Index

 
Page
Part I – FINANCIAL INFORMATION
 
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
Balance Sheets as of November 30, 2014 (unaudited)
 and August 31, 2014
3
 
 
 
 
 
Statements of Operations for the three months ended
November 30, 2014 and November 30, 2013 (unaudited)
4
 
 
 
 
 
Statements of Cash Flows for the three months ended
November 30, 2014 and November 30, 2013  (unaudited)
5
 
 
 
 
 
Notes to Financial Statements (unaudited)
6
 
 
 
 
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
29
 
 
 
 
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
44
 
 
 
Item 4.
Controls and Procedures
44
 
 
 
 
Part II - OTHER INFORMATION
 
 
 
 
 
 
Item 6.
Exhibits
45
 
 
 
 
SIGNATURES
46


2

SYNERGY RESOURCES CORPORATION
BALANCE SHEETS
(in thousands, except share data)
 
 
ASSETS
 
November 30,
2014
   
August 31,
2014
 
 
 
(unaudited)
   
 
Current assets:
 
   
 
Cash and cash equivalents
 
$
47,111
   
$
34,753
 
Accounts receivable:
               
Oil and gas sales
   
21,059
     
16,974
 
Joint interest billing and other
   
24,964
     
15,398
 
Commodity derivative
   
11,984
     
365
 
Earnest money deposit
   
6,250
     
-
 
Other current assets
   
1,074
     
750
 
Total current assets
   
112,442
     
68,240
 
 
               
Property and equipment:
               
Evaluated oil and gas properties, full cost method, net
   
295,396
     
275,018
 
Unevaluated oil and gas properties
   
126,994
     
95,278
 
Other property and equipment, net
   
4,849
     
9,104
 
Property and equipment, net
   
427,239
     
379,400
 
 
               
Commodity derivative
   
4,534
     
54
 
Other assets
   
850
     
848
 
 
               
Total assets
 
$
545,065
   
$
448,542
 
 
               
LIABILITIES AND SHAREHOLDERS' EQUITY
               
 
               
Current liabilities:
               
Trade accounts payable
 
$
354
   
$
1,747
 
Well costs payable
   
69,511
     
71,849
 
Revenue payable
   
25,251
     
14,487
 
Production taxes payable
   
18,983
     
14,376
 
Other accrued expenses
   
1,818
     
817
 
Commodity derivative
   
-
     
302
 
Total current liabilities
   
115,917
     
103,578
 
 
               
Revolving credit facility
   
77,000
     
37,000
 
Commodity derivative
   
-
     
307
 
Deferred tax liability, net
   
33,296
     
21,437
 
Asset retirement obligations
   
5,109
     
4,730
 
Total liabilities
   
231,322
     
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:
         
79,854,500 and 77,999,082 shares issued and outstanding, respectively
   
80
     
78
 
Additional paid-in capital
   
276,893
     
265,793
 
Retained earnings
   
36,770
     
15,619
 
Total shareholders' equity
   
313,743
     
281,490
 
 
               
Total liabilities and shareholders' equity
 
$
545,065
   
$
448,542
 
 
 
The accompanying notes are an integral part of these financial statements.
3


 
SYNERGY RESOURCES CORPORATION
STATEMENTS OF OPERATIONS
 (unaudited; in thousands, except share and per share data)
 
 
 
 
Three Months Ended
 
 
 
November 30,
   
November 30,
 
 
 
2014
   
2013
 
 
 
   
 
Oil and gas revenues
 
$
42,538
   
$
19,266
 
 
               
Expenses
               
Lease operating expenses
   
3,041
     
1,273
 
Production taxes
   
4,178
     
2,016
 
Depletion, depreciation
               
   and amortization
   
16,454
     
5,591
 
General and administrative
   
4,110
     
3,168
 
Total expenses
   
27,783
     
12,048
 
 
               
Operating income
   
14,755
     
7,218
 
 
               
Other income (expense)
               
Commodity derivative realized gain (loss)
   
1,432
     
(398
)
Commodity derivative unrealized gain
   
16,708
     
2,636
 
Interest income
   
-
     
31
 
Total other income
   
18,140
     
2,269
 
 
               
Income before income taxes
   
32,895
     
9,487
 
 
               
Income tax provision
   
11,744
     
3,387
 
Net income
 
$
21,151
   
$
6,100
 
 
               
Net income per common share:
               
Basic
 
$
0.27
   
$
0.08
 
Diluted
 
$
0.26
   
$
0.08
 
 
               
Weighted average shares outstanding:
               
Basic
   
79,008,719
     
73,674,865
 
Diluted
   
80,141,152
     
76,044,605
 
 
 
 
The accompanying notes are an integral part of these financial statements.
4

 
SYNERGY RESOURCES CORPORATION
 STATEMENTS OF CASH FLOWS
 (unaudited, in thousands)
 
 
 
 
Three Months Ended
 
 
 
November 30,
2014
   
November 30,
2013
 
Cash flows from operating activities:
 
   
 
Net income
 
$
21,151
   
$
6,100
 
Adjustments to reconcile net income to net
               
cash provided by operating activities:
               
Depletion, depreciation and amortization
   
16,454
     
5,591
 
Provision for deferred taxes
   
11,744
     
3,387
 
Stock-based compensation
   
793
     
419
 
Valuation increase in commodity derivatives
   
(16,708
)
   
(2,636
)
Changes in operating assets and liabilities:
               
Accounts receivable
               
    Oil and gas sales
   
(4,085
)
   
(2,064
)
    Joint interest billing and other
   
(9,566
)
   
(768
)
Accounts payable
               
    Trade
   
(1,393
)
   
(603
)
    Revenue
   
10,764
     
2,729
 
    Production taxes
   
4,607
     
2,145
 
    Accrued expenses
   
1,001
     
250
 
Other
   
(327
)
   
363
 
Total adjustments
   
13,284
     
8,813
 
Net cash provided by operating activities
   
34,435
     
14,913
 
 
               
Cash flows from investing activities:
               
Acquisition of property and equipment
   
(66,137
)
   
(57,127
)
Short-term investments
   
-
     
19,987
 
Earnest money deposit
   
(6,250
)
       
Net cash used in investing activities
   
(72,387
)
   
(37,140
)
 
               
Cash flows from financing activities:
               
Proceeds from exercise of warrants
   
10,699
     
23,771
 
Net proceeds from revolving credit facility
   
40,000
     
-
 
Shares withheld for payment of employee payroll taxes
   
(389
)
   
(34
)
Net cash provided by financing activities
   
50,310
     
23,737
 
 
               
Net increase in cash and cash equivalents
   
12,358
     
1,510
 
 
               
Cash and cash equivalents at beginning of period
   
34,753
     
19,463
 
 
               
Cash and cash equivalents at end of period
 
$
47,111
   
$
20,973
 
 
               
Supplemental Cash Flow Information (See Note 14)
               

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


5


SYNERGY RESOURCES CORPORATION
NOTES TO FINANCIAL STATEMENTS
November 30, 2014
(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.

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

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

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

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

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

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

Use of Estimates:     The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and gas reserves, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain.  Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.  Estimates and assumptions are revised periodically and the effects of revisions are reflected in the financial statements in the period it is determined to be necessary.  Actual results could differ from these estimates.
 
6


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

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 unevaluated properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs.  If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Wells in progress represent the costs associated with the drilling of oil and gas wells that have yet to be completed as of November 30, 2014.  Since the wells had not been completed as of November 30, 2014, they were classified within unevaluated oil and gas properties and were withheld from the depletion calculation and ceiling test.  The costs for these wells will be transferred into proved property when the wells commence production and will become subject to depletion and the ceiling test calculation in subsequent periods.

Under the full cost method of accounting, a ceiling test is performed each quarter.  The full cost ceiling test is an impairment test prescribed by SEC regulations.  The ceiling test determines a limit on the book value of oil and gas properties.  The capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion, depreciation, and amortization, and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, less future cash outflows associated with asset retirement obligations that have been accrued, plus the cost of unproved properties not being amortized, plus the lower of cost or estimated fair value of unproven properties being amortized.  Prices are held constant for the productive life of each well.  Net cash flows are discounted at 10%.  If net capitalized costs exceed this limit, the excess is charged to expense and reflected as additional accumulated depletion, depreciation and amortization.  The calculation of future net cash flows assumes continuation of current economic conditions.  Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount.  No provision for impairment was required for either the three months ended November 30, 2014 or 2013. 

The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12 month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the 12 month period prior to the end of the reporting period, unless prices are defined by contractual arrangements.  Prices are adjusted for basis or location differentials.
 
 
7


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

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

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

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

 
 
Three Months Ended
 
 
 
November 30,
   
November 30,
 
 
 
2014
   
2013
 
Capitalized Overhead
 
$
503
   
$
317
 

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.
 
8


Oil and Gas Sales:    The Company derives revenue primarily from the sale of crude oil and natural gas produced on its properties.  Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest.  Revenues are reported on a gross basis for the amounts received before taking into account production taxes and lease operating costs, which are reported as separate expenses.  Revenue is recorded and receivables are accrued using the sales method, which occurs in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser.  Payment is generally received between thirty and ninety days after the date of production.  Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser.  Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.
 
Major Customers and Operating Region:    The Company operates exclusively within the United States of America.  Except for cash and short-term investments, all of the Company’s assets are employed in and all of its revenues are derived from the oil and gas industry.   The table below presents the percentages of oil and gas revenue resulting from purchases by major customers.
 
 
 
Three Months Ended
 
 
 
November 30,
   
November 30,
 
Major Customers
 
2014
   
2013
 
Company A
   
68%
 
   
60%
 
Company B
   
12%
 
   
15%
 

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

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

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
November 30,
2014
   
As of
November 30,
2013
 
Company A
   
29%
 
   
29%
 
Company B
   
(1)
     
16%
 
Company C
   
(1)
     
10%
 
 
(1)  Balance was less than 10% of total receivable balances during the period.
 
Lease Operating Expenses:    Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred.  Lease operating expenses (also referred to as production or lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities, property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
 
9


 
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 November 30, 2014.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of November 30, 2014, 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 or “no premium” collars to reduce the effect of price changes on a portion of its future oil and gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the statement of operations. The Company values its derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors, as well as other relevant economic measures.  The Company compares the valuations calculated by it to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 7—Commodity Derivative Instruments.
 
10


 
Earnings Per Share Amounts:    Basic earnings per share includes no dilution and is computed by dividing net income or loss by the weighted-average number of shares outstanding during the period.  Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of the Company.  The number of potential shares outstanding relating to stock options and warrants is computed using the treasury stock method.  Potentially dilutive securities outstanding are not included in the calculation when such securities would have an anti-dilutive effect on earnings per share.
 
The following table sets forth the share calculation of diluted earnings per share:
 
 
 
Three Months Ended
 
 
 
November 30,
   
November 30,
 
 
 
2014
   
2013
 
 
 
   
 
Weighted-average shares outstanding-basic
   
79,008,719
     
73,674,865
 
Potentially dilutive common shares from:
               
Stock Options
   
793,270
     
551,060
 
Warrants
   
339,163
     
1,818,680
 
 
   
1,132,433
     
2,369,740
 
Weighted-average shares outstanding - diluted
   
80,141,152
     
76,044,605
 
 
 
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
 
 
 
November 30,
   
November 30,
 
 
 
2014
   
2013
 
 
 
   
 
Employee stock options
   
523,000
     
810,000
 
 
 
 Recent Accounting Pronouncements:    We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new pronouncements on US GAAP and the impact on us.

  In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2014-09, “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.
 
 
 
11

In December 2011, the FASB issued Accounting Standards Update 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”), and issued Accounting Standards Update 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“ASU 2013-01”) in January 2013. These updates require disclosures about the nature of an entity’s rights of offset and related arrangements associated with its recognized derivative contracts. The new disclosure requirements, which are effective for interim and annual periods beginning on or after January 1, 2013, were implemented by the Company on September 1, 2013. The implementation of ASU 2011-11 and ASU 2013-01 had no impact on the Company’s financial position or results of operations. See Note 7 for the Company’s derivative disclosures.
There were various updates recently issued by the Financial Accounting Standards Board, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on the Company's consolidated financial position, results of operations or cash flows. 
 
 

 
12

 
2.
Property and Equipment

The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
 
 
 
As of
   
As of
 
 
 
November 30, 2014
   
August 31, 2014
 
Oil and gas properties, full cost method:
 
   
 
   Unevaluated costs, not subject to amortization:
 
   
 
      Lease acquisition and other costs
 
$
61,133
   
$
41,531
 
      Wells in progress
   
65,861
     
53,747
 
         Subtotal, unevaluated costs
   
126,994
     
95,278
 
 
               
   Evaluated costs:
               
      Producing and non-producing
   
366,951
     
329,926
 
         Total capitalized costs
   
493,945
     
425,204
 
      Less, accumulated depletion
   
(71,555
)
   
(54,908
)
           Oil and gas properties, net
   
422,390
     
370,296
 
 
               
Land
   
4,478
     
3,898
 
Other property and equipment
   
822
     
5,961
 
Less, accumulated depreciation
   
(451
)
   
(755
)
            Other property and equipment, net
   
4,849
     
9,104
 
 
               
Total property and equipment, net
 
$
427,239
   
$
379,400
 
 
    
Periodically, the Company reviews its unevaluated properties to determine if the carrying value of such assets exceeds estimated fair value. The reviews for the three months ended November 30, 2014 indicated that estimated fair values of such assets exceeded carrying values, thus revealing no impairment. The full cost ceiling test, explained in Note 1, and, as performed for the three months ended November 30, 2014, similarly revealed no impairment of oil and gas assets.
 
During the quarter ended November 30, 2014, 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.  The updated classification for the disposal well and related equipment did not result in a change to previously reported depletion, depreciation, and amortization expense (“DDA”).  In future periods, DDA for the disposal well will be included in the calculation of depletion for the full cost pool, and will not be calculated as a component of depreciation. Secondly, as discussed in Note 3, the analysis of assets acquired in certain 2014 business combination transactions was completed and fair values associated with probable horizontal well development were reclassified from evaluated costs into unevaluated costs.



13

 

3.
Acquisitions
 
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 quarter ended November 30, 2014, 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.
 
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)


14

 
On August 27, 2013, the Company entered into a definitive purchase and sale agreement (“the Agreement”), with Apollo Operating, LLC (“Apollo”), for its interests in 38 producing oil and gas wells, partial interest (25%) in one water disposal well (the “Disposal Well”), and approximately 3,639 gross (1,000 net) mineral acres (“the Apollo Operating Assets”). On November 13, 2013, the Company closed the transaction for a combination of cash and stock.  Apollo received cash consideration of approximately $11.0 million and 550,518 shares of the Company’s common stock valued at $5.2 million.  Following its acquisition of the Apollo Operating Assets, the Company acquired all other remaining interests in the Disposal Well (the “Related Interests”) through several transactions with the individual owners of such interests. The Company acquired the Related Interests for approximately $3.7 million in cash consideration and 20,626 shares of the Company’s common stock, valued at $0.2 million.  No material transaction costs were incurred in connection with this acquisition.
 
The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of November 13, 2013. The following table summarizes the 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).
            
 
15


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

The reclassification of $15.3 million of acquired fair value has been treated as a change in estimate, and no retroactive adjustments were made to DDA, net income, or retained earnings.  Since only proved reserves are used to calculate DDA, and since proved reserves did not change, future DDA calculations will be reduced by the negligible amount associated with the removal of $15.3 million from the full cost pool.

 
4.
Depletion, depreciation and amortization (“DDA”)
 
Depletion, depreciation and amortization consisted of the following:

 
 
Three Months ended
 
 
 
November 30,
   
November 30,
 
(in thousands)
 
2014
   
2013
 
Depletion
 
$
16,304
   
$
5,490
 
Depreciation and amortization
   
150
     
101
 
Total DDA Expense
 
$
16,454
   
$
5,591
 
 
Capitalized costs of evaluated oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter.

5.
Asset Retirement Obligations
 
Upon completion or acquisition of a well, the Company recognizes obligations for its oil and gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling sites to 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 Three Months Ended
 November 30,
 
 
 
2014
   
2013
 
Inflation rate
   
3.90%
 
   
3.9 - 4.0%
 
Estimated asset life
 
25.0 - 39.0 years
   
24.0 - 40.0 years
 
Credit adjusted risk free interest rate
   
8.0%
 
   
8.0%
 
 
 
 
16


 
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
   
269
 
  Liabilities assumed
   
-
 
  Accretion expense
   
110
 
Asset retirement obligations, November 30, 2014
 
$
5,109
 
 
6.
Revolving Credit Facility
 
The description of the Company’s revolving credit facility contained in this Note 6 provides historical information that existed as of November 30, 2014.  As described in Note 15 – Subsequent Events, the facility was amended on December 15, 2014, to, among other things, increase the number of banks participating in the facility, name a new administrative agent bank, increase the commitment to $500 million and the borrowing base to $230 million, and to extend the maturity date.  Additional details regarding the amendment can be found in Item 2 – Management Discussion and Analysis of Financial Condition and Results of Operations and in a copy of the amendment filed as an exhibit to this quarterly report.
 
The Company maintains a revolving credit facility (“LOC”) with a bank syndicate.  The LOC is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit.  During the quarter ended November 30, 2014, the terms of the LOC provided for $300 million in the maximum amount of borrowings available to the Company, subject to a borrowing base limitation.  Community Banks of Colorado acted as the administrative agent for the bank syndicate with respect to the LOC.  The expiration date of the credit facility was May 29, 2019.
 
Interest under the LOC is payable monthly and accrues at a variable rate, subject to a minimum rate of 2.5%.  For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin of 0.5% to 1.5%, or the London Interbank Offered Rate (LIBOR) plus a margin of 1.75% to 2.75%.  The interest rate margin, as well as other bank fees, varies with utilization of the LOC.  The average annual interest rate for borrowings during the three months ended November 30, 2014, was 2.5%, representing the minimum rate.
 
Certain of the Company’s assets, including substantially all developed properties, have been designated as collateral under the arrangement.  The borrowing commitment is subject to adjustment based upon a borrowing base calculation that includes the value of oil and gas reserves.  The borrowing base limitation is subject to scheduled redeterminations on a semi-annual basis.  In certain events, and at the discretion of the bank syndicate, an unscheduled redetermination could be prepared.  During the quarter ended November 30, 2014, the borrowing base was $110 million.   As of November 30, 2014, based upon a borrowing base of $110 million and an outstanding principal balance of $77 million, the unused borrowing base available for future borrowing totaled approximately $33 million.
 
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.
 
Furthermore, the arrangement requires the Company to maintain certain financial ratio compliance covenants.  Under the requirements, on a quarterly basis, the Company must (a) not, at any time, permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0; and (b) not, as of the last day of the fiscal quarter, permit its adjusted current ratio, as defined, to be less than 1.0 to 1.0.  As of November 30, 2014, the most recent compliance date, the Company was in compliance with all loan covenants.
 
17


 
7.
Commodity Derivative Instruments

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

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.  The Company’s derivative contracts are currently with 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.  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 credit worthiness, the Company’s credit worthiness, 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.
 
18


 
The Company’s commodity derivative contracts as of November 30, 2014 are summarized below:
 
Settlement Period
Derivative
Instrument
 
Average Volumes
(BBls/MMBtu
per month)
   
Average
Strike
Price
   
Floor
Price
   
Celling
Price
 
Crude Oil - NYMEX WTI
 
 
   
   
   
 
Dec 1, 2014 - Dec 31, 2014
Collar
   
21,840
     
-
   
$
86.83
   
$
96.44
 
Dec 1, 2014 - Dec 31, 2014
Swap
   
56,840
   
$
87.08
     
-
     
-
 
 
 
                               
Jan 1, 2015 - Jun 30, 2015
Collar
   
7,000
     
-
   
$
80.00
   
$
92.50
 
Jan 1, 2015 - Jun 30, 2015
Collar
   
2,500
     
-
   
$
80.00
   
$
95.75
 
Jul  1, 2015 - Dec 31, 2015
Collar
   
9,000
     
-
   
$
80.00
   
$
92.25
 
Jan 1, 2015 - Dec 31, 2015
Collar
   
4,500
     
-
   
$
80.00
   
$
99.40
 
Jan 1, 2015 - Dec 31, 2015
Collar
   
6,000
     
-
   
$
85.00
   
$
101.30
 
Jan 1, 2015 -  Jun 30, 2015
Swap
   
20,000
   
$
90.10
     
-
     
-
 
Jul  1, 2015 - Dec 31, 2015
Swap
   
15,500
   
$
89.52
     
-
     
-
 
Jan 1, 2015 - Oct 31, 2015
Swap
   
14,600
   
$
78.65
     
-
     
-
 
 
 
                               
Jan 1, 2016 - 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
     
-
     
-
 
 
 
                               
 
 
                               
 
 
                               
Natural Gas - NYMEX Henry Hub
                               
Dec 1, 2014 - Dec 31, 2014
Swap
   
80,000
   
$
4.58
     
-
     
-
 
Dec 1, 2014 - Dec 31, 2014
Collar
   
30,000
     
-
   
$
4.07
   
$
4.18
 
Jan 1, 2015 - Dec 31, 2015
Collar
   
72,000
     
-
   
$
4.15
   
$
4.49
 
Jan 1, 2016 - May 31, 2016
Collar
   
60,000
     
-
   
$
4.05
   
$
4.54
 
Jun 1, 2016 - Aug 31, 2016
Collar
   
60,000
     
-
   
$
3.90
   
$
4.14
 

 
Offsetting of Derivative Assets and Liabilities

As of November 30, 2014 and 2013, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions.  In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at election of both parties, for transactions that occur on the same date and in the same currency.  They Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty.  The Company’s accounting policy is to offset these positions in its accompanying balance sheets.
 
 
19


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


 
  
 
As of November 30, 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
 
$
12,184
   
$
(200
)
 
$
11,984
 
Derivative contracts
Noncurrent assets
 
$
4,756
   
$
(222
)
 
$
4,534
 
Derivative contracts
Current liabilities
 
$
200
   
$
(200
)
 
$
-
 
Derivative contracts
Noncurrent liabilities
 
$
222
   
$
(222
)
 
$
-
 
 
 
 
  
 
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
 
 
November 30
 
November 30
 
 
2014
 
2013
 
Unrealized gain on commodity derivatives
$
16,708
 
$
2,636
 
Realized gain (loss) on commodity derivatives
 
1,432
   
(398
)
Total gain
$
18,140
 
$
2,238
 
 
 

Credit-Related Contingent Features
 
During the quarter ended November 30, 2014, 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.
 
20



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—Asset Retirement Obligations, 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—Acquisitions, for additional information.
 
 
21


 
The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of November 30, 2014 and August 31, 2014 by level within the fair value hierarchy (in thousands):
 
  
 
Fair Value Measurements at November 30, 2014
 
  
 
Level 1
   
Level 2
   
Level 3
   
Total
 
Financial assets and liabilities:
 
   
   
   
 
Commodity derivative asset
 
$
-
   
$
16,518
   
$
-
   
$
16,518
 
Commodity derivative liability
 
$
-
   
$
-
   
$
-
   
$
-
 
 
                               
  
 
Fair Value Measurements at August 31, 2014
 
  
 
Level 1
   
Level 2
   
Level 3
   
Total
 
Financial assets and liabilities:
                               
Commodity derivative asset
 
$
-
   
$
419
   
$
-
   
$
419
 
Commodity derivative liability
 
$
-
   
$
609
   
$
-
   
$
609
 

 
Commodity Derivative Instruments

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments.  Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At November 30, 2014, derivative instruments utilized by the Company consist of both “no premium” collars and swaps. The crude oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors including public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and credit facility borrowings. The carrying values of cash and cash equivalents, 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.

 
22


 
9.
Interest Expense
 
The components of interest expense are (in thousands):
 
 
 
Three Months Ended
 
 
 
November 30,
   
November 30,
 
 
 
2014
   
2013
 
 
 
   
 
Revolving credit facility
 
$
378
   
$
251
 
Amortization of debt issuance costs
   
137
     
94
 
Less, interest capitalized
   
(515
)
   
(345
)
Interest expense, net
 
$
-
   
$
-
 
 
10.
Shareholders’ Equity

 The Company’s classes of stock are summarized as follows:
 
 
 
As of November 30,
   
As of August 31,
 
 
 
2014
   
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
   
79,854,500
     
77,999,082
 
 
 
 Preferred Stock may be issued in series with such rights and preferences as may be determined by the Board of Directors.  Since inception, the Company has not issued any preferred shares.
 
 
Common stock warrants

The following table summarizes information about the Company’s issued and outstanding common stock warrants as of November 30, 2014:
 
Description
 
Number of Warrants
   
Exercise Price
   
Remaining Contractual Life (in years)
   
Exercise Price times Number of Warrants
 
Series C
   
778,330
   
 
$6.00
     
0.1
   
$
4,669,980
 
Series D
   
1,058
   
 
$1.60
     
0.1
   
$
1,693
 
 
   
779,388
                   
$
4,671,673
 
 
 
 

 
23

 
 
The following table summarizes activity for common stock warrants for the three month period ended November 30, 2014:
 
 
 
Number of
Warrants
   
Weighted-Average
Exercise Price
 
Outstanding, August 31, 2014
   
2,562,473
   
$
6.00
 
Granted
   
-
   
$
-
 
Exercised
   
(1,783,085
)
 
$
6.00
 
Expired
   
-
   
$
-
 
Outstanding, November 30, 2014
   
779,388
   
$
6.00
 
 
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
 
 
 
November 30,
   
November 30,
 
 
 
2014
   
2013
 
Stock options
 
$
500
   
$
419
 
Employee stock grants
   
293
     
-
 
 
 
$
793
   
$
419
 
 

During the three months ended November 30, 2014 and 2013, the Company granted the following employee stock options:
 
 
 
Three Months ended
 
 
 
November 30,
   
November 30,
 
 
 
2014
   
2013
 
Number of options to purchase common shares
   
75,000
     
150,000
 
Weighted-average exercise price
 
$
12.87
   
$
9.98
 
Term (in years)
   
10.0
     
10.0
 
Vesting Period (in years)
   
5
     
5
 
Fair Value (in thousands)
 
$
639
   
$
1,014
 
 
 
24

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

 
 
Three Months Ended
 
 
 
November 30,
2014
   
November 30,
2013
 
Expected term
 
6.5 years
   
6.5 years
 
Expected volatility
   
72%
 
   
74%
 
Risk free rate
   
1.95%
 
   
1.91%
 
Expected dividend yield
   
0.00%
 
   
0.00%
 
Forfeiture rate
   
0.30%
 
   
0.00%
 

 
The following table summarizes activity for stock options for the three months ended November 30, 2014:

 
 
Number
of Shares
   
Weighted-Average
 Exercise Price
 
Outstanding, August 31, 2014
   
2,167,000
   
$
5.94
 
Granted
   
75,000
   
$
12.87
 
Exercised
   
(120,000
)
 
$
3.76
 
Forfeited
   
-
     
-
 
Outstanding, November 30, 2014
   
2,122,000
   
$
6.31
 

 
The following table summarizes information about issued and outstanding stock options as of November 30, 2014:
 

 
Outstanding
Options
   
Vested
Options
 
Number of shares
   
2,122,000
     
831,100
 
Weighted-average remaining contractual life
 
7.9 years
   
7.1 years
 
Weighted-average exercise price
 
$
6.31
   
$
4.87
 
Aggregate intrinsic value (in thousands)
 
$
7,958
   
$
4,115
 

 
The estimated unrecognized compensation cost from unvested stock options as of November 30, 2014, which will be recognized ratably over the remaining vesting phase, is as follows:

 
Unvested Options at
November 30,
2014
 
Unrecognized compensation expense (in thousands)
 
$  5,533
 
Remaining vesting phase
 
3.4 years
 

 
 
25


 
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 fiscal years presented (in thousands):

 
Three Months ended
 
 
November 30,
 
November 30,
 
 
2014
 
2013
 
Rent expense
 
45
 
$
45
 

 
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 three months ended November 30, 2014 and 2013 (in thousands):

 
 
Three Months ended
 
 
 
November 30,
   
November 30,
 
 
 
2014
   
2013
 
Total Royalty Payments
 
$
53
   
$
82
 
 
26

 

13.
Other Commitments and Contingencies
 
As of November 30, 2014, the Company was using three rigs under contracts with Ensign United States Drilling, Inc.  All of the contracts are based upon turn-key pricing and have termination dates during the first half of fiscal year 2015.  At the option of the Company, the drilling commitments can be extended into future months, although pricing terms may be modified.  Actual payments due to Ensign will depend upon a number of variables, including the surface location, the target formation, measured depth of well and other technical details.
 
From time to time, the Company receives notice from other operators of their intent to drill and operate a well in which the Company 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 November 30, 2014, the Company was participating in 9 gross (2 net) new horizontal wells, with aggregate costs to its interest estimated at $9.1 million.  It is the Company’s policy to accrue costs on a non-operated well when it receives notice that active drilling operations have commenced.  Accordingly, the November 30, 2014 financial statements include accrued costs of $5.4 million for these wells. 

 
14.
Supplemental Schedule of Information to the Statements of Cash Flows
 
The following table supplements the cash flow information presented in the financial statements for the three months ended November 30, 2014 and 2013 (in thousands):

 
 
Three Months Ended
 
 
 
November 30,
   
November 30,
 
 
 
2014
   
2013
 
Supplemental cash flow information:
 
   
 
    Interest paid
 
$
321
   
$
251
 
    Income taxes paid
   
110
     
-
 
 
               
Non-cash investing and financing activities:
               
Accrued well costs
 
$
69,511
   
$
26,813
 
Assets acquired in exchange for common stock
   
-
     
9,898
 
Asset retirement costs and obligations
   
269
     
692
 
 
 
27

 
15.
Subsequent Events

The following discussion pertains to material events occurring subsequent to November 30, 2014, but prior to the issuance of the financial statements.

Amendment to Revolving Credit Facility

On December 15, 2014, the Company amended its revolving credit facility.  Under the amendment, the maximum loan commitment is $500 million and the borrowing base is $230 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 is the Joint Lead Arranger / Syndication Agent.  The maturity date of the facility was extended to 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.  Amounts borrowed under the LOC are secured by substantially all of the Company’s producing wells and developed oil and gas leases.  The interest rate on outstanding borrowings will be based on a pricing grid, which escalates with utilization and establishes a minimum of 2.5%.

Concurrent with the amendment, the Company increased its borrowings by approximately $66.2 million.  Proceeds from the additional borrowings were used to fund the mineral asset acquisition described below.

Acquisition of Mineral Assets

On December 15, 2014, the Company completed the acquisition of certain assets. These assets consisted of the following:

·
non-operated working interests in 17 horizontal wells (including 4 mid-reach laterals);

·
73 operated and 11 non-operated vertical wells;

·
35 permit applications for operated horizontal wells (including 20 extended reach laterals);

·
5,040 gross acres (4,053 net) with rights to the Codell and Niobrara formations;

·
2,400 gross acres (1,739 net) with rights to other formations, including the Sussex, Shannon and J-Sands;

·
3-D seismic data; and

·
miscellaneous equipment.

Working interests in the horizontal wells range from 6% to 40%.  Working interests in the vertical wells range from 5% to 100%.  The producing oil and gas properties are located in the Wattenberg Field, which is part of the Denver-Julesburg Basin.  Preliminary estimates indicate that the undeveloped acreage will provide locations to drill 150 horizontal wells.

For the acquisition of these assets, the Company paid approximately $125 million, consisting of $75 million in cash and 4,648,136 restricted shares of the Company’s common stock which, for purposes of the transaction, were valued at $50 million.
 
Exercise of Series C Warrants

Subsequent to November 30, 2014, the Company issued approximately 778,000 shares pursuant to the exercise of Series C warrants and received proceeds of approximately $4.7 million.


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 November 30, 2014, and the results of our operations for the three months ended November 30, 2014 and 2013. 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.  The area has produced oil and gas for over fifty years and has a history as one of the most prolific production areas in the country.  Substantially all of our producing wells are either in or adjacent to the Wattenberg Field.

In addition to the approximately 31,000 net developed and undeveloped acres that we hold in the Wattenberg Field, we hold approximately 28,000 undeveloped acres in an area directly to the north and east of the Wattenberg Field that is considered the Northern Extension area.  We are currently in the permit process to drill wells targeting the Greenhorn formation on our leasehold in this area and plan to spud the first well during 2015.  We have leased over 184,000 net undeveloped acres in western Nebraska and have entered into a joint exploration agreement with a Denver based private operating company to drill up to ten wells in this area.  We have received drilling title opinions on eight locations and we expect drilling activities to commence in Nebraska early in 2015.  We continue to maintain leases covering over 63,000 acres in Yuma and Washington Counties, Colorado in an area that has historically produced dry gas from the Niobrara formation.

Since commencing active operations in September 2008, we have undergone significant growth.  Our growth was primarily driven by (i) our activities as an operator where we drill and complete productive oil and gas wells; (ii) our participation as a part owner in wells drilled by other operating companies; and (iii) our acquisition of producing oil wells from other individuals or companies.  From inception through November 30, 2014, we have completed, acquired, or participated in 448 gross (297 net) successful oil and gas wells.  The following tables compare our recent activities with respect to vertical and horizontal wells:
 
 
 
 
VERTICAL WELLS
 
 
OPERATED WELLS
NON-OPERATED WELLS
 
 
Completed
   
Participated
   
Acquired
   
Total
 
Years ended:
 
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
 
 
   
   
   
   
   
   
   
 
Prior to 2012
   
56
     
47
     
13
     
4
     
63
     
44
     
132
     
95
 
August 31 2012
   
51
     
48
     
8
     
3
     
4
     
4
     
63
     
55
 
August 31, 2013
   
27
     
26
     
10
     
4
     
36
     
34
     
73
     
64
 
August 31, 2014
   
1
     
1
     
5
     
1
     
60
     
35
     
66
     
37
 
November 30, 2014
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
 
 
                                                               
Total
   
135
     
122
     
36
     
12
     
163
     
117
     
334
     
251
 

 
29

 
 
HORIZONTAL WELLS
 
 
OPERATED WELLS
NON-OPERATED WELLS
 
 
Completed
   
Participated
   
Acquired
   
Total
 
Years ended:
 
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
 
 
   
   
   
   
   
   
   
 
August 31, 2012
   
-
     
-
     
5
     
1
     
-
     
-
     
5
     
1
 
August 31, 2013
   
-
     
-
     
11
     
2
     
-
     
-
     
11
     
2
 
August 31, 2014
   
31
     
29
     
23
     
2
     
-
     
-
     
54
     
31
 
November 30, 2014
   
8
     
6
     
36
     
6
     
-
     
-
     
44
     
12
 
 
                                                               
Total
   
39
     
35
     
75
     
11
     
-
     
-
     
114
     
46
 

The preceding tables illustrate the transformation that has occurred with respect to the types of wells that we drill and complete.  Whereas early development efforts were focused on drilling vertical wells into the Niobrara, Codell, and J-Sand formations, we shifted our development efforts to horizontal wells in May 2013.  Horizontal wells are significantly more expensive and take longer to drill and complete than vertical wells, but ultimately yield greater returns.

During our fiscal 2015 first quarter ended November 30, 2014, we commenced production from eight new horizontal wells in the Wattenberg Field.  These included one well on our Phelps pad, a mid-length lateral well on our Eberle pad and six wells on our Weld 152 pad, all of which contributed to an increase in production.  Our consolidated production from producing wells increased from 5,894 barrels of oil equivalent (“BOE”) per day for the fiscal quarter ending August 31, 2014 to 8,278 BOE per day for the quarter ending November 30, 2014.

In addition to the 8 operated horizontal wells that reached productive status during the quarter ended November 30, 2014, we were the operator of 23 horizontal wells that were in various stages of drilling or completion.  We were participating as a non-operator in 9 horizontal wells and 2 vertical wells (total of 2 net non-operated wells) that were in various stages of the drilling or completion process.

As of November 30, 2014, we:

·
were the operator of 39 horizontal wells that were producing oil and gas and we were participating as a non-operating working interest owner in 75 horizontal producing wells;
·
were the operator of 269 vertical wells that were producing oil and gas and we were participating as a non-operating working interest owner in 65 producing wells;
·
were the operator of 23 wells in progress and we were participating as a non-operating working interest owner in 11 wells in progress;
·
held approximately 446,000 gross acres and 313,000 net acres under lease.
 

Strategy

Our basic strategy for continued growth includes additional drilling activities and acquisition of existing wells in well-defined areas that provide significant cash flow and rapid return on investment.  We attempt to maximize our return on assets by drilling in low risk areas and by operating wells in which we have a majority net revenue interest.  Our drilling efforts have been, and for the foreseeable future will continue to be, focused on the Wattenberg Field as it yields consistent results.

We believe that our basic strategy is sound whether oil and gas prices are high or low.  To reduce the risk of commodity price volatility, we generally hedge a portion of the revenues we will receive for our expected future production.  However, the most important aspect of our business that we can control is the costs associated with finding and developing our reserves.  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 oil and natural gas.  These costs not only include the capital required to drill and complete wells, but also general overhead operating and financing costs.

30

Our senior management team includes individuals with over thirty-three years of oil and gas operating experience in the Wattenberg Field in all types of commodity price environments.  Their experience has shown that in times of lower commodity prices it is imperative to control costs across the entire operating and corporate overhead spectrum.  Historically we have been one of the lowest cost producers in the Wattenberg Field and we are continuing to apply our proven acumen to lower future drilling and completion (“D&C”) costs.  Given this focus on cost, we anticipate we can achieve attractive economic rates of return even with current low commodity prices.  Our most recent budget for drilling and completing wells is approximately 13% lower than wells we brought into production less than sixty days ago and we believe we can realize another 10-20% reduction in D&C costs over the next twelve months.  With these efficiencies in hand, we believe we have a sustainable business model in almost any commodity price environment.

Historically, our cash flow from operations has not been sufficient to fund all of our growth plans and we relied on proceeds from the sale of debt and equity securities to provide adequate liquidity.  We also arranged for a bank credit facility to fund additional capital needs.  During the three months ended November 30, 2014, the primary sources of our capital resources was cash on hand at the beginning of the year, cash flow from operations, proceeds from our revolving credit facility and proceeds from the exercise of outstanding warrants.  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

Drilling operations

We employed three drilling rigs for most of the first fiscal quarter.  We began the fiscal year using two rigs.  One rig was drilling at the Weld 152 location and a second rig was drilling at the Kiehn location.  We contracted a third Ensign rig in September 2014 to drill eight wells on our Wiedeman pad.

Our horizontal wells are currently being drilled under contracts with Ensign United States Drilling, Inc. (“Ensign”).  To date, pricing is on a turn-key basis, with pricing adjustments based upon well location, target formation, and other technical details.  Two of the rigs fulfilled their contract obligations subsequent to November 30, 2014 and were released.  The third rig continues to drill wells at the Weis prospect.  We are currently negotiating future rig usage and pricing with Ensign.
 
Rig 134 completed drilling six wells at the Weld 152 location and moved to the Geis location.  All the wells at the Weld 152 location were stimulated with a hydraulic fracturing process during the quarter and commenced production during the month of November.  At the Geis location, Rig 134 drilled a total of eight wells, six of which were classified as wells in progress at quarter end, and two of which were spud subsequent to November 30, 2014.  Rig 134 was released after completing drilling at the Geis location.

Rig 131 drilled eight wells at the Keihn location and moved to the Weis location where it is scheduled to drill five wells.  Drilling operations on two of the Weis wells were completed by the end of November and three Weis wells will be drilled during our second fiscal quarter.

During the quarter, Rig 138 drilled six wells at our Weideman location.  Subsequent to November 30, 2014, the rig finished drilling two additional Weideman wells and was released.

31

We commenced production from eight wells during our first fiscal quarter. We are finalizing plans to commence production for 29 wells, which include the 23 wells in progress at November 30, 2014 and the 6 wells drilled in December and January. Our completion plans will consider current market conditions and will be tailored to provide the most advantageous cash flow to us. We expect the completion process to take several months.

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”) for a total purchase price of $125 million.  The purchase price was composed of $75 million in cash and $50 million in restricted common stock.

The Bayswater acquisition encompasses 5,040 gross (4,053 net) acres with rights to the Codell and Niobrara formations, and 2,400 gross (1,739 net) acres with rights to other formations including the Sussex, Shannon and J-Sand.  Additionally, we acquired non-operated working interests in 17 horizontal wells, all of which have been completed and are in the early phase of production, and 73 operated vertical wells as well as working interests in 11 non-operated vertical wells.  The working interests in the horizontal wells ranges from 6% to 40% while the working interests in the vertical wells ranges from 5% to 100%.
 
Preliminary estimates indicate that the undeveloped acreage will potentially support an additional 150 horizontal drilling locations.  We have no drilling commitments relative to this acquisition and all leases are held by production.  The leases are generally located in the southern portion of the field where infrastructure and lower gathering line pressures enables more efficient development.  We are encouraged by the initial results from the recent non-operated horizontal well completions and are evaluating the economic return potential of future development efforts.

Fifth Amendment to Revolving Credit Facility (“LOC”)

We continue to improve our borrowing arrangements to complement our growth strategy. On December 15, 2014, the Company amended its LOC.  Under the amendment, the maximum loan commitment is $500 million; however, the maximum amount the Company can borrow at any one time is subject to a borrowing base limitation, which stipulates that the Company may borrow up to the lesser of the maximum loan commitment or the borrowing base.  The borrowing base can increase or decrease based upon the value of the collateral, which secures any amounts borrowed under the line of credit.  For the most part, the value of the collateral will be derived from the estimated future cash flows of the Company’s proved oil and gas reserves, discounted by 10%.  Under the amendment, the initial borrowing base was set at $230 million.

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.  Amounts borrowed under the LOC are secured by substantially all of the Company’s producing wells and developed oil and gas leases.  In the unlikely event the Company fails to make any interest or principal payments when due or breaches any representation, warranty or covenant or defaults in the timely performance of any other obligation in its agreements with the funding banks, amounts due under the LOC will become immediately due and payable.

Under the December 15, 2014 amendment, the interest rate on outstanding borrowings will be based on a pricing grid, which escalates with utilization and establishes a minimum of 2.5%.  The LOC, as amended, expires on December 15, 2019.

32

Commodity contracts

We utilize swaps and collars on a portion of our expected future oil and gas production to reduce the impact of commodity price changes.  Our objective in using derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk.  Using swaps and collars, we have contracted for approximately 1.0 million barrels of oil and 1.3 million mcf of gas through December 31, 2016.  Since we designed our commodity derivative activity to protect our cash flow during periods of oil and gas price declines, the low average prices experienced during the first quarter of 2015 created a realized gain of $1.4 million for the first quarter.  Additionally, at the end of the first quarter of fiscal 2015, the decline in posted prices created a $16.7 million unrealized gain in the fair market value of our commodity derivatives.

Market Conditions

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

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

For the periods presented in this report, the following table presents the average NYMEX price as well as the differential between the NYMEX prices and the wellhead prices realized by us.
 
 
 
Three Months Ended
 
 
 
November 30,
   
November 30,
 
Oil (NYMEX WTI)
 
2014
   
2013
 
Average NYMEX Price
 
$
84.47
   
$
100.23
 
Realized Price
 
$
73.69
   
$
93.06
 
Differential
 
$
10.78
   
$
7.17
 
 
               
Gas (NYMEX Henry Hub)
               
Average NYMEX Price
 
$
3.94
   
$
3.65
 
Realized Price
 
$
4.74
   
$
4.86
 
Differential
 
$
0.80
   
$
1.21
 
 
Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX.  The negative differential was larger during the first quarter of fiscal 2015 when compared to the 2014 fiscal first quarter.  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.

During our fiscal 2015 first quarter ended November 30, 2014, the industry experienced a significant commodity price decline.  As reflected in published data, the price for West Texas Intermediate (WTI) oil settled at $97.86/bbl on Friday, August 29, 2014, the last trading day of our 2014 fiscal year.  The price of WTI settled at $65.94 per barrel on Friday November 28, 2014, which equates to an approximate 33% decline in oil prices during our fiscal first quarter.  The price of oil continued to decline subsequent to November 30, 2014, and settled at $48.65/bbl on Wednesday, January 7, 2015.  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.

33

A decline in oil prices will adversely affect our financial condition and results of operations.  Furthermore, low oil prices affect the value of our oil and gas 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 first quarter, the ceiling test amount was greater than our recorded costs and we did not record an impairment.  If low oil and gas prices continue through the second quarter, we will calculate the ceiling test with the lower prices, and will record an impairment if the ceiling test amount is less than our recorded costs.


RESULTS OF OPERATIONS

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

For the three months ended November 30, 2014, compared to the three months ended November 30, 2013

For the three months ended November 30, 2014, we reported net income of $21.2 million compared to $6.1 million during the three months ended November 30, 2013.  Earnings per basic and diluted share were $0.27 per basic and $0.26 per diluted share for the three months ended November 30, 2014 compared to $0.08 per basic and diluted share for the three months ended November 30, 2013.  Rapid growth in reserves, producing wells and daily production totals, as well as the impact of changing prices on our commodity hedge positions drove this increase.  The significant variances between the two years were primarily caused by increased revenues and expenses associated with production from 33 new horizontal wells and the acquisition of producing properties included in the Trilogy and Apollo transactions as well as increased production from our horizontal wells, as described previously.  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 November 30, 2014 we recorded total oil and gas revenues of $42.5 million compared to $19.3 million for the three months ended November 30, 2013, an increase of $23.3 million or 120.8%.

As of November 30, 2014, we owned interests in 297 net producing wells.  Net oil and gas production for the three months ended November 30, 2014 averaged 8,278 BOE per day. For the three months ended November 30, 2013, production averaged 3,208 BOE per day, a year-over-year increase of 158%.  As a further comparison, average BOE production was 5,894 per day during the quarter ended August 31, 2014, a quarter-over-quarter increase of 40.4%.  The significant increases in production from the comparable prior periods reflect our increased well count and shift to horizontal wells, each as discussed previously.

Our revenues are also sensitive to changes in commodity prices.  As shown in the following table, there has been a decrease of 14% in average realized prices between the periods presented.  The following table presents actual realized prices, without the effect of hedge transactions.  The impact of hedge transactions is presented later in this discussion.
 

 
34

Key production information is summarized in the following table:

  
 
Three Months Ended
   
 
  
 
November 30,
2014
   
November 30,
2013
   
Change
 
Production:
 
   
   
 
Oil (Bbls1)
   
466,656
     
168,278
     
177
%
Gas (Mcf2)
   
1,719,938
     
741,755
     
132
%
 
                       
Total production in BOE3
   
753,312
     
291,904
     
158
%
 
                       
Revenues (in thousands):
                 
 Oil
 
$
34,386
   
$
15,660
     
120
%
 Gas
   
8,152
     
3,606
     
126
%
  
 
$
42,538
   
$
19,266
     
121
%
Average sales price:
                       
 Oil
 
$
73.69
   
$
93.06
     
-21
%
 Gas
 
$
4.74
   
$
4.86
     
-2
%
 BOE
 
$
56.47
   
$
66.00
     
-14
%


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


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

  
 
Three Months Ended
 
  
 
November 30,
   
November 30,
 
 
 
2014
   
2013
 
Production Costs
 
$
3,035
   
$
1,203
 
Work-Over
   
6
     
70
 
Lifting cost
   
3,041
     
1,273
 
Severance and ad valorem taxes
   
4,178
     
2,016
 
Total LOE
 
$
7,219
   
$
3,289
 
 
               
Per BOE:
               
Production costs
 
$
4.03
   
$
4.12
 
Work-Over
   
0.01
     
0.24
 
Lifting cost
   
4.04
     
4.36
 
Severance and ad valorem taxes
   
5.55
     
6.91
 
Total LOE
 
$
9.59
   
$
11.27
 
 
35

Lease operating and work-over costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas.  Taxes make up the largest single component of direct costs and tend to increase or decrease primarily based on the value of oil and gas sold.  As a percent of revenues, taxes averaged approximately 10% for the three months ended November 30, 2014 and 2013.

During the first quarter of fiscal 2015, we continued to experience elevated production cost per BOE in connection with additional costs to bolster output from some of our older wells as well as additional costs to operate horizontal wells.  We continue to work diligently to mitigate production difficulties within the Wattenberg Field.  Additional wellhead compression has been added at some well locations and older equipment has been replaced or refurbished.  As expected, horizontal wells are more costly to operate than vertical wells, especially during the early stages of production.  Finally, costs incurred to comply with new environmental regulations are significant.

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

  
 
Three Months Ended
 
  
 
November 30,
   
November 30,
 
(in thousands)
 
2014
   
2013
 
Depletion
 
$
16,304
   
$
5,490
 
Depreciation and amortization
   
150
     
101
 
Total DDA
 
$
16,454
   
$
5,591
 
 
               
DDA expense per BOE
 
$
21.84
   
$
19.15
 
 
For the three months ended November 30, 2014, depletion of oil and gas properties was $21.84 per BOE compared to $19.15 for the three months ended November 30, 2013.  The increase in the DDA rate was the result of an increase in both the ratio of reserves produced and the total costs capitalized in the full cost pool.  Capitalized costs of evaluated oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning-of-quarter estimated total reserves determine the depletion rate.  For the three months ended November 30, 2014, production represented 2.3% of the reserve base compared to 2.1% for the three months ended November 30, 2013.  A contributing factor to the change in the ratio was the inclusion of additional horizontal wells in the calculation.  Consistent with the expected decline curve for wells targeting the Niobrara and Codell formations, we expect horizontal wells to exhibit robust production during the first few weeks, decline rapidly over the first six months, and eventually stabilize over an expected life in excess of 30 years.

In addition to a change in the ratio of production to reserves, our DDA rate was affected by the increasing costs of mineral leases, included as proven properties, and the costs associated with the acquisition of producing properties.  Leasing costs in the D-J Basin continue to increase with the success of horizontal development.  The allocation of the purchase price related to the November 2013 acquisitions of Trilogy Resources, LLC and Apollo Operating, LLC was at a higher cost per BOE than our historical cost of acquiring leaseholds and developing our properties.  Therefore, the increase in the ratio of costs subject to amortization to the reserves acquired is greater than our internally developed properties.  Both of these acquisitions include areas that have the potential for future development.  Successful horizontal development of these areas would have the impact of reducing cost per BOE.

36

General and Administrative (“G&A”) –The following table summarizes G&A expenses incurred and capitalized during the periods presented:
 
 
  
 
Three Months Ended
 
  
 
November 30,
   
November 30,
 
(in thousands)
 
2014
   
2013
 
G&A costs incurred
 
$
4,613
   
$
3,485
 
Capitalized costs
   
(503
)
   
(317
)
Total G&A
 
$
4,110
   
$
3,168
 
 
               
G&A Expense per BOE
 
$
5.46
   
$
10.85
 
 

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

Although G&A costs have increased as we grow the business, we strive to maintain an efficient overhead structure.  For the quarter ended November 30, 2014, G&A was $5.46 per BOE compared to $10.85 for the quarter ended November 30, 2013, primarily as a result of the increase in BOE produced during the first quarter of fiscal 2015 compared to comparable first quarter of 2014.

Our G&A expense for the quarter ended November 30, 2014 includes stock-based compensation of $0.8 million compared to $0.4 million for the quarter ended November 30, 2013.  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 2013 to 2014 reflects our increasing activities to acquire leases and develop the properties.

Other income (expense) – Neither interest expense nor interest income had a significant impact on our results of operations for the periods presented.  The interest costs that we incurred under our credit facility were eligible for capitalization into the full cost pool.  We capitalize interest costs that are related to the cost of assets during the period of time before they are placed into service.

Commodity derivative gains (losses) – As more fully described in the paragraphs titled “Oil and Gas Commodity Contracts” and “Hedge Activity Accounting” located in “Liquidity and Capital Resources,” we use commodity contracts to mitigate the risks inherent in the price volatility of oil and natural gas.  For the quarter ended November 30, 2014, we recorded an unrealized gain of $16.7 million to recognize the mark-to-market change in fair value of our commodity contracts for the quarter ended November 30, 2014.  In comparison, in the quarter ended November 30, 2013, we reported an unrealized gain of $2.6 million.  Unrealized gains and losses are non-cash items.
 

 
37

In addition, for the quarter ended November 30, 2014, we realized a cash settlement gain of $1.4 million related to contracts that settled during the quarter.  For the quarter ended November 30, 2013, we realized a loss of $398,000.

Income taxes – We reported income tax expense of $11.7 million for the three months ended November 30, 2014, calculated at an effective tax rate of 35.7%.  During the comparable prior year period, we reported income tax expense of $3.4 million, calculated at an effective tax rate of 35.7%.  For both periods, it appears that the tax liability will be substantially deferred into future years. During fiscal year 2015, we estimate that the effective tax rate will be reduced from the federal and state statutory rate by the impact of deductions for percentage depletion.

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

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


LIQUIDITY AND CAPITAL RESOURCES

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

Sources and Uses

At November 30, 2014, we had cash and cash equivalents of $47.1 million and an outstanding balance of $77.0 million under our revolving credit facility.  Our sources and (uses) of funds for the three months ended November 30, 2014, and 2013 are summarized below (in thousands):
 
 
 
Three Months Ended
 
 
 
November 30,
   
November 30,
 
 
 
2014
   
2013
 
Cash provided by operations
 
$
34,435
   
$
14,913
 
Capital expenditures
   
(66,137
)
   
(57,127
)
Other investing activities
   
(6,250
)
   
19,987
 
Cash provided by equity financing activities
   
10,310
     
23,737
 
Net borrowings
   
40,000
     
-
 
Net increase in cash and cash equivalents
 
$
12,358
   
$
1,510
 
 
 
38

 
Net cash provided by operating activities was $34.4 million and $14.9 million for the three months ended November 30, 2014 and 2013, respectively.  The significant improvement primarily reflects the operating contribution from new wells that were drilled and producing wells that were acquired.  The increase in net cash provided by operations allowed us to become less reliant on equity sales for financing our capital expenditures in fiscal 2015.

During the quarter, we received cash proceeds of $10.7 million from the exercise of Series C warrants.  Subsequent to November 30, 2014, additional Series C warrants were exercised and provided cash proceeds of $4.7 million.  As of December 31, 2014, all Series C warrants had been exercised.

Credit Arrangements

We maintain a borrowing arrangement with a syndicate of banks.  The arrangement, in the form of a revolving credit facility, was most recently amended on December 15, 2014.  The title of the most recent amendment is Fifth Amendment to Amended and Restated Credit Agreement (“Fifth Amendment”).  The Fifth Amendment increased the loan commitment from $300 million to $500 million and increased the borrowing base from $110 million to $230 million.  The borrowing base includes a “non-conforming” component of $30 million.

The Fifth Amendment expanded the bank syndicate to eight members and named SunTrust Bank as Administrative Agent and named KeyBank, National Association as Syndication Agent.  The maturity date of the loan commitment was extended to December 15, 2019.

Interest on our revolving line of credit accrues at a variable rate, which will equal or exceed the minimum rate of 2.5%.  The interest rate pricing grid contains a graduated escalation in applicable margin for increased utilization.  At our option, interest rates will be referenced to the Prime Rate plus a margin of 0.5% to 2.75%, or the London InterBank Offered Rate plus a margin of 1.75% to 4.00%.  

As of December 15, 2014, after giving effect to additional borrowings related to the Bayswater acquisition, we had approximately $84 million available for future borrowings, if needed.  Additional borrowings, if any, are expected to be used to fund acquisitions, expenditures for well drilling and development, and to provide working capital.

The arrangement contains covenants that, among other things, restrict the payment of dividends and require compliance with certain financial ratios.  The borrowing arrangement is primarily collateralized by certain of our assets, including producing properties.  The maximum lending commitment is subject to reduction based upon a borrowing base calculation, which will be re-determined based upon semi-annual reserve reports with effective dates of August 31 and February 28.    

Reconciliation of Cash Payments to Capital Expenditures

Capital expenditures reported in the statement of cash flows are calculated on a strict cash basis, which differs from the “all-inclusive” basis used to calculate other amounts reported in our financial statements.  Specifically, cash payments for acquisition of property and equipment as reflected in the statement of cash flows excludes non-cash capital expenditures and includes an adjustment (plus or minus) to reflect the timing of when the capital expenditure obligations are incurred and when the actual cash payment is made.  On the “all-inclusive” basis, capital expenditures totaled $64.2 million and $69.0 million for the three months ended November 30, 2014 and 2013, respectively.  A reconciliation of the differences between cash payments and the “all-inclusive” amounts is summarized in the following table (in thousands):

 
 
Three Months Ended
 
 
 
November 30,
   
November 30,
 
 
 
2014
   
2013
 
Cash payments for capital expenditures
 
$
66,137
   
$
57,127
 
Accrued costs, beginning of period
   
(71,849
)
   
(25,491
)
Accrued costs, end of period
   
69,511
     
26,813
 
Non-cash acquisitions, common stock
   
-
     
9,898
 
Other
   
383
     
692
 
All inclusive capital expenditures
 
$
64,182
   
$
69,039
 
 
39

Capital Expenditures

The majority of capital expenditures during the three months ended November 30, 2014, were applied to drilling or completion activities on wells which we operate.  Eight operated wells reached productive status during the quarter and 23 operated wells were in various stages of drilling or completion as of November 30, 2014.  We participated in drilling and completion activities on 47 gross (6.6 net) non-operated wells.

As of November 30, 2014, there were 34 wells in progress (23 net) with accrued capital expenditures of $65.9 million.

Other expenditures included $ 4.9 million for the acquisition of lands, leases and other mineral assets.

Capital Requirements

Our primary need for cash will be to fund our drilling and acquisition programs for the remainder of the fiscal year ending August 31, 2015.  Our cash requirements have increased significantly as we implement our horizontal drilling program.  Standard length horizontal wells we drilled early in the fiscal year are estimated to cost between $3.5 million and $3.8 million each.  However, as commodity prices have dropped we have negotiated lower costs from our service providers and revised our completion design and now are budgeting that the remaining wells to be drilled this fiscal year will cost between $3.0 million and $3.3 million each.  In order to maximize the efficient use of our capital we have reduced the amount of non-operated working interests in wells operated by others, either by swapping interests when appropriate or by outright selling of interests.  With this reallocation of drilling capital we believe we will drill more wells for less cost than we had originally estimated.  Our plans now call for drilling 43 to 45 operated wells (up from 35 to 40) and participating in 3 to 4 (net) non-operated wells.  Our revised fiscal 2015 budget calls for spending $190 million to $195 million for drilling and leasing activities compared to $200 million to $225 million in our original budget.

We plan to generate profits by producing oil and natural gas from wells that we drill or acquire.  For the near term, we believe that we have sufficient liquidity to fund our needs through cash on hand, cash flow from operations, and additional borrowings under our revolving credit facility.  However, to meet all of our long-term goals, we may need to raise some of the funds required to drill new wells through the sale of our securities, from our revolving credit facility or from third parties willing to pay our share of drilling and completing the wells.  We may not be successful in raising the capital needed to drill or acquire oil or gas wells.  Any wells which may be drilled by us may not produce oil or gas in commercial quantities.

Oil and Gas Commodity Contracts

We use derivative contracts to hedge against the variability in cash flows created by short-term price fluctuations associated with the sale of future oil and gas production.  Our hedge positions will generally cover a substantial portion of our forecasted production for a period of 24 months.  We typically enter into contracts covering between 45% and 85% of anticipated production levels.  During the three months ended November 30, 2014, we realized a cash gain from commodity derivatives of $1.4 million.  Our contracts during the three months ended November 30, 2014 covered crude oil sales of 177,000 bbls and natural gas sales of 330,000 mcf.  At November 30, 2014, we had open positions covering 978,000 bbls of oil and 1.3 million mcf of natural gas.  We do not use derivative instruments for speculative purposes.

Hedge Activity Accounting

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

During the quarter ended November 30, 2014, we reported an unrealized commodity activity gain of $16.7 million.  Unrealized gains and losses are non-cash items.  We also reported a realized gain of $1.4 million, representing the cash settlement proceeds for contracts settled during the period.

At November 30, 2014, we estimated that the fair value of our various commodity derivative contracts was a net asset of $16.5 million.  We value these contracts using fair value methodology that considers various inputs including a) quoted forecast prices, b) time value, c) volatility factors, d) counterparty risk, and e) other relevant factors.  The fair value of these contracts as estimated at November 30, 2014 may differ significantly from the realized values at their respective settlement dates.


40

Non-GAAP Financial Measures

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

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

The following table presents a reconciliation of adjusted EBITDA, a non-GAAP financial measure, to net income, its nearest GAAP measure:
 
 
 
Three Months Ended
 
 
 
November 30
   
November 30
 
(in thousands)
 
2014
   
2013
 
Adjusted EBITDA:
 
   
 
Net income
 
$
21,151
   
$
6,100
 
Depletion, depreciation and amortization
   
16,454
     
5,591
 
Provision for income tax
   
11,744
     
3,387
 
Stock-based compensation
   
793
     
419
 
Commodity derivative change
   
(16,708
)
   
(2,636
)
Interest income
   
-
     
(31
)
Adjusted EBITDA
 
$
33,434
   
$
12,830
 

 
TRENDS AND OUTLOOK

Oil prices traded as high as $107/bbl in June 2014, and have since declined more than 55%.  A continuing decline in oil and gas prices (i) will reduce our cash flow which, in turn, will reduce the funds available for exploring and replacing oil and gas reserves, (ii) will potentially reduce our current LOC borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of oil and gas prospects which have reasonable economic terms, (iv) may cause us to permit leases to expire based upon the value of potential oil and gas reserves in relation to the costs of exploration, and (v) may result in marginally productive oil and gas wells being abandoned as non-commercial.  However, price declines reduce the competition for oil and gas properties and correspondingly reduce the prices paid for leases and prospects.

During our first fiscal quarter, we employed three drilling rigs.  Our obligations under the contracts are scheduled to terminate during our second fiscal quarter and we retain the flexibility to adjust our rig count based on current market conditions.  All of the rigs are drilling multi-well pads in the Wattenberg Field.  Our focus on the Wattenberg Field is driven by the increasingly compelling results derived from higher density of wells drilled per spacing unit and the optimization of completion techniques.  We are currently spacing our well bores to allow for up to 24 wells per section of 640 acres and we are testing drilling patterns that could lead to an even higher number of wells per section.  We are also testing longer lateral wells and utilizing different amounts of proppant in order to determine the most efficient recovery of the hydrocarbons in place.

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

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

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

The success of horizontal drilling techniques in the D-J Basin has significantly increased quantities of oil and natural gas produced in the region.  Local refineries do not have sufficient capacity to process all of the crude oil available.  The imbalance of supply and demand in the area is expected to result in an increase in oil transported from the D-J Basin to other markets, generally via pipeline or railroad car.  The imbalance is having an impact on prices paid by oil purchasers and increased the differential between crude oil prices posted on NYMEX and the average wellhead prices realized by us.  Further details regarding posted prices and average realized prices are discussed in the section entitled “Market Conditions,” presented in this Item 2.  We continue to explore various alternatives with various oil purchasers, including a local refiner and an oil pipeline that we believe will provide sufficient take-away capacity for all of our oil production. 

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

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

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

 
CRITICAL ACCOUNTING POLICIES

There have been no changes in our critical accounting policies since August 31, 2014, and a detailed discussion of the nature of our accounting practices can be found in the section titled “Critical Accounting Policies”  in Part II, Item 7 of our Annual Report on Form 10-K for the year ended August 31, 2014.

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as “believes”, “expects”, “anticipates”, “intends”, “plans”, “estimates”, “should”, “likely” or similar expressions, indicates a forward-looking statement.

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

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

 
 
volatility of oil and natural gas prices;
 
 
operating hazards that result in losses;
 
 
uncertainties in the estimates of proved reserves;
 
 
effect of seasonal weather conditions and wildlife restrictions on our operations;
 
 
our need to expand our oil and natural gas reserves;
 
 
our ability to obtain adequate financing;
 
 
availability and capacity of gathering systems and pipelines for our production;
 
 
effect of local and regional factors on oil and natural gas prices;
 
 
incurrence of ceiling test write-downs;
 
 
our inability to control operations on properties we do not operate;
 
 
our ability to market our production;
 
 
the strength and financial resources of our competitors;
 
 
identifying future acquisitions;
 
 
uncertainty in global economic conditions;
 
 
legal and/or regulatory compliance requirements;
 
 
the amount of our indebtedness and ability to maintain compliance with debt covenants;
 
 
our need for capital;
 
 
key executives allocating a portion of their time to other business interests; and
 
 
effectiveness of our disclosure controls and our internal controls over financial reporting.

 
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Item 3.  Quantitative and Qualitative Disclosures About Market Risks

Commodity Price Risk - Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas.   The volatility of oil prices affects our results to a greater degree than the volatility of gas prices, as approximately 81% of 2014 revenues were from the sale of oil.  During the last few months, the price of oil as declined significantly.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil, the global supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, the strength of the U.S. dollar compared to other currencies, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources.

We attempt to mitigate fluctuations in short-term cash flow resulting from changes in commodity prices by entering into derivative positions on a portion of our expected oil and gas production.  We use derivative contracts to cover no less than 45% and no more than 85% of expected hydrocarbon production, generally over a period of two years.  We do not enter into derivative contracts for speculative or trading purposes.  As of November 30, 2014, we had open crude oil derivatives in a net asset position with a fair value of $16.5 million.  A hypothetical upward shift of 10% in the NYMEX forward curve of crude oil and natural gas prices would reduce the fair value of our position by $5.6 million.  A hypothetical downward shift of 10% in the NYMEX forward curve of crude oil and natural gas prices would increase the fair value of our position by $5.8 million.

During the quarter ended November 30, 2014, there was a material decline in the price of oil, thus increasing the underlying commodity price risk.

Interest Rate Risk - At November 30, 2014, we had debt outstanding under our bank credit facility totaling $77.0 million.  Interest on our bank credit facility accrues at a variable rate, based upon either the Prime Rate or the London InterBank Offered Rate (LIBOR).  At November 30, 2014, we were incurring interest at a rate of 2.5%.  We are exposed to interest rate risk on the bank credit facility if the variable reference rates increase.  A decrease in the variable interest rates would not have a significant impact on us, as the bank credit facility has a minimum interest rate of 2.5%.  If interest rates increase, our monthly interest paymen