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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, 2012

 

OR

 

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

 

Commission File Number: 333-123711

 

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 36, Exchange Plaza,

2 The Esplanade

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     x
     
Non-accelerated filer ¨ Smaller reporting company     ¨

 

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 1,814,527,926 ordinary shares outstanding as of November 7, 2012.

 

 
 

 

SAMSON OIL & GAS LIMITED

FORM 10-Q

QUARTER ENDED SEPTEMBER 30, 2012

 

TABLE OF CONTENTS

 

    Page
     
Part I — Financial Information 4
     
Item 1. Financial Statement (unaudited). 4
   
Consolidated Balance Sheets, September 30, 2012 and June 30, 2012 4
   
Consolidated Statement of Operations and Comprehensive Income (Loss) for the three months ended September 30, 2012 and 2011 5
   
Consolidated Statement of Changes in Stockholders’ Equity for the three months ended September 30, 2012 6
   
Consolidated Statement of Cash Flows for the three months ended September 30, 2012 and 2011 7
   
Notes to  Consolidated Financial Statements (unaudited) 8
     
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations. 13
     
Item 3. Quantitative and Qualitative Disclosures About Market Risk. 19
     
Item 4. Controls and Procedures. 19
   
Part II   — Other Information 19
     
Item 1. Legal Proceedings. 19
     
Item 1A. Risk Factors. 19
     
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds. 19
     
Item 3. Defaults Upon Senior Securities. 20
     
Item 4. Removed and Reserved. 20
     
Item 5. Other Information. 21
     
Item 6. Exhibits. 21
     
Signatures 22

 

2
 

 

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,” “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:

 

  · oil and natural gas prices and demand;

 

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

 

  · the timing, effects and success of our acquisitions, dispositions and 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 find, acquire, 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;

 

  · the strength and financial resources of our competitors;

 

  · our entrance into transactions in commodity derivative instruments;

 

  · climatic conditions;

 

  · the receipt of governmental permits and other approvals relating to our operations;

 

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

 

  · uncontrollable flows of oil, gas or well fluids.

 

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.

 

3
 

 

Part I — Financial Information

Item 1.   Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

   30-Sep-12   30-Jun-12 
ASSETS          
CURRENT ASSETS          
Cash and cash equivalents  $10,529,147   $18,845,894 
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively   1,321,449    1,288,159 
Prepayments   438,700    344,108 
Pipe inventory – held by third party   78,944    78,944 
Income tax receivable   4,347,556    4,347,456 
Total current assets   16,715,796    24,904,561 
PROPERTY, PLANT AND EQUIPMENT, AT COST          
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment   13,324,243    13,890,380 
Other property and equipment, net of accumulated depreciation and amortization of $276,406 and $252,254 at September 30, 2012 and June 30, 2012, respectively   428,220    448,061 
Net property, plant and equipment   13,752,463    14,338,441 
OTHER ASSETS          
Undeveloped capitalized acreage   12,287,945    10,017,287 
Capitalized exploration expense   9,341,697    6,362,989 
Income tax receivable   668,998    - 
Other   100,830    99,961 
TOTAL ASSETS  $52,867,729   $55,723,239 
           
LIABILITIES AND STOCKHOLDERS’ EQUITY          
CURRENT LIABILITIES          
Accounts payable  $2,039,215   $5,269,748 
Accruals   1,863,103    1,229,982 
Provision for annual leave   217,865    234,536 
Total current liabilities   4,120,183    6,734,266 
Capitalized lease   -    7,322 
Asset retirement obligations   822,006    808,572 
TOTAL LIABILITIES   4,942,189    7,550,160 
STOCKHOLDERS’ EQUITY – nil par value          
Common stock, 1,799,873,156 (equivalent to 89,993,658 ADR’s) and 1,771,889,967 (equivalent to 88,594,498 ADR’s) shares issued and outstanding at September 30, 2012 and June 30, 2012, respectively)   83,992,310    83,467,987 
Other comprehensive income   2,924,434    2,772,758 
Retained earnings (accumulated deficit)   (38,991,204)   (38,067,666)
Total stockholders’ equity   47,925,540    48,173,079 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY  $52,867,729   $55,723,239 

 

See accompanying Notes to Consolidated Financial Statements.

 

4
 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

 

 

   Three months ended 
   30-Sep-12   30-Sep-11 
REVENUES AND OTHER INCOME:          
Oil sales  $1,446,537   $2,176,436 
Gas sales   145,764    310,176 
Other liquids   4,457    5,666 
Interest income   71,640    113,806 
Other   12    19,157 
 TOTAL REVENUE AND OTHER INCOME   1,668,410    2,625,241 
           
EXPENSES:          
Lease operating expense   (811,989)   (626,797)
Depletion, depreciation and amortization   (590,767)   (733,309)
Exploration and evaluation expenditure   (361,944)   (107,956)
Accretion of asset retirement obligations   (13,434)   (5,434)
General and administrative   (1,482,812)   (1,899,581)
TOTAL EXPENSES   (3,260,946)   (3,373,077)
           
Income (loss) from operations   (1,592,536)   (747,836)
Income tax benefit/(provision)   668,998    188,178 
Net loss   (923,538)   (559,658)
OTHER COMPREHENSIVE GAIN (LOSS)          
Foreign Currency Translation   151,676    (573,632)
Total comprehensive income/(loss) for the period  $(771,862)  $(1,133,290)
           
Net earnings per common share from operations:          
Basic – cents per share   (0.05)   (0.03)
Diluted – cents per share   (0.05)   (0.03)
           
Weighted average common shares outstanding:          
Basic   1,784,580,214    1,742,741,392 
Diluted   1,784,580,214    1,742,741,392 

 

See accompanying Notes to Consolidated Financial Statements.

 

5
 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

 

           Other     
       Retained Earnings/   Comprehensive     
   Common Stock   (Accumulated Deficit)   Income   Total Equity 
Balance at June 30, 2012  $83,467,987   $(38,067,666)  $2,772,758   $48,173,079 
Net income (loss)   -    (923,538)   -    (923,538)
Foreign currency translation, net of tax of $nil   -    -    151,676    151,676 
Total comprehensive income/(loss) for the period   -    (923,538)   151,676    (771,862)
Stock based compensation   80,051    -    -    80,051 
Issue of share capital   444,272    -    -    444,272 
Balance at September 30, 2012  $83,992,310   $(38,991,204)  $2,924,434   $47,925,540 

 

See accompanying Notes to Consolidated Financial Statements.

 

6
 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

   Three months ended 
   30-Sep-12   30-Sep-11 
Cash flows from operating activities          
Receipts from customers  $1,653,515   $2,760,806 
Cash received from commodity derivative financial instruments   -    38,509 
Payments to suppliers & employees   (1,902,203)   (2,749,338)
Interest received   87,463    113,804 
Income taxes refund received/( paid)   (100)   (40,000)
Net cash flows provided by/(used in) operating activities   (161,325)   123,781 
Cash flows from investing activities          
Payments for plant & equipment   (6,910)   (54,705)
Payments for exploration and evaluation   (8,653,155)   (2,255,724)
Payments for oil and gas properties   (94,592)   (2,024,979)
Net cash flows (used in)/provided by investing activities   (8,754,657)   (4,335,408)
Cash flows from financing activities          
Proceeds from the exercise of options   444,272    290,581 
Net cash flows provided by financing activities   444,272    290,581 
Net increase/(decrease) in cash and cash equivalents   (8,471,710)   (3,921,046)
Cash and cash equivalents at the beginning of the fiscal period   18,845,894    58,448,477 
Effects of exchange rate changes on cash and cash equivalents   154,963    (580,339)
Cash and cash equivalents at end of fiscal period  $10,529,147   $53,947,092 

 

See accompanying Notes to Consolidated Financial Statements

 

7
 

 

SAMSON O IL & 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 to fairly state 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, 2012. The year-end Consolidated Balance Sheet presented herein was derived from audited Consolidated Financial Statements, but does not include all disclosures required by GAAP.

 

These Consolidated Financial Statements should be read in conjunction with our audited Consolidated Financial Statements included in our Annual Report on Form 10-K for the fiscal year ended June 30, 2012.

 

Accruals.   The components of accrued liabilities for the periods ended September 30, 2012 and June 30, 2012 includes accruals based on estimated costs relating to goods and services provided yet not invoiced and an amount payable for Samson’s employee bonus plan.

 

Recently Adopted Standards

 

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04 Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRSs.  The ASU amends previously issued authoritative guidance and is effective for interim and annual periods beginning after December 15, 2011.  The amendments change requirements for measuring fair value and disclosing information about those measurements.  Additionally, the ASU clarifies the FASB’s intent regarding the application of existing fair value measurement requirements and changes certain principles or requirements for measuring fair value or disclosing information about its measurements.  For many of the requirements, the FASB does not intend the amendments to change the application of the existing Fair Value Measurements guidance.  This guidance did not have an impact on our financial position or results of operations.  

 

In June 2011, the FASB issued ASU No. 2011-05 Presentation of Comprehensive Income.  The ASU amends previously issued authoritative guidance and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.  These amendments remove the option under current GAAP to present the components of other comprehensive income as part of the statements of changes in stockholder’s equity.  The adoption of this guidance will not have an impact on our financial position or results of operations, but has required the Company to present the statements of comprehensive income separately from its statements of equity, as these statements were previously presented on a combined basis.  This guidance has been adopted in this 10Q.

 

In September 2011, the FASB issued ASU No. 2011-08, Intangibles – Goodwill and Other (Topic 350): Testing Goodwill for Impairment. This update allows entities testing goodwill for impairment the option of performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step one of the two-step goodwill impairment test). If entities determine, on the basis of qualitative factors, that the fair value of their reporting unit is more likely than not less than the carrying amount, the two-step impairment test would be required. The amendments are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 2011. The adoption of this new guidance has not had any impact on our financial position or results of operations.

 

Recently Issued Pronouncements

 

In December 2011, the FASB issued ASU No. 2011-11 Disclosures about Offsetting Assets and Liabilities. The ASU requires additional disclosures about the impact of offsetting, or netting, on a company's financial position, and is effective for annual periods beginning on or after January 1, 2013 and interim periods within those annual periods, and retrospectively for all comparative periods presented. Under US GAAP, derivative assets and liabilities can be offset under certain conditions. The ASU requires disclosures showing both gross information and net information about instruments eligible for offset in the balance sheet. The Company is currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on the Company's financial position or results of operations.

 

8
 

 

2. Income Taxes

 

   Three months ended 
   30-Sep-12   30-Sep-11 
         
Income tax benefit/(expense)  $668,998   $188,178 
Effective tax rate   42.01%   25.16%

 

The Company has current year losses and available prior year cumulative net operating losses that maybe carried forward to reduce taxable income in future years. The Tax Reform Act of 1986 contains provisions that limit the utilization of net operating loss carryforwards if there has been a change in ownership as described in Internal Revenue Code Section 382. The Company’s prior year losses are limited by IRC Section 382, however, current year losses are not subject to these limitations.

 

This current year operating loss will be carried back to offset tax paid in the June 30, 2011 year end. This will generate a current year benefit and income tax receivable for the tax expected to be refunded from the carry back claim

 

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 benefit 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 common stock 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 common shares (unexercised stock options). In the event of a net loss, no potential common shares are included in the calculation of shares outstanding since the impact would be anti-dilutive.  The Company's unexercised stock options do not contain rights to dividends. When the Company records a net loss, none of the loss is allocated to the unexercised stock options since the securities are not obligated to share in Company losses. Consequently, in periods of net loss, outstanding options will have no dilutive impact to the Company’s basic earnings per share.

 

The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and warrants, for the periods presented:

 

   Three months ended 
   30-Sep-12   30-Sep-11 
Dilutive   -    - 
Anti–dilutive   226,477,135    319,220,449 

 

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

 

Continuing operations  Three months ended 
   30-Sep-12   30-Sep-11 
Net income (loss)  $(923,538)   (559,658)
           
Basic weighted average common shares outstanding   1,784,580,214    1,742,741,392 
Add: dilutive effect of stock options   -    - 
Add: bonus element for rights issue   -    - 
Diluted weighted average common shares outstanding   1,784,580,214    1,742,741,392 
Basic earnings per common share – cents per share   (0.05)   (0.03)
Diluted earnings per common share – cents per share   (0.05)   (0.03)

 

9
 

 

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 plugging and abandonment liabilities. 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 following table summarizes the activities for the Company’s asset retirement obligations for the three months ended September 30, 2012 and 2011:

 

   Three months ended 
   30-Sep-12   30-Sep-11 
Asset retirement obligations at beginning of period  $808,572   $236,024 
Liabilities incurred or acquired   -    - 
Liabilities settled   -    - 
Disposition of properties   -    - 
Accretion expense   13,434    5,434 
Asset retirement obligations at end of period   822,006    241,458 
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)   -    - 
Long-term asset retirement obligations  $822,006   $241,458 

 

Discount rates used to calculate the present value vary depending on the estimated timing of the obligation, but typically range between 4% and 9%.

 

5. Equity Incentive Compensation

 

Stock-based compensation is measured at the grant date based on the value of the awards, and the fair value is recognized on a straight-line basis over the requisite service period (usually the vesting period).

 

Total compensation cost recognized in the Statements of Operations for the grants under the Company’s equity incentive compensation plans was $80,051 and $318,605 during the three months ended September 30, 2012 and 2011.

 

As of September 30, 2012, there was $114,116 of total unrecognized compensation cost related to outstanding stock options. This cost is expected to be recognized over two years.

 

6. Hedging and Derivative Instruments

 

Commodity Derivative Agreements. The Company has in the past utilized swap and collar option contracts to hedge the effect of price changes on a portion of its future oil production but it is not currently doing so. The objective of the Company’s hedging activities and the use of derivative financial instruments was to achieve more predictable cash flows. While the use of these derivative instruments limits the downside risk of adverse price movements, they also may limit future revenues from favorable price movements.    

 

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 were all with a single multinational bank with no history of default with the Company. The derivative contracts were subject to termination by a non-defaulting party in the event of default by one of the parties to the agreement. No collateral was provided in relation to the derivative contracts entered into by the Company. Collateral may, however, be required for future contracts if the Company chooses to enter into additional derivative contracts in the future.

 

The Company has elected not to apply hedge accounting to any of its derivative transactions and, consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income for those commodity derivatives that would qualify as cash flow hedges.

 

As of September 30, 2012, the Company has no outstanding derivative agreements in relation to its oil or gas production.

 

10
 

  

7. 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 in puts. 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 less observable 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, 2012 and June 30, 2012.

 

   Carrying value at
September 30, 2012
   Level 1   Level 2   Level 3   Fair Value at
September 30,
2012
 
Assets                         
Cash and cash equivalents  $10,529,147   $10,529,147   $-   $-   $10,529,147 

 

   Carrying value at
June 30, 2012
   Level 1   Level 2   Level 3   Fair Value at
September 30,
2012
 
Assets                         
Cash and cash equivalents  $18,845,894   $18,845,894   $-   $-   $18,845,894 

 

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

 

Commodity Derivative Contracts.   In previous periods, the Company’s commodity derivative instruments consisted of collar contracts for oil. The Company valued the derivative contracts using industry standard models, based on an income approach, which considers various assumptions including quoted forward prices and contractual prices for the underlying commodities, time value and volatility factors, as well as other relevant economic measures. Substantially all of the assumptions can be observed throughout the full term of the contracts, can be derived from observable data or are supportable by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the fair value hierarchy. As at September 30, 2012 the Company did not have any derivative instrument contracts in place.

 

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

 

11
 

 

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.

 

8. Commitments and Contingencies

 

Environmental Matters

 

The Company has no material 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 matters will not result in material costs incurred.

 

Contingent Assets or Liabilities

There are no unrecorded contingent assets or liabilities in place for the Company at September 30, 2012 or June 30, 2012.

 

9. 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;

 

  · 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 or sale, then the relevant capitalized amount will be written off to the statement of operations.

 

Currently we have capitalized exploration expenditures of $9.3 million and undeveloped capitalized acreage of $12.2 million.  This primarily relates to costs in relation to our Hawk Springs (including 3D seismic acquisition costs) and Roosevelt projects (including the drilling and permitting of exploration wells). The costs include acreage acquisition costs in both of Hawk Springs and Roosevelt project areas. During the three months ended September 30, 2012 we continued drilling activities on our Spirit of America II well in our Hawk Springs project in Goshen County, Wyoming. To date we have capitalized approximately $7.0 million in relation to this well, including $2.0 million in the current quarter. We are currently awaiting a workover rig in order to gain access to frac the final stage of this well. The carrying value of this well will be reviewed again at December 31, 2012.

 

10.  Issue of Share Capital

 

During the three months ended September 30, 2012, 27,983,189 Australian 1.5 cent options were exercised for net proceeds of $444,272 to us. The options were issued in public rights offering conducted in October 2009.

 

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11. Cash Flow Statement

 

Reconciliation of the net profit/(loss) after tax to the net cash flows from operations:

 

   Three months ended 
   30-Sep-12   30-Sep-11 
         
Net (loss) after tax  $(923,538)  $(559,658)
Depletion, depreciation and amortization   590,767    733,309 
Stock based compensation   80,051    318,605 
Accretion of asset retirement obligation   13,434    5,434 
Exploration and evaluation expenditure   361,944    107,956 
Net (gain)/loss on fair value movement of fixed forward swaps   -    (21,350)
           
Changes in assets and liabilities:          
           
(Increase)/decrease in receivables   (33,290)   (809,443)
(Increase)/decrease in income tax receivable/deferred tax asset   (669,098)   (228,178)
Increase/(decrease) in provision for annual leave   (16,671)   24,360 
Increase/(decrease) in payables   435,076    552,746 
NET CASH FLOWS USED IN OPERATING ACTIVITIES  $(161,325)  $123,781 

 

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, 2012, included in our Annual Report on Form 10-K and the Consolidated Financial Statements included elsewhere herein.

 

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 Niobrara, Permian and Pennsylvanian in Goshen County, Wyoming and the Bakken in Williams County, North Dakota and Roosevelt County, Montana.  We are in the early stages of our first Niobrara shale project – Hawk Springs – and also of our Montana Bakken shale project – the Roosevelt project.

 

Our net oil production was 18,882 barrels of oil for the quarter ended September 30, 2012 compared to 24,601 barrels of oil for the quarter ended September 30, 2011.  Our net gas production was 41,091 Mcf for the quarter ended September 30, 2012 compared to 59,246 Mcf for the quarter ended September 30, 2011.

 

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 and in a manner consistent with preserving adequate liquidity and financial flexibility.

 

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Notable Activities during the Quarter Ended September 30, 2012 and Current Activities

 

Undeveloped Properties: Exploration Activities

 

Hawk Springs Project, Goshen County, Wyoming

Cretaceous Niobrara Formation & Permo-Penn Project, Northern D-J Basin

Samson 37.5% to 100% Working Interest

Production to date from the Niobrara Formation in the Defender US33 #2-29H well in Goshen County, WY has been sporadic due to the chemistry of the Niobrara oil, which has been producing an unusually high concentration of paraffin and asphaltene (11.74%). We have, following consultation with industry experts, designed a chemical treatment program to maintain these compounds in solution. This treatment program will require a change to the bottom hole configuration of the well, so a workover rig is scheduled to arrive on location in November to run this completion. Prior to the paraffin and asphaltene plugging, the well had established a consistent production rate of approximately 75 BOPD while maintaining a high fluid level in the wellbore. The go-forward plan is to increase the pump rate to lower the fluid level and thus increase the production rate.

 

Two stages of a three stage completion have taken place on the Spirit of America US34 #2-29 Permo-Penn exploration well. Most recently, Frac Stage #3 took place, which included 7 feet of log pay from 9247feet to-9254 feet, 7 feet of log pay from 9225 feet to 9232 feet, and 8 feet of log pay from 9167 feet to 9175 feet. The stimulation included 37,000 pounds of proppant. The initial shut-in pressure (ISIP) after fracking measured 4,238 psi. After 45 minutes the pressure bled down to 4163 psi and 70 bbls were flowed back before the well was shut-in with 3761 psi of pressure. During flowback operations 177 bbls of fluid was recovered before the wellbore plugged with salt. A coil tubing unit was used to drill out the salt plugs, however hot water was subsequently required to clear the plugs, and the plugging is consistent as the salt is precipitating out of the formation water as a result of a pressure drop and temperature cooling. This can be treated with an appropriate salt inhibitor to prevent the salt from precipitating out of the water. To date approximately 253 bbls of load water have been recovered out of approximately 1600 bbls that were pumped into the well. A workover rig will be required to remove the tubing and reset the retrievable bridge plug and packer in order to attempt to make a completion in the best zone, the 9300 foot sand (Frac Stage #2). This final frac stage is scheduled to occur in the coming quarter following this workover operation. To date approximately $7.0 million has been capitalized to this well and is carried in Capitalized Exploration Expenditure on the Balance Sheet, including $2.0 million during the current quarter.

 

Samson has mapped numerous similar prospects within its 3-D seismic area that will allow for follow-up to this well. The next such prospect is the Bluff Federal #1-12 well, which is 2,000 feet shallower than the Spirit of America well and is located within a 4-way structural closure. Samson currently expects to have a 50% working interest in the Bluff Federal well, although this has not been finalized.

 

Samson has two contiguous areas in the Hawk Springs Project. One of the areas is a joint venture with a private company and is subject to a joint venture with a Halliburton company.

 

Roosevelt Project, Roosevelt County, Montana

Mississippian Bakken Formation, Williston Basin

Samson 100% working interest in Australia II & Gretel II wells, 66.7% in any subsequent drilling, depending on the drilling location

We have an interest in approximately 45,000 gross acres (30,000 net acres) in the Roosevelt Project with Fort Peck Energy Co. (“FPEC”) having the remaining 15,000 net acres. Samson’s first Bakken appraisal (exploratory) well in the Roosevelt project area on the Ft. Peck Indian Reservation, the Australia II 12 KA 6 well, was drilled in December 2011. Approximately 3,425 barrels of oil have been produced through September, 2012. The well is currently being worked over for mechanical repairs but should be back on production during November 2012.

 

Samson’s second Bakken appraisal (exploratory) well, the Gretel II 12 KA 3, was drilled in January 2012 and fracture stimulated in March 2012. It appears that this well was drilled on the north side of the Brockton Fault zone, which is believed to be the western edge of the continuous Bakken oil. The Gretel II has produced oil, but with a high water cut. This well is currently shut-in and awaiting mechanical repairs. Although Australia II and Gretel II may be productive in the future, we do not believe that we will recover our costs associated with drilling them.

 

We currently have a third permitted exploratory well in this project – the Prairie Falcon. The drilling location of this well is south of the Brockton Fault zone and is north of the Abercrombie 1-10H well, an existing well which had an initial production of 630 BOPD. We are waiting on the results of two other nearby wells, which should help define the productive extension of the Elm Coulee Bakken fairway onto the Fort Peck Indian Reservation. If economic results are obtained from these offsetting wells, we plan to move ahead with the drilling of the Prairie Falcon well. We are currently looking for a joint venture participant for the drilling of the Prairie Falcon well and the continuing development of our leasehold on the Fort Peck Indian Reservation.

 

Drilling Program

 

Hawk Springs Project, Goshen County, Wyoming

Wildcat (Exploratory) Permo-Penn Hartville Formation, Northern D-J Basin

Bluff Federal #1-12

Samson will most likely have a 50% Working Interest, based on current expectations and leasehold positions

A better understanding of the Permian section has been achieved from the well data obtained in the Spirit of America US34 #2-29 well that has allowed us to high-grade the Bluff Federal prospect, which is currently being prepared to be drilled next year. From that data, several of the upper Permian zones calculate to be hydrocarbon bearing whereas the deepest zone, the 9500’ sand, calculates to contain formation water or is “wet”. The SOA #2 prospect depended on the 9500’ sand to be stratigraphically trapped (i.e. a sand pinch-out). The fact that this zone appears to be wet most likely means the sand does not pinch-out or trap at this particular prospect as the seismic data would indicate, but instead persists over a much larger area, requiring a structural closure to trap hydrocarbons in the reservoir. This 9500’ sand has also been mapped as a four-way dip structural closure just a few miles away and more than 2,000’ shallower at the Bluff Federal prospect.

 

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North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson various Working Interests

We anticipate undertaking a transaction by which we will swap our equity in the undrilled acreage in the southern three sections of this holding for the same amount of acreage in the northern three sections. Our equity in the current production will be unaffected by this transaction. The swap is aimed at allowing us to be or name the operator of the northern three sections and thereby develop the considerable potential in a timely manner. Based on current industry practice and evidenced by offset production, we believe that it is economically feasible to drill both the Bakken Formation and the underlying Three Forks Formation at a 160 acre density. Accordingly, we have identified ten infill development wells that can be drilled between the existing Bakken wells, four in the Bakken formation and six in the Three Forks Formation. The wells would be drilled from pads that would accommodate multiple well heads. The infill development drilling is tentatively planned to commence in the first quarter of 2013.

 

Developed Properties: Production Activities

 

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson various Working Interests

We have seven producing wells in the North Stockyard Field. These wells are located in Williams County, North Dakota, in Township 154N Range 99W.

 

1.The Harstad #1-15H well (34.5% working interest) was down for 33 days during the quarter due to pump rod failure and as a result averaged 19 BOPD for the quarter from the Mississippian Bluell Formation. After the workover, the well has been averaging 35 BOPD. The well has cumulative gross production of 99 MSTB and 82 MMcf.

 

2.The Leonard #1-23H well (10% working interest, 37.5% after non-consent penalty) was down for 44 days during the quarter for multiple workovers. As a result, the well averaged 25 BOPD and 33 Mcf/D during the quarter. After the workover, the well has been averaging 51 BOPD and 62 Mcfd. To date, the Leonard #1-23H well has produced approximately 99 MSTB and 102 MMcf.

 

3.The Gene #1-22H well (30.6% working interest) produced at an average daily rate of 110 BOPD and 90 Mcf/D during the quarter. The cumulative production to date is approximately 131 MSTB and 144 MMcf.

 

4.The Gary #1-24H (37% working interest) well was down for 13 days during the quarter due to pump rod failure. As a result, the well averaged 80 BOPD and 122 Mcf/D during the quarter. The cumulative production to date is approximately 129 MSTB and 210 MMcf.

 

5.The Rodney #1-14H (27% working interest) well produced at an average daily rate of 97 BOPD and 183 Mcf/D during the quarter. The cumulative production to date is approximately 96 MSTB and 132 MMcf.

 

6.Earl #1-13H (32% working interest) well was down for 33 days during the quarter due to tubing failure and as a result produced at an average daily rate of 140 BOPD and 222 Mcf/D during the quarter. Cumulative production to date is approximately 145 MSTB and 200 MMcf.

 

7.The Everett #1-15H (26% working interest) well was the sixth Bakken well drilled in the North Stockyard Field. The Everett well produced at an average daily rate of 170 BOPD and 244 Mcf/D during the quarter. Cumulative production to date is approximately 70 MSTB and 96 MMcf.

 

Sabretooth Gas Field, Brazoria County Texas

Oligocene Vicksburg Formation, Gulf Coast Basin

Samson 9.375% Working Interest

Production for the Davis Bintliff #1 well has held steady at an average rate of 2.6 MMcf/D and 28 BOPD for the quarter. The well has continued to be choked-back from a 10/64” choke (where it was making 4.3 Mmcf/D) to an 8/64” choke (where it is now making 2.6 Mmcf/D) due to depressed gas prices. Cumulative production to date is approximately 5 Bscf and 59 MBO.

 

Abercrombie 1-10H well, Richland County, Montana

Mississippian Bakken Formation, Williston Basin

Samson 0.75% working interest

The Abercrombie #1-10H (SSN 0.75% W.I.) well has produced a cumulative 29,000 barrels of oil while producing at an average rate of approximately 160 BOPD and 310 Mcf/D during the quarter.

 

15
 

 

Riva Ridge 6-7-33-56H well, Sheridan County, Montana

Mississippian Bakken Formation, Williston Basin

Samson 0.76% working interest

The Riva Ridge 6-7-33-56H well has been fracked and is now on production. It is producing at an average rate of approximately 138 BOPD and 15 Mcf/D during the quarter.

 

Looking Ahead

 

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

 

  · The continued appraisal and development, subject to the results of the appraisal operations, of our Hawk Springs and Roosevelt projects, including multiple conventional targets in the Permian and Pennsylvanian formations on our acreage in Goshen County, Wyoming and Roosevelt County, Montana respectively.

 

  · The continued development of our North Stockyard project in Williams County, North Dakota.

 

Results of Operations

 

In the first quarter of the year ending June 30, 2013, we reported a net loss of ($0.9) million, which can be attributed to lease operating expenses, depletion and depreciation and other costs exceeding our revenue.

 

Operating data

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

 

   Three months ended 
   30-Sep-12   30-Sep-11 
Production Volume          
Oil (Bbls)   18,882    24,601 
Natural gas (Mcf)   41,091    59,246 
BOE   25,731    34,475 
           
Oil Price per Bbl Produced (in dollars):          
Realized price  $76.61   $85.20 
Realized commodity derivative gain (loss)   -    - 
Net realized price  $76.61   $85.20 
           
Natural Gas Price per Mcf Produced (in dollars):          
Realized price  $3.55   $5.23 
Realized commodity derivative gain (loss)   -   $0.62 
Net realized price  $3.55   $5.85 
           
Expense per BOE (in dollars):          
Lease operating expenses  $25.56   $9.58 
Production and property taxes  $6.00   $8.59 
Depletion, depreciation and amortization  $22.05   $21.27 
General and administrative expense  $57.63   $55.10 

 

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

 

   Three months ended     
   31-Mar-12   31-Mar-11   1Q11 to 1Q12 change 
Oil sales  $1,446,537   $2,176,436   $(729,899)
Gas sales   145,764    310,176    (164,412)
Other liquids   4,457    5,666    (1,209)
Interest income   71,640    113,806    (42,166)
Other   12    19,157    (19,145)
              - 
Lease operating expense   (811,989)   (626,797)   (185,192)
Depletion, depreciation and amortization   (590,767)   (733,309)   142,542 
Exploration and evaluation expenditure   (361,944)   (107,956)   (253,988)
Accretion of asset retirement obligations   (13,434)   (5,434)   (8,000)
General and administrative   (1,482,812)   (1,899,581)   416,769 
Income tax (provision)/ benefit   668,998    188,178    480,820 
Net (loss)  $(923,538)  $(559,658)  $(363,880)

 

Three Months Comparison of Quarter Ended September 30, 2012 to Quarter Ended September 30, 2012

 

Oil and gas revenues

 

Oil revenues decreased from $2.1 million for the three months ended September 30, 2011 to $1.4 million for the three months ended September 30, 2012 as a result of a decrease in our oil production, coupled with a decrease in the realized price.  Oil production decreased slightly from 24,601 barrels for the quarter ended September 30, 2011 to 18,882 barrels for the quarter ended September 30, 2012.  Our realized oil price decreased from $85.20 for the quarter ended September 30, 2011 to $76.61 for the quarter ended September 30, 2012.

 

Gas revenues also decreased from $0.3 million for the quarter ended September 2011 to $0.14 million for the quarter ended September 30,2012 due a combination of a decrease in production volume and realized gas price. Production decreased by 13%, while the realized gas price decreased from $5.85 for the quarter ended September 30, 2011 to $3.55 for the quarter ended September 2012.

 

Exploration expense

 

Exploration expenditure increased from $0.1 million for the quarter ended September 30, 2011 to $0.36 million for the quarter ended September 30, 2012 primarily as a result of writing off $0.26 million in additional expenditure on our Australia II and Gretel II wells in our Roosevelt Project in Montana.

 

We currently have approximately $7.0 million capitalized in exploration expense on the balance sheet in relation to the Spirit of America II well. While this well is still being completed, depending on the outcome of it, it is possible that we will need to recognize impairment expense in relation to this expenditure. The magnitude of impairment expense, if any, is not yet known and will depend on future events.

 

Lease operating expense

 

Lease operating expenses increased from $0.6 million for the quarter ended September 30, 2011 to $0.8 million for the quarter ended September 30, 2012. This is largely due to increased lease operating expense in our North Stockyard field as a result of the high salt water content.

 

Depletion, depreciation and amortization expense

 

Depletion, depreciation and amortization expense decreased from $0.7 million for the quarter ended September 30, 2011 to $0.6 million for the quarter ended September 30, 2012. Depreciation, depletion and amortization expense per BOE remained consistent at $21.27 for the quarter ended September 30, 2011 compared to $22.05 for the quarter ended September 30, 2012.

 

General and administrative expense

 

General and administrative expense decreased slightly from $1.9 million for the quarter ended September 30, 2011 to $1.5 million for the quarter ended September 30, 2012.  Included within general and administrative expense is $0.7 million of employee benefits (including share based payments) for the current quarter compared with $1.1 million for the prior quarter. This decrease is due to lower share based payments expense and lower employee bonus accruals.  Other general and administrative costs including but not limited to legal fees, audit fees, investor relations and travel remained consistent at $0.75 million for the quarter ended September 30, 2011 and $0.8 million for the quarter ended September 30, 2012.

 

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Income tax (expense)/benefit

 

Income tax benefit increased from a benefit of $0.2 million for the quarter ended September 30, 2011 to a benefit of $0.67 million for quarter ended September 30, 2012.  The tax benefit recognized in the current year is a result of a portion of this year’s operating losses being carried back to the income tax expense recognized in the year ended June 30, 2011.

 

Cash Flows

 

The table below shows cash flows for the three month period ended: 

 

   Three months ended 
   30-Sep-12   30-Sep-11 
Cash provided by/(used in) operating activities  $(161,325)  $123,781 
Cash (used in)/provided by investing activities   (8,754,657)   (4,335,408)
Cash provided by/(used in) financing activities   444,272    290,581 

 

Cash provided by operations increased from an inflow of $0.12 million for the three months ended September 30, 2011 to cash outflow ($0.16) million for the three months ended September 30, 2012. Payments to suppliers and employees decreased significantly from $2.7 million for the three months ended September 30, 2011 to $1.9 million for three months ended September 30, 2012, as a result of decreasing general and administration costs.

 

Cash used in investing activities increase from cash outflow of $4.3 million for the three months ended September 30, 2011 to a cash outflow of $8.7 million for the three months ended September 30, 2012. The cash outflow for both three month periods ended September 30, 2012 and 2011 is as a result of drilling/exploration activities being conducted in our Hawk Springs and Roosevelt projects.

 

Cash provided by financing activities increased from a cash inflow of $0.3 million for the three months ended September 30, 2011 to cash inflow of $0.4 million for the three months ended September 30, 2012. Cash inflow for both of the three month periods is a result of the exercise of options during the respective period.

 

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 the fiscal year ending June 30, 2013 as well. Our current budget for exploration, exploitation and development capital expenditures in fiscal year ending June 30, 2013 is $9 million, of which we incurred approximately $5 million during the first quarter of the fiscal year. The remaining expenditure relates to:

·the completion of the Spirit of America II well,
·the salt water disposal well in our North Stockyard project as well as at least two development wells in this project and
·the initial well in our South Prairie Project in North Dakota.

 

We also have a rig commitment, expected to commence in December 2012, the total commitment over 18 months is $14.2 million.

 

We expect to fund our fiscal year 2013 capital expenditures with cash on hand and cash flow from operations, and there is also a possibility we will conduct an equity capital raising or debt financing. In addition, there is a possibility that we will pursue one or more significant acquisitions that require equity or debt financing. However, there is no guarantee that we will be able to fund all of the planned expenditure from our existing working capital or be able to raise the funds through the equity or debt markets.

 

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 fiscal year ending June 30, 2013, 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 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.

 

18
 

 

Currently our two main sources of liquidity are cash on hand, which was $10.5 million at September 30, 2012, and cash flow from operations. There is also a possibility that during the fiscal year ending June 30, 2013 we will conduct a equity capital raise or debt financing. During the past two fiscal years, our two main sources of liquidity were (i) approximately $73.2 million cash received from the sale of 24,166 acres in Goshen County, Wyoming to Chesapeake Energy Corporation and (ii) $6.3 million received from the sale of our interests in the Jonah and Lookout Wash fields. Both sales occurred during the fiscal year ended June 30, 2011. During the recent years prior to the fiscal year ended June 30, 2011, our primary sources of liquidity were (i) equity sales and (ii) a loan facility with Macquarie Bank Limited, which we repaid in full on May 30, 2011.

 

Our cash on hand position has decreased from the same period in the previously year largely due to exploration expenditures which have not produced meaningful cash flow to date from production results. In particular, both of the two Roosevelt project wells drilled in the fiscal year ended June 30, 2012 have so far failed to deliver positive results and one well in the Hawk Springs project well was also drilled unsuccessfully. If future drilling success rates or production are less than anticipated, 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 unevaluated properties. See the risk factors in our Annual Report on Form 10-K for the fiscal year ended June 30, 2012 including “Drilling results in emerging plays, such as our Hawk Springs and Roosevelt Projects, are subject to heightened risks.” and “Inadequate liquidity could materially and adversely affect our business operations.”

 

During the quarter ended September 30, 2012, 27,983,189 1.5 Australian cent (A$0.015) warrants were exercised for net proceeds of $ 0.4 million to us. The warrants exercised were issued in a public rights offering conducted in October 2009 and expire December 31, 2012.

  

Item 3.   Quantitative and Qualitative Disclosures About Market Risk.

 

There were no material changes to the disclosure made in our Annual Report on Form 10-K for the year ended June 30, 2012 regarding this matter.

 

Item 4.    Controls and Procedures.

 

As of September 30, 2012, 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, 2012, 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, 2012 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.

 

None.

 

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 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, 2012.  The risks disclosed in our Annual Report on Form 10-K could materially affect our business, financial condition or future results.  The risks described 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.

 

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Item 3.    Defaults Upon Senior Securities.

 

Not applicable.

 

Item 4.    Removed and Reserved.

 

Not applicable.

 

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Item 5.    Other Information.

 

Not applicable.

 

Item 6.    Exhibits.

 

Exhibit No.   Title of Exhibit
     
31.1*   Rule 13a-14(a)/15d-14(a) Certification of the Principal Executive Officer as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
     
31.2*   Rule 13a-14(a)/15d-14(a) Certification of the Principal Financial Officer as adopted 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 18 U.S.C., 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
     
101**   The following financial information from Samson Oil & Gas Limited’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 is formatted in XBRL (eXtensible Business Reporting Language): (i)  Consolidated Balance Sheets at September 30, 2012, (ii)  Consolidated Statements of Operations for the three months ended September 30, 2012 and September 30, 2011, (iii)  Consolidated Statement of Changes in Stockholders’ Equity at September 30, 2012 (iv)  Consolidated Statements of Cash Flows for the three months ended September 30, 2012 and September 30, 2011, and (v) the Notes to Consolidated Financial Statements.  The information in Exhibit 101 is “furnished” and not “filed,” as provided in Rule 402 of Regulation S-T.

 

*Filed herewith

** 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 9, 2012 By: /s/ Terence Barr
    Terence M. Barr
    Managing Director, President and Chief Executive Officer (Principal Executive Officer)
   
Date:  November 9, 2012 By: /s/ Robyn Lamont
    Robyn Lamont
    Chief Financial Officer (Principal Financial Officer)

 

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