Samson Oil & Gas LTD - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - Samson Oil & Gas LTD	Financial_Report.xls
EX-31.2 - EXHIBIT 31.2 - Samson Oil & Gas LTD	v301195_ex31-2.htm
EX-31.1 - EXHIBIT 31.1 - Samson Oil & Gas LTD	v301195_ex31-1.htm
EX-32.1 - EXHIBIT 32.1 - Samson Oil & Gas LTD	v301195_ex32-1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended December 31, 2011

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

Commission File Number: 1-33578

Samson Oil & Gas Limited

(Exact Name of Registrant as Specified in its Charter)

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

Level 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 1,751,330,020 ordinary shares outstanding as of February 6, 2011.

SAMSON OIL & GAS LIMITED

FORM 10-Q

QUARTER ENDED DECEMBER 31, 2011

TABLE OF CONTENTS

	Page

Part I - Financial Information	4

Item 1. Financial Statement (unaudited)	4

Consolidated Balance Sheets, December 31, 2011 and June 30, 2011	4

Consolidated Statement of Operations for the three and six months ended December 31, 2011 and 2010	5

Consolidated Statement of Changes in Stockholders’ Equity for the six months ended December 31, 2011	6

Consolidated Statement of Cash Flows for the six months ended December 31, 2011 and 2010	7

Notes to Consolidated Financial Statements (unaudited)	8

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

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.

Part I — Financial Information

Item 1. Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	December 31, 2011			June 30, 2011
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	42,404,819		$	58,448,477
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively		2,971,886			1,696,696
Prepayments		1,059,845			592,805
Pipe inventory – held by third party		142,967			489,526
Income tax receivable		2,618,870			2,578,870
Derivative instruments		-			22,268
Total current assets		49,198,387			63,828,642
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment		14,005,469			13,862,510
Undeveloped capitalized acreage		7,690,393			2,157,455
Capitalized exploration expense		7,417,629			1,190,283
Other property and equipment, net of accumulated depreciation and amortization of $224,540 and $192,138 at December 31, 2011 and June 2011, respectively		369,578			352,264
Net property, plant and equipment		29,483,069			17,562,512
OTHER ASSETS
Restricted cash		168,348			172,504
Income tax receivable		881,563			-
Other		32,318			34,174
TOTAL ASSETS	$	79,763,685		$	81,597,832

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	4,663,689		$	2,854,483
Accruals		1,547,765			389,000
Provision for annual leave		200,705			161,891
Total current liabilities		6,412,159			3,405,374
Capitalized lease		13,125			29,769
Asset retirement obligations		251,647			236,024
TOTAL LIABILITIES		6,676,931			3,671,167
STOCKHOLDERS’ EQUITY – nil par value
Common stock, 1,750,551,180 (equivalent to 87,527,599 ADR’s) and 1,731,978,789 (equivalent to 86,598,939 ADR’s) shares issued and outstanding at December 31, 2011 and June 30, 2011, respectively)		82,802,035			81,668,085
Other comprehensive income		2,739,789			3,089,795
Retained earnings (accumulated deficit)		(12,455,070	)		(6,831,215	)
Total stockholders’ equity		73,086,754			77,926,665
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	79,763,685		$	81,597,832

See accompanying Notes to Consolidated Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three months ended						Six months ended
	December 31, 2011			December 31, 2010			December 31, 2011			December 31, 2010
REVENUES AND OTHER INCOME:
Oil sales	$	1,666,006		$	1,463,503		$	3,842,442		$	2,106,087
Gas sales		263,087			209,788			573,263			420,219
Other liquids		2,255			-			7,921			-
Interest income		85,431			102,646			199,237			138,841
Gain on sale of exploration acreage		-			3,396,757			-			73,199,687
Other		1,979			840			21,136			1,051

EXPENSES:
Lease operating expense		(455,495	)		(423,601	)		(1,082,292	)		(676,713	)
Depletion, depreciation and amortization		(619,713	)		(713,509	)		(1,353,022	)		(1,130,877	)
Exploration and evaluation expenditure		(4,619,278	)		(833,121	)		(4,740,828	)		(980,946	)
Accretion of asset retirement obligations		(5,559	)		(7,097	)		(10,993	)		(14,193	)
General and administrative		(2,076,296	)		(3,740,126	)		(3,962,282	)		(4,512,840	)
Interest expense, net of capitalized costs		-			(251,277	)		-			(534,453	)

Income (loss) from continuing operations		(5,757,583	)		(795,197	)		(6,505,418	)		68,015,863
Income tax benefit/(provision)		693,385			95,781			881,563			(15,114,309	)
Earnings from continuing operations		(5,064,198	)		(699,416	)		(5,623,855	)		52,901,554
Total income (loss) from discontinued operations, net of income taxes		-			(6,469	)		-			211,765
Net income (loss)	$	(5,064,198	)	$	(705,885	)	$	(5,623,855	)	$	53,113,319

Net earnings per common share from continuing operations:
Basic – cents per share		(0.29	)		(0.04	)		(0.32	)		3.20
Diluted – cents per share		(0.29	)		(0.04	)		(0.32	)		2.75

Net earnings per common share from discontinued operations:
Basic – cents per share		-			Not meaningful			-			0.01
Diluted – cents per share		-			Not meaningful			-			0.01

Weighted average common shares outstanding:
Basic		1,750,222,724			1,664,472,446			1,746,423,566			1,652,836,871
Diluted		1,750,222,724			1,664,472,446			1,746,423,566			1,924,099,960

See accompanying Notes to Consolidated Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

						Other
			Retained Earnings/			Comprehensive
	Issued Capital		(Accumulated Deficit)			Income			Total Equity
Balance at June 30, 2011	$	81,668,085	$	(6,831,215	)	$	3,089,795		$	77,926,665
Net income (loss)		-		(5,623,855	)		-			(5,623,855	)
Foreign currency translation, net of tax of $nil		-		-			(350,006	)		(350,006	)
Total comprehensive income/(loss) for the period		-		(5,623,855	)		(350,006	)		(5,973,861	)
Stock based compensation		836,721		-						836,721
Issue of share capital		297,229		-						297,229
Balance at December 31, 2011	$	82,802,035	$	(12,455,070	)	$	2,739,789		$	73,086,754

See accompanying Notes to Consolidated Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six months ended
	December 31, 2011			December 31, 2010
Cash flows from operating activities
Receipts from customers	$	4,486,797		$	3,506,466
Cash received from commodity derivative financial instruments		38,508			121,203
Payments to suppliers & employees		(4,200,663	)		(3,811,717	)
Interest received		196,890			137,778
Interest paid		-			(505,713	)
Income taxes paid		-			(4,680,000	)
Net cash flows provided by/(used in) operating activities		521,532			(5,231,983	)
Cash flows from investing activities
Proceeds from sale of listed shares		-			49,040
Proceeds from sale of exploration acreage		-			75,598,201
Payments for plant & equipment		(51,495	)		-
Payments for exploration and evaluation		(14,518,508	)		(4,882,266	)
Payments for oil and gas properties		(1,929,585	)		(4,026,016	)
Net cash flows (used in)/provided by investing activities		(16,499,588	)		66,738,959
Cash flows from financing activities
Proceeds from issue of share capital		-			2,915,022
Proceeds from the exercise of options		297,229			-
Repayment of borrowings		-			(1,200,000	)
Payments for costs associated with capital raising		-			(244,282	)
Net cash flows provided by financing activities		297,229			1,470,740
Net increase/(decrease) in cash and cash equivalents		(15,680,827	)		62,977,716
Cash and cash equivalents at the beginning of the period		58,448,477			5,885,735
Effects of exchange rate changes on cash and cash equivalents		(362,831	)		935,996
Cash and cash equivalents at end of period	$	42,404,819		$	69,799,447

See accompanying Notes to Consolidated Financial Statements

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 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, 2011.

Accruals

The components of accrued liabilities for the periods ended December 31, 2011 and June 30, 2011 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 for the year ended December 31, 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						Six months ended
	December 31, 2011			December 31, 2010			December 31, 2011			December 31, 2010

Income tax benefit/(expense)	$	693,385		$	95,781		$	881,563		$	(15,114,309	)
Effective tax rate		12.05	%		12.04	%		13.55	%		22.22	%

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 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.

The tax for the period ending December 31, 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 activity, which was in excess of the net operating losses available to offset 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.

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 December 31,				Six months ended December 31,
	2011		2010		2011		2010
Dilutive		-		-		-		244,744,844
Anti–dilutive		238,307,570		260,475,788		271,320,247		6,777,174

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

Continuing operations	Three months ended December 31,						Six months ended December 31,
	2011			2010			2011			2010
Net income (loss) from continuing operations	$	(5,064,198	)	$	(699,416	)	$	(5,623,855	)	$	52,901,554

Basic weighted average common shares outstanding		1,750,222,724			1,664,472,446			1,746,423,566			1,652,836,871
Add: dilutive effect of stock options		-			-			-			244,774,843
Add: bonus element for rights issue		-			-			-			26,488,246
Diluted weighted average common shares outstanding		1,750,222,724			1,664,472,446			1,746,423,566			1,924,099,960
Basic earnings per common share – cents per share		(0.29	)		(0.04	)		(0.32	)		3.20
Diluted earnings per common share – cents per share		(0.29	)		(0.04	)		(0.32	)		2.75

Discontinued operations	Three months ended December 31,					Six months ended December 31,
	2011		2010			2011		2010
Net income (loss) from discontinued operations		-	$	(6,469	)		-	$	211,765

Basic weighted average common shares outstanding		-		1,664,472,446			-		1,652,836,871
Add: dilutive effect of stock options		-		-			-		244,774,843
Add: bonus element for rights issue		-		-			-		26,488,246
Diluted weighted average common shares outstanding		-		1,664,472,446			-		1,924,099,960
Basic earnings per common share – cents per share		-		Not meaningful			-		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 wells at the end of their productive lives and shut–in properties 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 for active properties or directly expensed for shut-in properties.

The following table summarizes the activities for the Company’s asset retirement obligations for the six months ended December 31, 2011 and 2010:

	Six months ended December 31,		Twelve months ended June 30,
	2011		2011
Asset retirement obligations at beginning of period	$	236,024	$	301,894
Liabilities incurred or acquired		4,630		22,936
Liabilities settled		-		-
Disposition of properties		-		(112,715	)
Accretion expense		10,993		23,909
Asset retirement obligations at end of period		251,647		236,024
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)				-
Long-term asset retirement obligations	$	251,647	$	236,024

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 $518,116 and $1,612,716 during the three months ended December 31, 2011 and 2010 and $836,721 and $1,612,716 during the six months ended December 31, 2011 and 2010.

Stock Options

The following table summarizes stock option activity for the six months ended December 31, 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		8,000,000			0.16				5,333,333
Exercised		(18,572,391	)		0.015				(18,572,391	)
Cancelled/expired		-

Outstanding at December 31, 2011		322,840,099			0.037		0.059		298,840,548

(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

In November 2011, 4,000,000 options were granted under the Samson Oil and Gas Limited Stock Option to a non-executive Director of the Company. These options have an exercise price of 15.5 cents (Australian) and expiry date of October 31, 2015. These options vested immediately. 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)			10.0
Exercise price (Australian cents)			15.5
Time to expiry (years)			4
Risk free rate (%)			6.00
Share price volatility (%)			124.61
Dividend yield			Nil

As of December 31, 2011, there was $424,127 of total unrecognized compensation cost related to outstanding stock options. This cost is expected to be recognized over three years.

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 may be 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.

As of December 31, 2011, the Company has not entered into any derivative agreements in relation to its oil or gas production.

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.

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

	Three months ended December 31,					Six months ended December 31,
Discontinued operations	2011		2010			2011		2010
Commodity derivative (losses)/gains, net	$	-	$	(48,879	)	$	-	$	132,636

	Three months ended December 31,				Six months ended December 31,
Continuing operations	2011		2010		2011		2010
Other income, net	$	-	$	-	$	16,240	$	-

Balance Sheet Classification	December 31, 2011		June 30, 2011
	Derivative
	Assets/Liabilities		Derivative Assets
Current assets - derivative instruments	$	-	$	22,268

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 December 31, 2011 and June 30, 2011.

Level 1

Level 2

Level 3

Fair Value at
December 31, 2011

Assets (Liabilities):

Commodity derivative contracts

–

	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. 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 December 31, 2011 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.

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 in 2016, and $10,294 thereafter. Net rent expense incurred for office space was $58,880 for the three months ending December 31, 2011 and $42,636 for the three months ending December 31, 2010 and $100,485 for the six months ending December 31, 2011 and $72,487 for the six months ending December 31, 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. The drilling of the first of these wells, the Australia II, commenced in November 2011 with costs incurred to date of $5.2 million and is expected to be fracture stimulated in February 2012. The second well commenced drilling in January 2012 and is estimated to cost $6.5 million. 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.

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 December 31, 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 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 $15.1 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 six months ended December 31, 2011 we drilled our first appraisal well in our Roosevelt Project, Australia II. This well is currently awaiting fracture stimulation. We have also incurred costs in relation to the permitting and location building of a number of other prospective well sites in the Roosevelt project area. Our second appraisal well in this project, Gretel II commenced drilling in January 2012, it is expected to be completed and fracture stimulated during the first quarter for calendar year 2012. Both the Hawk Springs and Roosevelt projects are exploratory projects, which support our capitalizing these costs until further assessment of the reserves and operating viability of the projects.

During the quarter, we continued drilling our Spirit of America well in our Hawk Springs Project. Numerous operational difficulties were incurred during the drilling of this well and it ultimately failed to reach its target. Accordingly costs associated with this well have been written off from capitalized exploration expenditure to the Statement of Operations in the amount of $4.5 million.

10. Issue of Share Capital

During the six months ended December 31, 2011, 18,572,391 1.5 Australian cent ($0.015) warrants were exercised for net proceeds of $297,229 to us. The warrants were issued in a rights offering in October 2009.

11. Cash Flow Statement

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

	Six months ended December 31,
	2011			2010

Net profit/(loss) after tax	$	(5,623,855	)	$	53,113,319
Net (gain)/loss recognized on re-measurement to fair-value of investments held for trading		-			(5,493	)
Depletion, depreciation and amortization		1,353,022			1,458,927
Stock based compensation		836,721			1,763,333
Accretion of asset retirement obligation		10,993			14,193
Exploration and evaluation expenditure		4,740,828			980,946
Net (gain)/loss on fair value movement of fixed forward swaps		22,268			(26,796	)
Gain on sale of exploration acreage		-			(73,199,687	)

Changes in assets and liabilities:

(Increase)/decrease in receivables		(1,275,190	)		102,314
(Increase)/decrease in income tax receivable/deferred tax asset		(921,563	)		-
Increase/(decrease) in income tax payable		-			10,548,336
Increase/(decrease) in provision for annual leave		38,814			52,334
Increase/(decrease) in payables		1,339,494			33,709

NET CASH FLOWS PROVIDED BY/(USED IN) OPERATING ACTIVITIES	$	521,532		$	(5,231,983	)

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, 2011, 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 18,580 barrels of oil for the quarter ended December 31, 2011 compared to 18,397 barrels of oil for the quarter ended December 30, 2010. Our net oil production was 43,516 barrels for the six months ended December 31, 2011 compared to 30,619 barrels of oil for the six months ended December 31, 2010. Our net gas production was 58,487 Mcf for the quarter ended December 31, 2011 compared to 143,902 Mcf for the quarter ended December 31, 2010. Our net gas production was 117,669 Mcf for the six months ended December 31, 2011 compared to 308,411 Mcf for the six months ended December 31, 2010.

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.

Events and Trends in the Quarter Ended December 31, 2011 and Outlook for the Quarter Ending March 31, 2012

Exploration Activities

Hawk Springs Project, Goshen County, Wyoming

During the current quarter, the Defender US 33 #2-29H (“Defender”) well, in our Hawk Springs project area in Goshen County, Wyoming was fracture stimulated in November 2011. A pump was placed on this well in December 2011 in order to pump the fluid pumped into the well during fracture stimulation. This pump did not perform adequately and a new pump was put in place in January 2012. The well is currently producing between 400-500 barrels of fluid per day with a 30% oil cut.

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. 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.

During the current quarter, the Spirit of America US 34 #1-29 well was drilled in our Hawk Springs project areas in Goshen County, Wyoming. Numerous operational difficulties were encountered while drilling this well and it ultimately failed to meet its target.

It is expected a second vertical test will be drilled at a later date in order to test the original Permian and Pennsylvanian targets.

Roosevelt Project, Roosevelt County, Montana

In November 2011, we commenced drilling of our Australia II KA 6 (“Australia II”), our first appraisal well in our Roosevelt Project area, in Roosevelt County, Montana. The drilling of this well was successfully completed and it is now awaiting fracture stimulation, expected to commence in February 2012.

The second appraisal well in the Roosevelt Project, Gretel II commenced drilling in early January 2012 and is expected to be completed in February 2012 and fracture stimulated following the fracture stimulation of Australia II.

Following the drilling of the two initial appraisal wells, Fort Peck Energy Company (“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)

Following the drilling of the two initial Bakken appraisal wells the Australia II 12 KA 6 well (completed and awaiting fracture stimulation) and the Gretel II 12 KA 3 well (in progress), both wells will be fracture stimulated and the production will be evaluated prior to beginning the development program. If commercial production is established in the Australia II 12 KA 6 or the Gretel II 12 KA 3, the development program would commence and include the drilling of the Australia III 12 KA 9 well (permitted) and the Australia IV 12 KA 16 well (permitted and surface casing set).

Hawk Springs Project, Goshen County, Wyoming

Cretaceous Niobrara Formation, Northern D-J Basin

Defender US33 #2-29H

Samson 37.5% Working Interest

The recent production from the first Niobrara appraisal well, the Defender US33 #2-29H, is currently being evaluated as is the data taken from logs and core to determine the next step to take in the development of the Niobrara Formation. The Defender well was drilled and funded 100% by Halliburton under their farmin agreement. Halliburton can earn into a second tranche acreage position within the joint venture area by drilling and funding 100% of another Niobrara horizontal well. It is anticipated that a decision whether to drill a new well will be made within the first quarter of calendar year 2012. The Defender well was completed with the plug and perf process in 15-stages which involved the placement of 3,000,000 pounds of proppant into the Niobrara Formation.

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 Spirit of America US34 #1-29 well was unsuccessful in reaching the Lower Permian and Pennsylvanian targets due to getting stuck in the Upper Permian Goose Egg Salt section. We intend to re-drill the 11,000’ vertical well test at a later date in order test the original Permian and Pennsylvanian conventional targets.

Production Activities

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson various Working Interests

Samson now has seven producing wells in the North Stockyard Field after the Everett #1-15H well was fracture stimulated in December. These wells are located in Williams County, North Dakota, in Township 154N Range 99W.

The Harstad #1-15H well (34.5% working interest) averaged 36 BOPD and 12 Mcf/D for the quarter from the Mississippian Bluell Formation. The well has performed as expected with a cumulative gross production of 95 MSTB and 82 MMcf.

The Leonard #1-23H well (10% working interest, 37.5% after non-consent penalty) averaged 43 BOPD and 54 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 91 MSTB and 89 MMcf.

The Gene #1-22H well (30.6% working interest) produced at an average daily rate of 58 BOPD and 32 Mcf/D during the quarter. The average daily rate is lower this quarter due to the well being worked over for rod pump failure and tubing failure. The cumulative production to date is approximately 104 MSTB and 115 MMcf.

The Gary #1-24H (37% working interest) well averaged 121 BOPD and 180 Mcf/D during the quarter. The cumulative production to date is approximately 101 MSTB and 161 MMcf.

The Rodney #1-14H (27% working interest) well produced at an average daily rate of 181 BOPD and 302 Mcf/D. The cumulative production to date is approximately 64 MSTB and 75 MMcf.

Earl #1-13H (32% working interest) well produced at an average daily rate of 289 BOPD and 360 Mcf/D. These average rates take into account several down days due to well workovers. Cumulative production to date is approximately 97 MSTB and 125 MMcf.

The Everett #1-15H well was the sixth Bakken well drilled in the North Stockyard Field and was fracture stimulated in December. During the first 24-hour period of production, the well produced 1,176 BOPD and 1,180 Mcf/D. The well has produced at an average daily rate of 740 BOPD and 865 Mcf/D during its first two weeks of production.

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

	Three months ended December 31, 2011						Three months ended September 30, 2011
Well	Net Mcf/D		Net BOPD		Net BOEPD		Net Mcf/D		Net BOPD		Net BOEPD
Leonard #1-23H		0.69		3.17		3.29		4.50		3.34		4.09
Harstad #1-15H		3.10		11.1		11.62		2.25		8.75		9.12
Gene #1-22H		1.33		12.49		12.71		8.77		28.87		30.33
Gary #1-24H		43.86		34.16		41.47		47.46		35.94		43.85
Rodney #1-14H		37.64		40.06		46.33		46.09		57.20		64.88
Earl #1-13H		80.49		68.70		82.12		130.31		99.84		121.55
Total		167.11		169.68		197.53		239.38		233.94		273.82

Sabretooth Gas Field, Brazoria County Texas

Oligocene Vicksburg Formation, Gulf Coast Basin

Samson 12.5% Working Interest

Production for the Davis Bintliff #1 well averaged 4.3 MMcf/D and 48 BOPD for the quarter, which is essentially a constant rate from inception. Cumulative production to date is approximately 4.2 Bscf and 50 MBO.

Lease Operating Expenses

Lease operating expenses have shown a general rising trend over the past three years. In the past, we have not been the 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 multiple conventional targets in the Permian and Pennsylvanian formations on our acreage in Goshen County, Wyoming

The continued appraisal and development of our Roosevelt project in Roosevelt County, Montana with the fracture stimulation of our Australia II well in February 2012 and drilling and fracture stimulation of our second test well, Gretel II in the first quarter of calendar year 2012

Results of Operations

In the second quarter of the year ending June 30, 2012, we reported a net loss of $5.1 million. The net loss includes drilling costs of $4.5 million associated with the Spirit of America well, which failed to reach its target and were expensed through the Statement of Operations during the quarter.

For the six months ended December 31, 2011, we reported a net loss of $5.6 million and net cash from operations of $0.5 million.

Operating data

The following table sets forth selected operating data (including the results of discontinued operations) for the three months ended:

	December 31, 2011		December 31, 2010		September 30, 2011
Production Volume
Oil (Bbls)		18,580		18,397		24,601
Natural gas (Mcf)		58,487		143,902		59,246
BOE (barrels of oil equivalent)		28,327		42,380		34,475
Oil Price per Bbl Produced (in dollars):
Realized price	$	89.66	$	80.97	$	85.20
Realized commodity derivative gain (loss)		-		-		-
Net realized price		89.66		80.97		85.20
Natural Gas Price per Mcf Produced (in dollars):
Realized price	$	4.49	$	3.69	$	5.23
Realized commodity derivative gain (loss)		-		0.41		0.62
Net realized price		4.49		4.10		5.85

Expense per BOE (in dollars):
Lease operating expenses	$	8.07	$	8.55	$	9.58
Production and property taxes		8.01		5.78		8.59
Depletion, depreciation and amortization		21.22		20.63		21.27
General and administrative expense		73.29		88.25		55.10
Interest expense, net of amounts capitalized		-		5.93		-

The following table sets forth selected operating data (including the results of discontinued operations) for the six months ended:

	December 31, 2011		December 31, 2010
Production Volume		43,516		30,619
Oil (Bbls)		117,669		308,411
Natural gas (Mcf)		63,128		81,420
BOE
Oil Price per Bbl Produced (in dollars):
Realized price	$	88.30	$	70.99
Realized commodity derivative gain (loss)		-		-
Net realized price		88.30		70.99
Natural Gas Price per Mcf Produced (in dollars):
Realized price	$	4.87	$	3.65
Realized commodity derivative gain (loss)		0.32		0.34
Net realized price		5.19		3.99

Expense per BOE (in dollars):
Lease operating expenses	$	8.85	$	7.24
Production and property taxes		8.28		5.01
Depletion, depreciation and amortization		20.89		17.55
General and administrative expense		62.76		55.02
Interest expense, net of amounts capitalized		-		6.52

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

	December 31, 2011			December 31, 2010			2Q10 to 2Q11 change			September 30, 2011			1Q11 to 2Q11 change
Oil sales	$	1,666,006		$	1,463,503		$	202,503		$	2,176,436		$	(510,430	)
Gas sales		263,087			209,788			53,299			310,176			(47,089	)
Other liquids		2,255			-			2,255			5,666			(3,441	)
Interest income		85,431			102,646			(17,215	)		113,806			(28,375	)
Gain on sale of exploration acreage		-			3,396,757			(3,396,757	)		-			-
Other		1,979			840			1,139			19,157			(17,178	)

Lease operating expense		(455,495	)		(423,601	)		(31,894	)		(626,797	)		171,302
Depletion, depreciation and amortization		(619,713	)		(713,509	)		93,796			(733,309	)		132,315
Exploration and evaluation expenditure		(4,619,278	)		(833,121	)		(3,786,157	)		(107,956	)		(4,511,322	)
Accretion of asset retirement obligations		(5,559	)		(7,097	)		1,538			(5,434	)		(125	)
General and administrative		(2,076,296	)		(3,740,126	)		1,663,830			(1,899,581	)		(176,715	)
Interest expense, net of capitalized costs		-			(251,277	)		251,277			-			-
Income tax (provision)/ benefit		693,385			95,781			597,604			188,178			505,207
Total income (loss) from discontinued operations net of income taxes		-			(6,469	)		6,469			-			-
Net income (loss)	$	(5,064,198	)	$	(705,885	)				$	(559,658	)

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

	December 31, 2011			December 31, 2010			2Q10 to 2Q11 change
Oil sales	$	3,842,442		$	2,106,087		$	1,736,355
Gas sales		573,263			420,219			153,044
Other liquids		7,921			-			7,921
Interest income		199,237			138,841			60,396
Gain on sale of exploration acreage		-			73,199,687			(73,199,687	)
Other		21,136			1,051			20,085

Lease operating expense		(1,082,292	)		(676,713	)		(405,579	)
Depletion, depreciation and amortization		(1,353,022	)		(1,130,877	)		(222,145	)
Exploration and evaluation expenditure		(4,740,828	)		(980,946	)		(3,759,882	)
Accretion of asset retirement obligations		(10,993	)		(14,193	)		3,200
General and administrative		(3,962,282	)		(4,512,840	)		550,558
Interest expense, net of capitalized costs		-			(534,453	)		534,453
Income tax (provision)/ benefit		881,563			(15,114,309	)
Total income (loss) from discontinued operations net of income taxes		-			211,765			(211,765	)
Net income (loss)	$	(5,623,855	)	$	53,113,319

Oil and gas revenues

Oil revenues increased from $1.5 million for the three months ended December 31, 2010 to $1.7 million for the three months ended December 31, 2011 primarily as a result of our increased focus on oil production. Oil production increased slightly from 18,397 barrels for the quarter ended December 31, 2010 to 18,580 barrels for the quarter ended December 31, 2011. Oil revenues have also increased as a result of an increase in the realized oil price. Our realized oil price increased from $80.97 for the quarter ended December 31, 2010 to $89.66 for the quarter ended December 31, 2011.

Oil revenues increased from $2.1 million for the six months ended December 31, 2010 to $3.8 million for the six months ended December 31, 2011. This increase is due to a 42% increase in production volumes and a 24% increase in realized price for the six months ended December 31, 2011 compared to the six months ended December 31, 2010.

Gas revenues increased from $0.2 million for the three months ended December 31, 2010 to $0.26 million for the three months ended December 31, 2011. This is primarily as result of the continuation 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 Mountain region, which often results in lower gas prices being recorded. Our realized gas price increased from $4.10 for the quarter ended December 31, 2010 to $4.49 for the quarter ended December 31, 2011. Excluding the results of discontinued operations, gas production increased 12.5% for the quarter ended December 31, 2011 over the quarter ended December 31, 2010.

Gas revenues increased slightly from $0.4 million for the six months ended December 31, 2010 to $0.57 million for the six months ended December 31, 2011. This increase is due a continuation in gas sales from our North Stockyard field, minimal gas sales were recognized from the North Stockyard field in the prior year and a 30% increase in realized price for the six months ended December 31, 2011 compared to the six months ended December 31, 2010. Excluding the results of discontinued operations, gas production increased 9.3% for the six months ended December 31, 2011 over the six months ended December 31, 2010.

Other revenues increased from $0.001 million for the six months ended December 31, 2010 to $0.02 million for the six months ended December 31, 2011. The increase is due to the funds received from the close out of our gas hedging position in July 2011. Previously cash proceeds from derivative instruments were allocated to discontinued operations.

Sale of exploration acreage

Sale of exploration acreage decreased from $3.4 million for the three months ended December 31, 2010 to $nil for the three months ended December 31, 2011. The sale in the prior period related to of our sale of exploration acreage in the Hawk Springs project area in Goshen County, Wyoming. This was a one-time event and is not expected to be repeated again in the foreseeable future.

Sale of exploration acreage decreased from $73.2 million for the six months ended December 31, 2010 to $nil for the six months ended December 31, 2011. As detailed above, the sale was a onetime event and is not expected to be repeated again in the foreseeable future.

Exploration expense

Exploration expenditure increased from $0.8 million for the three months ended December 31, 2010 to $4.6 million for the three months ended December 31, 2011. Included in the current period exploration expenditures is $4.5 million relating to the costs associated with drilling the Spirit of America well in our Hawk Springs project in Goshen County, Wyoming. Difficulties in drilling this well resulted in the well failing to reach our target depth and thus the costs associated with this well have been written off to the Statement of Operations. Exploration expenditure, excluding costs associated with drilling exploratory wells decreased from $0.8 million for the quarter ended December 31, 2010 to $0.1 million for the quarter ended December 31, 2011. This is due to the fact our main projects have reached a stage where more of the expenditure can be capitalized pending results of the exploration activities.

Exploration expenditure increased from $0.98 million for the six months ended December 31, 2010 to $4.7 million for the six months ended December 31, 2011. As detailed above $4.5 million relates to costs associated with our Spirit of America well. Other exploration expenditure decreased as our main projects have reached a stage where more of the expenditure can be capitalized pending results of the exploration activities.

Lease operating expense

Lease operating expenses stayed relatively consistent from $0.4 million for the quarter ended December 31, 2010 to $0.5 million for the quarter ended December 31, 2011

Lease operating expenses increased from $0.7 million for the six months ended December 31, 2010 to $1.1 million for the six months ending December 31, 2011 as there was more well activity during the six months ended December 31, 2011 compared to the number of wells online during the six months ended December 31, 2010.

Depletion, depreciation and amortization expense

Depletion, depreciation and amortization expense decreased slightly from $0.7 million for the quarter ended December 31, 2010 to $0.6 million for the quarter ended December 31, 2011. Depreciation, depletion and amortization expense per BOE remained consistent at $21.22 for the quarter ended December 31, 2011 compared to $20.63 for the quarter ended December 31, 2010.

Depletion, depreciation and amortization expense increased slightly from $1.1 million for the six months ended December 31, 2010 to $1.4 million for the same period ended December 31, 2011. This is a result of an increase in production from the prior period to the current period.

General and administrative expense

General and administrative expense decreased from $3.7 million for the quarter ended December 31, 2010 to $2.1 million for the quarter ended December 31, 2011. Included within general and administrative expense is $0.5 million of share based payments expense for the current quarter compared with $1.7 million for the prior quarter. The share based payments expense in the prior quarter relates to options granted to Directors that vested immediately, therefore all of the expense was recognized upon the grant date. $0.2 million of the share based payments expense in the current quarter relates to options granted to employees during the year ended June 30, 2011 that vested over a three year period and the expense is recognized over this period, resulting in a charge each quarter. $0.3 million in options expense was recognized in relation to options granted to a new Director which vested immediately upon grant on November 20, 2011.

Following the completion of the sale of our exploration acreage during the quarter ended December 31, 2010, bonuses of $0.5 million were awarded. Bonus expense for the quarter ended December 31, 2011 was $0.2 million. The bonus period is for the calendar year ended December 31, 2011. $0.4 million of this expense was recognized during the year ended June 30, 2011 and $0.2 million was accrued during the quarter ended September 30, 2011. The bonus payment for the calendar year ended December 31, 2011 is $0.8 million and is expected to be paid by March 2012.

Other administrative costs also decreased from $1.4 million the prior quarter to $0.8 million for the quarter ended December 31, 2011 due to lower compliance and corporate expenses.

General and administrative costs decreased from $4.5 million for the six months ended December 31, 2010 to $3.9 million for the six months ended December 31, 2011.

Interest expense

Interest expense decreased from $0.25 million for the quarter ended December 31, 2010, to nil for the period ended December 31, 2011. We repaid our debt in full during the year ended June 30, 2011 thus no longer incur interest expense.

Interest expense decreased from $0.5 million for the six months ended December 31, 2010 to nil for the six months ended December 31, 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 benefit increased from $0.09 million for the quarter ended December 31, 2010 to a benefit of $0.69 million for quarter ended December 31, 2011. 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.

Income tax expense decreased from $15.1 million for the six months ended December 31, 2010 to a benefit of $0.9 million for the six months ended December 31, 2011. As noted above, the tax expense recognized in the prior year was as a result of the sale of exploration acreage during that period. This was a one-off sale and no similar sale was recorded in the current period. 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 loss from discontinued operations in the quarter ended December 31, 2010 of $0.01 million compared to nil in the current quarter. The discontinued operations related to our interest in the Jonah and Lookout 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 December 31, 2011.

We recorded a gain from discontinued operations in the six months ended December 31, 2010 of $0.2 million compared to nil in the current quarter. The discontinued operations related to our interest in the Jonah and Lookout Wash fields in Wyoming. We sold these properties during the year ended June 30, 2011 and do not have any discontinued operations for the six months ended December 31, 2011.

Cash Flows

The table below shows cash flows, including those from discontinued operations, for the six month period ended:

	December 31, 2011			December 31, 2010
Cash provided by/(used in) operating activities		521,532			(5,231,983	)
Cash (used in)/provided by investing activities		(16,499,588	)		66,783,959
Cash provided by/(used in) financing activities		297,229			1,470,740

Cash provided by operations increased from an outflow of ($5,231,983) for the six months ended December 31, 2010 to an inflow of $521,532 for the six months ended December 31, 2011. The large cash outflow in the prior period was a result of income taxes paid of $4.7 million. No such tax payment was made during the current quarter.

Cash used in investing activities decreased from a cash inflow of $66,783,959 for the six months ended December 31, 2010 to a cash outflow of ($16,499,588) for the six ended December 31, 2011. The cash inflow in the prior period was primarily as a result of cash received from the sale of exploration acreage. The cash outflow for the six months ended December 31, 2011 is as a result of drilling and exploration activities being conducted in our Hawk Springs and Roosevelt projects.

Cash provided by financing activities decreased from a cash inflow of $1,470,740 million for the six months ended December 31, 2010 to a cash inflow of $297,229 million for the six months ended December 31, 2011. The cash inflow in the prior period was a result of cash being received from a capital raising that was completed during July 2010. Cash provided by financing activities in the current quarter was a result of the exercise of 18,572,391 options with net proceeds of $297,229.

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 $26.9 million, of which we have incurred approximately $14 million during the first six months of the fiscal year. The remaining expenditure relates to fracture stimulation of our Australia II well, drilling a second appraisal well in our Roosevelt project, drilling two infill wells in our North Stockyard project and drilling a Permian-Pennsylvanian test in our Hawk Springs project.

We expect to fund our fiscal year 2012 capital expenditures primarily from cash on hand supplemented with cash flow from 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 December 31, 2011, 18,572,391 1.5 Australian cent (A$0.015) warrants were exercised for net proceeds of $297,229 to us. The warrants exercised were issued in a public rights offering conducted in October 2009.

Debt obligations at December 31, 2011 decreased $10,216,540 to nil compared with the three months ended December 31, 2011, primarily due to the repayment in full of our loan facility with Macquarie Bank Limited in May 2011.

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 December 31, 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 December 31, 2011, 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 December 31, 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.

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 December 31, 2011 is formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets at December 31, 2011, (ii) Consolidated Statements of Operations for the six months ended December 31, 2011 and December 31, 2010, (iii) Consolidated Statement of Changes in Stockholders’ Equity at December 31, 2011 (iv) Consolidated Statements of Cash Flows for the six months ended December 31, 2011 and December 31, 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

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: February 9, 2012	By:	/s/Terence M. Barr
		Terence M. Barr
		Managing Director, President and Chief Executive Officer (Principal Executive Officer)

Date: February 9, 2012	By:	/s/Robyn Lamont
		Robyn Lamont
		Chief Financial Officer (Principal Financial Officer)

Samson Oil & Gas LTD - FORM 10-Q - February 9, 2012

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