Samson Oil & Gas LTD (Form: 10-Q, Received: 02/09/2015 17:11:04)

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, 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 2,837,782,022 ordinary shares outstanding as of February 6, 2015.

SAMSON OIL & GAS LIMITED

FORM 10-Q

QUARTER ENDED DECEMBER 31, 2014

TABLE OF CONTENTS

		Page

Part I — Financial Information		4

Item 1.	Financial Statements (unaudited)	4

	Consolidated Balance Sheets, December 31, 2014 and June 30, 2014	4

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

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

	Consolidated Statement of Cash Flows for the six months ended December 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	16

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	24

Item 4.	Controls and Procedures	24

Part II — Other Information		25

Item 1.	Legal Proceedings	25

Item 1A.	Risk Factors	25

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	25

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-Dec-14			30-Jun-14
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	3,881,138		$	6,846,394
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively		3,401,145			5,533,516
Prepayments		1,202,115			5,388,428
Fair value of derivative instrument		1,949,350			-
Short term deferred tax asset		84,946			84,946
Total current assets		10,518,694			17,853,284
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment of $21,079,958 and $21,219,361 at December 31, 2014 and June 30, 2014, respectively		46,866,724			34,430,793
Other property and equipment, net of accumulated depreciation and amortization of $486,953 and $421,443 at December 31, 2014 and June 30, 2014, respectively		317,766			365,566
Net property, plant and equipment		47,184,490			34,796,359
OTHER NON CURRENT ASSETS
Fair value of derivative instrument		256,940			-
Undeveloped capitalized acreage		2,937,920			12,349,767
Capitalized exploration expense		1,953,039			3,382,650
Other		354,619			459,169
TOTAL ASSETS	$	63,205,702		$	68,841,229

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	2,046,235		$	4,316,963
Accruals		4,386,154			3,261,674
Fair value of derivative instruments		-			284,376
Provision for annual leave		211,229			230,311
Total current liabilities		6,643,618			8,093,324
NON CURRENT LIABILITIES
Fair value of derivative instruments		-			128,998
Asset retirement obligations		1,124,377			897,859
Credit facility		15,500,000			6,000,000
Deferred tax liability		84,946			84,946
TOTAL LIABILITIES		23,352,941			15,205,127
STOCKHOLDERS’ EQUITY – nil par value
2,837,782,022 (equivalent to 141,889,101 ADR’s) and 2,837,756,933 (equivalent to 127,381,360 ADR’s) ordinary shares issued and outstanding at December 31, 2014 and June 30, 2014, respectively		104,491,774			104,535,894
Accumulated other comprehensive income		1,075,697			1,302,096
Accumulated deficit		(65,714,710	)		(52,201,888	)
Total stockholders’ equity		39,852,761			53,636,102
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	63,205,702		$	68,841,229

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						Six months ended
	31-Dec-14			31-Dec-13			31-Dec-14			31-Dec-13
REVENUES AND OTHER INCOME:
Oil sales	$	2,538,100		$	1,082,154		$	5,541,245		$	2,339,144
Gas sales		148,953			202,658			404,003			344,604
Other liquids		-			627			-			627
Interest income		9,884			86,853			19,523			101,298
Gain on derivative instruments		2,306,135			-			3,087,705			-
Gain on sale of oil and gas properties		-			-			-			2,524,411
Other		6,561			85			6,772			184
TOTAL REVENUE AND OTHER INCOME		5,009,633			1,372,377			9,059,248			5,310,268

EXPENSES:
Lease operating expense		(1,512,195	)		(586,926	)		(2,972,117	)		(1,231,676	)
Depletion, depreciation and amortization		(1,118,619	)		(417,723	)		(2,073,680	)		(881,805	)
Impairment expense		(3,027,288	)		-			(3,060,684	)		(83,121	)
Abandonment expense		(79,036	)		-			(214,803	)		-
Exploration and evaluation expenditure		(362,540	)		(51,669	)		(11,465,956	)		(319,374	)
Accretion of asset retirement obligations		(8,418	)		(17,117	)		(16,341	)		(32,813	)
Amortisation of borrowing costs		(31,972	)		-			(65,132	)		-
Interest expense		(147,343	)		-			(231,285	)		-
General and administrative		(1,260,793	)		(1,679,066	)		(2,472,072	)		(3,282,109	)
TOTAL EXPENSES		(7,548,204	)		(2,752,501	)		(22,572,070	)		(5,830,898	)

Loss from operations		(2,538,571	)		(1,380,124	)		(13,512,822	)		(520,630	)
Income tax benefit		-			-			-			-
Net loss		(2,538,571	)		(1,380,124	)		(13,512,822	)		(520,630	)
OTHER COMPREHENSIVE GAIN (LOSS)
Foreign currency translation loss		(97,689	)		(383,280	)		(226,399	)		(578,055	)
Total comprehensive loss for the period	$	(2,636,260	)	$	(1,763,404	)	$	(13,739,221	)	$	(1,098,685	)

Net loss per ordinary share from operations:
Basic – cents per share		(0.09	)		(0.05	)		(0.48	)		(0.02	)
Diluted – cents per share		(0.09	)		(0.05	)		(0.48	)		(0.02	)

Weighted average ordinary shares outstanding:
Basic		2,837,781,683			2,547,627,193			2,837,772,648			2,452,931,137
Diluted		2,837,781,683			2,547,627,193			2,837,772,648			2,452,931,137

See accompanying Notes to Consolidated Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

							Accumulated Other
							Other			Total
	Ordinary						Comprehensive			Stockholders
	Shares			(Accumulated Deficit)			Income			Equity
Balance at June 30, 2014	$	104,535,894		$	(52,201,888	)	$	1,302,096		$	53,636,102
Net loss		-			(13,512,822	)		-			(13,512,822	)
Foreign currency translation loss, net of tax of $nil		-			-			(226,399	)		(226,399	)
Total comprehensive loss for the period		-			(13,512,822	)		(226,399	)		(13,739,221	)
Stock based compensation		-			-			-			-
Exercise of options		880			-			-			880
Share issuance costs		(45,000	)		-			-			(45,000	)
Balance at December 31, 2014	$	104,491,774		$	(65,714,710	)	$	1,075,697		$	39,852,761

See accompanying Notes to Consolidated Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six months ended
	31-Dec-14			31-Dec-13
Cash flows (used in)/provided by operating activities
Receipts from customers	$	7,010,394		$	2,504,828
Payments to suppliers & employees		(6,349,789	)		(4,207,411	)
Interest received		19,499			102,019
Proceeds from derivative instruments		228,837			-
State income taxes paid		(107,135	)		-
Net cash flows provided by/(used in) operating activities		801,806			(1,600,564	)
Cash flows used in investing activities
Proceeds from sale of oil and gas properties		-			3,547,409
Payments for plant & equipment		(21,427	)		(25,041	)
Payments for exploration and evaluation		(1,399,142	)		(240,945	)
Payments for oil and gas properties		(11,313,174	)		(15,144,169	)
Net cash flows used in investing activities		(12,733,743	)		(11,862,746	)
Cash flows provided by financing activities
Issuance of share capital		-			7,337,138
Proceeds from the exercise of options		880			347
Proceeds from borrowings		9,500,000			-
Borrowing costs		(83,690	)		-
Interest paid		(172,917	)		-
Share issuance costs		(45,000	)		(561,239	)
Net cash flows provided by financing activities		9,199,273			6,776,246
Net decrease in cash and cash equivalents		(2,732,664	)		(6,687,064	)
Cash and cash equivalents at the beginning of the fiscal period		6,846,394			13,170,627
Effects of exchange rate changes on cash and cash equivalents		(232,592	)		(581,004	)
Cash and cash equivalents at end of fiscal period	$	3,881,138		$	5,902,559

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, 2014. The year-end Consolidated Balance Sheet presented herein was derived from audited Consolidated Financial Statements, but does not include all disclosures required by GAAP.

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

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

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

Recent Accounting Standards

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

2. Income Taxes

	Three months ended						Six months ended
	31-Dec-14			31-Dec-13			31-Dec-14			31-Dec-13

Income tax benefit	$	-		$	-		$	-		$	-
Effective tax rate		0.00	%		0.00	%		0.00	%		0.00	%

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.

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				Six months ended
	31-Dec-14		31-Dec-13		31-Dec-14		31-Dec-13
Dilutive		-		-		-		-
Anti–dilutive		389,168,104		300,885,050		389,177,139		261,058,802

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

	Three months ended						Six months ended
	31-Dec-14			31-Dec-13			31-Dec-14			31-Dec-13
Net income (loss)	$	(2,538,571	)		(1,380,124	)	$	(13,512,822	)		(520,630	)

Basic weighted average ordinary shares outstanding		2,837,781,683			2,547,627,193			2,837,772,648			2,452,931,137
Add: dilutive effect of stock options		-			-			-			-
Add: bonus element for rights issue		-			-			-			-
Diluted weighted average ordinary shares outstanding		2,837,781,683			2,547,627,193			2,837,772,648			2,452,931,137
Basic earnings per ordinary share – cents per share		(0.09	)		(0.05	)		(0.48	)		(0.02	)
Diluted earnings per ordinary share – cents per share		(0.09	)		(0.05	)		(0.48	)		(0.02	)

4. Asset Retirement Obligations

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

The liabilities settled in the six months to December 31, 2014 relate to work performed to plug and abandon three wells in our Greens Canyon prospect in Wyoming. These wells were drilled 10 years ago and did not produce economic quantities of hydrocarbons.

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

	Six months ended
	31-Dec-14			31-Dec-13
Asset retirement obligations at beginning of period	$	1,775,792		$	868,589
Liabilities incurred or acquired		42,805			154,735
Liabilities settled		(710,561	)		(8,136	)
Disposition of properties		-			-
Accretion expense		16,341			32,813
Asset retirement obligations at end of period		1,124,377			1,048,001
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)		-			-
Long-term asset retirement obligations	$	1,124,377		$	1,048,001

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 during the three months ended December 31, 2014 and $80,989 during the three months ended December 31, 2013.

Total compensation cost recognized in the Statements of Operations for the grants under the Company’s equity incentive compensation plans was $nil during the six months ended December 31, 2014 and $86,244 during the six months ended December 31, 2013.

As of December 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 was 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 workover was completed during the year ended June 30, 2014 and Slawson exercised its option to take over operation of the Billabong well bore.

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 Sail and Anchor well, which was drilled but not completed, at the time of sale, 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 at the time of the transaction.

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 December 31, 2014 and June 30, 2013.

	Carrying value at December 31, 2014		Level 1		Level 2		Level 3		Netting ⁽¹⁾			Fair Value at December 31, 2014
Current Assets:
Cash and cash equivalents	$	3,881,138	$	3,881,138	$	-	$	-	$	-		$	3,881,138
Derivative Instruments		1,949,350		-		1,960,723		-		(11,373	)		1,949,350

Non Current Assets
Derivative Instruments		256,940		-		722,491				(465,551	)		256,940
													-
Current Liabilities													-
Derivative instruments		-		-		11,373		-		(11,373	)		-
													-
Non Current Liabilities													-
Derivative Instruments		-		-		465,551				(465,551	)		-

	Carrying value at June 30, 2014		Level 1		Level 2		Level 3		Netting ⁽¹⁾			Fair Value at June 30, 2014
Current Assets:
Cash and cash equivalents	$	6,846,394	$	6,846,394	$	-	$	-	$	-		$	6,846,394
Derivative Instruments		-		-		56,380		-		(56,380	)		-

Non Current Assets
Derivative Instruments		-		-		61,493		-		(61,493	)		-

Current Liabilities
Derivative instruments		284,376		-		340,756		-		(56,380	)		284,376

Non Current Liabilities
Derivative Instruments		128,998		-		190,491		-		(61,493	)		128,998

(1)

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

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

Level 1 Fair value Measurements

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

Level 2 Fair Measurements

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

Other fair value measurements

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

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

Some oil and gas properties are stated at fair value as at December 31, 2014. As a result of the significant decline in oil prices experienced in recent months, the carrying value of oil and gas properties was reviewed and subject to impairment costs of $3.0 million. $2.7 million of this related to our Rainbow property in North Dakota, while the remaining $0.3 million related to various small non-operated properties in Wyoming.

8. Commitments and Contingencies

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

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

Halliburton Dispute

Halliburton Energy Services, Inc., a co-participant in the Company’s Hawk Springs project, has filed a complaint in Harris County, Texas District Court against Samson USA seeking unpaid oil revenue attributable to its ownership interest in the Hawk Springs Project, which was approximately $126,000 as of June 5, 2013, and has since increased to approximately $168,000. Samson USA has answered the complaint and has filed counterclaims against Halliburton arising out of Samson USA’s engagement of Halliburton’s Project Management group in May of 2011 to provide services in connection with its drilling program in Roosevelt County, Montana. In its counterclaims, Samson USA claims approximately $336,000 from Halliburton on account of Halliburton’s refusal to pay an invoice for demobilization of the drilling rig used in the Roosevelt project. Samson USA has also asked for a judicial accounting with respect to Halliburton’s fees and expenses charged to Samson in connection with the Spirit of America well in Goshen County, Wyoming, and the Australia II, well in Roosevelt County, Wyoming, because of Samson’s discovery of self-dealing and bill padding by Halliburton’s onsite project manager there. Halliburton has not yet filed an answer to Samson’s counterclaims but the parties are commencing discovery efforts in the lawsuit. While Samson believes that its counterclaims are meritorious and is confident that Samson will obtain a net positive recovery from the lawsuit, there can be no assurance as to the ultimate outcome of this litigation.

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 December 31, 2014 we had capitalized exploration expenditures of $2.3 million and undeveloped capitalized acreage expenditures of $2.9 million. This amount primarily relates to costs incurred in connection with our Hawk Springs projects.

Our Hawk Springs project, in Goshen County, Wyoming, includes $2.9 million in undeveloped capitalized acreage costs and $2.3 million in capitalized exploration expenditure. The capitalized exploration expenditure includes costs associated with the acquisition of our North Platte 3D seismic data and costs associated with the drilling of our Bluff Federal well in this project area. Operations are continuing on this well and it is expected to be completed by March 31, 2015. Due to expired leases, $0.1 million has been written off with respect to this project during the quarter ended September 30, 2014 and $0.2 million has been written off with respect to this project during the quarter ended December 31, 2014.

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 square miles 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 3-D seismic survey has been shot, processed, and interpreted. The agreement required Momentus to drill a Bakken horizontal by November 15, 2014, and as this did not occur negotiations have proceeded and now Momentus has until March 15, 2015 to pay Samson $100,000 to extend the farm-out agreement to December 31, 2015. If Momentus fails to pay Samson $100,000 by March 15, 2015, the farm-out will terminate.

It is understood that the extension is being requested as Momentus has failed to secure the funding to drill their earn-in well. Given the recent drop in oil prices, the lack of certainty with respect to Momentus’s ability to drill their earn in well and the fact that at this point in time we do not expect to spend any further funds on this project, the balance of $8.1 million capitalized with respect to this project was written off to the Statement of Operations during the quarter ended September 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 approved the drilling next of the Pubco Prospect, with the York 3-14 well, on the eastern edge of the South Prairie 3-D seismic survey. This well was drilled during the quarter ended September 30, 2014 and found the primary target to be water saturated. Given the lack of success from this project, we have written off the previously capitalized value of this project of $2.5 million to the Statement of Operations during the quarter ended September 30, 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 three months ended December 31, 2014, 1,064 Australian 3.8 cent options were exercised for net proceeds of $38.

During the six months ended December 31, 2014, 25,089 Australian 3.8 cent options were exercised for net proceeds of $880.

During the three months ended December 31, 2013 there were no issues of ordinary shares.

During the six months ended December 31, 2013 9,864 Australian 3.8 cent options were exercised for net proceeds of $347.

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

During the six months ended December 31, 2013, 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:

	Six months ended
	31-Dec-14			31-Dec-13
Net loss after tax	$	(13,512,822	)	$	(520,630	)
Depletion, depreciation and amortization		2,073,680			881,805
Stock-based compensation		-			86,244
Accretion of asset retirement obligation		16,341			32,813
Impairment expense		3,060,684			83,121
Exploration and evaluation expenditure		11,465,956			319,374
Gain on sale of oil and gas properties		-			(2,524,411	)
Amortisation borrowing costs		65,132			-
Abandonment expense		214,803			-
Non cash gain on derivative instruments		(2,619,664	)		-

Changes in assets and liabilities:

Decrease/(Increase) in receivables		2,132,371			(179,360	)
Decrease in income tax receivable/deferred tax asset		-			-
Increase/(decrease) in provision for annual leave		(19,082	)		38,851
(Decrease)/Increase in payables		(2,075,593	)		181,629
NET CASH FLOWS PROVIDED BY/(USED IN) OPERATING ACTIVITIES	$	801,806		$	(1,600,564	)

12. Credit Facility

	Six months ended
	31-Dec-14		31-Dec-13
Credit facility at beginning of period	$	6,000,000	$	-
Cash advanced under facility	$	9,500,000		-
Repayments		-		-
Credit facility at end of period	$	15,500,000	$	-
				-
Funds available for drawdown under the facility	$	3,500,000		-

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, which was increased to $15.5 million in June 2014. In November 2014, the borrowing base was increased to $19.0 million, of which $15.5 million has been drawn down.

Additional increases in the borrowing base, up to the credit facility maximum of $50.0 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 3.25% or approximately 3.48% for the quarter ended December 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

The credit facility also includes an annual cap on general and administrative expenditures of $6,000,000 per year to be tested for the first time for calendar year ended December 31, 2014 and each subsequent December 31 thereafter while the facility is in place.

As at December 31, 2014 we were in breach of our debt to EBITDAX covenant. We have received a waiver from Mutual of Omaha with respect to this breach for this quarter only. We were in compliance with all other covenants.

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, 2015 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 $0.4 million in borrowing costs (including legal fees and bank fees) 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 December 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 (a large multinational oil company) and are shown on a net basis on the Balance Sheet. The Company’s counterparty has entered into an inter-creditor agreement with Mutual of Omaha Bank, the provider of the Company’s credit facility, as such, no additional collateral is required by the counterparty.

During the quarter ended December 31, 2014 we recognized $2,306,135 gain on derivative instruments in the Statement of Operations.

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

In October 2014, we entered into a deferred put spread arrangement with respect to 36,600 barrels from production in 2016. These options have a floor of $82.50 (the Company receives $82.50 when the market price settles between $67.20 and $82.50) and a sub floor of $67.50 (the Company receives the market price plus $15 for any prices below $67.50) with a cost of $5.50 per barrel which is deferred until the settlement of the derivative instrument.

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

Oil Price Collars - WTI	Volumes (Bbls)		Floor US$		Ceiling US$
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$
January 2015 - December 2015		18,270		105.00
January 2016 - February 2016		2,788		105.00

Oil Price Swaps - WTI	Volumes (Bbls)		Avg Price US$
January 2015 - December 2015		39,791		92.61

14. Subsequent Events

No events have occurred subsequent to December 31, 2014 that would have an impact on our operations or the results of operations for the quarter ended December 31, 2014.

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, 2014, included in our Annual Report on Form 10-K and the Consolidated Financial Statements included elsewhere herein.

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

Overview

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Our strategy is to focus on the exploration, exploitation and development of our major oil plays – the 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 43,653 barrels of oil for the quarter ended December 31, 2014, compared to 12,788 barrels of oil for the quarter ended December 31, 2013. The increase in oil production was due to ten new wells commencing production in our North Stockyard project since December 2013. One new well commenced production during the quarter ended September 30, 2014 with an additional nine commencing production during the current quarter. Our net gas production was 39,043 Mcf for the quarter ended December 31, 2014, compared to 42,990 Mcf for the quarter ended December 31, 2013. The decrease in gas production is a result of a decrease in production from our main gas well, Sabretooth in Texas due to decreasing reservoir pressure, consistent with the production decline expected from this field. Gas produced from the new wells in the North Stockyard project, with the exception of the Sail & Anchor and Blackdog wells, is currently being flared while production facilities are being built and pipeline take away capacity is secured.

Our net oil production was 78,517 barrels of oil for the six months ended December 31, 2014 compared to 25,424 barrels of oil for the six months ended December 31, 2013. Our net gas production was 85,588 Mcf for the six months ended December 31, 2014 compared to 80,972 for the six months ended December 31, 2013. The increase in both oil and gas production is largely due to the eleven new wells that commenced production in our North Stockyard project in North Dakota.

For the six months ended December 31, 2014 and December 31, 2013, we reported a net loss of $13.4 million and a net loss of $0.5 million, respectively. The loss in the current period reflects a $11.0 million in write off of previously capitalized exploration expenditure and impairment expense of $3.0 million while the loss in the prior period reflects a $2.5 million gain from the sale of oil and gas properties. See “Results of Operations” below.

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

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

Undeveloped Properties: Exploration Activities

Hawk Springs Project, Goshen County, Wyoming

Permo-Penn Project, Northern D-J Basin

Samson 37.5% 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 Bluff Prospect was drilled in June to test multiple targets in the Permian and Pennsylvanian sections in a 4-way structural trapping configuration. The Bluff #1-11 well reached a total depth of 8,900 feet after intersecting the pre-Cambrian basement on June 13th.

Various oil shows were observed in the Cretaceous, Jurassic, Permian, and Pennsylvanian intervals while drilling. After running drill-pipe conveyed logging tools in the deeper portion of the well below the intermediate casing, the Pennsylvanian zones, were deemed to be too thin and uneconomic to produce. The Permian target zone (from 7738 to7756 feet) displayed excellent porosity (up to 29% density porosity). Further analysis of the Permian target zone proves that it is the source of the nitrogen gas kicks. The presence of nitrogen in the Permian target zone validates the trap in the Bluff prospect and has the potential to host an oil leg below the gas cap. This evidence led the partners to make the decision to drill out the cement plug, set and cement a 5 inch liner 100 feet beneath the Permian target sand.

The Permian target sand was recently flow tested at a rate of 8 MMcf/D on a 21/64 inch choke during a 40 hour flow test and then shut-in for a 10 day build-up using down-hole gauges. The buildup data has determined that the original reservoir pressure within the 9500 foot sand is 3,459 psi. A chromatographic analysis of the gas samples indicated that the majority of the gas was composed of nitrogen (97.5%), with some helium (0.15%), carbon dioxide (0.15%), and the rest hydrocarbons (2.2%). A pressure transient analysis has confirmed that the 9500 foot sand is highly permeable and also identified a movable fluid boundary (oil or water) downdip of the well. When the results are received from the isotope geochemistry analysis of the gas samples, it may give us an understanding as to the whether the source of the gas is organic or inorganic. If it is determined to be an organic source, it would be more likely that the fluid below the gas cap is oil and thus a downdip well may be drilled to determine this. The gas-oil interface is currently being identified through the integration of the pressure transient test data with newly processed inverted seismic data.

If it is determined to not drill the downdip well, three zones in the Jurassic and Cretaceous sections, which are behind the intermediate casing, will subsequently be perforated and flow-tested. Log pay was determined in the both the Dakota and Morrison Formations. Using a 60% water saturation as a cut-off to determine oil productive zones, 23.5 feet of log pay was indicated in the Dakota (from 6,393 to 6,485 feet) and 3.5 feet in the Morrison (from 6,605 to 6,625 feet). The Jurassic Canyon Springs Formation could also be productive. When comparing the Canyon Springs reservoir characteristics in the Bluff well to analog producing fields in the southern Powder River Basin, there are similarities between the two.

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 acquired 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.

The timing of the drilling of this well has not been determined as of yet and some uncertainty exists with respect to Momentus ability to fund the earn-in well.

The two Bakken wells that were drilled in 2011 and 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 and was plugged and abandoned in the prior year

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.

Drilling has been completed on the York #3-9 well located in T156N R82W S3 on the eastern flank of the Williston Basin, within the Pubco Prospect. Stephens Production Company drilled the well to a total depth of 5,100 feet. The top of the Glenburn target zone of the Mississippian Mission Canyon Formation was found as expected at a depth of 4,944 feet measured depth or 4,893 feet true vertical depth. The Glenburn was intersected 50 foot high to the two show wells originally thought to be near an oil-water contact, though the Glenburn was found to be wet, and thus the well was plugged. One can conclude the reasoning for the wet Glenburn zone is that the 4-way structural trap did not completely close on the eastern edge of the trap which coincides with edge of the 3-D seismic survey. The low-fold data along the edges of 3-D seismic surveys are not always reliable and was one of the risks accounted for in the original assessment of the Pubco prospect. Samson’s total cost for its 25% working interest in the York well was approximately $172,000. Since this was the first test of three different Glenburn structural closures mapped along the Devonian Prairie Salt dissolution edge, the remaining two prospects will be highly scrutinized by the Joint Venture to determine if they should still be drilled.

Although there are more prospects to be drilled in this project area, the joint venture partners have no immediate plans to pursue any further exploration at this point in time. Costs of $2.3 million with respect to seismic acquisition costs and acreage costs previously capitalized have been expensed to the Statement of Operations this quarter.

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.

Nine Three Forks Formation wells have now been drilled in the North Stockyard Oilfield. These wells were drilled as 8,000 foot laterals in a west-east orientation. Multistage hydraulic fracturing operations have been completed on the Bootleg 4-14-15TFH, Bootleg 5-14-15TFH, Bootleg 6-14-15TFH, Bootleg 7-14-15TFH and Bootleg 8-14-15TFH wells during the quarter. In January of 2015, the Ironbank 6 & 7 wells were both fracture stimulated.

The Billabong 2-13-14HBK well was successfully worked over and the well is scheduled to be fracture stimulated this month.

Rainbow Project, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson 23% and 52% working interest

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

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

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

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

The first well in this project area, the Gladys 1-20H well (23% working interest), has been drilled and completed. During the quarter the Gladys 1-20H well produced 24,390 barrels of oil (gross). This well is the first in the Rainbow project and is expected to support a drilling program of up to 14 wells, comprised of 8 wells in the middle Bakken and 6 in the Three Forks. Despite having an extensive drilling inventory in this project, Samson has no further drilling planned until there is a sustained recovery in oil prices.

Developed Properties: Production Activities

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson various working interests

We have seventeen 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 shut in for 90 days during the quarter due to downhole problems and production activities on offset wells. Cumulative gross production to December 31, 2014 was approximately 94 Mbbls.

The Leonard #1-23H well (10% working interest, 37.5% after non-consent penalty) was down for 12 days during the quarter due to an electrical malfunction. The well averaged 37 BOPD and 67 Mcf/D during the quarter. Cumulative gross production to December 31, 2014 was approximately 129 Mbbls and 142 MMcf.

The Gene #1-22H well (30.6% working interest) was down for approximately 1 day during the quarter due to an electrical malfunction. The well produced at an average daily rate of 60 BOPD and 108 Mcf/D during the quarter. Cumulative gross production to December 31, 2014 was approximately 182 Mbbls and 222 MMcf.

The Gary #1-24H (37% working interest) well was down for for the entire quarter due to offset production activity. Cumulative gross production to December 31, 2014 was approximately 180 Mbbls and 285 MMcf.

The Rodney #1-14H (27% working interest) well was down for the entire quarter due to planned shut-in periods while completing the offset wells. Cumulative gross production to December 31, 2014 was approximately 139 Mbbls and 195 MMcf.

The Earl #1-13H (32% working interest) well was down for the entire quarter due to planned shut-in periods while completing the offset wells. Cumulative gross production to September 30, 2014 was approximately 225 Mbbls and 327 MMcf.

The Everett #1-15H (26% working interest) well was down for 24 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 366 BOPD and 519 Mcf/D during the quarter. Cumulative gross production to December 31, 2014 was approximately 159 Mbbls and 211 MMcf.

The Sail & Anchor 4-13-14HBK well was down for the entire quarter due to planned shut in periods while completing offset wells. Cumulative gross production to December 31, 2014 was approximately 55 Mbbls and 32 MMcf.

The Coopers 1-23-13HBK well was down for 64 days during the quarter due to planned shut in periods while completing offset wells. The well averaged 78 BOPD during the quarter. Cumulative gross production to December 31, 2014 was 54 Mbbls.

The Little Creature 1- 15-14H well was down for the entire quarter due to planned shut in periods while completing offset wells. Cumulative gross production to December 31, 2014 was 73 Mbbls.

The Tooheys 4-15-14HBK well was down for 58 days during the quarter due to planned shut in periods while completing offset wells. The well averaged 110 BOPD during the quarter. Cumulative gross production to December 31, 2014 was 68 Mbbls

The Blackdog 3-13-14HBK well was down for the entire quarter due to planned shut in periods while completing offset wells. Cumulative gross production to December 31, 2014 was 110 Mbbls and 77 MMcf.

The Matilda Bay 1-15HBK well (32.97% working interest) was down for 29 days during the quarter due to planned shut in periods while completing offset wells. The well averaged 113 BOPD and 83 Mcf/D during the quarter. Cumulative gross production to December 31, 2014 was 110 Mbbls and 7 MMcf.

The Matilda Bay 2-15HBK well (32.97% working interest) was down for 48 days during the quarter due to planned shut in periods while completing offset wells. The well averaged 46 BOPD and 119 Mcf/D during the quarter. Cumulative gross production to December 31, 2014 was 30 Mbbls and 3 MMcf.

The Bootleg 4-14-15TFH well was down for 19 days during the quarter due to Ironbank 6 & 7 operations. During the quarter it averaged 449 BOPD. Cumulative gross production to December 31, 2014 was 55 Mbbls.

The Bootleg 5-14-15TFH well was down for 26 days during the quarter due to Ironbank 6 & 7 operations. During the quarter it averaged 411 BOPD. Cumulative gross production to December 31, 2014 was 48 Mbbls.

The Bootleg 7-14-15TFH well was successfully fracture stimulated during the quarter, however flowback operations have been delayed while offset activities continue on offset wells.

The Bootleg 8-14-15TFH well was successfully fracture stimulated during the quarter, however flowback operations have been delayed while offset activities continue on offset wells.

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 2.7 MMcf/d and 24 BOPD for the quarter. Cumulative production to December 31, 2014 is approximately 7.8 billion standard cubic feet and 84.7 Mbbls.

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 December 31, 2014, we reported a net loss of $2.5 million compared to a net loss of $1.4 million for the 2013 period.

For the six months ended December 31, 2014 we reported a net loss of $13.5 million compared to a net loss of $0.5 million for the 2013 period.

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

	Three months ended
	31-Dec-14		31-Dec-13		30-Sep-14
Production Volume
Oil (Bbls)		43,653		12,788		35,613
Natural gas (Mcf)		39,043		42,990		46,942
BOE (based on one barrel of oil to six Mcf of natural gas)		50,160		19,953		43,437

Sales Price
Realised Oil ($/Bbls)	$	58.14	$	84.62	$	84.33
Impact of settled derivative instruments	$	9.69	$	0.00	$	1.27
Derivative adjusted price	$	67.83	$	84.62	$	85.60

Realised Gas ($/Mcf)	$	3.82	$	4.71	$	5.43

Expense per BOE:
Lease operating expenses	$	24.17	$	22.06	$	24.83
Production and property taxes	$	5.97	$	7.35	$	8.78
Depletion, depreciation and amortization	$	22.30	$	20.94	$	21.99
General and administrative expense	$	25.14	$	84.15	$	27.89

	Six months ended
	31-Dec-14		31-Dec-13
Production Volume
Oil (Bbls)		78,517		25,424
Natural gas (Mcf)		85,588		80,972
BOE		92,782		38,919

Sales Price
Realised Oil ($/Bbls)	$	70.57	$	92.01
Impact of settled derivative instruments	$	5.96	$	0.00
	$	76.53	$	92.01

Gas ($/Mcf)	$	4.72	$	4.26

Expense per BOE:
Lease operating expenses	$	24.69	$	23.67
Production and property taxes	$	7.34	$	7.98
Depletion, depreciation and amortization	$	22.35	$	22.66
General and administrative expense	$	26.64	$	84.33

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

	Three months ended						Three months ended
	31-Dec-14			31-Dec-13			2Q15 to 2Q14 change			30-Sep-14			2Q15 to 1Q15 Change
Oil sales	$	2,538,100		$	1,082,154		$	1,455,946		$	3,003,145		$	(465,045	)
Gas sales		148,953			202,658			(53,705	)		255,050			(106,097	)
Other liquids		-			627			(627	)		-			-
Interest income		9,884			86,853			(76,969	)		9,639			245
Gain on derivative instruments		2,306,135			-			2,306,135			781,570			1,524,565
Gain on sale of oil and gas properties		-			-			-			-			-
Other		6,561			85			6,476			211			6,350

Lease operating expense		(1,512,195	)		(586,926	)		(925,269	)		(1,459,922	)		(52,273	)
Depletion, depreciation and amortization		(1,118,619	)		(417,723	)		(700,896	)		(955,061	)		(163,558	)
Impairment		(3,027,288	)		-			(3,027,288	)		(33,396	)		(2,993,892	)
Abandonment expense		(79,036	)		-			(79,036	)		(135,767	)		56,731
Exploration and evaluation expenditure		(362,540	)		(51,669	)		(310,871	)		(11,103,416	)		10,740,876
Accretion of asset retirement obligations		(8,418	)		(17,117	)		8,699			(7,923	)		(495	)
Interest expense		(147,343	)		-			(147,343	)		(33,160	)		(114,183	)
Amortisation of borrowing costs		(31,972	)		-			(31,972	)		(83,942	)		51,970
General and administrative		(1,260,793	)		(1,679,066	)		418,273			(1,211,279	)		(49,514	)
Income tax benefit		-			-			-			-			-
Net loss	$	(2,538,571	)	$	(1,380,124	)	$	(1,158,447	)	$	(10,974,251	)	$	8,435,680

	Six months ended
	31-Dec-14			31-Dec-13			2Q15 to 2Q14 change
Oil sales	$	5,541,245		$	2,339,144		$	3,202,101
Gas sales		404,003			344,604			59,399
Other liquids		-			627			(627	)
Interest income		19,523			101,298			(81,775	)
Gain on derivative instruments		3,087,705			-			3,087,705
Gain on sale of oil and gas properties		-			2,524,411			(2,524,411	)
Other		6,772			184			6,588
								-
Lease operating expense		(2,972,117	)		(1,231,676	)		(1,740,441	)
Depletion, depreciation and amortization		(2,073,680	)		(881,805	)		(1,191,875	)
Impairment		(3,060,684	)		(83,121	)		(2,977,563	)
Abandonment expense		(214,803	)		-			(214,803	)
Exploration and evaluation expenditure		(11,465,956	)		(319,374	)		(11,146,582	)
Accretion of asset retirement obligations		(16,341	)		(32,813	)		16,472
Interest expense		(231,285	)		-			(231,285	)
Amortisation of borrowing costs		(65,132	)		-			(65,132	)
General and administrative		(2,472,072	)		(3,282,109	)		810,037
Income tax (provision)/ benefit		-			-			-
Net loss	$	(13,512,822	)	$	(520,630	)	$	(12,992,192	)

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

Oil and gas revenues

Oil revenues increased from $1.1 million for the three months ended December 31, 2013 to $2.5 million for the three months ended December 31, 2014, as a result of increased production in our North Stockyard project following the commencement of production from ten new wells in this project area during the period from January 1, 2014 to December 31, 2014. Oil production increased from 12,788 barrels for the three months ended December 31, 2013 to 43,653 for the three months ended December 31, 2014. The realized oil price decreased from $84.62 per Bbl for the three months ended December 31, 2013 to $58.14 per Bbl (excluding the impact of derivatives) for the three months ended December 31, 2014 following a decrease in global oil prices.

Oil revenues increased from $2.3 million for the six months ended December 31, 2013 to $5.5 million for the six months ended December 31, 2014, as a result of increased production in our North Stockyard project following the commencement of production from ten new wells in this project area. Oil production increased from 25,424 barrels for the six months ended December 31, 2013 to 78,517 for the six months ended December 31, 2014. The realized oil price decreased from $92.01 per Bbl for the six months ended December 31, 2013 to $70.57 per Bbl for the six months ended December 31, 2014 following a decrease in global oil prices.

Gas revenues decreased from $0.2 million for the three months ended December 31, 2013 to $0.1 million for the three months ended December 31, 2014. Production decreased from 42,990 Mcf for the quarter ended December 31, 2013 to 39,043 Mcf for the quarter ended December 31, 2014. The realized gas price also decreased slightly from $4.71 per Mcf for the quarter ended December 31, 2013 to $3.82 per Mcf for the quarter ended December 31, 2014 due to a general decrease in the price of natural gas.

Gas revenues increased slightly from $0.3 million for the six months ended December 31, 2013 to $0.4 million for the six months ended December 31, 2014. Production increased slightly from 80,972 Mcf for the six months ended December 31, 2013 to 85,588 Mcf for the six months ended December 31, 2014. The realized gas price also increased from $4.26 per Mcf for the six months ended December 31, 2013 to $4.72 per Mcf for the six months ended December 31, 2014 due to more liquids rich gas coming from our North Stockyard field.

Sale of oil and gas properties

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 was subject to the delivery of a useable well bore in Billabong, valued in the agreement at $0.9 million, which was delivered during the quarter ended June 30, 2014.

There were no such sales during the quarter or six months ended December 31, 2014.

Exploration expense

Exploration expenditures increased from $0.05 million for the quarter ended December 31, 2013, to $0.4 million for the quarter ended December 31, 2014. Expenditure in the current period relates to $0.2 million of previously capitalized exploration acreage written off in relation to lease expirations in our Hawk Springs project area. The remaining funds relate to general exploration expenditure on current and potential exploration projects.

Exploration expenditure for the six months ended December 31, 2014 increased to $11.5 million compared to $0.3 million for the six months ended December 31, 2013. $8.1 million of exploration expenditure relates to previously capitalized exploration costs written off in relation to our Roosevelt project. Part of this project has been farmed out to Momentus Energy and activities are continuing in this area, however given the recent decline in oil prices and the exploratory nature of this project, we believe there is substantial doubt over Momentus’s ability to drill its earn in well. $2.5 million of exploration expenditure relates to previously capitalized exploration costs written off in relation to our South Prairie project. During the six months ended December 31, 2014, the York 3-9 well was drilled in this project area at a cost of $0.2 million to us. The well was a dry hole and will be immediately plugged and abandoned. This was the second dry hole in this project area and no further drilling is planned in the immediate future. $0.3 million was also written off with respect to value of lease expirations in our Hawk Springs project area.

The expenditure in the prior period relates to $0.2 million in dry hole costs in relation to the Matson well in the South Prairie project. This well was a dry hole.

Impairment expense

During the three months and six months ended December 31, 2014 we recognized $3.1 million in impairment expense compared to nil and $0.1 million in the prior comparative periods. $2.8 million relates to our Rainbow field in North Dakota, while the remaining $0.3 million relates to smaller fields in Wyoming. The decrease in the value of these properties is a result of the decrease in the future expected oil price. The production performance of these wells continues to meet expectations. Certain fields, subject to impairment, are carried at fair value at December 31, 2014.

Abandonment expense

Abandonment expense increased from nil in the quarter ended December 31, 2013 to $0.1 million during the quarter ended December 31, 2014. The cost in the current period relate to additional costs associated with abandoning three wells in our Greens Canyon project area in Wyoming. Plugging and abandonment activities commenced in July 2014 and have been completed. These wells were drilled over 10 years ago and were not economic.

Lease operating expense

Lease operating expenses increased from $0.6 million for the quarter ended December 31 2013, to $1.5 million for the quarter ended December 31, 2014. The increase is due to increased production. Costs per BOE increased slightly from $22.06 for the quarter ended December 31, 2013 to $24.17 for the quarter ended December 31, 2014, excluding production taxes.

Lease operating expenses increased from $1.2 million for the six months ended December 31 2013, to $3.0 million for the six months ended December 31, 2014. The increase is due to increased production. Costs per BOE increased slightly from $23.67 for the six months ended December 31, 2013 to $24.69 for the six months ended December 31, 2014.

Depletion, depreciation and amortization expense

Depletion, depreciation and amortization expense increased from $0.4 million for the quarter ended December 31, 2013 to $1.1 million for the quarter ended December 31, 2014. The increase in depletion is primarily a result of the increase in the production. The per BOE cost increased slightly from $20.94 for the three months ended December 31, 2013 to $22.30 for the three months ended December 31, 2014.

Depletion, depreciation and amortization expense increased from $0.9 million for the six months ended December 31, 2013 to $2.1 million for the six months ended December 31, 2014. The increase in depletion is primarily a result of the increase in the production. The per BOE cost remained consistent at $22.66 for the six months ended December 31, 2013 to $22.35 for the six months ended December 31, 2014.

General and administrative expense

General and administrative expense decreased from $1.7 million for the quarter ended December 31, 2013 to $1.3 million for the three months ended December 31, 2014. We have been actively trying to reduce our general and administrative costs in recent periods. A change in the use of professional service providers has contributed to the decrease in the general and administrative costs from the prior period.

General and administrative expense decreased from $3.3 million for the six months ended December 31, 2013 to $2.5 million for the six months ended December 31, 2014. We have been actively trying to reduce our general and administrative costs in recent periods. A change in the use of professional service providers has contributed to the decrease in the general and administrative costs from the prior period.

Cash Flows

The table below shows cash flows for the following periods:

	Six months ended
	31-Dec-14			31-Dec-13
Cash provided by/(used in) operating activities	$	801,806		$	(1,600,564	)
Cash used in investing activities		(12,733,743	)		(11,862,746	)
Cash provided by financing activities		9,199,273			6,776,246

Cash provided by/(used in) operations changed from an outflow of $1.6 million for the six months ended December 30, 2013, to a net inflow of $0.8 million for the six months ended December 31, 2014. Cash receipts from customers increased from $2.5 million for six months ended December 31, 2013 to $7.0 million for the six months ended December 31, 2014, due to an increase in production. Payments to suppliers and employees also includes $1.0 million in payments made for abandonment operations during the six months ended December 31, 2014 which were not incurred in prior periods.

Cash used in investing activities increased from $11.9 million for the six months ended December 31, 2013 to $12.7 million of cash used for the six months ended December 31, 2014. The cash outflow for both periods relates to ongoing drilling activities in our North Stockyard project in North Dakota and exploration expenditure drilling our Bluff well in the Hawk Springs project.

Cash provided by financing activities increased from a cash inflow of $6.8 million for the six months ended December 31, 2013, to a cash inflow of $9.2 million for the six months ended December 31, 2014. Cash inflow for the prior period was a result of the issue of 318,452,166 ordinary shares to raise $7.3 million before expenses. Cash inflow in the current period is a result of the drawdown of borrowings from our credit facility with Mutual of Omaha.

All options outstanding as at December 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 2015 as well.

Our current budget for exploration, exploitation and development capital expenditures in fiscal 2015 is $18.4 million, of which we incurred approximately $11.8 million during the first six 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 prior registered direct offerings, our sale of development acreage to Slawson and drawdowns from our credit facility with Mutual of Omaha Bank. The remaining $6.6 million in planned capital expenditures, relates to the drilling and completion of 2 additional wells in our North Stockyard infill project and the payment for the Gladys well in our Rainbow project, also in North Dakota. Due to the decrease in oil price, we do not have any additional development drilling planned for the immediate future. We are also continuing to perform analysis work on our Bluff well in our Hawk Springs project.

In January 2014, we entered into a $25 million credit facility with Mutual of Omaha Bank. We drew down the remaining $4.5 million in borrowing base in October 2014. 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.

In November 2014, we entered into the First Amendment to the Company’s Credit Agreement with Mutual of Omaha Bank to increase the borrowing base of the reserve based lending facility to $19 million, increase the maximum available under the facility to $50 million and decrease the interest rate.

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

The credit facility also includes an annual cap on general and administrative expenditures of $6,000,000 commencing the twelve months ended December 31, 2014.

For the quarter ended December 31, 2014 we were in breach of our Debt to EBITDAX covenant. Mutual of Omaha have given us a waiver with respect to this breach for the current period only. We were in compliance with all other covenants.

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 2015 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, 2015, 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 six months ended December 31, 2014 have been cash on hand, which was $3.8 million at December 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) equity issued to raise $21.4 million and (ii) our tax refund of $5.6 million from the Internal Revenue Service, received in February 2013. During the recent years prior to the fiscal year ended June 30, 2012, our primary sources of liquidity were the sale of acreage and other oil and gas assets.

Our cash position as of December 31, 2014 decreased from December 31, 2013 largely due to payments for drilling and fracturing activities 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, 2014 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 completion of our remaining two development wells in one of our Bakken projects - the North Stockyard 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 six months ended December 31, 2014 to the disclosure made in our Annual Report on Form 10-K for the year ended June 30, 2014 regarding this matter.

Item 4. Controls and Procedures.

As of December 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 December 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 additional changes in our internal control over financial reporting that occurred during the three months ended December 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.

Halliburton Dispute

Halliburton Energy Services, Inc., a co-participant in the Company’s Hawk Springs project, has filed a complaint in Harris County, Texas District Court against Samson USA seeking unpaid oil revenue attributable to its ownership interest in the Hawk Springs Project, which was approximately $126,000 as of June 5, 2013, and has since increased to approximately $164,000. Samson USA has answered the complaint and has filed counterclaims against Halliburton arising out of Samson USA’s engagement of Halliburton’s Project Management group in May of 2011 to provide services in connection with its drilling program in Roosevelt County, Montana. In its counterclaims, Samson USA claims approximately $336,000 from Halliburton on account of Halliburton’s refusal to pay an invoice for demobilization of the drilling rig used in the Roosevelt project. Samson USA has also asked for a judicial accounting with respect to Halliburton’s fees and expenses charged to Samson in connection with the Spirit of America well in Goshen County, Wyoming, and the Australia II, well in Roosevelt County, Wyoming, because of Samson’s discovery of self-dealing and bill padding by Halliburton’s onsite project manager there. Halliburton has not yet filed an answer to Samson’s counterclaims but the parties are commencing discovery efforts in the lawsuit. While Samson believes that its counterclaims are meritorious and is confident that Samson will obtain a net positive recovery from the lawsuit, there can be no assurance as to the ultimate outcome of this litigation.

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, 2014. 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

10.1		First Amendment to the Term Loan Credit Agreement among Samson Oil and Gas USA, Inc. as a borrower, Samson Oil & Gas Limited and Samson Oil and Gas Montana, Inc. as guarantors and Mutual of Omaha Bank as lender and administrative agent.

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 December 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: February 9, 2015	By:	/s/ Terry Barr
		Terence M. Barr
		Managing Director, President and Chief Executive Officer (Principal Executive Officer)

Date: February 9, 2015	By:	/s/ Robyn Lamont
		Robyn Lamont
		Chief Financial Officer (Principal Financial Officer)

Exhibit 10.1

FIRST AMENDMENT TO CREDIT AGREEMENT

THIS FIRST AMENDMENT TO CREDIT AGREEMENT (the “First Amendment to Credit Agreement,” or this “Amendment” ) is entered into effective as of November 24, 2014, among SAMSON OIL AND GAS USA, INC. , a Colorado corporation ( “Borrower” ), and MUTUAL OF OMAHA BANK , as Administrative Agent and L/C Issuer (the “Administrative Agent” ), and the financial institutions executing this Amendment as Lenders.

RECITALS

A. Borrower, the financial institutions signing as Lenders and Administrative Agent are parties to a Credit Agreement dated as of January 27, 2014 (the “Original Credit Agreement” ).

B. The parties desire to amend the Original Credit Agreement as hereinafter provided.

NOW, THEREFORE, in consideration of these premises and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

1. Same Terms . All terms used herein which are defined in the Original Credit Agreement shall have the same meanings when used herein, unless the context hereof otherwise requires or provides. In addition, (i) all references in the Loan Documents to the “Agreement” shall mean the Original Credit Agreement, as amended by this Amendment, as the same shall hereafter be amended from time to time, and (ii) all references in the Loan Documents to the “Loan Documents” shall mean the Loan Documents, as amended by this Amendment, the Modification Papers, as the same shall hereafter be amended from time to time. In addition, the following terms have the meanings set forth below:

“Effective Date” means the date when (a) those Lenders comprising the Required Lenders have executed this Amendment, and (b) the conditions set forth in Section 2 of this Amendment have been complied with to the satisfaction of the Administrative Agent, unless waived in writing by the Administrative Agent.

“Authorization Certificate” : See Section 2E .

“First Amendment to Mortgage” : See Section 2B .

“Guarantor Confirmation Letter” : See Section 2C .

“Modification Papers” means this Amendment, the First Amendments to Mortgage, the Guarantor Confirmation Letters, the Security Agreement Confirmation Letter, the Authorization Certificates, the No Material Adverse Change Certificate, and all of the other documents and agreements executed in connection with the transactions contemplated by this Amendment.

“No Material Adverse Change Certificate” : See Section 2F .

“Security Agreement Confirmation Letter” : See Section 2D .

2. Conditions Precedent . The obligations, agreements and waivers of Lenders as set forth in this Amendment are subject to the satisfaction (in the opinion of Administrative Agent), unless waived in writing by Administrative Agent, of each of the following conditions (and upon such satisfaction, this Amendment shall be deemed to be effective as of the Effective Date):

FIRST AMENDMENT TO CREDIT AGREEMENT – Page 1

A. First Amendment to Credit Agreement . This Amendment shall be in full force and effect.

B. First Amendment to Mortgage . Borrower shall have executed and delivered to Administrative Agent an amendment to the Oil and Gas Mortgages (each a “First Amendment to Mortgage” ), which shall be in form and substance satisfactory to Administrative Agent.

C. Guarantor Confirmation Letters . Each Guarantor shall have executed a letter in favor of Administrative Agent (each a “Guarantor Confirmation Letter” ) confirming that its Guaranty remains in full force and effect.

D. Security Agreement Confirmation Letter . Borrower shall have executed a letter in favor of Administrative Agent (the “Security Agreement Confirmation Letter” ) confirming that the Security Agreement continues to secure all of the Obligations.

E. Authorization Certificate . Borrower shall have delivered certificate appropriate Loan Parties (each an “Authorization Certificate” ) satisfactory in form and substance to Administrative Agent authorizing the execution, delivery and performance of the Modification Papers to which it is a party.

F. Representations and Warranties . Administrative Agent shall have received a certificate (the “No Material Adverse Change Certificate” ) to the effect that all representations and warranties contained herein or in the other Modification Papers or otherwise made in writing in connection herewith or therewith shall be true and correct in all material respects (provided that any such representations or warranties that are, by their terms, already qualified by reference to materiality shall be true and correct without regard to such materiality standard) with the same force and effect as though such representations and warranties have been made on and as of the Effective Date, or if made as of a specific date, as of such date.

G. Opinion of Counsel . There shall have been delivered a favorable opinion of counsel of Borrower and each other Loan Party covering such matters incident to the Modification Papers as Administrative Agent may reasonably request.

H. Borrowing Base Increase Fee . Administrative Agent shall have received payment of a fee for the increase of the Borrowing Base described below in the amount of $35,000.

I. Mortgage and Title Coverage . (i) Borrower shall have mortgaged to Administrative Agent such additional oil and gas properties so as to comply with the 80% mortgage coverage requirements required by Section 2.13(a) of the Original Credit Agreement, and (ii) Borrower shall have provided Administrative Agent with title data acceptable to Administrative Agent so as to comply with the 80% title coverage requirements of Section 2.13(b) of the Original Credit Agreement.

J. Fees and Expenses . Administrative Agent shall have received payment of all out-of-pocket fees and expenses (including reasonable attorneys’ fees and expenses) incurred by Administrative Agent in connection with the preparation, negotiation and execution of the Modification Papers.

FIRST AMENDMENT TO CREDIT AGREEMENT – Page 2

3. Amendments to Original Credit Agreement . On the Effective Date, the Original Credit Agreement shall be deemed to be amended as follows:

(a) Clause (b) of the definition of “Applicable Rate” in Section 1.01 of the Original Credit Agreement shall be amended to read in its entirety as follows:

“(b) with respect to Eurodollar Rate Loans and Letters of Credit, 3.25%; and”

(b) Section 8.07 of the Original Credit Agreement shall be amended to read in its entirety as follows:

“ 8.07. Limitation on General and Administrative Expenses . Permit Borrower’s general and administrative expenses for the operation of all of its oil and gas properties (either direct or payable to outside operators or agents) as determined in accordance with COPAS accounting procedures, and all salaries, bonuses, withdrawals, distributions, consulting and professional fees other than expenses of Borrower’s exploratory staff and other forms of compensation, and all other overhead, to exceed $6,000,000 per calendar year beginning with the twelve months ended December 31, 2014 (for avoidance of doubt, expenses of Borrower’s exploratory staff are not subject to this covenant) .”

(c) Schedule 2.01 attached to the original Credit Agreement is hereby replaced with Schedule 2.01 attached to this Amendment.

4. Increase of Borrowing Base . On the Effective Date, the Borrowing Base is hereby increased from $15,500,000 to $19,000,000. The Borrowing Base, as adjusted, will remain in effect until next adjusted but pursuant to the provisions of Article IV of the Original Credit Agreement.

5. Certain Representations . Borrower represents and warrants that, as of the Effective Date: (a) each Loan Party has full power and authority to execute the Modification Papers to which it is a party and such Modification Papers constitute the legal, valid and binding obligation of such Loan Party enforceable in accordance with their terms, except as enforceability may be limited by general principles of equity and applicable bankruptcy, insolvency, reorganization, moratorium, and other similar laws affecting the enforcement of creditors’ rights generally; and (b) no authorization, approval, consent or other action by, notice to, or filing with, any governmental authority or other person is required for the execution, delivery and performance by each Loan Party thereof. In addition, Borrower represents that after giving effect to this Amendment all representations and warranties contained in the Original Credit Agreement and the other Loan Documents are true and correct in all material respects (provided that any such representations or warranties that are, by their terms, are requalified by reference to materiality shall be true and correct without regard to such materialty standard) on and as of the Effective Date as if made on and as of such date except to the extent that any such representation or warranty expressly relates solely to an earlier date, in which case such representation or warranty is true and correct in all material respects (or true and correct without regard to such materiality standard, as applicable) as of such earlier date.

6. No Further Amendments . Except as previously amended in writing or as amended hereby, the Original Credit Agreement shall remain unchanged and all provisions shall remain fully effective between the parties.

FIRST AMENDMENT TO CREDIT AGREEMENT – Page 3

7. Acknowledgments and Agreements . Borrower acknowledges that on the date hereof all outstanding Obligations are payable in accordance with their terms, and Borrower waives any defense, offset, counterclaim or recoupment with respect thereto. Borrower, Administrative Agent , L/C Issuer and each Lender do hereby adopt, ratify and confirm the Original Credit Agreement, as amended hereby, and acknowledge and agree that the Original Credit Agreement, as amended hereby, is and remains in full force and effect. Borrower acknowledges and agrees that its liabilities and obligations under the Original Credit Agreement, as amended hereby, and under the other Loan Documents, are not impaired in any respect by this Amendment. Any breach of any representations, warranties and covenants under this Amendment shall be Default or an Event of Default, as applicable, under the Original Credit Agreement.

8. Limitation on Agreements . The modifications set forth herein are limited precisely as written and shall not be deemed (a) to be a consent under or a waiver of or an amendment to any other term or condition in the Original Credit Agreement or any of the Loan Documents, or (b) to prejudice any right or rights that Administrative Agent now has or may have in the future under or in connection with the Original Credit Agreement and the other Loan Documents, each as amended hereby, or any of the other documents referred to herein or therein. The Modification Papers shall constitute Loan Documents for all purposes.

9. Confirmation of Security . Borrower hereby confirms and agrees that all of the Collateral Documents that presently secure the Obligations shall continue to secure, in the same manner and to the same extent provided therein, the payment and performance of the Obligations as described in the Original Credit Agreement as modified by this Amendment.

10. Counterparts . This Amendment may be executed in any number of counterparts, each of which when executed and delivered shall be deemed an original, but all of which constitute one instrument. In making proof of this Amendment, it shall not be necessary to produce or account for more than one counterpart thereof signed by each of the parties hereto.

11. Incorporation of Certain Provisions by Reference . The provisions of Section 11.15 of the Original Credit Agreement captioned “Governing Law, Jurisdiction; Etc.” and Section 11.16 of the Original Credit Agreement captioned “Waiver of Right to Trial by Jury” are incorporated herein by reference for all purposes.

12. Entirety, Etc . This Amendment and the other Modification Papers and all of the other Loan Documents embody the entire agreement between the parties. THIS AMENDMENT AND ALL OF THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES.

[This space is left intentionally blank. Signature pages follow.]

FIRST AMENDMENT TO CREDIT AGREEMENT – Page 4

IN WITNESS WHEREOF, the parties hereto have executed this Amendment to be effective as of the date and year first above written.

	BORROWER

	SAMSON OIL AND GAS USA, INC.

	By:	/s/ Terry Barr
		Terry Barr
		President, Treasurer and CEO

FIRST AMENDMENT TO CREDIT AGREEMENT – Signature Page

	ADMINISTRATIVE AGENT

	MUTUAL OF OMAHA BANK, as Administrative Agent

	By:	/s/ Edward M. Fenk
		Edward M. Fenk
		Manager, Energy Lending

	LENDER

	MUTUAL OF OMAHA BANK

	By:	/s/ Edward M. Fenk
		Edward M. Fenk
		Manager, Energy Lending

FIRST AMENDMENT TO CREDIT AGREEMENT – Signature Page

SCHEDULE 2.01

APPLICABLE PERCENTAGES, MAXIMUM CREDIT AMOUNTS,

and ALLOCATIONS OF INITIAL BORROWING BASE

	Applicable			Maximum Credit		Allocation of
Lender	Percentage			Amount		Borrowing Base

Mutual of Omaha Bank		100.000000000	%	$	50,000,000	$	19,000,000

Total		100.000000000	%	$	50,000,000	$	19,000,000

SCHEDULE 2.01 – Solo Page

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Terence M. Barr, certify that:

I have reviewed this Quarterly Report on Form 10-Q of Samson Oil & Gas Limited;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

The company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

The company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

/s/ Terry Barr
Terence M. Barr
Managing Director, President and Chief Executive Officer
February 9, 2015

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Robyn Lamont, certify that:

I have reviewed this Quarterly Report on Form 10-Q of Samson Oil & Gas Limited;

(a)

(b)

(c)

(d)

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

/s/ Robyn Lamont
Robyn Lamont
Chief Financial Officer
February 9, 2015

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), the undersigned officers of Samson Oil & Gas Limited (the “Company”), do hereby certify, to such officer’s knowledge, that:

(1) The Quarterly Report on Form 10-Q for the quarter ended December 31, 2014 (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Terry Barr
Terence M. Barr
President, Chief Executive Officer and Managing Director
February 9, 2015

/s/ Robyn Lamont
Robyn Lamont
Chief Financial Officer
February 9, 2015