UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

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

 

For the quarterly period ended September 30, 2016

OR

 

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

 

Commission File Number: 001-33578

 

Samson Oil & Gas Limited

(Exact Name of Registrant as Specified in its Charter)

 

Australia N/A
(State or Other Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification No.)

 

Level 16, AMP Building,

140 St Georges Terrace

Perth, Western Australia 6000

 
(Address Of Principal Executive Offices) (Zip Code)

 

+61 8 9220 9830

(Registrant’s Telephone Number, Including Area Code)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   x   Yes     ¨    No

 

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

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer ¨ Accelerated filer     ¨
     
Non-accelerated filer ¨ Smaller reporting company     x

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ¨ No x

 

There were 3,215,854,701 ordinary shares outstanding as of November 11, 2016.

 

 

 

 

SAMSON OIL & GAS LIMITED

FORM 10-Q

QUARTER ENDED September 30, 2016

 

TABLE OF CONTENTS

 

    Page
     
Part I — Financial Information 3
     
Item 1. Financial Statements (unaudited) 3
   
Consolidated Balance Sheets, September 30, 2016 and June 30, 2016 3
   
Consolidated Statement of Operations and Comprehensive Income (Loss) for the three months ended September 30, 2016 and 2015 4
   
Consolidated Statement of Changes in Stockholders’ Equity/(Deficit) for the three months ended September 30, 2016 5
   
Consolidated Statement of Cash Flows for the three months ended September 30, 2016 and 2015 6
   
Notes to  Consolidated Financial Statements (unaudited) 7
     
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operation 14
     
Item 3. Quantitative and Qualitative Disclosures About Market Risk 21
     
Item 4. Controls and Procedures 21
   
Part II   — Other Information 21
     
Item 1. Legal Proceedings 21
     
Item 1A. Risk Factors 21
     
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 21
     
Item 3. Defaults Upon Senior Securities 21
     
Item 4. Mine Safety Disclosures 21
     
Item 5. Other Information 22
     
Item 6. Exhibits 22
     
Signatures 23

 

i  

 

 

FORWARD-LOOKING STATEMENTS

 

Written forward–looking statements may appear in documents filed with the Securities and Exchange Commission (“SEC”), including this quarterly report, documents incorporated by reference, reports to shareholders and other communications.

 

The U.S. Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for forward–looking information to encourage companies to provide prospective information about themselves without fear of litigation so long as the information is identified as forward looking and is accompanied by meaningful cautionary statements identifying important factors that could cause actual results to differ materially from those projected in the information. Samson relies on this safe harbor in making forward–looking statements.

 

Forward–looking statements appear in a number of places in this quarterly report and include but are not limited to management’s comments regarding business strategy, exploration and development drilling prospects and activities at our oil and gas properties, oil and gas pipeline availability and capacity, natural gas and oil reserves and production, meeting our capital raising targets and following any use of proceeds plans, our ability to and methods by which we may raise additional capital, production and future operating results.

 

In this quarterly report, the use of words such as “anticipate,” “continue,” “could,” “estimate,” “expect,” “likely,” “may,” “will,” “project,” “should,” “believe” and similar expressions are intended to identify uncertainties. While we believe that the expectations reflected in those forward–looking statements are reasonable, we cannot assure you that these expectations will prove to be correct. Our actual results could differ materially from those anticipated in these forward–looking statements. The differences between actual results and those predicted by the forward–looking statements could be material. Forward-looking statements are based upon our expectations relating to, among other things:

 

  · our future financial position, including cash flow, debt levels and anticipated liquidity;

 

  · the timing, effects and success of our exploration and development activities;

 

  · uncertainties in the estimation of proved reserves and in the projection of future rates of production;

 

  · timing, amount, and marketability of production;

 

  · third party operational curtailment, processing plant or pipeline capacity constraints beyond our control;

 

  · our ability to acquire and dispose of oil and gas properties at favorable prices;

 

  · our ability to market, develop and produce new properties;

 

  · declines in the values of our properties that may result in write-downs;

 

  · effectiveness of management strategies and decisions;

 

  · oil and natural gas prices and demand;

 

  · unanticipated recovery or production problems, including cratering, explosions, fires;

 

  · the strength and financial resources of our competitors;

 

  · our entrance into transactions in commodity derivative instruments;

 

  · climatic conditions; and

 

Many of these factors are beyond our ability to control or predict. Neither these factors nor those included in the “Risk Factors” section of this quarterly report represent a complete list of the factors that may affect us.  We do not undertake to update the forward–looking statements made in this report.

 

  2  

 

 

Part I — Financial Information

Item 1.   Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

    30-Sep-16     30-Jun-16  
ASSETS                
CURRENT ASSETS                
Cash and cash equivalents   $ 1,582,924     $ 2,654,812  
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively     2,286,138       1,996,415  
Prepayments     211,264       183,305  
Oil inventory     219,288       463,768  
Fair value of derivative instrument     -       -  
Oil and gas properties held for sale     13,770,844       13,768,865  
Total current assets     18,070,458       19,067,165  
PROPERTY, PLANT AND EQUIPMENT, AT COST                
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment of $15,519,067 and $15,049,015 at September 30, 2016 and June 30, 2016, respectively     31,544,973       31,522,323  
Other property and equipment, net of accumulated depreciation and amortization of $624,427 and $573,995 at September 30, 2016 and June 30, 2016, respectively     340,742       308,474  
Net property, plant and equipment     31,885,715       31,830,797  
OTHER NON CURRENT ASSETS                
Fair value of derivative instrument     -       -  
Undeveloped capitalized acreage     220,703       220,703  
Restricted cash - bonding     450,000       450,000  
Other     404,364       474,325  
TOTAL ASSETS   $ 51,031,240     $ 52,042,990  
                 
LIABILITIES AND STOCKHOLDERS’ (DEFICIT)/ EQUITY                
CURRENT LIABILITIES                
Accounts payable   $ 4,126,165     $ 4,125,643  
Accruals     1,654,647       1,629,975  
Fair value of derivative instruments     1,410,421       1,671,653  
Promissory Note     4,164,285       4,046,428  
Credit facility     11,500,000       11,500,000  
Provision for annual leave     241,995       194,497  
Total current liabilities     23,097,513       23,168,196  
NON CURRENT LIABILITIES                
Asset retirement obligations     3,515,456       3,450,245  
Fair value of derivative instruments     782,431       1,233,076  
Credit facility     19,000,000       19,000,000  
TOTAL LIABILITIES     46,395,400       46,851,517  
STOCKHOLDERS’ (DEFICIT)/EQUITY – nil par value                
3,215,854,701 (equivalent to 16,079,273 ADR’s) and 3,215,854,701 (equivalent to 16,079,273 ADR’s) ordinary shares issued and outstanding at September 30, 2016 and June 30, 2016, respectively     105,685,180       105,719,184  
Accumulated other comprehensive income     941,531       927,718  
Accumulated deficit     (101,990,871 )     (101,455,429 )
Total stockholders’ (deficit)/equity     4,635,840       5,191,473  
TOTAL LIABILITIES AND STOCKHOLDERS’(DEFICIT)/ EQUITY   $ 51,031,240     $ 52,042,990  

 

See accompanying Notes to Consolidated Financial Statements.

 

  3  

 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

 

    Three months ended  
    30-Sep-16     30-Sep-15  
REVENUES AND OTHER INCOME:                
Oil sales   $ 3,586,208     $ 2,422,583  
Gas sales     142,526       216,747  
Other liquids     15,033       1,346  
Interest income     115       1,535  
Gain on derivative instruments     443,356       372,552  
Other     165,943       17,637  
TOTAL REVENUE AND OTHER INCOME     4,353,181       3,032,400  
                 
EXPENSES:                
Lease operating expense     (2,194,315 )     (1,728,729 )
Depletion, depreciation and amortization     (519,883 )     (1,483,732 )
Impairment expense     (244,480 )     (120,022 )
Exploration and evaluation expenditure     (6,055 )     (493,068 )
Accretion of asset retirement obligations     (79,187 )     (14,888 )
Amortization of borrowing costs     (66,849 )     (35,486 )
Interest expense     (623,393 )     (190,039 )
General and administrative     (1,154,461 )     (1,060,595 )
TOTAL EXPENSES     (4,888,623 )     (5,126,559 )
                 
Loss from operations     (535,442 )     (2,094,159 )
Income tax benefit     -       -  
Net loss     (535,442 )     (2,094,159 )
OTHER COMPREHENSIVE GAIN (LOSS)                
Foreign currency translation gain/(loss)     13,813       (70,784 )
Total comprehensive loss for the period   $ (521,629 )   $ (2,164,943 )
                 
Net loss per ordinary share from operations:                
Basic – cents per share     (0.02 )     (0.07 )
Diluted – cents per share     (0.02 )     (0.07 )
                 
Weighted average ordinary shares outstanding:                
Basic     3,215,854,701       2,837,823,386  
Diluted     3,215,854,701       2,837,823,386  

 

See accompanying Notes to Consolidated Financial Statements.

  

  4  

 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ (DEFICIT)/EQUITY

(Unaudited)

 

                Accumulated Other        
                Other     Total  
    Ordinary           Comprehensive     Stockholders  
    Shares     (Accumulated Deficit)     Income     Deficit  
Balance at June 30, 2016   $ 105,719,184     $ (101,455,429 )   $ 927,718     $ 5,191,473  
Net loss     -       (535,442 )     -       (535,442 )
Foreign currency translation loss, net of tax of $nil     -       -       13,813       13,813  
Total comprehensive loss for the period     -       (535,442 )     13,813       (521,629 )
Cost associated with issue of equity     (34,004 )     -       -       (34,004 )
Balance at September 30, 2016   $ 105,685,180     $ (101,990,871 )   $ 941,531     $ 4,635,840  

 

See accompanying Notes to Consolidated Financial Statements.

 

  5  

 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

    Three months ended  
    30-Sep-16     30-Sep-15  
Cash flows provided by operating activities                
Receipts from customers   $ 3,406,824     $ 4,232,135  
Payments to suppliers & employees     (2,744,718 )     (2,631,047 )
Interest received     115       1,556  
Proceeds from derivative instruments     (188,389 )     19,632  
Interest paid     (402,634 )     (204,948 )
Net cash flows provided by operating activities     71,198       1,417,328  
Cash flows used in investing activities                
Proceeds from sale of oil and gas properties     156,139       -  
Payments for plant & equipment     (77,690 )     -  
Payments for exploration and evaluation     (16,130 )     (299,136 )
Payments for oil and gas properties     (1,199,566 )     (998,516 )
Net cash flows used in investing activities     (1,140,872 )     (1,297,652 )
Cash flows provided by financing activities                
Proceeds from the exercise of options     -       1,475  
Net cash flows provided by financing activities     -       1,475  
Net (decrease) in cash and cash equivalents     (1,069,674 )     121,151  
Cash and cash equivalents at the beginning of the fiscal period     2,654,812       2,062,720  
Effects of exchange rate changes on cash and cash equivalents     (2,214 )     (70,271 )
Cash and cash equivalents at end of fiscal period   $ 1,582,924     $ 2,113,600  

 

See accompanying Notes to Consolidated Financial Statements

 

  6  

 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1. Basis of Presentation

 

These Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial reporting. All adjustments which are normal and recurring by nature, in the opinion of management, necessary for fair statement of Samson Oil & Gas Limited’s (the Company) Consolidated Financial Statements have been included herein. Interim results are not necessarily indicative of expected annual results because of the impact of fluctuations in prices received for oil and natural gas, as well as other factors. In the course of preparing the Consolidated Financial Statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events, and, accordingly, actual results could differ from amounts previously established.

 

The Company’s Consolidated Financial Statements have been prepared on a basis consistent with the accounting principles and policies reflected in the Company’s audited financial statements as of and for the year ended June 30, 2016. The year-end Consolidated Balance Sheet presented herein was derived from audited Consolidated Financial Statements, but does not include all disclosures required by GAAP.

 

It is suggested that these financial statements be read in conjunction with the financial statements and the notes thereto included in the Company’s latest annual report (“Form 10-K”).

 

Accruals.   Accrued liabilities at June 30, 2016 consist primarily of estimates for goods and services received but not yet invoiced. Accrued liabilities at September 30, 2016 primarily consisted of the deposit received from Angelus Energy with respect to the pending acquisition of our North Stockyard properties. This transaction closed on October 28, 2016. The effective date of the transaction was October 29, 2016. The accounting for this divestment will be recognized during the quarter ended December 31, 2016.

 

Prepayments. Prepayments at September 30, 2016 and June 30, 2016 include insurance premiums and other subscription costs paid in advance for the year.

 

Comparatives. Changes have been made to the classification of certain prior period comparatives in order to remain consistent with the current period presentation. These changes have had no material impact on the financial statements.

 

Recent Accounting Standards

 

In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements –Going Concern (“ASU 2014-15”). The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for fiscal years ending after December 15, 2016 and annual and interim periods thereafter. This standard is not expected to have an impact on the Company’s consolidated financial statements and we are currently assessing the expected impact on footnote disclosures.

 

2. Income Taxes

 

The Company has cumulative net operating losses (“NOLs”) that may be carried forward to reduce taxable income in future years. The Tax Reform Act of 1986 contains provisions that limit the utilization of NOLs if there has been a change in ownership as described in Internal Revenue Code Section 382. The Company’s prior year NOLs are limited by IRC Section 382.

 

ASC Topic 740 requires that a valuation allowance be provided if it is more likely than not that some portion or all deferred tax assets will not be realized. The Company’s ability to realize the benefits of its deferred tax assets will depend on the generation of future taxable income through profitable operations. Due to the Company’s history of losses and the uncertainty of future profitable operations, the Company has recorded a full valuation allowance against its deferred tax assets.

 

3. Earnings Per Share

 

Basic earnings (loss) per share is calculated by dividing net earnings (loss) attributable to ordinary shares by the weighted average number of shares outstanding for the period. Under the treasury stock method, diluted earnings per share is calculated by dividing net earnings (loss) by the weighted average number of shares outstanding including all potentially dilutive ordinary shares (which in Samson’s case consists of unexercised stock options). In the event of a net loss, however no potential ordinary shares are included in the calculation of shares outstanding since the impact would be anti-dilutive.  

 

  7  

 

 

The following table details the weighted average dilutive and anti-dilutive securities outstanding, which consist of transferable options to purchase ordinary shares which are tradeable on the ASX (“options”), for the periods presented:

 

    Three months ended  
    30-Sep-16     30-Sep-15  
Dilutive     -       -  
Anti–dilutive     320,615,486       324,626,401  

 

The following tables set forth the calculation of basic and diluted loss per share:

 

    Three months ended  
    30-Sep-16     30-Sep-15  
Net income (loss)   $ (535,442 )     (2,094,159 )
                 
Basic weighted average ordinary shares outstanding     3,215,854,701       2,837,823,386  
Basic earnings per ordinary share – cents per share     (0.02 )     (0.07 )
Diluted earnings per ordinary share – cents per share     (0.02 )     (0.07 )

 

4. Asset Retirement Obligations

 

The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut–in properties at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to those obligations. 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 using the units–of–production method.

 

The amount recorded as a current liability in the current period, relates to work expected to be performed in our Hawk Springs project in Wyoming prior to December 31, 2016.

 

The following table summarizes the activities for the Company’s asset retirement obligations for the three months ended September 30, 2016 and 2015:

 

    Three months ended  
    30-Sep-16     30-Sep-15  
Asset retirement obligations at beginning of period   $ 3,750,245     $ 1,810,674  
Liabilities incurred or acquired     -       -  
Liabilities settled     (13,976 )     (46,130 )
Disposition of properties     -       -  
Accretion expense     79,187       14,888  
Asset retirement obligations at end of period     3,815,456       1,779,432  
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)     (300,000 )     -  
Long-term asset retirement obligations   $ 3,515,456     $ 1,779,432  

 

  8  

 

 

5. Fair Value Measurements

 

Fair value is defined as the price that would be received in the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. The FASB has established a fair value hierarchy that 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 measurement) and the lowest priority to unobservable inputs (level 3 measurement).

 

The three levels of the fair value hierarchy are as follows:

 

  · Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

 

  · Level 2—Pricing inputs are other than quoted prices in active markets included in level 1, but are either directly or indirectly observable as of the reported date and for substantially the full term of the instrument. Inputs may include quoted prices for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies.

 

  · Level 3—Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

 

Financial assets and liabilities are classified in their entirety 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 fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of September 30, 2016 and June 30, 2016.

 

    Carrying value at
September 30, 2016 		    Level 1     Level 2     Level 3     Netting (1)     Fair Value at
September 30, 2016 		 
Current Assets:                                                
Cash and cash equivalents   $ 1,582,924     $ 1,582,924     $ -     $ -     $ -     $ 1,582,924  
Derivative Instruments     -       -       127,936       -       (127,936 )     -  
                                                 
Non Current Assets                                                
Derivative Instruments     -       -       143,102               (143,102 )     -  
                                                 
Current Liabilities                                                
Derivative instruments     1,410,421       -       1,538,357       -       (127,936 )     1,410,421  
                                                 
Non Current Liabilities                                                
Derivative Instruments     782,431       -       925,533               (143,102 )     782,431  
                                                 
    Carrying value at
June 30, 2016 		    Level 1     Level 2     Level 3     Netting (1)     Fair Value at
June 30, 2016 		 
Current Assets:                                                
Cash and cash equivalents   $ 2,654,812     $ 2,654,812     $ -     $ -     $ -     $ 2,654,812  
Derivative Instruments     -       -       136,727       -       (136,727 )     -  
                                                 
Non Current Assets                                                
Derivative Instruments     -       -       220,317       -       (220,317 )     -  
                                                 
Current Liabilities                                                
Derivative instruments     1,671,653       -       1,808,380       -       (136,727 )     1,671,653  
                                                 
Non Current Liabilities                                                
Derivative Instruments     1,233,076       -       1,453,393       -       (220,317 )     1,233,076  

 

(1) Netting In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.

 

  9  

 

 

The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above:

 

Level 1 Fair value Measurements

Fair Value of Financial Instruments.    The Company’s financial instruments consist primarily of cash and cash equivalents, restricted cash, accounts receivable and payable and derivatives (discussed below). The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short–term maturities.

 

Level 2 Fair Measurements

Derivative Contracts. The Company’s derivative contracts consist of oil collars and oil call options. The fair value of these contracts are based on inputs that are either readily available in the public market, such as oil future prices or inputs that can be corroborated from active markets. Fair value is determined through the use of a discounted cash model using applicable inputs discussed above.

 

Other fair value measurements

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis.

The Company also applies fair value accounting guidance to measure non–financial assets and liabilities such as business acquisitions, proved oil and gas properties, and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. These items are primarily valued using the present value of estimated future cash inflows and/or outflows. Given the unobservable nature of these inputs, they are deemed to be Level 3.

 

Some oil and gas properties are stated at fair value as at June 30, 2016. As a result of the significant decline in oil prices experienced in recent months, the carrying value of oil and gas properties was reviewed and subject to impairment costs of $11 million for the twelve months ended June 30, 2016, the majority of which related to our North Stockyard field due to the sustained decrease in the oil price.

 

Following the sale of our North Stockyard property in October 2016, we closed out 42,300 barrels of oil hedges and 220,750 mcf of natural gas hedges at a cost of $169,182 to us, including $165,003 in deferred premiums.

 

6. Commitments and Contingencies

 

The Company has no accrued environmental liabilities for its sites, including sites in which governmental agencies have designated the Company as a potentially responsible party, because it is not probable that a loss will be incurred and the minimum cost and/or amount of loss cannot be reasonably estimated. However, due to uncertainties associated with environmental assessment and remediation activities, future expense to remediate the currently identified sites, and sites identified in the future, if any, could be incurred. Management believes, based upon current site assessments, that the ultimate resolution of any such matters will not materially affect our results of operations or cash flows.

 

From time to time, we are involved in various legal proceedings through the ordinary course of business. While the ultimate outcome is not known, management believes that any resolution will not materially impact the financial statements.

 

7. Capitalized Exploration Expense

 

We use the successful efforts method of accounting for exploration and evaluation expenditure in respect of each area of interest. The application of this policy requires management to make certain estimates and assumptions as to future events and circumstances, in particular the assessment of whether economic quantities of reserves have been found.  Any such estimates and assumptions may change as new information becomes available.

 

Exploration and evaluation assets are assessed for impairment when facts and circumstances indicate that the carrying amount of an exploration and evaluation asset may exceed its recoverable amount.  When assessing for impairment consideration is given to but not limited to the following:

 

§ the period for which Samson has the right to explore;

 

§ planned and budgeted future exploration expenditure;

 

  10  

 

 

§ activities incurred during the year; and

 

§ activities planned for future periods.

  

If, after having capitalized expenditures under our policy, we conclude that we are unlikely to recover the expenditures through future exploitation, then the relevant capitalized amount will be written off to expense.

 

As of September 30, 2016 we had capitalized exploration expenditures of $220,703. This amount primarily relates to costs incurred in connection with our Cane Creek project in Utah.

 

Exploration or divestment activities are continuing in all exploration areas. The outcome of these activities remains uncertain and may result in write offs in future periods if the related efforts prove unsuccessful.

 

8.  Share Capital

 

Issue of Share Capital  

The company has not issued any share capital during the three months ended September 30, 2016.

 

During the three months ended September 30, 2015, 52,279 options with an exercise price of 3.8 cents (Australian) per ordinary share were exercised for net proceeds of $1,475.

 

All options exercised were issued in a public rights offering conducted in June 2013.

 

9. Cash Flow Statement

 

Reconciliation of loss after tax to the net cash flows from operations:

 

    Three months ended  
    30-Sep-16     30-Sep-15  
             
Net loss after tax   $ (535,442 )   $ (2,094,159 )
Depletion, depreciation and amortization     519,883       1,483,732  
Accretion of asset retirement obligation     79,187       14,888  
Impairment expense     244,480       120,022  
Exploration and evaluation expenditure     6,055       493,068  
Amortization borrowing costs     66,849       35,486  
Non cash (gain)/loss on derivative instruments     (711,876 )     (352,920 )
Proceeds from sale of assets     156,139       -  
                 
Changes in assets and liabilities:                
                 
Decrease in receivables     (289,723 )     1,785,424  
Increase/(decrease) in provision for annual leave     47,498       (26,363 )
(Decrease)/Increase in payables     488,148       (41,850 )
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES   $ 71,198     $ 1,417,328  

 

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10. Credit Facility

 

    Three months ended  
    30-Sep-16     30-Sep-15  
Credit facility at beginning of period   $ 30,500,000     $ 18,699,000  
Cash advanced under facility   $ -       -  
Cash committed to be advanced under facility     -          
Repayments     -       -  
Credit facility at end of period (1)   $ 30,500,000     $ 18,699,000  
                 
Less amount of credit facility currently due for repayment within a year, recorded seperately in Current Liabilities   $ (11,500,000 )     -  
Total non current credit facility at end of period     19,000,000       18,699,000  
                 
Funds available for drawdown under the facility     -       -  

 

(1) $11.5 million of the facility has been presented as a current liability as it represents the portion of the facility that was required to be paid down upon the closing of the sale of the North Stockyard field. This sale closed on October 28, 2016 and the pay down of the facility occurred October 31, 2016.

 

In January 2014, we entered into a $25.0 million credit facility with our primary lender, Mutual of Omaha Bank, with an initial borrowing base of $8.0 million, which was increased to $15.5 million in June 2014. In March 2016, the facility was extended to $30.5 million to partly fund the Foreman Butte acquisition. As a result of this amendment to the facility agreement, the following changes were made to the original facility agreement:

· The addition of more restrictive financial covenants (including the debt to EBITDA ratio and the minimum liquidity requirement);
· Increases in the interest rate and unused facility fee;
· The addition of a minimum hedging requirement of 75% of forecasted production;
· A requirement to reduce our general and administrative costs from $6 million per year to $3 million per year;
· A requirement to raise $5 million in equity on or before September 30, 2016 (this was extended to November 15, 2016 and then effective November 10, 2016 Mutual of Omaha agreed that this requirement had been met following the $1.4 million capital raise completed in April 2016 and by the application of retained funds from the North Stockyard sale);
· A requirement to pay down at least $10 million of the loan by June 30, 2016 (which was increased to $11.5 million and extended to October 31, 2016 in line with the closing of the North Stockyard sale) and we repaid $11.5 million on October 31, 2016; and
· The addition of a monthly cash flow sweep whereby 50% of cash operating income will be used to repay outstanding borrowings under the Credit Agreement. No repayments have been made under this covenant.

 

Effective November 10, 2016 Mutual of Omaha increased our borrowing base to $20 million, of which $19 million is drawn. We have entered into further negotiations with Mutual of Omaha and expect a new borrowing base will be determined in early 2017 based on a November 30, 2016 reserve report. While we can make no assurances we believe it is likely that this facility will be syndicated with another bank.

 

The borrowing base under our credit facility may be increased, (up to the credit facility maximum of $50.0 million) or decreased depending on the value of our reserves. Borrowing base redeterminations are performed by the lender every six months based on our June and December reserve reports. While we can make no assurances, we expect the November 2016 redetermination mentioned above will be a wildcard determination, which the facility agreement allows once a year. We also have the ability to request a borrowing base redetermination at another period, once a year. The facility matures October 31, 2017. The interest rate is LIBOR plus 6.00% or approximately 6.30% for the quarter ended September 30, 2016. This decreased to 3.5% plus LIBOR following the pay down of the facility in October 2016.

 

The credit facility includes the following covenants, tested on a quarterly basis:

· Current ratio greater than 1
· Debt to EBITDAX (annualized) ratio no greater than 5.75 for the quarter ended March 30, 2016 through to September 30, 2016 reducing to 4.00 by September 30, 2017
· Senior leverage ratio of no greater than 4.25 to 1 for the quarter ended June 30, 2016 reducing to 3.75 for the quarter ending December 31, 2016 and thereafter
· Interest coverage ratio minimum of between 2.5 and 1.0

 

We were in compliance with all of our covenants as at June 30, 2016.

 

As at September 30, 2016 we were in breach of our spending cap with respect to the general and administrative expenses. We have received a waiver with respect to this covenant.

 

We were in compliance with all other covenants as at September 30, 2016.

 

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If the current pricing environment does not improve it will difficult to maintain compliance with covenants based our current debt levels. If we are not in compliance with the financial covenants in the credit facility, or if we do not receive a waiver from the lender, and if we fail to cure any such noncompliance during the applicable cure period, the due date of our debt could be accelerated by the lender. In addition, failure to comply with any of the covenants under our credit facility could adversely affect our ability to fund ongoing operations.

 

We incurred $0.6 million in borrowing costs (including legal fees and bank fees) in connection with the establishment of this facility which have been deferred and are being amortized over the life of the facility.

 

11. Derivatives

 

The Company has not designated any of its derivative contracts as hedges for accounting purposes. The Company records all derivative contracts at fair value. Changes in derivative contracts are recognized in earnings. Changes in settlements and valuation gains and losses are included in loss/(gain) on derivative instruments in the Statement of Operations. These contracts are settled on a monthly basis. Derivative assets and liabilities arising from the Company’s derivative contracts with the same counterparty that provide for net settlement are reported on a net basis in the Balance Sheet.

 

The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil. The Company seeks to manage this risk through the use of commodity derivative contracts These derivative contracts allow the Company to limit its exposure to commodity price volatility on a portion of its forecasted oil sales. At September 30, 2016, the Company’s commodity derivative contracts consisted of collars and fixed price swaps, which are described below:

 

Collar Collars contain a fixed floor price (put) and fixed ceiling price (call).  If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price.  If the market price is between the call and the put strike price, no payments are due from the either party.
   
Fixed price swap The Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

 

All of the Company’s derivative contracts are with the same counterparty (a large multinational oil company) and are shown on a net basis on the Balance Sheet. The Company’s counterparty has entered into an inter-creditor agreement with the Company’s primary lender, and as such, no additional collateral is required by the counterparty.

 

During the quarter ended September 30, 2016 we recognized $443,356 in gain on derivative instruments in the Statement of Operations.

 

Following the closing of the North Stockyard project, we closed out we closed out a portion of our previous hedge positions in line with the reduced production forecast.

 

Following the sale of our North Stockyard property in October 2016, we closed out 42,300 barrels of oil hedges and 220,750 mcf of natural gas hedges at a cost of $169,182 to us, including $165,003 in deferred premiums.

 

At September 30, 2016 the Company’s open derivative contracts consisted of the following:

 

Collars                                
                              Deferred  
Product   Start Date   End Date   Volume (BO/Mmbtu)     Floor     Ceiling     Premium  
WTI   1-Oct-16   30-Apr-18     110,667       41.50       63.00       (383,070 )
Henry Hub   1-Oct-16   31-Oct-16     32,364       1.90       2.40       -  
Henry Hub   1-Nov-16   31-Mar-17     134,088       2.60       3.35       (17,431 )
Henry Hub   1-Apr-17   31-Oct-17     167,682       2.40       2.91       -  
Henry Hub   1-Nov-17   30-Apr-18     127,030       2.80       3.60       (24,135 )
                                      (424,636 )

 

Costless Swaps                                
Product   Start   End   Volume (BO)     Swap              
WTI   1-Oct-16   31-Dec-16     42,780       41.20                  
WTI   1-Jan-17   31-Dec-17     141,255       44.09                  
WTI   1-Jan-18   30-Apr-18     39,720       45.55                  

 

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12. Subsequent Events

 

On October 28, 2016 we closed on the sale of the North Stockyard properties. The effective date of the transaction was October 29, 2016. The sales price was $15.05 million of which $1.0 million was received as a deposit on June 30, 2016 and is recorded as a payable on September 30, 2016. The assets sold are categorized as held for sale in the Balance Sheet as at September 30, 2016 for the amount of $13.7 million. Upon completion of the sale we will also release $0.4 million in long term liability currently held in our Asset Retirement Obligation as we are no longer responsible for the retirement obligation for the wells sold. On October 31, 2016 we paid down our credit facility with Mutual of Omaha by $11.5 million.

 

Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

The following is management’s discussion and analysis of certain significant factors that have affected aspects of our financial position and the results of operations during the periods included in the accompanying Condensed Financial Statements. You should read this in conjunction with the discussion under “Management's Discussion and Analysis of Financial Condition and Results of Operations” and the audited Financial Statements for the year ended June 30, 2016, included in our Annual Report on Form 10-K and the Consolidated Financial Statements included elsewhere herein.

 

Throughout this report, a barrel of oil or Bbl means a stock tank barrel (“STB”) and a thousand cubic feet of gas or Mcf means a thousand standard cubic feet of gas (“Mscf”).

 

Overview

 

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties.  Our strategy is to focus on the exploration, exploitation and development of our major oil plays – the Madison Group reservoirs in the Williston Basin in Williams and McKenzie Counties, North Dakota, and Roosevelt County in Montana.   Our principal exploratory play is located in the Paradox Basin in Utah.

 

In March 2016 we closed on an acquisition (the “Foreman Butte Acquisition”) of certain assets located in North Dakota and Montana, which we refer to as the “Foreman Butte Project,” for a purchase price of $16 million. The acquired assets consist of producing oil and gas wells, shut in wells and associated facilities. The wells are located in the Madison and Ratcliffe formations. The majority of these wells will be operated by us, however there are a number of non-operated wells also included in this package.

 

Our net oil production was 90,957 barrels of oil for the quarter ended September 30, 2016, compared to 60,723 barrels of oil for the quarter ended September 30, 2015.  The decrease in oil production expected from the natural decline in production witnessed in Bakken wells in our North Stockyard project was offset by the increase in production as a result of the Foreman Butte Acquisition.

 

Our net gas production was 68,580 Mcf for the quarter ended September 30, 2016, compared to 95,559 Mcf for the quarter ended September 30, 2015. Coupled with the expected decrease in production witnessed in the Bakken, during the quarter seven significant gas or associated gas wells were down (and not producing) for a total of 300 days in aggregate. Associated gas produced in the Foreman Butte is not as significant as the oil production, therefore the acquisition has not offset the normal production declines.

 

For the three months ended September 30, 2016 and September 30, 2015, we reported a net loss of $0.5 million and a net loss of $2.1 million, respectively. The loss in the current period reflects $0.5 million in depletion and amortization while the loss in the prior period reflects a $1.5 million depletion, amortization and impairment expenditure. See “Results of Operations” below.

 

In the execution of our strategy, our management is principally focused on economically developing additional reserves of oil and on maximizing production levels through exploration, exploitation and development activities on a cost-effective basis.

 

Notable Activities and Status of Material Properties during the Quarter Ended September 30, 2016 and Current Activities

 

Acquisition: Producing Properties

 

Foreman Butte Project, McKenzie County, North Dakota

Mississippian Madison Formation, Williston Basin

Samson 87% Operated Average Working Interest

We continued our extensive workover program of returning previously shut-in wells to production. This program has resulted in more than a three-times increase in production since we took over operatorship in June. The initial workovers involved five workover rigs completing operations on 32 wells. New workover operations are commencing on additional shut-in wells in an effort to continue to increase oil production.

 

Lease operating expenses have been reduced from those incurred by the previous operator making previously un-economical wells economical in the current pricing environment. We have achieved this by negotiating below-market rig rates and by specifically addressing our chemical and well treatment programs including fresh water and hot oiling. Produced water transportation and disposal has been significantly decreased by optimizing truck routes, disposal destinations, and negotiating reduced rates across the board. Transport and general trucking costs have been nearly eliminated by employing full time employees and owning equipment. Additionally, these crews have allowed us to handle all weed control issues without having to employ contractors to perform this function. We intend to continue to focus on cost control as a key initiative moving forward.

 

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While the initial results of the multi-stage acid stimulation on the Maris 1-16H well are inconclusive, due to an emulsion now being produced with the oil, the fresh water cleanout of the Evans 1-10H well was a success in that it created a two times uplift in production. These two wells are horizontal open hole completions in the Ratcliffe Member of the Mississippian Madison Formation, which is predominantly a limestone reservoir.

 

The multi-stage acid stimulation job on the Maris 1-16H well placed 4,600 bbls of HCl acid and included in addition to other water based fluids, the injection of 4,200 barrels of diversion agent, spacers and pads necessary to complete the placement of acid in 19 stages across 5 zones. The Maris well is currently producing around 20 BOPD and 200 barrels of water per day.

 

The Evans 1-10H fresh water cleanout operation involved pumping 4,000 barrels of water into the wellbore to remove any blockages and salt deposits potentially blocking the well bore or reducing production. The Evans well is currently producing around 60 BOPD and 400 BWPD.

 

We plan to continue to assess the results of both the acid stimulation and the fresh water clean out, however it currently appears as if the remaining 18 wells to be worked over in Foreman Butte Field would be better suited for fresh water cleanouts rather than multi-stage acid stimulations. Importantly a fresh water clean out is substantially less expensive ($100,000) than an acid stimulation ($500,000).

 

We are currently preparing to re-enter the Mission Canyon lateral of the Banks 1-18H well. This well was originally drilled as a dual lateral in the Mission Canyon and Ratcliffe zones, but was never produced from the Mission Canyon lateral due to a stuck whipstock and cast iron bridge plug that was set above the Mission Canyon interval in order to drill the lateral in the shallower Ratcliffe zone. Since the Ratcliffe zone is now depleted for the most part, we are planning to attempt to unseat the stuck whipstock and cast iron bridge plug to access the Mission Canyon lateral. Mudlog and drilling reports show that hundreds of barrels of oil were produced while drilling the Mission Canyon lateral in 2005. While we can make no assurances, if sustained production can be achieved from accessing and producing the Mission Canyon zone, many additional new wells could soon be drilled to delineate a new field discovery.

 

A production efficiency and enhancement study has been initiated that will help identify sub-performing wells, relative to historical and forecasted production. Examples of sub-performance include high fluid levels, inefficient stroke lengths and/or speeds, worn pumps, poor rod designs, and improperly-sized pumping units. Additionally, the study will help quantify important reservoir characteristics, such as connectivity and reservoir pressure, which will be used to model the field and provide direction for appropriate economic development.

 

Undeveloped Properties: Exploration Activities

 

Hawk Springs Project, Goshen County, Wyoming

Permo-Penn Project, Northern D-J Basin

Samson 37.5% working interest

 

A recompletion in the Bluff #1-11 well will be attempted in November 2016. The Jurassic Canyon Springs Formation will be perforated and flow tested first. If this is unsuccessful, the Cretaceous Dakota Formation will subsequently be perforated and flow tested.

 

Spirit of America US34 #2-29 well

Samson 100% Working Interest

This well will be plugged and abandoned during the second quarter of fiscal 2017.

 

Cane Creek Project, Grand & San Juan Counties, Utah

Pennsylvanian Paradox Formation, Paradox Basin

Samson 100% Working Interest

On November 5, 2014, we entered into an Other Business Arrangement (“OBA”) with the Utah School and Institutional Trust Lands Administration (“SITLA”) covering approximately 8,080 gross/net acres located in Grand and San Juan Counties, Utah, all of which are administered by SITLA. We were granted an option period for two years in order to enter into a Multiple Mineral Development Agreement (“MMDA”) with another company who hold leases to extract potash in an acreage position situated within our project area. In November 2015, we paid an extension fee of $40,000 in order to extend the option period to December 2016. Subsequently, the MMDA has been finalized and is awaiting signature by both parties. Upon entering into the MMDA, SITLA is obligated to deliver oil and gas leases covering our project area at cost of $75 per acre to us.

 

This acreage is located in the heart of the Cane Creek Clastic Play of the Paradox Formation along the Cane Creek anticline. The primary drilling objective is the overpressured and oil saturated Cane Creek Clastic interval. Keys to the play to date include positioning along the axis of the Cane Creek anticline and exposure to open natural fractures. The 3-D seismic is currently being designed to image these natural fractures. The seismic shoot was surveyed and permitted this past summer. While we can make no assurances, we believe this project has the potential to provide very robust economics in a low priced oil environment using the evidence obtained from a nearby competitor well that has produced 802,967 BO in just over two years.

 

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Developed Properties: Drilling Activities

 

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Bakken & Three Forks infill wells

Samson ~25-30% working interest

 

The sale of this project area was completed on October 28, 2016. The impact of this sale has not been included in the accounts as September 30, 2016 as the effective date of the transaction was not until October 29, 2016. The project was sold for $15.05 million and its carrying value was $13.7 million as of September 30, 2016.

 

Rainbow Project, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson 23% and 52% working interest

 

In 2013, we acquired 656 acres in a 1,255 acre drilling unit and 294 acres in a 1,280 acre drilling unit. Both drilling units are located in the Rainbow Project, Williams County, North Dakota. The Rainbow Project is located in Sections 17, 18, 19 and 20 in T158N R99W.

 

Samson acquired the net acres in the Rainbow Project from the vendor as part of an acreage trade and is obligated provide a $1 million carry (10% of expected costs to drill and complete the first well) to the vendor, for the first development well to be drilled in the Rainbow Project.

 

Samson has assessed the project based on offset well data and believes that the project will support 16 wells, 8 in the middle Bakken and 8 in the first bench of the Three Forks. These wells would be expected to be configured as north-south orientated 10,000 foot horizontals.

 

In the western drilling unit of the acquired acreage, we hold a 52% working interest. In the eastern drilling unit, our interest is 23%. Continental Resources has been designated as Operator, due to their larger working interest.

 

The first well in this project area, the Gladys 1-20H well (23% working interest), was drilled and completed in January 2014. During the quarter the Gladys 1-20H well produced 6,448 barrels of oil (gross). We have no further drilling planned in this project area until there is a sustained recovery in the oil prices, however six additional wells could be drilled in the 1280 acre unit.

 

Results of Operations

 

For the three months ended September 30, 2016, we reported a net loss of $0.5 million compared to a net loss of $2.1 million for the same period in 2015.

 

The following tables sets forth selected operating data for the three months ended:

 

    Three months ended  
    30-Sep-16     30-Sep-15  
Production Volume                
Oil (Bbls)     90,957       60,723  
Natural gas (Mcf)     68,580       95,559  
BOE (Barrels of oil equivalent - based on one barrel of oil to six Mcf of natural gas)     102,387       76,650  
                 
Sales Price                
Realized Oil ($/Bbls)   $ 39.43     $ 39.90  
Impact of settled derivative instruments   $ (2.95 )   $ 0.32  
Derivative adjusted price   $ 36.48     $ 40.22  
                 
Realized Gas ($/Mcf)   $ 2.08     $ 2.27  
                 
Expense per BOE:                
Lease operating expenses   $ 18.05     $ 18.65  
Production and property taxes   $ 3.38     $ 3.90  
Depletion, depreciation and amortization   $ 5.08     $ 19.36  
General and administrative expense   $ 11.28     $ 13.84  

 

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The following table sets forth results of operations for the following periods:

 

    Three months ended        
    30-Sep-16     30-Sep-15     1Q16 to 1Q15 change  
Oil sales   $ 3,586,208     $ 2,422,583     $ 1,163,625  
Gas sales     142,526       216,747       (74,221 )
Other liquids     15,033       1,346       13,687  
Interest income     115       1,535       (1,420 )
Gain on derivative instruments     443,356       372,552       70,804  
Other     165,943       17,637       148,306  
                         
Lease operating expense     (2,194,315 )     (1,728,729 )     (465,586 )
Depletion, depreciation and amortization     (519,883 )     (1,483,732 )     963,849  
Impairment     (244,480 )     (120,022 )     (124,458 )
Abandonment expense     -       -       -  
Exploration and evaluation expenditure     (6,055 )     (493,068 )     487,013  
Accretion of asset retirement obligations     (79,187 )     (14,888 )     (64,299 )
Interest expense     (623,393 )     (190,039 )     (433,354 )
Loss on  derivative instruments     -       -       -  
Amortization of borrowing costs     (66,849 )     (35,486 )     (31,363 )
Acquisition costs     -       -       -  
General and administrative     (1,154,461 )     (1,060,595 )     (93,866 )
Net loss   $ (535,442 )   $ (2,094,159 )   $ 1,558,717  

 

Comparison of Quarter Ended September 30, 2016 to Quarter Ended September 30, 2015

 

Oil and gas revenues

 

Oil revenues increased from $2.4 million for the three months ended September 30, 2015 to $3.6 million for the three months ended September 30, 2016, as a result of the decrease in the oil price despite an increase in oil production. Oil production increased from 60,723 barrels for the three months ended September 30, 2015 to 90,957 for the three months ended September 30, 2016. This increase was due to our Foreman Butte acquisition which was completed in April 2016. This project added 60,347 barrels of oil to our production total for the three months ended September 30, 2016 compared to nil for the three months ended September 30, 2015. The increase in production was offset in part by a decrease in the realized oil price which decreased from $39.90 per Bbl for the three months ended September 30, 2015 to $39.43 per Bbl (excluding the impact of derivatives) for the three months ended September 30, 2016 following a decrease in global oil prices.

 

Gas revenues decreased from $0.2 million for the three months ended September 30, 2015 to $0.1 million for the three months ended September 30, 2016. This decrease is due to a decrease in gas production which has offset an increase in the realized gas price. Production decreased from 95,559 Mcf for the quarter ended September 30, 2015 to 68,580 Mcf for the quarter ended September 30, 2016. The decrease in production was due to a number of our wells being down during the quarter ended September 30, 2016. The Foreman Butte acquisition has not added significantly to the gas production as the wells in the acquisition area do not have a high gas content. The decrease in production was compounded by a decrease in the realized gas price which decreased slightly from $2.27 per Mcf for the quarter ended September 30, 2015 to $2.08 per Mcf for the quarter ended September 30, 2016.

 

Impact of North Stockyard sale

During the quarter ended September 30, 2016 the North Stockyard field, which was sold effective October 29, 2016 produced 27,266 barrels of oil or approximately 30% of our total production for the quarter. During the quarter, the North Stockyard field produced 54,669 mcf of gas or approximately 80% of our gas production.

 

Commencing October 29, 2016 we will no longer receive the benefit of production from this field.

 

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Exploration expense

 

Exploration expenditures decreased from $0.5 million for the quarter ended September 30, 2015, to $6,055 for the quarter ended September 30, 2016. Exploration costs in both periods relate to general exploration work and delay rentals payable to keep exploration leases alive. With the continued weak oil price, exploration expenditure has been significantly reduced. Leases have been let go as they expire or delay rentals not made causing the leases to expire.

 

Impairment expense

 

During the three months ended September 30, 2015 we recognized $0.1 million in impairment expense compared to $0.2 million during the quarter ended September 30, 2016. The impairment recognized in the current quarter relates to a write down in the value of oil inventory held on the balance sheet related to our accounting policy of the holding inventory at the lower of cost or net realizable value. The impairment recognized in the prior quarter primarily relates to our Gladys well in the Rainbow field and is driven by the sustained decrease in the oil price seen in the past year.

 

Lease operating expense

 

Lease operating expenses (LOE) increased from $1.7 million for the quarter ended September 30, 2015, to $2.2 million for the quarter ended September 30, 2016. Costs per BOE have remained consistent at around $19.00 per BOE for the quarters ended September 30, 2016 and 2015.

 

Impact of North Stockyard sale

During the quarter ended September 30, 2016 the North Stockyard field contributed $0.5 million to the lease operating expense. This equates to approximately $13 per barrel, including production taxes.

 

Commencing October 29, 2016 we will no longer be responsible for the lease operating costs or production taxes associated with this field.

 

Depletion, depreciation and amortization expense

 

Depletion, depreciation and amortization expense decreased from $1.5 million for the quarter ended September 30, 2015 to $0.5 million for the quarter ended September 30, 2016. The decrease in depletion is a result of the increase in the reserve base over which depletion is following the Foreman Butte project acquisition. Depletion has not been charged on the North Stockyard assets, as is customary when assets are held for sale. The per BOE cost decreased from $19.36 for the three months ended September 31, 2015 to $5.08 for the three months ended September 30, 2016.

 

General and administrative expense

 

General and administrative expense increased slightly from $1.1 million for the quarter ended September 30, 2015 to $1.2 million for the quarter ended September 30, 2016. We have been actively trying to reduce our general and administrative costs in recent periods. The slight increase in general and administrative costs has been offset at on a per BOE basis by increased production. The BOE costs decreased from $13.84 for the quarter ended September 30, 2015 to $11.28 for the quarter ended September 30, 2016.

 

Cash Flows

 

The table below shows cash flows for the following periods: 

 

    Three months ended  
    30-Sep-16     30-Sep-15  
Cash provided by operating activities   $ 71,198     $ 1,417,328  
Cash used in investing activities     (1,140,872 )     (1,297,652 )
Cash provided by financing activities     -       1,475  

 

Cash provided by operations decreased from a net inflow of $1.4 million for the three months ended September 30, 2015, to a net inflow of $0.07 million for the three months ended September 30, 2016. Cash receipts from customers decreased from $4.2 million for three months ended September 30, 2015 to $3.4 million for the three months ended September 30, 2016, due to a decrease in the realized oil price despite an increase in production. Payments to suppliers and employees also increased slightly from $2.6 million for the three months ended September 30, 2015 to $2.8 million for the three months ended September 30, 2016 following increased workover activity in our Foreman Butte project area.

 

Cash used in investing activities decreased from $1.3 million for the three months ended September 30, 2015 to $1.1 million for the three months ended September 30, 2016. The cash outflow for the prior period related to ongoing activities in our North Stockyard project in North Dakota. The cash outflow in the current period relates to continued work in Foreman Butte field.

 

Cash provided by financing activities decreased from a cash inflow of $1,475 for the three months ended September 30, 2015 to $nil for the three months ended September 30, 2016. Cash inflow for the prior period related to in proceeds from the exercise of options.

 

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All options outstanding as at September 30, 2016 are currently out of the money.

 

Liquidity, Capital Resources and Capital Expenditures

 

Our primary use of capital has been acquiring, developing and exploring oil and natural gas properties and we anticipate this will be our primary use of capital during fiscal 2017.  

 

Following the closing of our Foreman Butte Acquisition, our current budget for exploration, exploitation and development capital expenditures in fiscal 2017 is $3.0 million, of which we incurred approximately $1.5 million during the first three months of the fiscal year. These expenditures were funded through our current cash on hand and cash generated from oil sales. We have additional workovers planned in our Foreman Butte Project during the course of the year.

 

In January 2014, we entered into a $25.0 million credit facility with our primary lender, Mutual of Omaha Bank, with an initial borrowing base of $8.0 million, which was increased to $15.5 million in June 2014. In November 2014, the borrowing base was increased to $19.0 million, which was fully drawn prior to the closing of the Foreman Butte Acquisition. In March 2016, our credit facility was amended to increase the borrowing base to $30.5 million to partially fund the Foreman Butte Acquisition. An additional $4 million in financing was also provided by the seller. This promissory note is due April 1, 2017 and has a 10% interest rate. We were required under the amended credit agreement to repay Mutual of Omaha $10 million by June 30, 2016. This was ultimately increased to $11.5 million and extended to October 31, 2016. The pay down was achieved through the sale of our North Stockyard property for $15.05 million on October 28, 2016 and was made on October 31, 2016.

 

As a result of the amendment of the credit facility, the interest rate has been increased to 6% plus the 90 day LIBOR or approximately 6.5% from April 1, 2016 onwards. This will be reduced following the pay down of the facility as detailed above. The amendment to our credit facility also requires us to comply with additional restrictions, which are described below. Following the repayment of the facility on October 31, 2016 the interest rate has been reduced to LIBOR plus 3.5%.

 

As of November 10, 2016 our borrowing base was increased to $20 million by Mutual of Omaha Bank, of which $19 million has been drawn down. The additional borrowing base capacity has no additional restrictions on it.

 

The borrowing base under our credit facility may be increased (up to the credit facility maximum of $50.0 million, which would require syndication of the loan) or decreased in the future depending on the value of our reserves. Borrowing base redeterminations are performed by the lender every six months based on our June and December reserve reports. We also have the ability to request a borrowing base redetermination at another period, once a year. The facility matures January 28, 2017. Mutual of Omaha Bank have indicated that they will perform a borrowing base determination based on our November 30, 2016 reserves. We can make no assurances, but we expect this borrowing base review to result in a significant increase to our current borrowing base and have commenced discussions with other banks with a view to syndicating the loan, at the suggestion of Mutual of Omaha Bank.

 

In March 2016, the facility was extended to $30.5 million to partly fund the Foreman Butte acquisition. As a result of this amendment to the facility agreement, the following changes were made to the original facility agreement:

· The addition of more restrictive financial covenants (including the debt to EBITDA ratio and the minimum liquidity requirement);
· Increases in the interest rate and unused facility fee;
· The addition of a minimum hedging requirement of 75% of forecasted production;
· A requirement to reduce our general and administrative costs from $6 million per year to $3 million per year;
· A requirement to raise $5 million in equity on or before September 30, 2016 (this was extended to November 15, 2016 and then effective November 10, 2016. Mutual of Omaha agreed that this requirement had been met following the $1.4 million capital raise completed in April 2016 and by the application of retained funds from the North Stockyard sale);
· A requirement to pay down at least $10 million of the loan by June 30, 2016 (which was increased to $11.5 million and extended to October 31, 2016 in line with the closing of the North Stockyard sale) and we repaid $11.5 million on October 31, 2016; and
· The addition of a monthly cash flow sweep whereby 50% of cash operating income will be used to repay outstanding borrowings under the Credit Agreement. No repayments have been made under this covenant.

 

The credit facility includes the following covenants, tested on a quarterly basis:

· Current ratio greater than 1
· Debt to EBITDAX (annualized) ratio no greater than 5.75 for the quarter ended March 30, 2016 through to September 30, 2016 reducing to 4.00 by September 30, 2017
· Senior leverage ratio of no greater than 4.25 to 1 for the quarter ended June 30, 2016 reducing to 3.75 for the quarter ending December 31, 2016 and thereafter
· Interest coverage ratio minimum of between 2.5 and 1.0

 

We were in compliance with all of our covenants as at June 30, 2016.

 

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As at September 30, 2016 we were in breach of our spending cap with respect to the general and administrative expenses. We have received a waiver with respect to this covenant.

 

We were in compliance with all other covenants as at September 30, 2016.

 

$11.5 million of the credit facility in the current period has been presented as a current liability; the remaining $19 million has been recorded as a non-current liability and is due for repayment October 2017. We are working with the bank to renegotiate our facility and extend its term. We believe we will meet the covenants in the future, however if we do not we will continue to ask for waivers on a quarterly basis as necessary; however there can be no guarantee they will be granted. If we do not receive a waiver from the lender, and if we fail to cure any such noncompliance during the applicable cure period, the due date of our debt could be accelerated by the lender. In addition, failure to comply with any of the covenants under our credit facility could adversely affect our ability to fund ongoing operations.

 

The funds drawn from our credit facility were used to fund drilling in our North Stockyard project in North Dakota and more recently, to partially fund the Foreman Butte acquisition.

 

Uncertainties relating to our capital resources and requirements include the effects of results from our exploration and drilling program and changes in oil and natural gas prices, either of which could lead us to accelerate or decelerate exploration and drilling activities. The aggregate levels of capital expenditures for our fiscal year ending June 30, 2017, and the allocation of those expenditures, are dependent on a variety of factors, including the availability of capital resources to fund the expenditures and changes in our business assessments as to where our capital can be most profitably employed. Accordingly, the actual levels of capital resources and expenditures and the allocation of those expenditures may vary materially from our estimates.

 

We are continually monitoring the capital resources available to us to meet our future financial obligations, planned capital expenditure activities and liquidity.  Our future success in growing our proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring such additional productive reserves.

 

Our main sources of liquidity during the three months ended September 30, 2016 were cash on hand and cash flow from operations.

 

During the prior four fiscal years, our three main sources of liquidity were (i) borrowings under our credit facility, (ii) equity issued to raise $21.4 million and (iii) our tax refund of $5.6 million from the Internal Revenue Service, received in February 2013. During the years prior to the fiscal year ended June 30, 2012, our primary sources of liquidity were the sale of acreage and other oil and gas assets.

 

Our cash position as of September 30, 2016 decreased from June 30, 2016 largely due to payments for recompletion and workover activities in our Foreman Butte project in North Dakota and Montana.

 

In October 2016, we closed on the sale of our North Stockyard project for $15.05 million. $11.5 million of this has been used to pay down our credit facility with Mutual of Omaha Bank. $0.2 million was used to close out a portion of our hedge positions to balance our hedge book following the sale of production. The remaining $3.35 million, including the $1.0 million deposit paid in June 2016, will be used for future working capital.

 

In April 2016, we issued 378,020,400 ordinary shares at $0.0037 per ordinary share to raise gross proceeds of $1,398,675.

 

In April 2016, we also received cash of $725,000 from Halliburton following the settlement of our legal dispute with them.

 

If future production rates are less than anticipated, and/or the oil price continues to deteriorate for an extended period, the value of our position in affected areas will decline, our results of operations, financial condition and liquidity will be adversely impacted and we could incur material write-downs of oil and gas properties. See the risk factors in our Annual Report on Form 10-K for the fiscal year ended June 30, 2016. See also Part II, Item 1A of this report below.

 

Looking Ahead

 

We plan to focus on the following objectives in the coming 12 months:

 

· Continued focus on cost savings and efficiency across all aspects of the Company including lease operating costs and general and administrative costs;
· Continued focus on strengthening the balance sheet through strong capital management;
· The successful integration of the properties and assets acquired in the Foreman Butte Acquisition, and the review and workover of such assets;
· The continued appraisal of our Cane Creek project in the Paradox basin in Utah;
· The continued search and appraisal of new development and exploration projects that add value to our current portfolio at lower oil prices;

 

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· Repayment of the $4 million promissory note issued to the seller in the Foreman Butte Acquisition; and
· Regaining and maintaining compliance with NYSE MKT listing standards.

 

Our ability to meet these objectives will depend on our ability to raise additional capital to fund the planned development programs.

 

Item 3.   Quantitative and Qualitative Disclosures About Market Risk.

 

Not applicable.

 

Item 4.    Controls and Procedures.

 

As of September 30, 2016, we have carried out an evaluation under the supervision of, and with the participation of, our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

 

Our Chief Executive Officer and Chief Financial Officer have concluded that, as of September 30, 2016, our disclosure controls and procedures were effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.  

 

There were no changes in our internal control over financial reporting that occurred during the three months ended September 30, 2016, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time in the future.

 

Part II — Other Information

 

Item 1.    Legal Proceedings.

 

In the ordinary course of our business we are named from time to time as a defendant in various legal proceedings.  We maintain liability insurance and believe that our coverage is reasonable in view of the legal risks to which our business ordinarily is subject.

 

Item 1A.   Risk Factors.

 

In addition to the risks described above and other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended June 30, 2016.  The risks disclosed herein and in our Annual Report on Form 10-K could materially affect our business, financial condition or future results.  The risks described herein and in our Annual Report on Form 10-K are not the only risks facing us.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our business, financial condition or operating results in the future.

 

Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds.

 

Not applicable.

 

Item 3.    Defaults Upon Senior Securities.

 

Not applicable.

 

Item 4.    Mine Safety Disclosures.

 

Not applicable.

 

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Item 5.    Other Information.

 

Not applicable.

 

Item 6.    Exhibits.

 

Exhibit No.   Title of Exhibit
     
31.1   Certification of the Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
     
31.2   Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
     
32.1   Certifications of the Principal Executive Officer and Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
     
101.INS   XBRL Instance Document
     
101.SCH   XBRL Taxonomy Extension Schema Document
     
101.CAL   XBRL Taxonomy Extension Calculation Linkbase Document
     
101.DEF   XBRL Taxonomy Extension Definition Linkbase Document
     
101.LAB   XBRL Taxonomy Extension Label Linkbase Document
     
101.PRE   XBRL Taxonomy Extension Presentation Linkbase Document
     
    *Furnished herewith

 

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Signatures

 

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

 

  SAMSON OIL & GAS LIMITED
   
Date:  November 14, 2016 By: /s/ Terry Barr
    Terence M. Barr
    Managing Director, President and Chief Executive Officer (Principal Executive Officer)
   
Date: November 14, 2016 By: /s/ Robyn Lamont
    Robyn Lamont
    Chief Financial Officer (Principal Financial Officer)

 

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