Samson Oil & Gas (SSNYY) 10-Q 2012 Q1 Quarterly report

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, 2011

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 ¨  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 1,750,169,370 ordinary shares outstanding as of October 26, 2011.

SAMSON OIL & GAS LIMITED

FORM 10-Q

QUARTER ENDED SEPTEMBER 30, 2011

TABLE OF CONTENTS

		Page
Part I — Financial Information		3
Item 1.	Financial Statements.	3
Consolidated Balance Sheets (unaudited), September 30, 2011 and June 30, 2011		3
Consolidated Statement of Operations (unaudited), quarters ended September 30, 2011 and 2010		4
Consolidated Statement of Changes in Stockholders’ Equity (unaudited) for the three months ended September 30, 2011		5
Consolidated Statement of Cash Flows (unaudited), quarters ended September 30, 2011 and 2010		6
Notes to  Consolidated Financial Statements (unaudited)		7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	14
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	22
Item 4.	Controls and Procedures.	22
Part II— Other Information		22
Item 1.	Legal Proceedings.	22
Item 1A.	Risk Factors.	22
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	22
Item 3.	Defaults Upon Senior Securities.	22
Item 4.	Removed and Reserved.	22
Item 5.	Other Information.	23
Item 6.	Exhibits.	23
Signatures		24

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,” “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 our forward–looking statements.

2

Part I — Financial Information

Item 1.  Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

 CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2011			June 30, 2011
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	53,947,092		$	58,448,477
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively		2,506,139			1,696,696
Prepayments		242,561			592,805
Pipe inventory – held by third party		468,845			489,526
Income tax receivable		2,807,048			2,578,870
Derivative instruments		917			22,268
Total current assets		59,972,602			63,828,642
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment		14,427,264			13,862,510
Undeveloped capitalized acreage		6,761,957			2,157,455
Capitalized exploration expense		1,917,884			1,190,283
Other property and equipment, net of accumulated depreciation and amortization of $204,716 and $192,138 at September 30, 2011 and June 2011, respectively		385,784			352,264
Net property, plant and equipment		23,492,889			17,562,512
OTHER ASSETS
Restricted cash		168,157			172,504
Other		31,125			34,174
TOTAL ASSETS	$	83,664,773		$	81,597,832
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	5,180,542		$	2,854,483
Accruals		633,750			389,000
Provision for annual leave		186,251			161,891
Total current liabilities		6,000,543			3,405,374
Capitalized lease		20,211			29,769
Asset retirement obligations		241,458			236,024
TOTAL LIABILITIES		6,262,212			3,671,167
STOCKHOLDERS’ EQUITY – nil par value
Common stock, 1,750,169,370 (equivalent to 87,508,468 ADR’s) and 1,732,043,789 (equivalent to 86,602,189 ADR’s) shares issued and outstanding at September 30, 2011 and June 30, 2011, respectively)		82,277,271			81,668,085
Other comprehensive income		2,516,163			3,089,795
Retained earnings (accumulated deficit)		(7,390,873	)		(6,831,215	)
Total stockholders’ equity		77,402,561			77,926,665
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	83,664,773		$	81,597,832

See accompanying Notes to Consolidated Financial Statements.

3

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three months ended
	September 30, 2011			September 30, 2010
REVENUES AND OTHER INCOME:
Oil sales	$	2,176,436		$	642,585
Gas sales		310,176			210,431
Other liquids		5,666			-
Interest income		113,806			36,195
Gain on sale of exploration acreage		-			69,802,931
Other		19,157			211
		2,625,241			70,692,353
EXPENSES:
Lease operating expense		(626,797	)		(253,112	)
Depletion, depreciation and amortization		(733,309	)		(417,368	)
Exploration and evaluation expenditure		(107,956	)		(147,825	)
Accretion of asset retirement obligations		(5,434	)		(7,097	)
General and administrative		(1,899,581	)		(772,765	)
Interest expense, net of capitalized costs		-			(283,176	)
		(3,373,077	)		(1,881,343	)
Income (loss) from continuing operations		(747,836	)		68,811,010
Income tax benefit/(provision)		188,178			(15,210,040	)
Earnings from continuing operations		(559,658	)		53,600,970
Total income (loss) from discontinued operations, net of income taxes		-			218,234
Net income (loss)	$	(559,658	)	$	53,819,204
Net earnings per common share from continuing operations:
Basic – cents per share		(0.03	)		3.23
Diluted – cents per share		(0.03	)		2.73
Net earnings per common share from discontinued operations:
Basic – cents per share		-			0.01
Diluted – cents per share		-			0.01
Weighted average common shares outstanding:
Basic		1,742,741,392			1,658,828,159
Diluted		1,742,741,392			1,957,938,184

See accompanying Notes to Consolidated Financial Statements.

4

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

	Issued Capital		Retained Earnings/ (Accumulated Deficit)			Other Comprehensive Income			Total Equity
Balance at June 30, 2011	$	81,668,085	$	(6,831,215	)	$	3,089,795		$	77,926,665
Net income (loss)		-		(559,658	)		-			(559,658	)
Foreign currency translation, net of tax of $nil		-		-			(573,632	)		(573,632	)
Total comprehensive income/(expense) for the period		-		(559,658	)		(573,632	)		(1,133,290	)
Stock based compensation		318,605		-			-			318,605
Issue of share capital		290,581		-			-			290,581
Balance at September 30, 2011	$	82,277,271	$	(7,390,873	)	$	2,516,163		$	77,402,561

See accompanying Notes to Consolidated Financial Statements.

5

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three months ended
	September 30, 2011			September 30, 2010
Cash flows from operating activities
Receipts from customers	$	2,760,806		$	1,492,536
Cash received from commodity derivative financial instruments		38,509			62,071
Payments to suppliers & employees		(2,749,338	)		(1,575,434	)
Interest received		113,804			36,195
Interest paid		-			(260,039	)
Income taxes paid		(40,000	)		-
Net cash flows provided by/(used in) operating activities		123,781			(244,671	)
Cash flows from investing activities
Proceeds from sale of listed shares		-			49,040
Proceeds from sale of exploration acreage		-			69,802,931
Payments for plant & equipment		(54,705	)		-
Payments for exploration and evaluation		(2,255,724	)		(504,710	)
Payments for oil and gas properties		(2,024,979	)		(4,101,096	)
Net cash flows (used in)/provided by investing activities		(4,335,408	)		65,246,165
Cash flows from financing activities
Proceeds from issue of share capital		290,581			2,909,596
Repayment of borrowings		-			(600,000	)
Payments for costs associated with capital raising		-			(234,240	)
Net cash flows provided by financing activities		290,581			2,075,356
Net increase/(decrease) in cash and cash equivalents		(3,921,046	)		67,076,850
Cash and cash equivalents at the beginning of the financial year		58,448,477			5,885,735
Effects of exchange rate changes on cash and cash equivalents		(580,339	)		661,299
Cash and cash equivalents at end of year	$	53,947,092		$	73,623,884

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, 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, 2011. The year-end Consolidated Balance Sheet was derived from audited Consolidated Financial Statements included in the report, 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, 2011.

Recent Accounting 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 will 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 will require the Company to present the statements of comprehensive income separately from its statements of equity, as these statements are currently presented on a combined basis.  

2. Income Taxes

	Three months ended
	September 30, 2011			September 30, 2010
Income tax benefit/(expense)	$	188,178		$	(15,210,040	)
Effective tax rate		23.89	%		22.22	%

7

The Company has current year losses and available prior year cumulative net operating losses 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 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 year’s current 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.

The tax for the period ending September 30, 2010 is current tax expense.  This expense is the result of the sale of property that generated an extraordinary gain, when combined with the ordinary operating activity, was in excess of the net operating losses available to offset the net income for the period.  Deferred taxes for the period continue to be zero as there is a full valuation allowance on the remaining net deferred tax asset.

Accounting Standards Codification (“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 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 September 30,
	2011		2010
Dilutive		-		332,081,205
Anti–dilutive		319,220,499		14,879,077

The following tables set forth the calculation of basic and diluted earnings per share for continuing and discontinued operations:

Continuing operations	Three months ended September 30,
	2011			2010
Net income (loss) from continuing operations	$	(559,658	)	$	53,600,970
Basic weighted average common shares outstanding		1,742,741,392			1,658,828,159
Add: dilutive effect of stock options		-			272,621,779
Add: bonus element for rights issue		-			26,488,246
Diluted weighted average common shares outstanding		1,742,741,392			1,957,938,184
Basic earnings per common share – cents per share		(0.03	)		3.23
Diluted earnings per common share – cents per share		(0.03	)		2.73

8

Discontinued operations	Three months ended September 30,
	2011		2010
Net income (loss) from discontinued operations		-	$	218,234
Basic weighted average common shares outstanding		-		1,658,828,159
Add: dilutive effect of stock options		-		272,621,779
Add: bonus element for rights issue		-		26,488,246
Diluted weighted average common shares outstanding		-		1,957,938,184
Basic earnings per common share – cents per share		-	$	0.01
Diluted earnings per common share – cents per share		-		0.01

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, 2011 and 2010:

	Three months ended September 30,
	2011		2010
Asset retirement obligations at beginning of period	$	236,024	$	301,894
Liabilities incurred or acquired		-		3,419
Liabilities settled		-		–
Disposition of properties		-		–
Accretion expense		5,434		7,097
Asset retirement obligations at end of period		241,458		312,410
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)		-		-
Long-term asset retirement obligations	$	241,458	$	312,410

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 $318,605 and $nil during the three months ended September 30, 2011 and 2010.

9

Stock Options

The following table summarizes stock option activity for the three months ended September 30, 2011:

	Number of Shares			Weighted Average Exercise Price (Australian Cents)		Aggregate Intrinsic Value (Australian Cents)(1)		Number of Shares Exercisable
Outstanding at July 1, 2011		333,412,940			0.033				312,079,606
Granted		4,000,000			0.164				1,333,333
Exercised		(18,192,441	)		0.015				(18,192,499	)
Cancelled/expired		-
Outstanding at September 30, 2011		319,220,499			0.036		0.089		295,220,498

(1) The intrinsic value of a stock option is the amount by which the market value of the underlying stock at the end of the related period exceeds the exercise price of the option at the Balance Sheet date.

In July 2011, 4,000,000 stock options were granted under the Samson Oil & Gas Limited Stock Option Plan to an employee of the Company.  These options have an exercise price of 16.4 cents (Australian) and an expiry date of December 31, 2014. One third of these stock options vested on July 31, 2011.  Another third will vest on July 31, 2012 with the remaining third vesting on July 31, 2013, provided the employee is still employed by the Company on those dates.

The fair value of each option granted was estimated using the Black-Scholes option pricing model. The following assumptions were used to compute the weighted average fair market value of options granted:

Share price at grant date (Australian cents)		14.0
Exercise price (Australian cents)		16.40
Time to expiry (years)		4
Risk free rate (%)		1.14
Share price volatility (%)		85.68
Dividend yield	Nil

As of September 30, 2011, there was $631,379 of total unrecognized compensation cost related to outstanding stock options. This cost is expected to be recognized over three years.

Bonus Plan

For the portion of performance share awards subject to market based criteria, the fair value as of the balance sheet date was estimated using a Monte Carlo valuation model. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of the Company's common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-month vesting period. The key assumptions used in valuing the market-based restricted shares were as follows:

Number of simulations	200,000
Expected volatility	84	%
Risk free interest rate	0	%

$244,750 in vesting expense has been recognized during the quarter, bringing the total accrual for the bonus plan to $633,750.  No payments have been made in regard to the bonus plan to the date of this report.

10

6. Hedging and Derivative Instruments

Commodity Derivative Agreements.  The Company utilizes swap and collar option contracts to hedge the effect of price changes on a portion of its future oil production. The objective of the Company’s hedging activities and the use of derivative financial instruments is 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 are with a single multinational bank with no history of default with the Company. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. No collateral has been provided in relation to the current contracts outstanding. Collateral maybe required for future contracts.

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.

The components of commodity derivative losses (gains) in the  Consolidated Statements of Operations are as follows:

	Three months ended September 30,
Discontinued operations	2011		2010
Commodity derivative gains, net	$	-	$	181,714

	Three months ended September 30,
Continuing operations	2011		2010
Other income, net	$	17,158	$	-

Balance Sheet Classification	September 30, 2011		June 30, 2011
	Derivative Assets		Derivative Assets
Current assets - derivative instruments	$	917	$	22,268

As of September 30, 2011, the Company had entered into collar agreements related to its oil production. The aggregate economic effects of those agreements are summarized below. Location and quality differentials attributable to the Company’s properties are not included in the following prices. The agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX WTI (oil).

Date	Call/Put	Volume – Barrels		Price – $ per Barrel
July 2011 – Dec 2011	Put		4,733		60.00
July 2011 – Dec 2011	Call		4,733		102.90

These terms of these derivative arrangements are in line with Master International Swaps and Derivatives Agreement.

Following the sale of our interest in the Jonah and Lookout Wash properties our exposure to natural gas price fluctuations decreased significantly.  On July 6, 2011, we closed out our remaining gas derivative positions.  The termination of these positions resulted in Macquarie Bank Limited (the counter party to the hedges) paying us $36,500.

11

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 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 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, 2011 and June 30, 2011.

	Level 1		Level 2		Level 3		Fair Value at September 30, 2011
Assets (Liabilities):
Commodity derivative contracts	$	–	$	917	$	–	$	917

	Level 1		Level 2		Level 3		Fair Value at  June 30, 2011
Assets (Liabilities):
Commodity derivative contracts	$	–	$	22,268	$	–	$	22,268

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

Commodity Derivative Contracts.  The Company’s commodity derivative instruments consist of collar contracts for oil. The Company values 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.

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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.

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

Leases–The Company has entered into lease agreements for office space in Denver, Colorado and Perth, Western Australia. As of June 30, 2011, future minimum lease payments under operating leases that have initial or remaining non–cancelable terms in excess of one year are $159,091 in 2012, $143,572 in 2013, $118,721 in 2014, $121,029 in 2015, $123,339, 2016 and $10,294 thereafter.  Net rent expense incurred for office space was $41,604 for the quarter ending September 30, 2011 and $29,851 for the quarter ending September 30, 2010.

Drilling commitments – The Company has contracted to drill two horizontal wells in our Roosevelt project area as part of our agreement with Fort Peck Energy Company.  These wells are expected to cost approximately $6.5 million each.  This cost is an estimate only and is dependent on the performance of drilling operations and the cost of oil services at the time of drilling.  Drilling permits have been received for both of these wells, with the first well expected to spud in November 2011.

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.

There are no unrecorded contingent assets or liabilities in place for the Company at September 30, 2011 or June 30, 2011.

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 expenditure under our policy, we conclude that we are unlikely to recover the expenditure by future exploitation or sale, then the relevant capitalized amount will be written off to the income statement.

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Currently we have capitalized exploration expenditure of $1.9 million.  This primarily relates to monies expended on our Hawk Springs (including 3D seismic acquisition costs) and Roosevelt projects.  We are currently in the process of drilling three exploratory wells in our Hawk Springs project area.  The costs incurred to date in relation to our drilling activities for the Spirit of America and Constellation wells have been capitalized pending their completion.  We are also drilling the Defender exploratory well in the Hawk Springs project area.  This well is 100% carried by Halliburton, therefore no costs have been capitalized by Samson.

10.  Issue of Share Capital

During the quarter ended September 30, 2011, 18,192,441 1.5 Australian cent warrants were exercised for net proceeds of $290,581 to us. The warrants were issued in a public rights offering conducted in October 2009.

11. Cash Flow Statement

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

	Three months ended September 30,
	2011			2010
Net profit/(loss) after tax	$	(559,658	)	$	53,819,204
Net (gain)/loss recognized on re-measurement to fair-value of investments held for trading		-			(5,494	)
Depletion, depreciation and amortization		733,309			565,183
Stock based compensation		318,605			150,617
Accretion of asset retirement obligation		5,434			7,097
Exploration and evaluation expenditure		107,956			147,825
Net (gain)/loss on fair value movement of fixed forward swaps		(21,350	)		(134,807	)
Gain on sale of exploration acreage		-			(69,802,931	)
Changes in assets and liabilities:
(Increase)/decrease in receivables		(809,443	)		(163,997	)
(Increase)/decrease in income tax receivable		(228,178	)		-
Increase/(decrease) in income tax payable		-			15,327,290
Increase/(decrease) in provision for annual leave		24,360			7,175
Increase/(decrease) in payables		552,746			(161,833	)
NET CASH FLOWS USED IN OPERATING ACTIVITIES	$	123,781		$	(244,671	)

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

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 24,601 barrels of oil for the quarter ended September 30, 2011 compared to 12,222 barrels of oil for the quarter ended September 30, 2010.  Our net gas production was 59,246 Mcf for the quarter ended September 30, 2011 compared to 166,542 Mcf for the quarter ended September 30, 2010.

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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.

Trends and Events in the Three Months Ended September 30, 2011

Exploration Activities

In July 2011, we completed the initial acquisition of 20,000 acres of leasehold in Roosevelt County, Montana for approximately $3.5 million. We retain the option to acquire a further 20,000 acres which has been leased and is in our control (tranche 2).  This acquisition will be evaluated with a two well drilling program.

We have received the permits to drill the two initial wells, Australia II 12 KA 6 and Gretel II 12 KA 3, and pad construction is underway. Both wells are planned to be drilled as 4,500 foot laterals in the middle Bakken Formation and then fracture stimulated using a multi stage, external casing packer completion technique. The Australia II well is expected to be spud in November 2011 with the Gretel II following directly after.  Although not expected to be drilled immediately, we have also received a permit for Australia III KA 9.

Following the drilling of the two initial appraisal wells, FPEC will have the right to back into a 33.34% position in both tranches by reimbursing Samson’s acreage and drilling costs to the extent of that equity. In such an event, Samson will have a 66.66% working interest and a 53.34% net revenue interest.

FPEC is owned by North American Resource Partners (NARP) and the Assiniboine and Sioux Tribes. NARP is a portfolio company of Quantum Energy Partners, a private equity fund with substantial experience in energy transactions with Indian Nations. While Samson is not part of FPEC or NARP, the importance of having both of these Fort Peck Tribes as equity partners, albeit indirectly, was an important part of Samson’s decision to invest in the Roosevelt Project.

Drilling Program

Roosevelt Project, Roosevelt County, Montana

Mississippian Bakken Formation, Williston Basin

Australia II 12 KA 6 and Gretel II 12 KA 3

Samson 100% Working Interest (subject to a 33.34% back in)

Two horizontal appraisal wells, Australia II 12 KA 6 and Gretel II 12 KA 3, are scheduled to be drilled in the Roosevelt Project during the 4th quarter of calendar year 2011 to test the middle member of the Bakken Formation.  In addition to Australia II 12 KA 6, and Gretel II 12 KA 3, Australia III 12 KA 9 has also been surveyed and staked, and permits on all three locations have been approved.  20-inch surface casing has been also been set on the Australia IV 12 KA 16 well.

Hawk Springs Project, Goshen County, Wyoming

Cretaceous Niobrara Formation, Northern D-J Basin

Defender US33 #2-29H

Samson 37.5% Working Interest

The first Niobrara appraisal well, the Defender US33 #2-29H, commenced drilling operations in mid-August and reached a total depth of 11,089 feet in late September.  This well was drilled and funded 100% by Halliburton under their farmin agreement.  A vertical pilot well was initially drilled and logged to a depth of 7,450’ and approximately 100 feet of conventional core was cut from the Niobrara Formation.  Stress fields and fracture orientations were identified from the core and FMI logs, which determined the south-north azimuth of the horizontal lateral. The vertical pilot borehole was then plugged back to a kick-off point above the Niobrara.   From the kick-off point, the borehole angle was built until it was horizontal and the bit was positioned within the Niobrara “B” zone.  7-inch intermediate casing was then set through the curve and the lateral was drilled for a distance of 4,300’ entirely within the Niobrara “B” zone.  The well is currently waiting to be completed.  It will be completed with the plug and perf process in 15-stages which will involve the placement of 3,000,000 pounds of proppant into the Niobrara Formation.

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Hawk Springs Project, Goshen County, Wyoming

Wildcat (Exploratory) targets in the Permian & Pennsylvanian, Northern D-J Basin

Spirit of America US34 #1-29

Samson 100% Working Interest

The first Permian and Pennsylvanian appraisal well, the Spirit of America US34 #1-29, is currently being drilled.  The well will be drilled as an 11,000’ vertical test to the Precambrian basement to test multiple conventional targets; in particular, two closed structural traps in the Permian and Pennsylvanian sections.

Hawk Springs Project, Goshen County, Wyoming

Cretaceous Niobrara Formation, Northern D-J Basin

Constellation US20 State #1-36H

Samson 100% Working Interest

The Constellation US20 State #1-36H well is planned as Samson’s second Niobrara well and is located outside the Halliburton/Mountain Energy Joint Venture area. This drilling of this well is dependent on the completion results of the Defender US33 #2-29H well. Preparatory operations of drilling and cementing the surface casing portion of the hole to a depth of 1,772 feet have been accomplished.

Production Activities

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson various Working Interests

Samson has working interests in six producing wells and one well will be undergoing fracture stimulation in the North Stockyard Field in November. These wells are located in Williams County, North Dakota, in Township 154N Range

99W.

1. The Harstad #1-15H well (34.5% working interest) averaged 34 BOPD and 8 Mcf/D for the quarter from the Mississippian Bluell Formation. The well has performed as expected with a cumulative gross production of 92 MSTB and 81 MMcf.

2. The Leonard #1-23H well (10% working interest, 37.5% after non-consent penalty) averaged 46 BOPD and 50 Mcf/D during the quarter. This well was drilled as a horizontal lateral into the highly productive middle member of the Bakken Formation. To date, the Leonard #1-23H well has produced approximately 87 MSTB and 83 MMcf.

3. The Gene #1-22H well (30.6% working interest) produced at an average daily rate of 115 BOPD and 35 Mcf/D during the quarter. The cumulative production to date is approximately 99 MSTB and 112 MMcf.

4. The Gary #1-24H well (37% working interest) averaged 132 BOPD and 150 Mcf/D during the quarter. The cumulative production to date is approximately 90 MSTB and 146 MMcf.

5. The Rodney #1-14H well (27% working interest) produced at an average daily rate of 284 BOPD and 259 Mcf/D.  The cumulative production to date is approximately 48 MSTB and 49 MMcf.

6. Earl #1-13H well (32% working interest) produced at an average daily rate of 417 BOPD and 452 Mcf/D.  These average rates take into account several down days due to well workovers.  Cumulative production to date is approximately 71 MSTB and 93 MMcf.

7. The Everett #1-15H well (26% working interest) was the sixth Bakken well drilled in the North Stockyard Field in May. The well is still currently waiting on completion with an expected November frac date.

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Samson’s net average daily (after royalties) production rate for the quarter is set out below:

Well	Net Mcf/D	Net BOPD	Net BOEPD
Leonard #1-23H	4.50	3.34	4.09
Harstad #1-15H	2.25	8.75	9.12
Gene #1-22H	8.77	28.87	30.33
Gary #1-24H	47.46	35.94	43.85
Rodney #1-14H	46.09	57.20	64.88
Earl #1-13H	130.31	99.84	121.55
Total	239.38	233.94	273.82

Sabretooth Gas Field, Brazoria County, Texas

Oligocene Vicksburg Formation, Gulf Coast Basin

Samson 12.5% Working Interest

During the quarter this well reached pay out and thus Samson’s net revenue interest has dropped from 12.5% to 9%. Production for the Davis Bintliff #1 well averaged 4.42 MMcf/D and 51.2 BOPD for the quarter, which is essentially a constant rate from inception.  Cumulative production to date is approximately 3.8 Bcf and 45,800 barrels of oil.

Completed our first quarter reporting as a U.S. domestic issuer

We commenced filing as a U.S. domestic issuer on July 1, 2011. Since we remain organized in Australia, we are still considered to be a domestic company in Australia as well.  As a result, we are required to report in the U.S. using U.S. Generally Accepted Accounting Principles (“U.S. GAAP”) and in Australia using International Financial Reporting Standards (“IFRS”).  During the quarter, we filed our first Annual Report on Form 10-K, converted our selling shareholder registration statement on Form F-3 to the domestic issuer Form S-3, and filed three Current Reports on Form 8-K.

Lease Operating Expenses

Lease operating expenses have shown a general rising trend over the past three years.  In the past, we have not been operator of our material fields, so these costs were largely outside of our control.  We expect to have more control over our lease operating costs in the coming years as we will be the operator of our two major projects – Hawk Springs and Roosevelt.  Because these projects are largely exploration plays at this time, we do not have any historical lease operating expense information.

Looking Ahead

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

· The appraisal and development of our Hawk Springs project, including both conventional and unconventional targets on our acreage in Goshen County, Wyoming through the completion of our two test wells – Defender US 33 #2-29H and Spirit of America US#34 1-29.

· The appraisal and development of our Roosevelt project in Roosevelt County, Montana with drilling expected to commence on our first test well, Australia II 12 KA 6 in the fourth quarter of calendar year 2011.

Results of Operations

The following table reflects the components of our oil and natural gas production and sales prices, and our operating revenues, costs and expenses, for the periods indicated, including results from discontinued operations.

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	Three Months Ended September 30,				% Increase (Decrease)
	2011		2010
Production Volume:
Oil (Bbls)		24,601		12,222		101
Natural gas (Mcf)		59,246		166,542		(64	)
BOE		34,475		27,757		24
Oil Price per Bbl Produced (in dollars):
Realized price	$	85.20	$	66.30		28
Realized commodity derivative gain (loss)		-		-
Net realized price	$	85.20	$	66.30		28
Natural Gas Price per Mcf Produced (in dollars):
Realized price	$	5.23	$	3.82		37
Realized commodity derivative gain (loss)		0.62		0.28		121
Net realized price	$	5.85	$	4.10		43
Expense per BOE:
Lease operating expenses	$	9.58	$	8.34		15
Production and property taxes		8.59		6.28		37
Depletion, depreciation and amortization		21.27		20.36		4
General and administrative expense		55.10		28.42		94
Interest expense, net of amounts capitalized	$	-	$	10.45		(100	)

The following table sets forth results of operations for the periods indicated, including total income from discontinued operations:

	Three months ended  September 30,						Variance			% Change
	2011			2010
Oil sales	$	2,176,436		$	642,585		$	1,533,851			239
Gas sales		310,176			210,431			99,745			47
Other liquids		5,666			-			5,666			100
Interest income		113,806			36,195			77,611			214
Gain on sale of exploration acreage		-			69,802,931			(69,802,931	)		(100	)
Other		19,157			211			18,946			8,979
Lease operating expense		(626,797	)		(253,112	)		373,685			148
Depletion, depreciation and amortization		(733,309	)		(417,368	)		315,941			76
Exploration and evaluation expenditure		(107,956	)		(147,825	)		(39,869	)		27
Accretion of asset retirement obligations		(5,434	)		(7,097	)		1,663			23
General and administrative		(1,899,581	)		(772,765	)		1,110,692			141
Interest expense, net of capitalized costs		-			(283,176	)		(283,179	)		100
Income tax (provision)/ benefit		188,178			(15,210,040	)		(15,398,218	)		101
Total income (loss) from discontinued operations net of income taxes		-			218,234			(218,234	)		(100	)
Net income (loss)	$	(559,658	)	$	53,819,204

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Net income (loss)

The result for the three months ended September 30, 2011 was a net loss attributable to shareholders, after income tax, of $0.56 million.  The net loss for the quarter was due to continued exploration expenditure and general and administrative expenditure. 

Oil and gas revenues

Oil revenues increased from $0.6 million for the three months ended September 30, 2010 to $2.2 million for the three months ended September 30, 2011 primarily as a result of our increased focus on oil production.  Since the quarter ended September 30, 2010, two new oil wells in our North Stockyard project have come online.  Oil production has increased from 12,222 barrels for the quarter ended September 30, 2010 to 24,601 barrels for the quarter ended September 30, 2011.  Oil revenues have also increased as a result of an increase in the realized oil price.  Our realized oil price increased from $66.30 for the quarter ended September 30, 2010 to $85.20 for the quarter ended September 30, 2011.

Gas revenues increased from $0.2 million for the three months ended September 30, 2010 to $0.3 million for the three months ended September 30, 2011.  This is primarily as result of the commencement of gas sales from our North Stockyard field during the current quarter.  Gas sold in this field obtains a higher price due to the lower supply of gas in this area compared to the level of supply usually seen in the Rocky Mountains, which often results in lower gas prices being recorded. Our realized gas price increased from $4.10 for the quarter ended September 30, 2010 to $5.85 for the quarter ended September 30, 2011.

Sale of exploration acreage

Sale of exploration acreage decreased from $70 million for the three months ended September 30, 2010 to $nil for the three months ended September 30, 2011.  The sale in the prior period was the result of our sale of exploration acreage in Hawk Springs project area in Goshen County, Wyoming. This was a one-off sale and is not expected to be repeated again in the foreseeable future.

Exploration expense

Exploration expenditure remained consistent at $0.1 million for the quarters ended September 30, 2010 and September 30, 2011.  Exploration expenditure in both  quarters relates to delay rental payments, that are most often made annually in order to maintain our lease hold position on non-producing leases.

Lease operating expense

Lease operating expenses increased from $0.2 million for the quarter ended September 30, 2010 to $0.6 million for the quarter ended September 30, 2011.  A portion of the increase can be attributed to more activity; for example, we brought two wells in our North Stockyard project on line since the corresponding period in the prior year.  Some of the increase can also be attributed to increased lease operating expenses being incurred by the operators of our fields, for example increased activity in North Dakota in order to exploit the Bakken formation has also contributed to increased lease operating expenses

Depletion, depreciation and amortization expense

Depletion, depreciation and amortization expense has increased from $0.4 million for the quarter ended September 30, 2010 to $0.7 million for the period ended September 30, 2011. This is as a result of increased oil production from 12,222 barrels of oil for the quarter ended September 30, 2010 to 24,601 barrels of oil for the quarter ended September 30, 2011.  Depletion, depreciation and amortization per BOE did not move significantly between the two periods.

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General and administrative expense

General and administrative expense increased from $0.8 million for the quarter ended September 30, 2010 to $1.9 million for the quarter ended September 30, 2011.  Included within general and administrative expense is $0.3 million of share based payments for the current quarter compared with $0.15 for the prior quarter.  The share based payments expense in the current quarter relates to the vesting expense for options granted to employees during the year ended June 30, 2011.  All employees were given a pay increase effective January 1, 2011 which increased employee benefit costs from $0.3 million to $0.5 million.  An additional $0.2 million has been accrued in relation to our 2011 bonus plan.  No such bonus plan was in place for the period ended September 30, 2010.

Other administrative costs also increased from $0.35 million the prior quarter to $0.9 million for the quarter ended September 30, 2011 due to increased activity.

Interest expense

Interest expense decreased from $0.3 million for the quarter ended September 30, 2010, to nil for the period ended September 30, 2011.  We repaid our debt in full during the year ended June 30, 2011 thus no longer incur interest expense.

Income tax expense

Income tax expense decreased from $15.2 million for the quarter ended September 30, 2010 to benefit of $0.19 million for quarter ended September 30, 2011.  The income tax expense recognized in the prior quarter was as a result of the sale of the exploration acreage.  This was a one-off sale and no similar sale was recorded in the current quarter.  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 prior year.

Discontinued operations

We recorded a gain from discontinued operations in the quarter ended September 30, 2010 of $0.2 million compared to nil in the current quarter.  The discontinued operations related to our interest in the Jonah and Look Out Wash fields in Wyoming.  We sold these properties during the year ended June 30, 2011 and do not have any discontinued operations for the quarter ended September 30, 2011.

Cash Flows

	Three months ended  September 30,
	2011			2010
Cash provided by/(used in) operating activities	$	123,781		$	(244,671	)
Cash (used in)/ provided by investing activities		(4,335,408	)		65,246,165
Cash provided by financing activities		290,581			2,075,356

Cash provided by operations increased from an outflow of ($244,671) for the three months ended September 30, 2010 to cash inflow of $123,781 for the three months ended September 30, 2011.  This increase was primarily due to increased receipts from debtors as a result of increased oil production and realized oil prices.

Cash used in investing activities decreased from a cash inflow of $65,249,165 for the three months ended September 30, 2010 to cash outflow of ($4,335,408) for the three months ended September 30, 2011.  The cash inflow in the prior year was primarily as result of cash received from the sale of exploration acreage.  The cash outflow for the quarter ended September 30, 2011 related to monies spent on the continued exploration of our Hawk Springs and Roosevelt projects and monies expended on drilling activities in our North Stockyard project.

Cash provided by financing activities decreased from $2,075,356 for the quarter ended September 30, 2010 to $290,581 for the quarter ended September 30, 2011.  The cash inflow in the prior quarter relates to cash received in relation to a capital raising completed in June and July 2010 and cash received as a result of the exercise of options. The cash received from the current quarter relates to the exercise of options.

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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, 2012 as well. Our current budget for exploration, exploitation and development capital expenditures in fiscal year ending June 30, 2012 is $18 million, of which we have incurred approximately $6.01 million during the first quarter of the fiscal year. We expect to fund our fiscal year 2012 capital expenditures primarily with cash flow from cash on hand and operations. Uncertainties relating to our capital resources and requirements include the effects of changes in oil and natural gas prices and results from our drilling program, either of which could lead us to accelerate or decelerate activities, including but not limited to our drilling, as well as the possibility that we will pursue one or more significant acquisitions that require debt or equity financing.

As we continue to grow, 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 proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional productive reserves.

Most recently, our main sources of liquidity have been cash received from the sale of 24,166 acres in Goshen County, Wyoming to Chesapeake Energy Corporation for approximately $73.2 million, and from the sale of our interests in the Jonah and Lookout Wash fields for $6.3 million. 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.

During the quarter ended September 30, 2011, 18,192,441 1.5 Australian cent (A$0.015) warrants were exercised for net proceeds of $290,581 to us. The warrants exercised were issued in a public rights offering conducted in October 2009.

Debt obligations at September 30, 2011 decreased $10,711,885 to nil compared with the three months ended September 30, 2010, primarily due to the repayment in full of our loan facility with Macquarie Bank Limited in May 2011.

Recently Issued Accounting Pronouncements

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 will 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 U.S. 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 will require the Company to present the statements of comprehensive income separately from its statements of equity, as these statements are currently presented on a combined basis.  

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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, 2011 regarding this matter.

Item 4.  Controls and Procedures.

As of September 30, 2011, 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, 2011, our disclosure controls and procedures are 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, 2011 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, 2011.  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.

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, 2011 is formatted in XBRL (eXtensible Business Reporting Language): (i)  Consolidated Balance Sheets at September 30, 2011, (ii)  Consolidated Statements of Operations for the three months ended September 30, 2011 and September 30, 2010, (iii)  Consolidated Statement of Changes in Stockholders’ Equity at September 30, 2011 (iv)  Consolidated Statements of Cash Flows for the three months ended September 30, 2011 and September 30, 2010, 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:   October 30, 2011	By:	/s/ Terence M. Barr
		Terence M. Barr
		Managing Director, President and Chief Executive Officer (Principal Executive Officer)
Date:  October 30, 2011	By:	/s/ Robyn Lamont
		Robyn Lamont
		Chief Financial Officer (Principal Financial Officer)

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