10-Q 1 v378025_10q.htm FORM 10-Q

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 March 31, 2014

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

Commission File Number: 001-33578

Samson Oil & Gas Limited

(Exact Name of Registrant as Specified in its Charter)

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

Level 16, AMP Building,

140 St Georges Terrace

Perth, Western Australia 6000

(Address Of Principal Executive Offices)

(Zip Code)

+61 8 9220 9830

(Registrant’s Telephone Number, Including Area Code)

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

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

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

Large accelerated filer	¨	Accelerated filer 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 2,837,738,013 ordinary shares outstanding as of May 6, 2014.

SAMSON OIL & GAS LIMITED

FORM 10-Q

QUARTER ENDED MARCH 31, 2014

TABLE OF CONTENTS

		Page

Part I — Financial Information		3

Item 1.	Financial Statements (unaudited)	4

	Consolidated Balance Sheets, March 31, 2014 and June 30, 2013	4

	Consolidated Statement of Operations and Comprehensive Income (Loss) for the three months and nine months ended March 31, 2014 and 2013	5

	Consolidated Statement of Changes in Stockholders’ Equity for the nine months ended March 31, 2014	6

	Consolidated Statement of Cash Flows for the nine months ended March 31, 2014 and 2013	7

	Notes to Consolidated Financial Statements (unaudited)	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	15

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	24

Item 4.	Controls and Procedures	24

Part II — Other Information		24

Item 1.	Legal Proceedings	24

Item 1A.	Risk Factors	24

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	24

Item 3.	Defaults Upon Senior Securities	25

Item 4.	Mine Safety Disclosures	25

Item 5.	Other Information	26

Item 6.	Exhibits	26

Signatures		27

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:

our future financial position, including cash flow, anticipated liquidity, outcome of capital raising efforts, and debt levels;

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

our ability to find, acquire, market, develop and produce new properties and dispose of properties;

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;

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;

oil and natural gas prices and demand;

our entrance into transactions in commodity derivative instruments;

climatic conditions;

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

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

uncontrollable flows of oil, gas or well fluids.

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

Part I — Financial Information

Item 1. Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



	31-Mar-14			30-Jun-13
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5,753,379		$	13,170,627
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively		3,223,409			3,090,666
Prepayments		4,850,322			411,113
Pipe inventory – held by third party		-			78,944
Income tax receivable		778,175			777,804
Total current assets		14,605,285			17,529,154
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment of $19,862,016 and $18,318,918 at March 31, 2014 and June 30, 2013, respectively		30,821,935			19,992,018
Other property and equipment, net of accumulated depreciation and amortization of $387,751 and $351,037 at March 31, 2014 and June 30, 2013, respectively		395,698			367,657
Net property, plant and equipment		31,217,633			20,359,675
OTHER NON CURRENT ASSETS
Undeveloped capitalized acreage		12,369,412			12,369,412
Capitalized exploration expense		2,641,907			2,468,934
Deferred borrowing costs		178,201			-
Other		79,239			79,490
TOTAL ASSETS	$	61,091,677		$	52,806,665

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	2,833,033		$	1,381,407
Accruals		684,639			5,406,982
Fair value of derivative instruments		11,559			-
Provision for annual leave		310,944			242,368
Total current liabilities		3,840,175			7,030,757
NON CURRENT LIABILITIES
Asset retirement obligations		1,083,708			868,589
Credit facility		6,000,000			-
TOTAL LIABILITIES		10,923,883			7,899,346
STOCKHOLDERS’ EQUITY – nil par value
2,547,627,193 (equivalent to 127,381,360 ADR’s) and 2,229,165,163 (equivalent to 111,452,258 ADR’s) ordinary shares issued and outstanding at March 31, 2014 and June 30, 2013, respectively		99,580,828			92,717,784
Accumulated other comprehensive income		1,277,581			1,978,250
Accumulated deficit		(50,690,615	)		(49,788,715	)
Total stockholders’ equity		50,167,794			44,907,319
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	61,091,677		$	52,806,665

See accompanying Notes to Consolidated Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)



	Three months ended						Nine months ended

	31-Mar-14			31-Mar-13			31-Mar-14			31-Mar-13
REVENUES AND OTHER INCOME:
Oil sales	$	2,564,894		$	1,007,000		$	4,904,038		$	3,911,000
Gas sales		337,852			132,000			682,456			497,000
Other liquids		-			1,000			627			5,000
Interest income		7,607			37,000			108,905			164,000
Gain on sale of oil and gas properties		217,665			-			2,742,076			-
Other		16,642			1,000			16,826			112,000
TOTAL REVENUE AND OTHER INCOME		3,144,660			1,178,000			8,454,928			4,689,000

EXPENSES:
Lease operating expense		(1,124,478	)		(499,000	)		(2,356,154	)		(2,353,000	)
Depletion, depreciation and amortization		(720,394	)		(359,000	)		(1,602,199	)		(1,449,000	)
Impairment expense		(714	)		(6,000	)		(83,835	)		(250,000	)
Exploration and evaluation expenditure		(22,411	)		(7,416,000	)		(341,785	)		(7,817,000	)
Accretion of asset retirement obligations		(17,417	)		(14,000	)		(50,230	)		(41,000	)
Loss on derivative instruments		(79,156	)		-			(79,156	)		-
Amortisation of borrowing costs		(10,931	)		-			(10,931	)		-
Interest expense		(29,903	)		-			(29,903	)		-
General and administrative		(1,520,524	)		(1,805,000	)		(4,802,635	)		(4,624,000	)
TOTAL EXPENSES		(3,525,928	)		(10,099,000	)		(9,356,828	)		(16,534,000	)

Loss from operations		(381,268	)		(8,921,000	)		(901,900	)		(11,845,000	)
Income tax benefit		-			-			-			2,036,000
Net loss		(381,268	)		(8,921,000	)		(901,900	)		(9,809,000	)
OTHER COMPREHENSIVE GAIN (LOSS)
Foreign currency translation gain (loss)		(122,614	)		(10,000	)		(700,669	)		79,000
Total comprehensive gain/(loss) for the period	$	(503,882	)	$	(8,931,000	)	$	(1,602,569	)	$	(9,730,000	)

Net loss per ordinary share from operations:
Basic – cents per share		(0.01	)		(0.45	)		(0.04	)		(0.52	)
Diluted – cents per share		(0.01	)		(0.45	)		(0.04	)		(0.52	)

Weighted average ordinary shares outstanding:
Basic		2,547,627,193			1,996,871,729			2,484,035,681			1,870,519,291
Diluted		2,547,627,193			1,996,871,729			2,484,035,681			1,870,519,291

See accompanying Notes to Consolidated Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)



							Accumulated
							Other			Total
	Ordinary			(Accumulated			Comprehensive			Stockholders
	Shares			Deficit)			Income			Equity
Balance at June 30, 2013	$	92,717,784		$	(49,788,715	)	$	1,978,250		$	44,907,319
Net loss		-			(901,900	)		-			(901,900	)
Foreign currency translation loss, net of tax of $nil		-			-			(700,669	)		(700,669	)
Total comprehensive loss for the period		-			(901,900	)		(700,669	)		(1,602,569	)
Stock based compensation		86,244			-			-			86,244
Issue of share capital		7,338,040			-			-			7,338,040
Share issuance costs		(561,240	)		-			-			(561,240	)
Balance at March 31, 2014	$	99,580,828		$	(50,690,615	)	$	1,277,581		$	50,167,794

See accompanying Notes to Consolidated Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine months ended
	31-Mar-14			31-Mar-13
Cash flows (used in)/provided by operating activities
Receipts from customers	$	4,164,889		$	3,687,000
Payments to suppliers & employees		(6,960,365	)		(7,095,000	)
Interest received		108,885			164,000
Payments for derivative instruments		(67,596	)		-
Income tax refund		-			5,597,000
Net cash flows (used in)/provided by operating activities		(2,754,187	)		2,353,000
Cash flows used in investing activities
Proceeds from sale of oil and gas properties		4,488,825			-
Payments for plant & equipment		(61,894	)		(10,000	)
Payments for exploration and evaluation		(532,769	)		(7,774,000	)
Payments for oil and gas properties		(20,445,691	)		(4,294,000	)
Net cash flows used in investing activities		(16,551,529	)		(12,078,000	)
Cash flows provided by financing activities
Issuance of share capital		7,337,138			2,721,000
Proceeds from the exercise of options		902			3,343,000
Proceeds from borrowings		6,000,000			-
Borrowing costs		(189,112	)		-
Share issuance costs		(561,240	)		-
Net cash flows provided by financing activities		12,587,688			6,064,000
Net decrease in cash and cash equivalents		(6,718,028	)		(3,661,000	)
Cash and cash equivalents at the beginning of the fiscal period		13,170,627			18,846,000
Effects of exchange rate changes on cash and cash equivalents		(699,220	)		145,000
Cash and cash equivalents at end of fiscal period	$	5,753,379		$	15,330,000

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

The Company’s Consolidated Financial Statements have been prepared on a basis consistent with the accounting principles and policies reflected in the Company’s audited financial statements as of and for the year ended June 30, 2013. 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, 2013.

Accruals. Accrued liabilities at March 31, 2014 and June 30, 2013 consist primarily of estimates for goods and services received but not yet invoiced.

Prepayments. Prepayments at March 31, 2014 and June 30, 2013 consist primarily of cash advanced to the operators of our drilling projects for future drilling operations. As at March 31, 2014, cash had been advanced to the operator of our North Stockyard infill development project for the drilling and/or completion of five wells.

Recent Accounting Standards

There are no new accounting pronouncements that have not been adopted by the Company as of March 31, 2014 that will have a material effect on the Company’s financial statements.

2. Income Taxes

	Three months ended						Nine months ended

	31-Mar-14			31-Mar-13			31-Mar-14			31-Mar-13

Income tax benefit	$	-		$	-		$	-		$	2,036,000
Effective tax rate		0.00	%		0.00	%		0.00	%		17.00	%

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

In the tax year ended June 30, 2012, the Company generated an NOL of $33 million which exceeded the amount of taxable income, after NOL, generated in the tax year ended June 30, 2011. As a result, the NOL from June 30, 2012 was carried back to the year of June 30, 2011, generating a refund of tax paid in that year. The Company’s remaining NOLs will be carried forward to offset future taxable income.

During the quarter ending March 31, 2013, the Company received a $5.6 million income tax refund from the Internal Revenue Service of the taxes paid in a prior period noted above. $0.8 million remains as receivable in the Balance Sheet and is expected to be received within the current year.

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

3. Earnings Per Share

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

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

	Three months ended				Nine months ended
	31-Mar-14		31-Mar-13		31-Mar-14		31-Mar-13
Dilutive		-		-		-		-
Anti–dilutive		302,178,528		75,890,103		274,565,281		200,849,957

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

	Three months ended						Nine months ended
	31-Mar-14			31-Mar-13			31-Mar-14			31-Mar-13
Net income (loss)	$	(381,268	)		(8,921,000	)	$	(901,900	)		(9,809,000	)

Basic weighted average ordinary shares outstanding		2,547,627,193			1,996,871,729			2,484,035,681			1,870,519,291
Basic earnings per ordinary share – cents per share		(0.01	)		(0.45	)		(0.04	)		(0.52	)
Diluted earnings per ordinary share – cents per share		(0.01	)		(0.45	)		(0.04	)		(0.52	)

4. Asset Retirement Obligations

The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut–in properties at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to those obligations. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted using the units–of–production method.

During the three months ended September 30, 2013, we recorded an out-of-period adjustment to increase our asset retirement obligations by $0.15 million, capitalized asset retirement costs by $0.085 million and expensed $0.065 million. Based upon an evaluation of the relevant factors, we concluded that the related impact of this out-of-period adjustment was not material to our consolidated financial statements for any current or prior period.

The following table summarizes the activities for the Company’s asset retirement obligations for the nine months ended March 31, 2014 and 2013:

	Nine months ended
	31-Mar-14			31-Mar-13
Asset retirement obligations at beginning of period	$	868,589		$	809,000
Liabilities incurred or acquired		178,911			4,000
Liabilities settled		(13,920	)		-
Disposition of properties		(102	)		-
Accretion expense		50,230			41,000
Asset retirement obligations at end of period		1,083,708			854,000
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)		-			-
Long-term asset retirement obligations	$	1,083,708		$	854,000

5. Equity Incentive Compensation

Stock-based compensation is measured at the grant date based on the estimated fair value of the awards with the resulting amount recognized as compensation expense 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 $nil and $57,000 during the three months ended March 31, 2014 and 2013 and $86,244 and $209,000 during the nine months ended March 31, 2014 and 2013 respectively.

As of March 31, 2014, there was $nil total unrecognized compensation cost related to outstanding stock options.

6. Sale of Oil and Gas Assets

In August 2013, we divested half our equity position in the undeveloped acreage in the North Stockyard project to Slawson Exploration Company Inc. (“Slawson”) for $5.562 million in cash and other consideration while retaining our full interest in the currently producing wells in the North Stockyard field. $0.9 million of the cash portion of the purchase price is subject to the delivery of a useable well bore in Billabong. While work is continuing on this well bore, it had to be suspended to permit other drilling operations to proceed on the same pad. The Billabong work is currently expected to recommence by the end of June 2014. The remaining $4.6 million in consideration was transferred into an escrow account on the sale date, less $0.4 million which was transferred to Slawson as it related to cash calls from other non-operator parties received by Samson prior to the sale. As at March 31, 2014, the entire $4.6 million in sale funds have been released from the escrow account.

As a consequence of the transaction the rig contract with Frontier was also terminated, with no penalty payment. Slawson is now the operator of the project going forward for the development of the undeveloped acreage.

Along with the undeveloped acreage for which a gain on sale was recognized in the Income Statement of $2.52 million, we have also transferred a 25% working interest in the drilled but not completed, at the time of sale, Sail and Anchor well, as well as a 25% working interest in the salt water disposal well drilled in the prior year in the North Stockyard project for $2.92 million, recognized as a reimbursement in the capitalized costs for these assets on the March 31, 2014 Balance Sheet.

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 unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of March 31, 2014 and June 30, 2013.

	Carrying value at March 31, 2014		Level 1		Level 2		Level 3		Netting ⁽¹⁾			Fair Value at March 31, 2014
Assets
Cash and cash equivalents	$	5,753,379	$	5,753,379	$	-	$	-	$	-		$	5,753,379
Derivative asset	$	-	$	-	$	50,503	$	-	$	(50,503	)	$	-

Current Liabilities
Derivative instruments	$	11,559	$	-	$	62,062	$	-	$	(50,503	)	$	11,559

	Carrying value at June 30, 2013		Level 1		Level 2		Level 3		Level 3		Fair Value at June 30, 2013
Assets
Cash and cash equivalents	$	13,170,627	$	13,170,627	$	-	$	-	$	-	$	13,170,627

(1) Represents the impact of netting assets and liabilities with counterparties with which the right of offset exists

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

Level 1 Fair value Measurements

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

Level 2 Fair Measurements

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

Other fair value measurements

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

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

8. Commitments and Contingencies

Environmental Matters

The Environmental Protection Agency proposed a cash settlement of $60,000 in relation to a 400 barrel oil spill on the Pierce well site in February 2009. The spill was contained and the area rehabilitated to the satisfaction of the appropriate authorities in 2009. The costs associated with the spill and subsequent remediation were covered by our insurance. The settlement was paid subsequent to March 31, 2014 and is included within the accrual balance on the Consolidated Balance Sheet.

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

State Income Tax Matters

The State of North Dakota has made a claim against our wholly owned subsidiary, Samson Oil and Gas USA, Inc. relating to additional corporate income tax allegedly due for the years ended June 30, 2007 through June 30, 2011 in an amount of $597,852. On December 23, 2013, we filed a Statement of Grounds for Protest with the North Dakota Office of State Tax Commissioner responding to and protesting the allegations. At this time, we cannot predict the ultimate outcome of this disputed claim.

Halliburton Dispute

We have an ongoing dispute with Halliburton Energy Services, Inc., a co-participant in our Hawk Springs project. The dispute also relates to our 2012 drilling program in our Roosevelt project in Montana, where Halliburton provided us with project management services. We are claiming $302,000 from Halliburton for an unpaid invoice arising out of the Roosevelt project while Halliburton is claiming at least $126,000 in unpaid oil revenue from the Hawk Springs Project. We have engaged in sporadic negotiations with Halliburton over the past two years to try to resolve these offsetting liabilities, but it now appears likely that the competing claims will be the subject of a lawsuit between the parties. While we believe that our own claim against Halliburton is meritorious, we cannot predict the ultimate resolution of the dispute, whether it is resolved by litigation or negotiated settlement.

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, then the relevant capitalized amount will be written off to expense.

As of March 31, 2014 we had capitalized exploration expenditures of $2.6 million and undeveloped capitalized acreage expenditures of $12.4 million. This amount primarily relates to costs incurred in connection with our Hawk Springs, Roosevelt and South Prairie projects.

Our Hawk Springs project, in Goshen County, Wyoming, includes $3.0 million in undeveloped capitalized acreage costs and $1.5 million in capitalized exploration expenditure. The capitalized exploration expenditure includes costs associated with the acquisition of our North Platte 3D seismic data. During the nine months ended March 31, 2014, we spent and capitalized $0.1 million on our Bluff Federal well in the Hawk Springs project. This well is expected to be completed by June 2014, following the finalization of farmouts associated with this well.

Our Roosevelt project, in Roosevelt County, Montana, includes $7.8 million in undeveloped capitalized acreage costs and $0.3 million in capitalized exploration expenditure. The capitalized exploration expenditure consists of costs associated with well permitting, surface use agreements and other expenses associated with drilling preparation activities. In December 2013, we entered into a seismic and drilling agreement with Momentus Energy Corp, a Canadian exploration and development company based in Calgary. Momentus has committed to the acquisition of approximately 20 squares of 3-D seismic data at no cost to us. Following the acquisition of the seismic data, Momentus has the option to drill a horizontal Bakken well on our acreage at 100% cost to it. Upon Momentus drilling this well, it will have earned the right to 50% of the test well and 50% of our acreage in the Roosevelt project. The farmout arrangement with Momentus was then finalized during the quarter ended March 31, 2014. Permitting and surveying for the seismic shoot has been completed with acquisition of the seismic data expected to be completed during the quarter ended June 30, 2014.

Our South Prairie project in Ward and Renville counties, North Dakota, includes $1.6 million in undeveloped acreage costs and $0.9 million in capitalized exploration expenditure. This expenditure relates to 3-D seismic acquisition costs. We are not the operator of this project. The joint venture is focusing on developing three structural closure prospects (Pubco, Deering, and Birch) along the Prairie Salt edge in the South Prairie 3-D project. The joint venture has approved the drilling next of the Pubco Prospect on the eastern edge of the South Prairie 3-D seismic survey. We anticipate this well will be drilled before the end of Q3 of calendar year 2014.

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

10. Issue of Share Capital

During the nine months ended March 31, 2014, 25,864 Australian 3.8 cent options were exercised for net proceeds of $902. The options were issued in a public rights offering conducted in June 2013.

During the nine months ended March 31, 2014, we issued 318,452,166 ordinary shares for 2.5 cents (Australian cents)/2.3 cents (United States cents) for proceeds of $7.3 million. The ordinary shares were issued to investors in the US and Australia. In conjunction with these issues we also issued 132,380,866 warrants with an exercise price of 3.8 cents (Australian) and expiry date of March 31, 2017.

11. Cash Flow Statement

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

	Nine months ended
	31-Mar-14			31-Mar-13

Net loss after tax	$	(901,900	)	$	(9,809,000	)
Depletion, depreciation and amortization		1,602,199			1,449,000
Stock-based compensation		86,244			209,000
Accretion of asset retirement obligation		50,230			41,000
Impairment expense		83,835			250,000
Exploration and evaluation expenditure		341,785			7,384,000
Gain on sale of oil and gas properties		(2,742,076	)		-
Amortisation borrowing costs		10,931			-
Non cash loss on derivative instruments		11,559			-

Changes in assets and liabilities:

Increase in receivables		(1,421,605	)		(838,000	)
Decrease in income tax receivable/deferred tax asset		-			3,560,000
Increase/(decrease) in provision for annual leave		68,576			(21,000	)
Increase in payables		56,035			128,000
NET CASH FLOWS USED IN OPERATING ACTIVITIES	$	(2,754,187	)	$	2,353,000

12. Credit Facility

	Nine months ended
	31-Mar-14		31-Mar-13
Cash advanced under facility	$	6,000,000		-
Repayments		-		-
Credit facility at end of period	$	6,000,000	$	-
				-
Funds available for drawdown under the facility	$	2,000,000		-

In January 2014, we entered into a $25.0 million credit facility with Mutual of Omaha Bank, with an initial borrowing base of $8.0 million, of which $6.0 million has been drawn down. We expect the remaining $2.0 million in borrowing base will be drawn down prior to June 30, 2014 on an as needed basis. Additional increases in the borrowing base, up to the credit facility maximum of $25 million, may be made available to us in the future depending on the value of our reserves. Borrowing base redeterminations are performed by the lender every six months at June and December. We also have the ability to request a borrowing base redetermination at another period, once a year. The facility matures January 28, 2017. The interest rate is LIBOR plus 3.75% or approximately 3.98% for the quarter ended March 31, 2014.

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

Current ratio greater than 1

Debt to EBITDAX (annualized) ratio no greater than 3.5

Interest coverage ratio minimum of between 2.5 and 1.0

As at March 31, 2014 we were in compliance with all of these quarterly covenants.

The credit facility also includes an annual cap on general and administrative expenditure of $6,000,000 per fiscal year.

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

These funds, along with cash on hand and cash flow from operations, will be used to fund drilling in our North Stockyard project in North Dakota. We expect to fund our remaining capital expenditures for the fiscal year ending June 30, 2014 thereby, though we may obtain additional capital through further drawdowns of our credit facility (if possible) or another capital raising program or asset sales.

We incurred $0.2 million in borrowing costs which have been deferred and will be amortized over the life of the facility.

13. Derivatives

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

The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil. The Company seeks to manage this risk through the use of commodity derivative contracts These derivative contracts allow the Company to limit its exposure to commodity price volatility on a portion of its forecasted oil sales. At March 31, 2014, the Company’s commodity derivative contracts consisted of collars and fixed price swaps, which are described below:

Collar

Collars contain a fixed floor price (put) and fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from the either party.

Fixed price swap

The Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

All of the Company’s derivative contracts are with the same counterparty and are shown on a net basis on the Balance Sheet. The Company’s counterparty has entered into an inter-creditor agreement with Mutual of Omaha Bank, the provider of the Company’s credit facility, as such, no additional collateral is required by the counterparty.

No cash settlement has been made in relation to the derivative contracts as at March 31, 2014. $79,156 in loss due to change in fair value movement has been included in loss on derivative instrument in the Statement of Operations for the three month and nine month periods ending March 31, 2014.

We intend to increase our derivative portfolio as our production increases in order to provide downside protection to our future production.

At March 31, 2014 the Company’s open derivative contracts consisted of the following:

Oil Price Collars - WTI	Volumes (bbls)		Floor US$		Ceiling US$
March 2014- December 2014		18,443		90.00		99.30
January 2015 - December 2015		18,270		85.00		89.85
January 2016 - February 2016		2,788		85.00		89.85

Oil Price Swaps - WTI	Volumes (bbls)		Price US$
March 2014- December 2014		18,443		105.00
January 2015 - December 2015		18,270		105.00
January 2016 - February 2016		2,788		105.00

14. Subsequent Events

In April 2014, we issued 290,110,820 ordinary shares for 2.0 cents (Australian cents)/1.9 cents (United States cents) for proceeds of US$5.4 million, before costs. The ordinary shares were issued to investors in the US and Australia. We also issued 87,033,246 warrants over ordinary shares to these investors at no cost to them. The warrants have an exercise price of 3.3 cents (Australian cents) and an expiry date of April 30, 2018.

In April 2014, we sold our interests in Rennerfeldt 1-13H and Rennerfeldt 2-13H in our North Stockyard project in North Dakota to the operator of the project for a gain of $200,000. We had made cash prepayments with respect to these wells to the operator, which were applied to new wells that we are participating in.

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, 2013, included in our Annual Report on Form 10-K and the Consolidated Financial Statements included elsewhere herein.

Throughout this report, a barrel of oil or Bbl means a stock tank barrel (“STB”).

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.

Our net oil production was 29,074 barrels of oil for the quarter ended March 31, 2014, compared to 11,387 barrels of oil for the quarter ended March 31, 2013. The increase in oil production was due to four new wells commencing production in our North Stockyard project during the quarter – Coopers, Tooheys, Little Creatures and Blackdog. Our net gas production was 48,762 Mcf for the quarter ended March 31, 2014, compared to 39,830 Mcf for the quarter ended March 31, 2013. The increase in gas production also is a result of increased takeaway capacity for the existing wells in our North Stockyard project. Gas produced from the new wells in the North Stockyard project is currently being flared while production facilities are being built and pipeline take away capacity is secured.

Our net oil production was 54,498 barrels of oil for the nine months ended March 31, 2014 compared to 48,013 barrels of oil for the nine months ended March 31, 2013. Our net gas production was 129,734 Mcf for the nine months ended March 31, 2014 compared to 132,058 Mcf for the nine months ended March 31, 2013. The increase in oil production was due to five new wells in our North Stockyard project commencing production during this period – Sail and Anchor, Little Creatures, Coopers, Tooheys and Blackdog. Our net gas production remained generally flat between the nine months ended March 31, 2013 to March 31, 2014.

For the nine months ended March 31, 2014 and March 30, 2013, we reported a net loss of $0.9 million and a net loss of $9.8 million, respectively. The loss in the current period reflects a $2.7 million gain from the sale of oil and gas properties while the loss in the prior period included an income tax benefit of $2.0 million. See “Results of Operations” below.

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

During the nine month period ended March 31, 2014, we issued a total of 318,452,166 ordinary shares in a registered direct offering with investors in the US and Australia. The placement raised $7.3 million, before costs. The placement also included options to subscribe for an additional four ordinary shares for each ten ordinary shares subscribed for at an exercise price of A$0.038 per share, with an expiry date of March 31, 2017.

Notable Activities and Status of Material Properties during the Quarter Ended March 31, 2014 and Current Activities

Undeveloped Properties: Exploration Activities

Hawk Springs Project, Goshen County, Wyoming

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

Samson 37.5% to 100% working interest

We have two contiguous areas in the Hawk Springs Project. One of the areas is a joint venture with a private company and is subject to a joint venture with Halliburton Energy Services, Inc.

The Defender US33 #2-29H well is only pumped intermittently and produced 482 Bbls of oil during the quarter.

The Spirit of America US34 #2-29 (the SOA #2) intersected two excellent quality Permian age reservoirs, the 9,300 ft. sand, which appears to be oil saturated and the 9,500 ft. sand which is water saturated. Integrating the well data to the 3-D seismic data shows that an amplitude anomaly (lithology/porosity indicator) is associated with the 9500’ sand, indicating a thick and porous reservoir exists everywhere the amplitude is mapped. After further examination of the 3D seismic and additional data, we believe that the likely reason for the lack of oil saturation in the 9500’ sand is that a leak point can be established by a fortuitous juxtaposition of another porous reservoir across a fault that intersects the amplitude anomaly. Because this arrangement in the SOA prospect appears to be unique in the project area, Samson believes that the potential of the remaining two dozen prospects in the Hawk Springs project has been re-established, since these prospects do not appear to be affected by any recognized faulting.

The Bluff #1-11 has been drilled to a depth of 1,037 feet with an air-drill rig and surface casing has been set. A larger top-drive rig will drill the remainder of the well when that rig becomes available. The well will test a four-way dip structural closure in the Permian and Pennsylvanian age rocks to a depth of approximately 8,550 feet. The well is located three miles to the northwest of the Spirit of America US34 #2-29 well (SOA #2) and is planned to be more than 2000 feet shallower in depth. The excellent reservoir properties and oil shows seen in the SOA #2 well has allowed Samson to validate the 3-D seismic data and consequently high-grade the Bluff prospect. We have farmed out 65% of this project and are currently sourcing a rig to recommence the drilling of this well. The prospect will be drilled vertically to a depth of approximately 8,550 feet to test multiple targets in the Permian and Pennsylvanian sections at a net cost of approximately $1,000,000 to us.

Roosevelt Project, Roosevelt County, Montana

Mississippian Bakken Formation, Williston Basin

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

We have an interest in approximately 45,000 gross acres (30,000 net acres) in the Roosevelt Project with Fort Peck Energy Co. (“FPEC”) having the remaining 15,000 net acres.

In December 2013, we entered into a seismic and drilling agreement with Momentus Energy Corp, a Canadian exploration and development company based in Calgary. Momentus has committed to acquire approximately 20 squares of 3-D seismic data at no cost to us. Following the acquisition of the seismic data, Momentus has the option to drill a horizontal Bakken well on our acreage at 100% its own cost. Upon Momentus drilling this well, it will have earned the right to 50% of the test well and 50% of our acreage in the Roosevelt project. The program, consisting of 3-D seismic acquisition and the cost of drilling the Bakken well, is valued at approximately $10 million. This farmout arrangement was finalized during the quarter ended March 2014. Permitting associated with the acquisition of the 3-D seismic data has commenced. The acquisition of data is expected to be completed during the quarter ended June 30, 2014. In addition, Momentus has the right to earn 50% of the Australia II and Gretel II well bores and the 1,280 acres surrounding those well sites by performing a workover program suitable to Samson.

The two Bakken wells that were drilled in 2011and 2012 in the Roosevelt Project have proven to be uneconomic.

South Prairie Project, North Dakota

Mississippian Mission Canyon Formation, Williston Basin

Samson 25% working interest

Samson has a 25% working interest in 25,590 net acres located on the eastern flank of the Williston Basin in North Dakota. The first well of the project, the Matson #3-1 well was drilled and determined to be a dry hole, which will be plugged and abandoned. During the nine months ended March 31, 2014, $0.2 million was written off as dry hole expense.

Based on the technical analysis of this result, the forward program will show a preference for structural closures that exist along the salt edge rather than those created by dissolution events further interior to the salt edge. The joint venture is focusing on developing three structural closure prospects (Pubco, Deering, and Birch) along the Prairie Salt edge in the South Prairie 3-D project. The joint venture has approved the drilling of the Pubco Prospect on the eastern edge of the South Prairie 3-D seismic survey next. We anticipate this well will be drilled before the end of Q2 of calendar year 2014 at an estimated cost of $150,000 net to us.

Developed Properties: Drilling Activities

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Bakken & Three Forks infill wells

Samson ~25-30% working interest

On January 1, 2013, we and the operator group negotiated a non-cash acreage swap for the Middle Bakken/First Bench of the Three Forks (MB/TF), whereby we traded certain interests in our undeveloped acres in the Southern Tier for these parties’ undeveloped acres in the Northern Tier. As a result of this acreage swap we owned 64% and 57%, respectively, in the two overlapping 1,280 acre spacing units located in the Northern Tier. Our net production from current producing wells was not affected. In August 2013, we divested half our equity position in the undeveloped acreage in the North Stockyard project to Slawson Exploration Company Inc. (“Slawson”) for $5.562 million in cash and other consideration while retaining our full interest in the currently producing wells in the North Stockyard field. Slawson is now the operator of the Northern Tier acreage.

We have identified 14 infill development wells in this acreage that can be drilled between the existing Bakken wells and in the Three Forks Formation with 160 acre spacing. To date five of those wells have already been drilled and put on production (Sail & Anchor, Little Creatures, Tooheys, Coopers and Blackdog, two are awaiting fracture stimulation (Matilda Bay 1 & 2) and drilling has commenced on another four wells (Ironbark 1 & 2, Bootleg 1 & 2). Samson has sold its interest in two wells (Rennerfeldt 1 & 2) with one well awaiting workover operations (Billabong).

The Billabong 2-13-14HBK well (24.86% working interest, subject to the delivery of a useable well bore to Slawson) was drilled in the Middle Bakken Formation but upon cementing the 4 ½ inch production liner, the bottom of the drill string became cemented in the hole. Wash-over operations have been halted while other drilling operations take place on the same pad location. Operations are expected to recommence by the end of June 2014.

The Coopers 2-15-14HBK (27.7% working interest), Tooheys 4-15-15HBK (27.7% working interest), Little Creature 1-15-14HBK (27.7%) and Blackdog (25.03% working interest) 3-13-14H wells have all been drilled and completed with production commencing during the current quarter.

Rainbow Project, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson 23% and 52% working interest

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

Samson acquired the net acres in the Rainbow Project from the vendor as part of an acreage trade and is obligated provide a $1 million carry (10% of expected costs to drill and complete the first well) to the vendor, for the first development well to be drilled in the Rainbow Project. Samson has the ability, subject to the vendor acquiring additional acres, to acquire a further 407 acres by carrying the vendor for $0.7 million in the second well in the project.

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

A drilling permit for the Rainbow 10-19-18HBK well has been approved (SSN 23%). Continental will be the operator of this well and intends to drill it in the summer of 2014.

In the western drilling unit of the acquired acreage, Samson holds a 52% working interest. In the eastern drilling unit, Samson’s interest is 23% but with the option to increase it to 55% in the second tranche.

Developed Properties: Production Activities

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson various working interests

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

The Harstad #1-15H well (34.5% working interest) was down for the entire quarter due to electrical and downhole problems. Cumulative gross production to March 31, 2014 is approximately 113 MSTB.

The Leonard #1-23H well (10% working interest, 37.5% after non-consent penalty) was down for 22 days during the quarter due to an electrical malfunction and a tubing failure. The well averaged 38 BOPD and 10 Mscf/D during the quarter. To date, the Leonard #1-23H well has produced approximately 116 MSTB and 122 MMscf.

The Gene #1-22H well (30.6% working interest) was down for approximately 20 days during the quarter due to parted sucker rods. The well produced at an average daily rate of 46 BOPD and 144 Mscf/D during the quarter. Cumulative gross production to March 31, 2014 is approximately 165 MSTB and 197 MMscf.

The Gary #1-24H (37% working interest) well was down for less than three days during the quarter mostly due to an electrical failure. The well averaged 97 BOPD and 127 Mscf/D during the quarter. Cumulative gross production to March 31, 2014 is approximately 167 MSTB and 266 MMscf.

The Rodney #1-14H (27% working interest) well was down for the quarter due to planned shut-in periods while completing the offset wells. The cumulative production to date is approximately 119 MSTB and 169 MMscf.

The Earl #1-13H (32% working interest) well was down for 21 days during the quarter due to planned shut-in periods while completing the offset wells. The well produced at an average daily rate of 136 BOPD and 196 Mscf/D. Cumulative gross production to March 31, 2014 is approximately 207 MSTB and 300 MMscf.

The Everett #1-15H (26% working interest) well was down for 35 days during the quarter due to planned shut in periods while completing the offset wells. The Everett well produced at an average daily rate of 121 BOPD and 55 Mscf/D during the quarter. Cumulative production to March 31, 2014 is approximately 113 MSTB and 137 MMscf.

The Sail & Anchor 4-13-14HBK well was shut-in most of the quarter due to simultaneous drilling operations. The well produced 5,541 BO over the 13 days for an average daily rate of 426 BOPD.

The Coopers 1-23-13HBK well came on production February 4^th and produced for 15 days during the quarter due but was shut-in because of other well site operations. During this period the well produced 8,717 BO. The well had an IP rate of 566 BOPD.

The Little Creature 3-15-14HBK well came on production January 31^st and was restricted to 48 days on line during the quarter due to other well site operations. During this period the well produced 26,788 BO. The well had an IP rate of 501 BOPD.

The Tooheys 4-15-14HBK well came on production January 24^th and was restricted to 55 days on line during the quarter due to other well site operations. During this period the well produced 31,906 BO. The well had an IP rate of 1,076 BOPD.

The Blackdog 3-13-14HBK well came on production March 27^th and produced 2,720 BO during the frac flow back period. The well had an IP rate of 1,995 BOPD.

Although production data is somewhat limited due to the relatively short amount of time the new wells have been producing, our North Stockyard wells are generally meeting or exceeding our predrill production expectations.

Sabretooth Gas Field, Brazoria County Texas

Oligocene Vicksburg Formation, Gulf Coast Basin

Samson 9.375% working interest

Production for the Davis Bintliff #1 well averaged 3.9 MMscf/D and 31 BOPD for the quarter. Cumulative production to March 31, 2014 is approximately 7.1 Bscf and 78 MSTB.

All production amounts above indicate gross production, rather than only the production attributable to our respective working interest for each well. See “Results of Operations” below for the total production volumes attributed to Samson during the quarter.

Results of Operations

For the three months ended March 31, 2014, we reported a net loss of $0.4 million compared to a net loss of $8.9 million for the 2013 period.

For the nine months ended March 31, 2014 we reported a net loss of $0.9 million and a net loss of $9.8 million, after income tax benefit of $2.0 million for the nine months ended March 31, 2013.

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


	Three months ended
	31-Mar-14		31-Mar-13		31-Dec-13
Production Volume
Oil (Bbls)		29,074		11,387		12,788
Natural gas (Mcf)		48,762		39,380		42,990
BOE (based on one barrel of oil to six Mcf of natural gas)		37,201		17,950		19,953

Sales Price (excluding the impact of derivative instruments)
Oil ($/Bbls)	$	88.22	$	88.43	$	84.62
Gas ($/Mcf)	$	6.93	$	3.35	$	4.71
BOE ($/BOE)	$	78.03	$	63.51	$	64.39

Expense per BOE:
Lease operating expenses	$	21.44	$	27.80	$	22.06
Production and property taxes	$	8.79	$	6.32	$	7.35
Depletion, depreciation and amortization	$	19.36	$	20.00	$	20.94
General and administrative expense	$	40.87	$	100.56	$	84.15

	Nine months ended
	31-Mar-14		31-Mar-13
Production Volume
Oil (Bbls)		54,498		48,013
Natural gas (Mcf)		129,734		132,058
BOE		76,120		70,023

Sales Price (excluding the impact of derivative instruments)
Oil ($/Bbls)	$	89.99	$	81.46
Gas ($/Mcf)	$	5.26	$	3.76
BOE ($/BOE)	$	73.39	$	62.95

Expense per BOE:
Lease operating expenses	$	22.58	$	33.60
Production and property taxes	$	8.38	$	6.25
Depletion, depreciation and amortization	$	21.05	$	20.69
General and administrative expense	$	63.09	$	66.04

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


	Three months ended									Three months ended
	31-Mar-14			31-Mar-13			3Q14 to 3Q13 change			31-Dec-13			3Q14 to 2Q13 Change
Oil sales	$	2,564,894		$	1,007,000		$	1,557,894		$	1,082,154		$	1,482,740
Gas sales		337,852			132,000			205,852			202,658			135,194
Other liquids		-			1,000			(1,000	)		627			(627	)
Interest income		7,607			37,000			(29,393	)		86,853			(79,246	)
Gain on sale of oil and gas properties		217,665			-			217,665			-			217,665
Other		16,642			1,000			15,642			85			16,557

Lease operating expense		(1,124,478	)		(499,000	)		(625,478	)		(586,926	)		(537,552	)
Depletion, depreciation and amortization		(720,394	)		(359,000	)		(361,394	)		(417,723	)		(302,671	)
Impairment		(714	)		(6,000	)		5,286			-			(714	)
Exploration and evaluation expenditure		(22,411	)		(7,416,000	)		7,393,589			(51,669	)		29,258
Accretion of asset retirement obligations		(17,417	)		(14,000	)		(3,417	)		(17,117	)		(300	)
Loss on derivative instruments		(79,156	)		-			(79,156	)		-			(79,156	)
Interest expense		(29,903	)		-			(29,903	)		-			(29,903	)
Amortization of borrowing costs		(10,931	)		-			(10,931	)		-			(10,931	)
General and administrative		(1,520,524	)		(1,805,000	)		284,476			(1,679,066	)		158,542
Income tax benefit		-			-			-			-			-
Net loss	$	(381,268	)	$	(8,921,000	)	$	8,539,732		$	(1,380,124	)	$	998,856


	Nine months ended
	31-Mar-14			31-Mar-13			3Q14 to 3Q13 change
Oil sales	$	4,904,038		$	3,911,000		$	993,038
Gas sales		682,456			497,000			185,456
Other liquids		627			5,000			(4,373	)
Interest income		108,905			164,000			(55,095	)
Gain on sale of oil and gas properties		2,742,076			-			2,742,076
Other		16,826			112,000			(95,174	)
								-
Lease operating expense		(2,356,154	)		(2,353,000	)		(3,154	)
Depletion, depreciation and amortization		(1,602,199	)		(1,449,000	)		(153,199	)
Impairment		(83,835	)		(250,000	)		166,165
Exploration and evaluation expenditure		(341,785	)		(7,817,000	)		7,475,215
Accretion of asset retirement obligations		(50,230	)		(41,000	)		(9,230	)
Loss on derivative instruments		(79,156	)		-			(79,156	)
Interest expense		(29,903	)		-			(29,903	)
Amortization of borrowing costs		(10,931	)		-			(10,931	)
General and administrative		(4,802,635	)		(4,624,000	)		(178,635	)
Income tax (provision)/ benefit		-			2,036,000			(2,036,000	)
Net loss	$	(901,900	)	$	(9,809,000	)	$	8,907,100

Three Months Comparison of Quarter Ended March 31, 2014 to Quarter Ended March 31, 2013 and Nine Month Comparison of the Period Ended March 31, 2014 to the Period Ended March 31, 2013.

Oil and gas revenues

Oil revenues increased from $1.0 million for the three months ended March 31, 2013 to $2.6 million for the three months ended March 31, 2014, as a result of increased production in our North Stockyard project following the commencement of production from five new wells in this project area. The realized oil price remained consistent at $88.43 per Bbl for the three months ended March 31, 2013 and $88.22 per Bbl for the three months ended March 31, 2014.

Oil revenues likewise increased from $3.9 million for the nine months ended March 31, 2013 to $4.9 million for the nine months ended March 31, 2014 as a result of an increase in our oil production and an increase in our realized oil price. Oil production increased from 48,013 Bbls for the nine months ended March 31, 2013 to 54,498 Bbls for the nine months ended March 31, 2014. Our realized oil price increased from $81.46 per Bbl for the nine months ended March 31, 2013 to $89.99 per Bbl for the nine months ended March 31, 2014.

Gas revenues increased from $0.1 million for the three months ended March 31, 2013 to $0.3 million for the three months ended March 31, 2014. Production increased from 39,380 Mcf for the quarter ended March 31, 2013 to 48,762 Mcf for the quarter ended March 31, 2014. The realized gas price also increased from $3.35 per Mcf for the quarter ended March 31, 2013 to $6.93 per Mcf for the quarter ended March 31, 2014.

Gas revenues also increased slightly from at $0.5 million for the nine months ended March 31, 2013 to $0.7 million for the nine months ended March 31, 2014. Production decreased slightly from 132,058 Mcf for the nine months ended March 31, 2013 to 129,734 Mcf for the nine months ended March 31, 2014. This decrease in production was offset by an increase in the realized gas price, from $3.76 per Mcf for the nine months ended March 31, 2013 to $5.26 per Mcf for the nine months ended March 31, 2014.

Sale of oil and gas properties

In March 2014, we finalized the sale of our Deep Draw well in Campbell County, Wyoming for cash of $0.2 million. This well had been previously impaired and thus had no written down value.

In August 2013, we divested half of our equity position in the undeveloped acreage in the North Stockyard project to Slawson Exploration Company Inc. for $5.562 million in cash and other consideration while retaining our full interest in the currently producing wells in the North Stockyard field. As a consequence of the transaction the rig contract with Frontier was also terminated, without penalty. Slawson is now the operator of the project and responsible for the development of the remaining undeveloped acreage.

Along with the undeveloped acreage, we also transferred a 25% working interest in the then drilled but not yet completed, at the time of the sale, Sail and Anchor well, as well as a 25% working interest in the salt water disposal well and associated water handling facilities drilled in the prior year in the North Stockyard project. A portion of the purchase price remains subject to the delivery of a useable well bore in Billabong, valued in the agreement at $0.9 million and other customary post-closing adjustments.

Exploration expense

Exploration expenditures decreased from $7.4 million for the quarter ended March 31, 2013, to $0.02 million for the quarter ended March 31, 2014. The expenditure in the prior period relates to expensing $7.4 million in expenditure in relation to our Spirit of America II well in our Hawk Springs project in Goshen County, Wyoming. This well failed to intersect hydrocarbons and was deemed to be a dry hole.

Exploration expenditure decreased from $7.8 million for the nine months ended March 31, 2013 to $0.3 million for the nine months ended March 31, 2014. During the nine months ended March 31, 2013, the exploration expenditure relates to expenses incurred on our Australia II and Gretel II leases, the write off of our Spirit of America II well, detailed above, as well as other general exploration expenditure. During the nine months ended March 31, 2014 the exploration expenditure relates to dry hole costs associated with the Matson well in our South Prairie project in North Dakota of $0.2 million plus other general exploration expenditures.

Lease operating expense

Lease operating expenses increased from $0.5 million for the quarter ended March 31, 2013, to $1.1 million for the quarter ended March 31, 2014. The increase is due to increased production. Costs per BOE decreased from $27.80 for the quarter ended March 31, 2013 to $21.44 for the quarter ended March 31, 2014. Costs in the prior year were high due to high water disposal costs associated with the Australia II and Gretel II wells in our Roosevelt project in Montana, which did not contribute significant production.

Lease operating expenses remained consistent at $2.4 million for the nine months ended March 31, 2013 and March 31, 2014. Costs per BOE decreased from $33.60 for the nine months ended March 31, 2013 to $22.58 for the nine months ended March 31, 2014. Costs in the prior year were high due to high water disposal costs associated with the Australia II and Gretel II wells in our Roosevelt project in Montana, which did not contribute significant production. Costs have also decreased in our North Stockyard project, following the drilling of the salt water disposal well which has reduced the costs of salt water disposal in that project area.

Depletion, depreciation and amortization expense

Depletion, depreciation and amortization expense increased from $0.4 million for the quarter ended March 31, 2013 to $0.7 million for the quarter ended March 31, 2014. The increase in depletion is a result of the increase in the production. The per BOE cost remained fairly consistent at $20.00 for the three months ended March 31, 2013 and $19.36 for the three months ended March 31, 2014.

Depletion, depreciation and amortization expense increased slightly from $1.5 million for the nine months ended March 31, 2013 to $1.6 million for the nine months ended March 31, 2014. Depreciation, depletion and amortization expense per BOE also remained consistent at $20.69 for the nine months ended March 31, 2013 compared to $21.05 for the nine months ended March 31, 2014; however, production overall increased, leading to an increase in depletion expense.

General and administrative expense

General and administrative expense decreased from $1.8 million for the quarter ended March 31, 2013 to $1.5 million for the three months ended March 31, 2014. This decrease is due a decrease in corporate activity during the current quarter.

General and administrative expense increased slightly from $4.6 million for the nine months ended March 31, 2013 to $4.8 million for the nine months ended March 31, 2014. This increase is largely due to an increase in corporate activity surrounding funding strategies and investor relations.

Income tax benefit

Income tax benefit was $nil for the nine months ended March 31, 2014 compared to a benefit of $2.0 million for the nine months ended March 31, 2013. The income tax benefit recognized in the prior year is a result of a portion of the prior year’s operating losses being carried back to obtain a refund of income taxes paid in prior years.

Cash Flows

The table below shows cash flows for the following periods:


	Nine months ended
	31-Mar-14			31-Mar-13
Cash provided by/(used in) operating activities	$	(2,754,187	)	$	2,353,000
Cash used in investing activities		(16,551,529	)		(12,078,000	)
Cash provided by financing activities		12,587,688			6,064,000

Cash (used in)/provided by operations increased from an inflow of $2.4 million for the nine months ended March 31, 2013, to a net outflow of $2.8 million for the nine months ended March 31, 2014. Cash receipts from customers increased from $3.7 million for nine months ended March 31, 2013 to $4.2 million for the nine months ended March 31, 2014, due to an increase in production and an increase in the realized oil price. Cash inflow in the prior period includes an income tax refund of $5.6 million received during the quarter ended March 31, 2013.

Cash used in investing activities increased from $12.1 million for the nine months ended March 31, 2013 to $16.6 million of cash used for the nine months ended March 31, 2014. The cash outflow for the nine months ended March 31, 2014, relates to drilling activities in our North Stockyard project in North Dakota. The cash outflow for the period ended March 31, 2013, relates to drilling and exploration activities conducted in our Hawk Springs and Roosevelt projects.

Cash provided by financing activities increased from a cash inflow of $6.1 million for the nine months ended March 31, 2013, to a cash inflow of $12.5 million for the nine months ended March 31, 2014. Cash inflow for the prior period was a result of the exercise of non-compensatory options and equity issue. The increase in the current period is a result of shares issued during the period as described below and the drawdown of borrowings from our credit facility with Mutual of Omaha.

All options outstanding as at March 31, 2014 are currently out of the money.

Liquidity, Capital Resources and Capital Expenditures

Our primary use of capital has been acquiring, developing and exploring oil and natural gas properties and we anticipate this will be our primary use of capital during fiscal 2014 as well.

Our current budget for exploration, exploitation and development capital expenditures in fiscal 2014 is $28.0 million, of which we incurred approximately $18.7 million during the first nine months of the fiscal year. We were able to make these expenditures, which were required to participate in the drilling and completion of the first five wells in our North Stockyard infill development program, by using the proceeds from our recent registered direct offering and our sale of development acreage to Slawson. The remaining $9.3 million in planned capital expenditures, relates to the drilling and completion of three additional wells in our North Stockyard infill project and the drilling or our Bluff well in our Hawk Springs project.

In January 2014, we entered into a $25 million credit facility with Mutual of Omaha Bank, with an initial borrowing base of $8.0 million, of which $6.0 million has been drawn down, including $2.0 million during the quarter ended March 31, 2014. We expect the remaining $2.0 million in borrowing base will be drawn down prior to June 30, 2014 on an as needed basis. Additional increases in the borrowing base, up to the credit facility maximum of $25 million, may be made available to us in the future depending on the value of our future reserves. Borrowing base redeterminations are performed by the lender every six months at June and December. We also have the ability to request a borrowing base redetermination at another period, once a year.

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

Current ratio greater than 1

Debt to EBITDAX (annualized) ratio no greater than 3.5

Interest coverage ratio minimum of 2.5 to 1.0

As at March 31, 2014 we were in compliance with all quarterly covenants.

The credit facility also includes an annual cap on general and administrative expenditure of $6,000,000 per fiscal year.

The funds drawn from our credit facility will be used to fund drilling in our North Stockyard project in North Dakota. We expect to fund our remaining capital expenditures for fiscal 2014 with cash on hand, cash flow from operations, and drawdowns of our credit facility (to the extent available). We may also elect, where we consider it reasonable and appropriate, to raise funds by the sale of selected assets.

Uncertainties relating to our capital resources and requirements include the effects of results from our exploration and drilling program and changes in oil and natural gas prices, either of which could lead us to accelerate or decelerate exploration and drilling activities. The aggregate levels of capital expenditures for our fiscal year ending June 30, 2014, and the allocation of those expenditures, are dependent on a variety of factors, including the availability of capital resources to fund the expenditures and changes in our business assessments as to where our capital can be most profitably employed. Accordingly, the actual levels of capital resources and expenditures and the allocation of those expenditures may vary materially from our estimates.

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

Our two main sources of liquidity during the nine months ended March 31, 2014 have been cash on hand, which was $5.8 million at March 31, 2014, cash flows from operations, proceeds from our registered direct offering completed in August 2013, the sale of development acreage to Slawson and the new credit facility entered into in January 2014. In April 2014, we issued 290,110,820 ordinary shares and 87,033,246 options to raise $5.4 million, before costs.

During the prior three fiscal years, our three main sources of liquidity were (i) approximately $73.2 million cash received from the sale of 24,166 acres in Goshen County, Wyoming to Chesapeake Energy Corporation, (ii) $6.3 million received from the sale of our interests in the Jonah and Lookout Wash fields and (iii) our tax refund of $5.6 million from the Internal Revenue Service, received in February 2013. 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 raises and (ii) a loan facility with Macquarie Bank Limited, which we repaid in full on May 30, 2011.

Our cash position as of March 31, 2014 decreased from March 31, 2013 largely due to payments for drilling and fracking in our North Stockyard project in North Dakota.

If future drilling success rates or production are less than anticipated, the value of our position in affected areas will decline, our results of operations, financial condition and liquidity will be adversely impacted and we could incur material write-downs of unevaluated properties. See the risk factors in our Annual Report on Form 10-K for the fiscal year ended June 30, 2013 including “Drilling results in emerging plays, such as our Hawk Springs and Roosevelt Projects, are subject to heightened risks.” and “Inadequate liquidity could materially and adversely affect our business operations.” See also Part II, Item 1A of this report below.

Looking Ahead

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


	·	The continued development of our Bakken projects - our North Stockyard project in Williams County, North Dakota and the initial development of our Rainbow project in Williams County, North Dakota.

	·	The continued appraisal and development of our Hawk Springs project, including multiple conventional targets in the Permian and Pennsylvanian formations.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

There were no material changes during the nine months ended March 31, 2014 to the disclosure made in our Annual Report on Form 10-K for the year ended June 30, 2013 regarding this matter.

Item 4. Controls and Procedures.

As of March 31, 2014, 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 March 31, 2014, 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 March 31, 2014, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time in the future.

Part II — Other Information

Item 1. Legal Proceedings.

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

Environmental Matters

The Environmental Protection Agency agreed to a cash settlement of $60,000 in relation to a 400 barrel oil spill on the Pierce well site in February 2009. The spill was contained and the area rehabilitated to the satisfaction of the appropriate authorities in 2009. The costs associated with the spill and subsequent remediation were covered by our insurance and paid in 2009. While the cash settlement was paid after the quarter ending March 31, 2014, it has been accrued on the Balance Sheet for that quarter.

State Income Tax Matters

Halliburton Dispute

We have an ongoing dispute with Halliburton Energy Services, Inc., a co-participant in our Hawk Springs project. The dispute also relates to our 2012 drilling program in our Roosevelt project in Montana, where Halliburton provided us with project management services. We are claiming $302,000 from Halliburton on account of an unpaid invoice arising out of the Roosevelt project while Halliburton is claiming at least $126,000 in unpaid oil revenue from the Hawk Springs Project. We have engaged in sporadic negotiations with Halliburton over the past two years to try to resolve these offsetting liabilities, but it now appears likely that the competing claims will be the subject of a lawsuit between the parties. While we believe that our own claim against Halliburton is meritorious, we cannot predict the ultimate resolution of the dispute, whether it is resolved by litigation or negotiated settlement.

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, 2013. 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. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

Exhibit No.		Title of Exhibit

31.1		Certification of the Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1		Certifications of the Principal Executive Officer and Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101		The following financial information from Samson Oil & Gas Limited’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 is formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheet, (ii) Consolidated Statements of Operations, (iii) Consolidated Statement of Changes in Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements.

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: May 9, 2014	By:	/s/ Terence M. Barr
		Terence M. Barr
		Managing Director, President and Chief Executive Officer (Principal Executive Officer)

Date: May 9, 2014	By:	/s/ Robyn Lamont
		Robyn Lamont
		Chief Financial Officer (Principal Financial Officer)