Quarterly Report (10-q)

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, 2015

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 ¨

Non-accelerated filer	¨	Smaller reporting company x

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 2,837,834,301 ordinary shares outstanding as of February 15, 2016.

SAMSON OIL & GAS LIMITED

FORM 10-Q

QUARTER ENDED December 31, 2015

TABLE OF CONTENTS

		Page

Part I — Financial Information		4

Item 1.	Financial Statements (unaudited)	4

	Consolidated Balance Sheets, December 31, 2015 and June 30, 2015	4

	Consolidated Statement of Operations and Comprehensive Income (Loss) for the three months ended December 31, 2015 and 2014 and six months ended December 31, 2015 and 2014	5

	Consolidated Statement of Changes in Stockholders’ Equity (Deficit) for the six months ended December 31, 2015	6

	Consolidated Statement of Cash Flows for the six months ended December 31, 2015 and 2014	7

	Notes to Consolidated Financial Statements (unaudited)	8

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	24

Item 4.	Controls and Procedures	24

Part II — Other Information		24

Item 1.	Legal Proceedings	24

Item 1A.	Risk Factors	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, debt levels and anticipated liquidity;

•

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

•

uncertainties in the estimation of proved reserves and in the projection of future rates of production;

•

timing, amount, and marketability of production;

•

third party operational curtailment, processing plant or pipeline capacity constraints beyond our control;

•

our ability to acquire and dispose of oil and gas properties at favorable prices;

•

our ability to market, develop and produce new properties;

•

declines in the values of our properties that may result in write-downs;

•

effectiveness of management strategies and decisions;

•

oil and natural gas prices and demand;

•

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

•

the strength and financial resources of our competitors;

•

our entrance into transactions in commodity derivative instruments;

•

climatic conditions; and

•

effectiveness of management strategies and decisions.

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-15			30-Jun-15
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	943,289		$	2,062,720
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively		1,714,094			3,645,223
Prepayments		684,830			372,079
Fair value of derivative instrument		723,370			159,216
Total current assets		4,065,583			6,239,238
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment of $56,894,155 and $44,273,976 at December 31,2015 and June 30, 2015, respectively		17,360,238			29,715,540

Other property and equipment, net of accumulated depreciation and amortization of $553,012 and $553,428 at December 31, 2015 and June 30, 2015, respectively		145,824			248,521

Net property, plant and equipment		17,506,062			29,964,061
OTHER NON CURRENT ASSETS
Fair value of derivative instrument		-			101,269
Undeveloped capitalized acreage		-			2,491,422
Capitalized exploration expense		202,573			1,388,798
Other		214,624			342,069
TOTAL ASSETS	$	21,988,842		$	40,526,857

LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY
CURRENT LIABILITIES
Accounts payable	$	952,185		$	1,678,915
Accruals		245,465			1,999,344
Credit facility		19,000,000			-
Provision for annual leave		194,019			219,414
Total current liabilities		20,391,669			3,897,673
NON CURRENT LIABILITIES
Asset retirement obligations		1,794,356			1,263,674
Credit facility		-			18,699,000
TOTAL LIABILITIES		22,186,025			23,860,347
STOCKHOLDERS’ (DEFICIT) EQUITY – nil par value
2,837,834,301 (equivalent to 14,189,172 ADR’s) and 2,837,782,022 (equivalent to 14,188,910 ADR’s) ordinary shares issued and outstanding at December 31, 2015 and June 30, 2015, respectively		104,493,249			104,491,774
Accumulated other comprehensive income		932,095			996,256
Accumulated deficit		(105,622,527	)		(88,821,520	)
Total stockholders’ (deficit) equity		(197,183	)		16,666,510
TOTAL LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY	$	21,988,842		$	40,526,857

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-15			31-Dec-14			31-Dec-15			31-Dec-14
REVENUES AND OTHER INCOME:
Oil sales	$	1,898,240		$	2,538,100		$	4,320,823		$	5,541,245
Gas sales		210,212			148,953			426,959			404,003
Other liquids		27,201			-			28,547			-
Interest income		667			9,884			2,202			19,523
Gain on derivative instruments		200,017			2,306,135			572,569			3,087,705
Other		265			6,561			17,902			6,772
TOTAL REVENUE AND OTHER INCOME		2,336,602			5,009,633			5,369,002			9,059,248

EXPENSES:
Lease operating expense		(1,102,441	)		(1,512,195	)		(2,831,170	)		(2,972,117	)
Depletion, depreciation and amortization		(1,399,511	)		(1,118,619	)		(2,883,243	)		(2,073,680	)
Impairment expense		(9,682,965	)		(3,027,288	)		(9,802,987	)		(3,060,684	)
Abandonment expense		-			(79,036	)		-			(214,803	)
Exploration and evaluation expenditure		(3,699,651	)		(362,540	)		(4,192,719	)		(11,465,956	)
Accretion of asset retirement obligations		(15,116	)		(8,418	)		(30,004	)		(16,341	)
Amortization of borrowing costs		(35,486	)		(31,972	)		(70,972	)		(65,132	)
Interest expense		(196,357	)		(147,343	)		(386,396	)		(231,285	)
General and administrative		(911,925	)		(1,260,793	)		(1,972,518	)		(2,472,072	)
TOTAL EXPENSES		(17,043,452	)		(7,548,204	)		(22,170,009	)		(22,572,070	)

Loss from operations		(14,706,850	)		(2,538,571	)		(16,801,007	)		(13,512,822	)
Income tax benefit		-			-			-			-
Net loss		(14,706,850	)		(2,538,571	)		(16,801,007	)		(13,512,822	)
OTHER COMPREHENSIVE GAIN (LOSS)
Foreign currency translation gain/(loss)		6,623			(97,689	)		(64,161	)		(226,399	)
Total comprehensive loss for the period	$	(14,700,227	)	$	(2,636,260	)	$	(16,865,168	)	$	(13,739,221	)

Net loss per ordinary share from operations:
Basic – cents per share		(0.52	)		(0.09	)		(0.59	)		(0.48	)
Diluted – cents per share		(0.52	)		(0.09	)		(0.59	)		(0.48	)

Weighted average ordinary shares outstanding:
Basic		2,837,834,301			2,837,781,683			2,837,828,903			2,837,772,648
Diluted		2,837,834,301			2,837,781,683			2,837,828,903			2,837,772,648

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			Deficit
Balance at June 30, 2015	$	104,491,774	$	(88,821,520	)	$	996,256		$	16,666,510
Net loss		-		(16,801,007	)		-			(16,801,007	)
Foreign currency translation loss, net of tax of $nil		-		-			(64,161	)		(64,161	)
Total comprehensive loss for the period		-		(16,801,007	)		(64,161	)		(16,865,168	)
Exercise of options		1,475		-			-			1,475
Balance at December 31, 2015	$	104,493,249	$	(105,622,527	)	$	932,095		$	(197,183	)

See accompanying Notes to Consolidated Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six months ended
	31-Dec-15			31-Dec-14
Cash flows (used in)/provided by operating activities
Receipts from customers	$	6,543,082		$	7,010,394
Payments to suppliers & employees		(5,738,781	)		(6,349,789	)
Interest received		2,188			19,499
Interest paid		(398,837	)		(172,917	)
Proceeds from/(Payments for)derivative instruments		109,684			228,837
State income taxes paid		-			(107,135	)
Net cash flows provided by operating activities		517,336			628,889
Cash flows used in investing activities
Payments for plant & equipment		-			(21,427	)
Payments for exploration and evaluation		(314,639	)		(1,399,142	)
Payments for oil and gas properties		(1,558,976	)		(11,313,174	)
Net cash flows used in investing activities		(1,873,615	)		(12,733,743	)
Cash flows provided by financing activities
Proceeds from the exercise of options		1,475			880
Proceeds from borrowings		301,000			9,500,000
Borrowing costs		-			(83,690	)
Share issuance costs		-			(45,000	)
Net cash flows (used in)/provided by financing activities		302,475			9,372,190
Net increase/(decrease) in cash and cash equivalents		(1,053,804	)		(2,732,664	)
Cash and cash equivalents at the beginning of the fiscal period		2,062,720			6,846,394
Effects of exchange rate changes on cash and cash equivalents		(65,627	)		(232,592	)
Cash and cash equivalents at end of fiscal period	$	943,289		$	3,881,138

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, 2015. 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, 2015 and June 30, 2015 consist primarily of estimates for goods and services received but not yet invoiced.

Prepayments. Prepayments at December 31, 2015 consist primarily of a $0.5 million deposit paid in connection with a purchase and sale agreement that we entered into on December 31, 2015. This deposit is only refundable if certain conditions with respect to title or environmental defects are identified and the transaction does not close as proposed. Refer to the discussions below under “Credit Facility” and “Subsequent Events” for additional discussion of this agreement. Other prepayments include insurance premiums paid in advance for the year.

Prepayments at June 30, 2015 consists primarily of cash advanced to the operators of our South Prairie exploration project for a future exploration well and insurance premiums paid in advance for the year. The exploration well was drilled in October 2015 and was a dry hole. Costs were expensed as incurred.

Recent Accounting Standards

There are no new accounting pronouncements that have not been adopted by the Company as of December 31, 2015 that will have a material effect on the Company’s financial statements.

2. Income Taxes

The Company has cumulative net operating losses (“NOLs”) 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.

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 transferable options to purchase ordinary shares which are tradeable on the ASX (“options”), for the periods presented:

	Three months ended				Six months ended
	31-Dec-15		31-Dec-14		31-Dec-15		31-Dec-14
Dilutive		-		-		-		-
Anti–dilutive		324,615,486		389,168,104		323,287,581		389,177,139

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

	Three months ended						Six months ended
	31-Dec-15			31-Dec-14			31-Dec-15			31-Dec-14
Net income (loss)	$	(14,706,850	)		(2,538,571	)	$	(16,801,007	)		(13,512,822	)

Basic weighted average ordinary shares outstanding		2,837,834,301			2,837,781,683			2,837,828,903			2,837,772,648
Basic earnings per ordinary share – cents per share		(0.52	)		(0.09	)		(0.59	)		(0.48	)
Diluted earnings per ordinary share – cents per share		(0.52	)		(0.09	)		(0.59	)		(0.48	)

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 liabilities settled in the quarter ended December 31, 2015 relates to the plugging of one well in our North Stockyard property, the Harstad. This well’s performance was sub-optimal and experienced high levels of hydrogen sulphide.

The following table summarizes the activities for the Company’s asset retirement obligations for the three months ended December 31, 2015 and 2014:

	Six months ended
	31-Dec-15			31-Dec-14
Asset retirement obligations at beginning of period	$	1,810,674		$	1,775,792
Liabilities incurred or acquired		-			42,805
Liabilities settled		(46,322	)		(710,561	)
Disposition of properties		-			-
Accretion expense		30,004			16,341
Asset retirement obligations at end of period		1,794,356			1,124,377
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)		-			-
Long-term asset retirement obligations	$	1,794,356		$	1,124,377

5. 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, 2015 and June 30, 2015.

	Carrying value at December 31, 2015		Level 1		Level 2		Level 3		Netting ⁽¹⁾			Fair Value at December 31, 2015
Current Assets:
Cash and cash equivalents	$	943,289	$	943,289	$	-	$	-	$	-		$	943,289
Derivative Instruments		723,370		-		2,030,217		-		(1,306,847	)		723,370

Non Current Assets
Derivative Instruments		-		-		-				-			-

Current Liabilities
Derivative instruments		-		-		1,306,847		-		(1,306,847	)		-

Non Current Liabilities
Derivative Instruments		-		-		-				-			-

	Carrying value at June 30, 2015		Level 1		Level 2		Level 3		Netting ⁽¹⁾			Fair Value at June 30, 2015
Current Assets:
Cash and cash equivalents	$	2,062,720	$	2,062,720	$	-	$	-	$	-		$	2,062,720
Derivative Instruments		159,216		-		379,540		-		(220,324	)		159,216

Non Current Assets
Derivative Instruments		101,269		-		298,703		-		(197,434	)		101,269

Current Liabilities
Derivative instruments		-		-		220,324		-		(220,324	)		-

Non Current Liabilities
Derivative Instruments		-		-		197,434		-		(197,434	)		-

(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, 2015. 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 $9.6 million relating to our North Stockyard field due to the continued decrease in the oil price.

6. 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

In 2013, Halliburton Energy Services, Inc., a co-participant in the Company’s Hawk Springs project, 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. The unpaid oil revenue was approximately $126,000 at that time, and has since increased to approximately $170,000. Samson USA answered the complaint, including counterclaims against Halliburton arising out of Samson USA’s engagement of Halliburton’s Project Management group in May of 2011 in connection with its drilling program in Roosevelt County, Montana. In those counterclaims, Samson USA claimed 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 also counterclaimed for a judicial accounting of the fees and expenses Halliburton charged to Samson in connection with the Spirit of America well in Goshen County, Wyoming, and the Australia II well in Roosevelt County, Wyoming, in light of Samson USA’s prior discovery of self-dealing and bill padding by Halliburton’s onsite project manager. In September 2015, Samson filed an amended counterclaim in which it has alleged that (i) Halliburton selected a rig that was inappropriate for the geology where the Spirit of America 1 well was located, and (ii) the project supervisor assigned by Halliburton to oversee the construction and drilling of the Spirit of America 1 well was unqualified and lacked the credentials and experience to perform the duties required of a project manager. Samson has alleged that Halliburton’s failure in this regard caused Halliburton to be unable to reach the target reservoir and, in the process, caused Samson to incur $4,505,587 in costs that could have been avoided if a proper rig and qualified project supervisor had been selected and used on the project. The parties have attended one mediation session with a court appointed mediator, however this failed to reach an agreement. Another mediation is scheduled to be held on March 10, 2016.

While Samson believes its counterclaims are meritorious and is confident that Samson USA will obtain a net positive recovery from the litigation, there can be no assurance as to the ultimate outcome.

7. 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, 2015 we had capitalized exploration expenditures of $0.2 million. This amount primarily relates to costs incurred in connection with our Cane Creek project in Utah.

During the six months ended December 31, 2015 we have written off $4.1 million in capitalized exploration expenditure, of which $1.3 million related to our Bluff well in our Hawk Springs project. This well has been shut in to observe pressure build up in the well bore. We have not yet determined our final course of action with respect to this well bore, however given the current oil price environment its unlikely that we will commit any further funds to this well in the near term, therefore all costs capitalized associated with this well have been written off. We also wrote off $2.4 million in previously capitalized expenditure in relation to leasehold costs for our Hawk Springs project. In past periods we had written off this leasehold costs as the associated acreage expired. Following the continued deterioration in the oil price, we are not currently committing any funds to further exploration on this leasehold and thus the decision was made to expense all previously capitalized expenditures. The remaining $0.4 million in costs written off relates to costs capitalized with respect to activities on our Spirit of America 1 and Spirit of America 11 wells in our Hawk Springs project in Goshen County, Wyoming. Work performed on these wells failed to demonstrate that hydrocarbons existed in economic quantities.

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.

8. Share Capital

Issue of Share Capital

During the six months ended December 31, 2015, 52,279 options with an exercise price of 3.8 cents (Australian) per ordinary share were exercised for net proceeds of $1,475.

During the six months ended December 31, 2014 24,025 options with an exercise price of 3.8 cents (Australian) per ordinary share were exercised for net proceeds of $880.

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

9. Cash Flow Statement

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

	Six months ended
	31-Dec-15			31-Dec-14

Net loss after tax	$	(16,801,007	)	$	(13,512,822	)
Depletion, depreciation and amortization		2,883,243			2,073,680
Accretion of asset retirement obligation		30,004			16,341
Impairment expense		9,802,987			3,060,684
Exploration and evaluation expenditure		4,192,719			11,465,956
Amortization borrowing costs		70,972			65,132
Abandonment expense		-			214,803
Non cash (gain)/loss on derivative instruments		(462,885	)		(2,619,664	)

Changes in assets and liabilities:

Decrease in receivables		1,931,129			2,132,371
Increase/(decrease) in provision for annual leave		(25,395	)		(19,082	)
(Decrease)/Increase in payables		(1,104,431	)		(2,248,510	)
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	517,336		$	628,889

10. Credit Facility

	Six months ended
	31-Dec-15		31-Dec-14
Credit facility at beginning of period	$	18,699,000	$	6,000,000
Cash advanced under facility	$	301,000		9,500,000
Repayments		-		-
Credit facility at end of period ⁽¹⁾	$	19,000,000	$	15,500,000
				-
Funds available for drawdown under the facility	$	-		3,500,000

(1)

In January 2014, we entered into a $25.0 million credit facility with our primary lender, 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 which was fully drawn down as of December 31, 2015. As a result, unless the borrowing base is increased or we pay down outstanding borrowings, we are unable to borrow additional amounts under this facility.

Our primary lender is currently assessing our borrowing base in conjunction with the pending acquisition of certain assets including proved reserves in Montana and North Dakota, as announced in a Form 8-K filed on January 7, 2016. The acquisition was due to close on February 15^th, but the continuing volatility in petroleum markets has prevented us from concluding arrangements for financing of the acquired assets with our primary lender. While we remain optimistic that we will obtain the necessary financing and close the acquisition, our failure to meet the February 15th deadline entitles the seller to terminate the purchase agreement at any time. We currently expect that the necessary financing will be obtained on or before February 29th, 2016, and that the seller will close the sale on that date. There can be no assurance, however, that the seller will not exercise its right to terminate before we obtain the funds needed and close the transaction. Our primary lender has indicated that it is considering providing the funds needed to close the acquisition. If it does agree to provide the funds, we expect our borrowing base to be increased to $34.5 million following the closing of the acquisition. We believe that this funding would be subject to certain additional commitments, including finding an additional source of capital in order to reduce the lender’s exposure within a reasonable time period following the closing of the acquisition and a continued reduction in our general and administrative expenditure.

If this acquisition does not close as proposed or is terminated by the seller, it is likely that our borrowing base would be decreased, and we would need to repay outstanding amounts under the credit facility in excess of the decreased borrowing base to cure the resulting breach. Under the credit facility, we must commence repayment of outstanding amounts in excess of the reduced borrowing base within 30 days of our receipt of a borrowing base deficiency notice. Such excess is required to be repaid in six equal consecutive monthly installments, unless our primary lender consents to an extension or amendment to this timeline. Our failure to timely repay such amounts would be deemed an event of default under our credit agreement. In the current oil pricing climate, there can be no guarantee of our ability to timely repay such amounts.

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 based on our June and December reserve reports. We also have the ability to request a borrowing base redetermination at another period, once a year. The facility matures January 28, 2017. The interest rate is LIBOR plus 3.75% or approximately 3.98% for the quarter ended December 31, 2015.

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 which was tested for the first time for the 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 received a waiver from our primary lender with respect to this breach for this quarter only. We were in compliance with all other covenants.

As at March 31, 2015 we were in breach of our debt to EBIDTAX covenant. We received a waiver from our primary lender with respect to this breach for this quarter only. We were in compliance with all other covenants.

We were in compliance with all of our covenants as at June 30, 2015.

As at September 30, 2015 we were in breach of our Debt to EBITDAX and interest coverage ratio covenants. We received a waiver from our primary lender with respect to these covenants for this quarter only.

As at December 31, 2015 we were in breach of our Debt to EBITDAX and interest coverage ratio covenants. We have requested a waiver from our primary lender with respect to these covenants for this quarter only, and it is still considering this request.

If the current pricing environment does not improve it will be difficult to maintain compliance with 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.

We incurred $0.4 million in borrowing costs (including legal fees and bank fees) in connection with the establishment of this facility which have been deferred and are being amortized over the life of the facility.

11. 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, 2015, 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 the Company’s primary lender, and as such, no additional collateral is required by the counterparty.

During the quarter ended December 31, 2015 we recognized $200,017 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 $67.50 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.

In April 2015, we closed out our open 2015 hedge positions (from April 2015 to December 2015) for net proceeds of $1.2 million. We also entered into a three way costless collar arrangement with respect to 73,500 barrels from production from May 2015 to December 2015. These options have a ceiling of $70.50, a floor of $45.00 (the Company receives $45.00 when the market price settles between $32.50 and $45.00) and a sub floor of $32.50 (the Company receives the market price plus $15 for any prices below $32.50).

Also in April, we also entered into a deferred three way collar with respect to 27,375 (average of 75 barrels per day) for 2016 production. The options have a ceiling of $80, a floor or $55 and a sub floor of $45. These options have a premium of $1.63 per barrel, which is deferred until the contract settlement.

At December 31, 2015 the Company’s open derivative contracts consisted of the following:

Oil Price Collars - WTI	Volumes (Bbls)		Sub Floor US$		Floor US$		Ceiling US$
January 2016 - February 2016		2,788		-		85.00		89.85
January 2016- December 2016		36,600		-		67.50		82.50
January 2016 -December 2016		27,450		40.00		55.00		80.00

Oil Price Swaps - WTI

Volumes (Bbls)

Price US$

January 2016 - February 2016

2,788

105.00

12. Subsequent Events

As announced in a Form 8-K filed on January 7, 2016, Samson Oil and Gas USA Inc. (a wholly owned subsidiary of the Company) entered into a contract to acquire oil and gas leases, producing oil and gas wells, currently shut-in wells and associated facilities in North Dakota and Montana for consideration of $16.5 million. The acquisition was due to close on February 15^th, but the continuing volatility in petroleum markets has prevented us from concluding arrangements for financing of the acquired assets with our primary lender. While we remain optimistic that we will obtain the necessary financing and close the acquisition, our failure to meet the February 15th deadline entitles the seller to terminate the purchase agreement at any time. We currently expect that the necessary financing will be obtained on or before February 29th, 2016, and that the seller will close the sale on that date. There can be no assurance, however, that the seller will not exercise its right to terminate before we obtain the funds needed and close the transaction.

No events other than those previously mentioned have occurred subsequent to December 31, 2015 that would have an impact on our operations or the results of operations for the quarter ended or six months ended December 31, 2015.

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, 2015, 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.

Our net oil production was 51,888 barrels of oil for the quarter ended December 31, 2015, compared to 43,653 barrels of oil for the quarter ended December 31, 2014. The increase in oil production was due to new wells commencing production in our North Stockyard project since we commenced the drilling program in December 2013.

Our net gas production was 93,332 Mcf for the quarter ended December 31, 2015, compared to 39,043 Mcf for the quarter ended December 31, 2014.

Our net oil production was 113,124 barrels of oil for the six months ended December 31, 2015 compared to 78,517 barrels of oil for the six months ended December 31, 2014. The increase in oil production is due to new wells commencing production in our North Stockyard project.

Our net gas production was 183,414 Mcf for the six months ended December 31, 2015, compared to 85,588 Mcf for the six months ended December 31, 2014.

For the three months ended December 31, 2015 and December 31, 2014, we reported a net loss of $14.7 million and a net loss of $2.5 million, respectively. The loss in the current period reflects a $3.7 million in exploration expenditure and impairment expense of $9.7 million while the loss in the prior period reflects a $3.0 million of impairment expenditure. See “Results of Operations” below.

For the six months ended December 31, 2015 and December 31, 2014, we reported a net loss of $16.8 million and a net loss of $13.5 million, respectively. The loss in the current period reflects a $4.2 million in exploration expenditure and impairment expense of $9.8 million while the loss in the prior period reflects a $3.0 million of impairment expenditure and $11.5 million in write off of previously capitalized exploration expenditure. 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 and Six Months Ended December 31, 2015 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 2014 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. Various oil shows were observed in the Cretaceous, Jurassic, Permian, and Pennsylvanian intervals while drilling. The Permian target zone (from 7738 feet to 7756 feet) exhibited excellent porosity (29% density porosity). Detailed analysis of the Permian target zone proved that it was the source of the nitrogen gas that was seen while drilling the well. 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 data led the partners to make the decision to complete the Permian target sand.

The Permian target sand was 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 pounds per square inch. 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. Isotope Geochemistry analysis of the gas samples, has identified the source of the nitrogen, which is from a post-mature organic kerogen in the black shales of the Pennsylvanian section. The hydrocarbons in the samples are mixed thermogenic post mature gases generated in the wet gas/condensate window. All of the gathered evidence supports the theory that the fluid below the gas cap is likely to be oil. The gas-fluid interface has been identified through the integration of the pressure transient test data with newly processed inverted seismic data.

We concluded our extended flow test on the Bluff #1-11 well. The Permian Hartville sand (from 7738 feet-7756 feet) produced 1.2 BCF of nitrogen gas during a 100 day flow test. The goals of the test were to determine the reservoir drive mechanism and the type of fluid (oil or water, which was identified from the pressure transient analysis and seismic inversion data) beneath the nitrogen gas cap. From the pressure transient analysis data, we forecasted that it would take another year and half before the water or oil leg could be seen at the well. The gas/fluid contact moved 180 feet over the 100 day flow test period and would have to move another 420 feet to eventually reach the wellbore. Due to this lack of movement, we have shut the well in for 4 months to monitor the pressure build-up which can hopefully determine if there is any continuing fluid movement in the reservoir. If the pressure builds back up to the original bottom hole pressure, we may be able to determine that the drive mechanism is an active water drive at which point it may be worth opening the well up again to flow and look for an oil leg. If the bottom hole reservoir pressures remain low after the build-up, the Permian Hartville zone will be abandoned and additional recompletions will occur in the uphole zones where other hydrocarbon shows were observed.

Following the continued degradation in the oil price, $1.4 million, representing all current costs associated with this well have been written off during the quarter ended December 31, 2015. The review of the pressure buildup is expected to be completed by mid-year 2016 however additional costs are not expected to be incurred with respect to this well unless a sustained recovery in the oil price is observed.

Spirit of America US34 #2-29 well

Samson 100% Working Interest

In an effort to establish continuous production from the Muddy Formation, the tubing in the SOA 1-29 well was perforated 120 feet above the packer in September 2015 in order to establish tubing and casing annulus communication. Two feet of perforations (7650 feet -7652 feet) were shot with four shots per foot (eight shots fired in all). During October 2015, the well underwent a swabbing operation to remove a full column of fluid from the wellbore to allow the well to flow freely. Subsequent to this operation, the well failed to produce economic quantities of hydrocarbons and no further work is planned with respect to this well bore. $0.2 million in expense was written off to dry hole costs in relation to this well during the quarter ended September 30, 2015. Additional costs of $0.2 million were incurred during the quarter ended December 31, 2015 and have been written off to dry hole expense.

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

In June 2015, we elected to participate in our proportionate 25% working interest in 900 net acres in the Birch prospect. The target zone is the Wayne zone of the Mississippian Mission Canyon Formation to be found at an expected depth of 4,800 feet, measured depth. We participated at our proportionate 25% working interest in the drilling of the Badger #1 well in Section 29 of Township 157N, Range 81W in Ward County, North Dakota. The well was drilled to a depth of 4,900 feet in 7 days for the total cost of approximately $350,000 (our share is approximately $90,000). The prospect was identified as a 375 acre 4-way structural closure on the South Prairie 3-D seismic survey. Approximately 30 feet of structural closure relief was interpreted. The targeted porosity zone of the Mississippian Mission Canyon Formation was found at a depth of 4,774feet MD, which was 55 feet structurally high to the offsetting Anschutz Helseth #1 well and 36 feet high to the offsetting Apache Corporation’s Ward Estate #1-29 well proving the existence of the 4-way structural closure. However, low resistivity readings, a lack of oil shows, and calculated high water saturations (>80%) indicate the targeted reservoir is non-productive. Hence, the decision was made to plug and abandon the well.

This well was drilled in October 2015 and $0.1 million in costs was expensed to dry hole costs during the quarter ended December 31, 2015.

Cane Creek Project, Grand & San Juan Counties, Utah

Pennsylvanian Paradox Formation, Paradox Basin

Samson 100% Working Interest

On November 5, 2014, we entered into an Other Business Arrangement (“OBA”) with the Utah School and Institutional Trust Lands Administration (“SITLA”) covering approximately 8,080 gross/net acres located in Grand and San Juan Counties, Utah, all of which are administered by SITLA. We were granted an option period for two years in order to enter into a Multiple Mineral Development Agreement (“MMDA”) with another company who hold leases to extract potash in an acreage position situated within our project area. In November 2015, we paid an extension fee of $40,000 in order to extend the option period to December 2016. Subsequently, the MMDA has been finalized and is awaiting signature by both parties. Upon entering into the MMDA, SITLA is obligated to deliver oil and gas leases covering our project area at cost of $75 per acre to us.

This acreage is located in the heart of the Cane Creek Clastic Play of the Paradox Formation along the Cane Creek anticline. The primary drilling objective is the overpressured and oil saturated Cane Creek Clastic interval. Keys to the play to date include positioning along the axis of the Cane Creek anticline and exposure to open natural fractures. The 3-D seismic is currently being designed to image these natural fractures. The seismic shoot was surveyed and permitted this past summer. We believe this project has the potential to provide very robust economics in a low priced oil environment using the evidence obtained from a nearby competitor well that has produced 802,967 BO in just over two years.

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.

Due to high hydrogen sulphide content in the well, the Harstad well was plugged and abandoned during the current quarter ended September 30, 2015.

We have 23 wells in this field with all wells currently producing.

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), was drilled and completed in January 2014. During the quarter the Gladys 1-20H well produced 11,858 barrels of oil (gross). Samson has no further drilling planned in this project area until there is a sustained recovery in the oil prices.

Developed Properties: Production Activities

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson various working interests

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

They produce 92% of our total oil production and 81% of our total gas production for the December 2015 quarter.

Results of Operations

For the three months ended December 31, 2015, we reported a net loss of $14.7 million compared to a net loss of $2.5 million for the same period in 2014.

For the six months ended December 31, 2015 we reported a net loss of $16.8 million compared to a net loss of $13.5 million for the same period in 2014.

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

	Three months ended
	31-Dec-15		31-Dec-14		30-Sep-15
Production Volume
Oil (Bbls)		51,888		43,653		60,723
Natural gas (Mcf)		93,332		39,043		95,559
BOE (Barrels of oil equivalent - based on one barrel of oil to six Mcf of natural gas)		67,443		50,160		76,650

Sales Price
Realized Oil ($/Bbls)	$	36.58	$	58.14	$	39.90
Impact of settled derivative instruments	$	1.74	$	9.69	$	0.32
Derivative adjusted price	$	38.32	$	67.83	$	40.22

Realized Gas ($/Mcf)	$	2.25	$	3.82	$	2.27

Expense per BOE:
Lease operating expenses	$	12.38	$	24.17	$	18.65
Production and property taxes	$	4.16	$	5.97	$	3.90
Depletion, depreciation and amortization	$	20.75	$	22.30	$	19.36
General and administrative expense	$	13.52	$	25.14	$	13.84

	Six months ended
	31-Dec-15		31-Dec-14
Production Volume
Oil (Bbls)		113,124		78,517
Natural gas (Mcf)		183,414		85,588
BOE		143,693		92,782

Sales Price
Realized Oil ($/Bbls)	$	38.20	$	70.57
Impact of settled derivative instruments	$	0.97	$	5.96
	$	39.17	$	76.53

Realized Gas ($/Mcf)	$	2.33	$	4.72

Expense per BOE:
Lease operating expenses	$	15.67	$	24.69
Production and property taxes	$	4.03	$	7.34
Depletion, depreciation and amortization	$	20.07	$	22.35
General and administrative expense	$	13.73	$	26.64

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

	Three months ended									Three months ended
	31-Dec-15			31-Dec-14			2Q15 to 2Q14			30-Sep-15			2Q15 to 1Q15
Oil sales	$	1,898,240		$	2,538,100		$	(639,860	)	$	2,422,583		$	(524,343	)
Gas sales		210,212			148,953			61,259			216,747			(6,535	)
Other liquids		27,201			-			27,201			1,346			25,855
Interest income		667			9,884			(9,217	)		1,535			(868	)
Gain on derivative instruments		200,017			2,306,135			(2,106,118	)		372,552			(172,535	)
Other		265			6,561			(6,296	)		17,637			(17,372	)

Lease operating expense		(1,102,441	)		(1,512,195	)		409,754			(1,728,729	)		626,288
Depletion, depreciation and amortization		(1,399,511	)		(1,118,619	)		(280,892	)		(1,483,732	)		84,221
Impairment		(9,682,965	)		(3,027,288	)		(6,655,677	)		(120,022	)		(9,562,943	)
Abandonment expense		-			(79,036	)		79,036			-			-
Exploration and evaluation expenditure		(3,699,651	)		(362,540	)		(3,337,111	)		(493,068	)		(3,206,583	)
Accretion of asset retirement obligations		(15,116	)		(8,418	)		(6,698	)		(14,888	)		(228	)
Interest expense		(196,357	)		(147,343	)		(49,014	)		(190,039	)		(6,318	)
Amortization of borrowing costs		(35,486	)		(31,972	)		(3,514	)		(35,486	)		-
General and administrative		(911,925	)		(1,260,793	)		348,868			(1,060,595	)		148,670
Net loss	$	(14,706,850	)	$	(2,538,571	)	$	(12,168,279	)	$	(2,094,159	)	$	(12,612,691	)

Comparison of Quarter Ended December 31, 2015 to Quarter Ended December 31, 2014 and for the six months ended December 31, 2015 and six months ended December 31, 2014.

Oil and gas revenues

Oil revenues decreased from $2.5 million for the three months ended December 31, 2014 to $1.9 million for the three months ended December 31, 2015, as a result of the decrease in the oil price. Oil production increased from 43,653 barrels for the three months ended December 31, 2014 to 51,888 for the three months ended December 31, 2015. The realized oil price decreased from $58.14 per Bbl for the three months ended December 31, 2014 to $36.58 per Bbl (excluding the impact of derivatives) for the three months ended December 31, 2015 following a decrease in global oil prices.

Oil revenues decreased from $5.5 million for the six months ended December 31, 2014 to $4.3 million for the six months ended December 31, 2015, as a result of the decrease in the oil price. Oil production increased from 78,517 barrels for the six months ended December 31, 2014 to 113,124 for the six months ended December 31, 2015. The realized oil price decreased from $70.57 per Bbl for the six months ended December 31, 2014 to $38.20 per Bbl (excluding the impact of derivatives) for the six months ended December 31, 2015 following a decrease in global oil prices.

Gas revenues also increased slightly from $0.1 million for the three months ended December 31, 2014 to $0.2 million for the three months ended December 31, 2015. This increase is due to an increase in production which has offset the decrease in the realized gas price for the three month period. Production increased from 39,043 Mcf for the quarter ended December 31, 2014 to 93,332 Mcf for the quarter ended December 31, 2015. The increase in production was offset by a decrease in the realized gas price which decreased from $3.82 per Mcf for the quarter ended December 31, 2014 to $2.25 per Mcf for the quarter ended December 31, 2015 due to a general decrease in the price of natural gas.

Gas revenues remained constant at $0.4 million for the six months ended December 31, 2014 and December 31, 2015. Production increased significantly from 85,588 Mcf for the six months ended December 31, 2014 to 183,414 Mcf for the six months ended December 31, 2015. The increase in production was due to the operators of our North Stockyard field being able to capture and sell a greater percentage of gas production following the installation of certain infrastructure improvements. The increase in production was offset by a decrease in the realized gas price which decreased from $4.72 per Mcf for the six months ended December 31, 2014 to $2.33 per Mcf for the six ended December 31, 2015 due to a general decrease in the price of natural gas.

Exploration expense

Exploration expenditures increased from $0.4 million for the quarter ended December 31, 2014, to $3.7 million for the quarter ended December 31, 2015. $0.1 million of the expenditure relates to the Badger well, drilled in our South Prairie prospect in North Dakota. This well was drilled in October 2015 and failed to produce hydrocarbons, therefore the costs associated with the well have been expensed in the current quarter. While work has continued on our Bluff well in our Hawk Springs project in Wyoming during the current quarter, the significant deterioration in global oil and gas prices seen during the quarter make it unlikely that further work to bring this well into production will be completed in the near term. $1.3 million in previously capitalized costs have been written off with respect to the Bluff well. $2.4 million was expensed in relation to our Hawk Springs project, and $0.5 million was expensed in relation to our Spirit of America 1 and 11 wells. Work performed on our Spirit of America 1 well failed to establish hydrocarbons in economic quantities.

$2.2 million was written off with respect to costs associated with acreage leasehold in our Hawk Springs project in Goshen County, Wyoming in the current quarter. Prior to this quarter, we were expensing these costs in line with lease expirations, however following the continued fall in the oil price, no further funds are expected to be spent with respect to this project in the near term, therefore all leasehold costs have been expensed.

Expenditure in the prior period relate to previously capitalized exploration expenditure written off in relation to lease expirations with respect to our Hawk Springs project in Wyoming.

Exploration expenditures decreased from $11.5 million for the six months ended December 31, 2014, to $4.2 million for the six months ended December 31, 2015. $0.1 million of the expenditure relates to the Badger well, drilled in our South Prairie prospect in North Dakota. This well was drilled in October 2015 and failed to produce hydrocarbons, therefore the costs associated with the well have been expensed in the current quarter.

Expenditure in the prior period relates previously capitalized exploration expenditure written off, primarily in relation to the Roosevelt project in Montana and the South Prairie project in North Dakota.

Impairment expense

During the three months ended December 31, 2015 we recognized $9.7 million in impairment expense compared to $3.0 during the quarter ended December, 2015. The impairment recognized in the current quarter primarily relates to our North Stockyard field and is driven by the sustained decrease in the oil price seen in the past year. The impairment during the quarter ended December 31, 2014 relates to our Gladys well in our Rainbow project.

During the six months ended December 31, 2015 we recognized $9.8 million in impairment expense compared to $3.1 million in the six months ended December 31, 2014.

Abandonment expense

Abandonment expense decreased from $0.1 million for the three months ended December 31, 2014 to $nil for the three months ended December 31, 2015.

Abandonment expense decreased from $0.2 million for the six months ended December 31, 2014 to $nil for the six months ended December 31, 2015.

Lease operating expense

Lease operating expenses (LOE) decreased from $1.5 million for the quarter ended December 31, 2014, to $1.1 million for the quarter ended December 31, 2015. Costs per BOE have decreased significantly from $24.17 for the quarter ended December 31, 2014 to $12.38 for the quarter ended December 31, 2015. Followed the continued deterioration in the oil price, a renewed focus on cost control has been implemented by the operators of our most significant wells, which are located in the North Stockyard Project in North Dakota.

Lease operating expenses decreased from $3.0 million for the six months ended December 31, 2014, to $2.8 million for the six months ended December 31, 2015. An increase in production has been offset by a decrease in LOE per barrel. Costs per BOE have decreased significantly from $24.69 for the six months ended December 31, 2014 to $15.67 for the six months ended December 31, 2015.

Depletion, depreciation and amortization expense

Depletion, depreciation and amortization expense increased from $1.1 million for the quarter ended December 31, 2014 to $1.4 million for the quarter ended December 31, 2015. The increase in depletion is primarily a result of the increase in the production. The per BOE cost decreased from $22.30 for the three months ended December 31, 2014 to $20.73 for the three months ended December 31, 2015.

Depletion, depreciation and amortization expense increased from $2.1 million for the six months ended December 31, 2014 to $2.9 million for the six months ended December 31, 2015. The increase in depletion is primarily a result of the increase in the production. The per BOE cost decreased from $22.35 for the six months ended December 31, 2014 to $20.05 for the six months ended December 31, 2015.

General and administrative expense

General and administrative expense decreased from $1.3 million for the quarter ended December 31, 2014 to $0.9 million for the quarter ended December 31, 2015. We have been actively trying to reduce our general and administrative costs in recent periods. Salaries were reduced by 15% for all employees effective September 1, 2015. We also reduced our staffing levels in light of the continued weakness in the global oil market. As a result of lower expense and increased production, general and administrative costs on a per BOE basis decreased from $25.14 for the quarter ended December 31, 2014 to $13.52 for the quarter ended December 31, 2015.

General and administrative expense also decreased from $2.5 million for the six months ended December 31, 2014 to $1.9 million for the six months ended December 31, 2015. As a result of lower expense and increased production, general and administrative costs on a per BOE basis decreased from $26.64 for the six months ended December 31, 2014 to $13.73 per BOE for the six months ended December 31, 2015.

Cash Flows

The table below shows cash flows for the following periods:

	Six months ended
	31-Dec-15			31-Dec-14
Cash provided by operating activities	$	517,336		$	628,889
Cash used in investing activities		(1,873,615	)		(12,733,743	)
Cash (used in)/provided by financing activities		302,475			9,372,190

Cash provided by operations changed from a net inflow of $0.6 million for the six months ended December 31, 2014, to a net inflow of $0.9 million for the six months ended December 31, 2015. Cash receipts from customers decreased from $7.0 million for six months ended December 31, 2014 to $6.5 million for the six months ended December 31, 2015, due to a decrease in the realized oil price despite an increase in production. Payments to suppliers and employees decreased from $6.3 million for the six months ended December 31, 2014 to $5.7 million for the six months ended December 31, 2015 following continued cost saving initiatives.

Cash used in investing activities decreased from $12.7 million for the six months ended December 31, 2014 to $1.8 million of cash used for the six months ended December 31, 2015. The cash outflow for the prior period related to ongoing drilling activities in our North Stockyard project in North Dakota. The cash outflow in the current period relates to continued work in our North Stockyard field, though no new wells were drilled in this period. It also includes the $0.5 million non-refundable deposit paid to the seller in relation to our pending acquisition of certain oil and gas assets in North Dakota and Montana.

Cash provided by financing activities decreased from a cash inflow of $9.3 million for the six months ended December 31, 2014 to $0.3 million for the six months ended December 31, 2015. Cash inflow for the current period $0.3 million in proceeds from borrowings from our credit facility. Cash inflow in the prior period is a result of the drawdown of borrowings from our credit facility with our primary lender.

All options outstanding as at December 31, 2015 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.

Our current budget for exploration, exploitation and development capital expenditures in fiscal 2016 is $1.4 million, of which we incurred approximately $1.1 million during the first three months of the fiscal year. These expenditures were funded through our current cash on hand and cash generated from oil sales. Due to the sustained decrease in oil price, we do not have any additional development or exploration drilling planned for the immediate future.

In January 2014, we entered into a $25.0 million credit facility with our primary lender, 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, which is fully drawn at December 31, 2015. As a result, unless the borrowing base is increased or we pay down outstanding borrowings, we are unable to borrow additional amounts under this facility.

Our primary lender is currently assessing our borrowing base in conjunction with the pending acquisition of certain assets including proved reserves in Montana and North Dakota, as announced in a Form 8-K filed on January 7, 2016. The acquisition was due to close on February 15^th, but the continuing volatility in petroleum markets has prevented us from concluding arrangements for financing of the acquired assets with the Company’s primary lender. While we remain optimistic that we will obtain the necessary financing and close the acquisition, our failure to meet the February 15th deadline entitles the seller to terminate the purchase agreement at any time. We currently expect that the necessary financing will be obtained on or before February 29th, 2016, and that the seller will close the sale on that date. There can be no assurance, however, that the seller will not exercise its right to terminate before we obtain the funds needed and close the transaction. The Company’s primary lender has indicated that it is considering providing the funds needed to close the acquisition. If it does agree to provide the funds, we expect our borrowing base to be increased to $34.5 million following the closing of the acquisition. We believe that this funding would be subject to certain additional commitments, including finding an additional source of capital in order to reduce the lender’s exposure within a reasonable time period following the closing of the acquisition and a continued reduction in our general and administrative expenditure.

In November 2014, we entered into the First Amendment to the Company’s Credit Agreement with our primary lender 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. Our primary lender has given us a waiver with respect to this breach for that quarter only. We were in compliance with all other covenants.

For the quarter ended March 31, 2015 we were in breach of our Debt to EBITDAX covenant. Our primary lender has given us a waiver with respect to this breach for that only. We were in compliance with all other covenants.

We were in compliance with all of our covenants for the quarter ended June 30, 2015.

The credit facility in the current period has been presented as a current liability. In previous periods (prior to the quarter ended September 30, 2015) the facility was presented as a non-current liability. Due to the continuing weakness in the global oil price, there is doubt as to whether or not we will be able to meet our future debt covenants. We are working with the bank to renegotiate our facility and will continue to ask for waivers on a quarterly basis as necessary; however there can be no guarantee they will be granted. 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.

The funds drawn from our credit facility were used to fund drilling in our North Stockyard project in North Dakota.

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 main sources of liquidity during the six months ended December 31, 2015 was cash on hand and cash flow from operations. We also drew down the remaining $301,000 from our primary lender in December 2015. This drawdown in part funded our non-refundable $500,000 deposit for our pending acquisition of oil and gas assets in North Dakota and Montana.

During the prior three fiscal years, our three main sources of liquidity were (i) borrowings under our credit facility, (ii) equity issued to raise $21.4 million and (iii) our tax refund of $5.6 million from the Internal Revenue Service, received in February 2013. During the 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, 2015 decreased from June 30, 2015 largely due to payments for drilling and fracturing activities in our North Stockyard project in North Dakota, a deposit of $500,000 paid for our pending acquisition and lower oil and gas revenues due to lower commodity prices..

If future production rates are less than anticipated, the oil price continues to deteriorate for an extended, or our proposed acquisition does not close, 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, 2015 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 five main objectives in the coming 12 months:

Continued focus on cost savings and efficiency across all aspects of the Company including lease operating costs and general and administrative costs

Continued focus on strengthening the Balance Sheet through an appropriate injection of capital

The closing of our proposed acquisition of certain oil and gas assets in North Dakota and Montana, and if the closing occurs, the review and workover of such assets;

The continued appraisal of our Cane Creek project in the Paradox basin in Utah; and

The continued search and appraisal of new development and exploration projects that add value to our current portfolio at lower oil prices

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.

Not applicable.

Item 4. Controls and Procedures.

As of December 31, 2015, 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, 2015, our disclosure controls and procedures were effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2015, 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

While Samson believes its counterclaims are meritorious and is confident that Samson USA will obtain a net positive recovery from the litigation, there can be no assurance as to the ultimate outcome.

Item 1A. Risk Factors.

Our failure to close the pending acquisition of oil and gas assets in North Dakota and Montana may result in a borrowing base deficiency under our credit facility with our primary lender. If not timely remedied, this borrowing base deficiency would result in an event of default under the credit facility.

The closing of our pending acquisition of certain oil and gas assets in North Dakota and Montana is contingent on our obtaining financing to pay the remaining $16 million of the $16.5 million purchase price for the assets. As of February, 15, 2016, the seller has the right to terminate the purchase and sale agreement at any time. If this acquisition does not close as proposed or is terminated by the seller, it is likely that our borrowing base would be decreased, and we would need to repay outstanding amounts under the credit facility in excess of the decreased borrowing base to cure the resulting breach. Under the credit facility, we must commence repayment of outstanding amount in excess of the reduced borrowing base within 30 days of our receipt of a borrowing base deficiency notice. Such excess is required to be repaid in six equal consecutive monthly installments, unless our primary lender consents to an extension or amendment to this timeline. Our failure to timely repay such amounts would be deemed an event of default under our credit agreement. In the current oil pricing climate, there can be no guarantee of our ability to timely repay such amounts, at which time will need to assess our liquidity position.

In addition to the risks described above and 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, 2015. The risks disclosed herein and in our Annual Report on Form 10-K could materially affect our business, financial condition or future results. The risks described herein and in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our business, financial condition or operating results in the future.

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

Not applicable

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

Exhibit No.		Title of Exhibit

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

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

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

101.INS		XBRL Instance Document
101.SCH		XBRL Taxonomy Extension Schema Document
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB		XBRL Taxonomy Extension Label Linkbase Document
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

		*Furnished herewith

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	SAMSON OIL & GAS LIMITED

Date: February 22, 2016	By:	/s/ Terry Barr
		Terence M. Barr
		Managing Director, President and Chief Executive Officer (Principal Executive Officer)

Date: February 22, 2016	By:	/s/ Robyn Lamont
		Robyn Lamont
		Chief Financial Officer (Principal Financial Officer)

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 22, 2016

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 22, 2016

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, 2015 (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 22, 2016

/s/ Robyn Lamont
Robyn Lamont
Chief Financial Officer
February 22, 2016

Document And Entity Information - shares	6 Months Ended
Document And Entity Information - shares	Dec. 31, 2015	Feb. 15, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Trading Symbol	SSN
Entity Registrant Name	Samson Oil & Gas LTD
Entity Central Index Key	0001404079
Current Fiscal Year End Date	--06-30
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		2,837,834,301

Consolidated Balance Sheets - USD ($)	Dec. 31, 2015	Jun. 30, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 943,289	$ 2,062,720
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively	1,714,094	3,645,223
Prepayments	684,830	372,079
Fair value of derivative instruments	723,370	159,216
Total current assets	4,065,583	6,239,238
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment of $56,894,155 and $44,273,976 at December 31,2015 and June 30, 2015, respectively	17,360,238	29,715,540
Other property and equipment, net of accumulated depreciation and amortization of $553,012 and $553,428 at December 31, 2015 and June 30, 2015, respectively	145,824	248,521
Net property, plant and equipment	17,506,062	29,964,061
OTHER NON CURRENT ASSETS
Fair value of derivative instruments		101,269
Undeveloped capitalized acreage		2,491,422
Capitalized exploration expense	202,573	1,388,798
Other	214,624	342,069
TOTAL ASSETS	21,988,842	40,526,857
CURRENT LIABILITIES
Accounts payable	952,185	1,678,915
Accruals	245,465	1,999,344
Provision for annual leave	194,019	219,414
Credit facility	19,000,000
Total current liabilities	20,391,669	3,897,673
NON CURRENT LIABILITIES
Asset retirement obligations	1,794,356	1,263,674
Credit Facility	19,000,000	18,699,000
TOTAL LIABILITIES	22,186,025	23,860,347
STOCKHOLDERS' (DEFICIT)/ EQUITY - nil par value
2,837,834,301 (equivalent to 14,189,172 ADR's) and 2,837,782,022 (equivalent to 14,188,910 ADR's) ordinary shares issued and outstanding at September 30, 2015 and June 30, 2015, respectively	104,493,249	104,491,774
Accumulated other comprehensive income	932,095	996,256
Accumulated deficit	(105,622,527)	(88,821,520)
Total stockholders' (deficit)/ equity	(197,183)	16,666,510
TOTAL LIABILITIES AND STOCKHOLDERS' (DEFICIT)/ EQUITY	$ 21,988,842	$ 40,526,857

Consolidated Balance Sheets (Parenthetical) - USD ($)	Dec. 31, 2015	Jun. 30, 2015
Consolidated Balance Sheets [Abstract]
Other property and equipment, net of accumulated depreciation and amortization	$ 553,012	$ 553,428
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment	$ 56,894,155	$ 44,273,976
Common stock, par value	$ 0
Common stock, shares issued	2,837,834,301	2,837,782,022
Common stock, shares issued ADR	14,189,172	14,188,910
Common stock, shares outstanding ADR	14,189,172	14,188,910

Consolidated Statements Of Operations And Comprehensive Income (Loss) - USD ($)	3 Months Ended		6 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
REVENUES AND OTHER INCOME:
Interest income	$ 667	$ 9,884	$ 2,202	$ 19,523
Gain on derivative instruments	200,017	2,306,135	572,569	3,087,705
Other	265	6,561	17,902	6,772
TOTAL REVENUE AND OTHER INCOME	2,336,602	5,009,633	5,369,002	9,059,248
EXPENSES:
Lease operating expense	(1,102,441)	(1,512,195)	(2,831,170)	(2,972,117)
Depletion, depreciation and amortization	(1,399,511)	(1,118,619)	(2,883,243)	(2,073,680)
Impairment expense	(9,682,965)	(3,027,288)	(9,802,987)	(3,060,684)
Abandonment expense		(79,036)		(214,803)
Exploration and evaluation expenditure	(3,699,651)	(362,540)	(4,192,719)	(11,465,956)
Accretion of asset retirement obligations	(15,116)	(8,418)	(30,004)	(16,341)
Amortisation of borrowing costs	(35,486)	(31,972)	(70,972)	(65,132)
Interest expense	(196,357)	(147,343)	(386,396)	(231,285)
General and administrative	(911,925)	(1,260,793)	(1,972,518)	(2,472,072)
TOTAL EXPENSES	(17,043,452)	(7,548,204)	(22,170,009)	(22,572,070)
Loss from operations	(14,706,850)	(2,538,571)	(16,801,007)	(13,512,822)
Net loss	(14,706,850)	(2,538,571)	(16,801,007)	(13,512,822)
OTHER COMPREHENSIVE GAIN (LOSS) [Abstract]
Foreign Currency Translation gain/( loss)	6,623	(97,689)	(64,161)	(226,399)
Total comprehensive loss for the period	$ (14,700,227)	$ (2,636,260)	$ (16,865,168)	$ (13,739,221)
Net gain/(loss) per ordinary share from operations:
Basic - cents per share	$ (0.52)	$ (0.09)	$ (0.59)	$ (0.48)
Diluted - cents per share	$ (0.52)	$ (0.09)	$ (0.59)	$ (0.48)
Weighted average ordinary shares outstanding:
Basic	2,837,834,301	2,837,781,683	2,837,828,903	2,837,772,648
Diluted	2,837,834,301	2,837,781,683	2,837,828,903	2,837,772,648
Oil [Member]
REVENUES AND OTHER INCOME:
Sales	$ 1,898,240	$ 2,538,100	$ 4,320,823	$ 5,541,245
Gas [Member]
REVENUES AND OTHER INCOME:
Sales	210,212	$ 148,953	426,959	$ 404,003
Other Liquids [Member]
REVENUES AND OTHER INCOME:
Sales	$ 27,201		$ 28,547

Consolidated Statements Of Changes In Stockholders' Equity - 6 months ended Dec. 31, 2015 - USD ($)	Ordinary Shares [Member]	Retained Earnings/(Accumulated Deficit) [Member]	Other Comprehensive Income (Loss) [Member]	Total
Balance at Jun. 30, 2015	$ 104,491,774	$ (88,821,520)	$ 996,256	$ 16,666,510
Net loss		(16,801,007)		(16,801,007)
Foreign Currency Translation, net tax of $nil			(64,161)	(64,161)
Total comprehensive loss for the period		(16,801,007)	(64,161)	(16,865,168)
Exercise of Options	1,475			1,475
Balance at Dec. 31, 2015	$ 104,493,249	$ (105,622,527)	$ 932,095	$ (197,183)

Consolidated Statements Of Changes In Stockholders' Equity (Parenthetical)	6 Months Ended
	Dec. 31, 2015 USD ($)
Consolidated Statements Of Changes In Stockholders' Equity [Abstract]
Foreign currency translation, tax	$ 0

Consolidated Statements Of Cash Flows - USD ($)	6 Months Ended
Consolidated Statements Of Cash Flows - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Cash flows (used in)/provided by operating activities
Receipts from customers	$ 6,543,082	$ 7,010,394
Proceeds from/(Payments for) derivative instruments	109,684	228,837
Payments to suppliers & employees	(5,738,781)	(6,349,789)
Interest received	2,188	19,499
Interest paid	(398,837)	(172,917)
State income taxes paid		(107,135)
Net cash flows provided by operating activities	517,336	628,889
Cash flows from investing activities
Payments for plant & equipment		(21,427)
Payments for exploration and evaluation	(314,639)	(1,399,142)
Payments for oil and gas properties	(1,558,976)	(11,313,174)
Net cash flows used in investing activities	(1,873,615)	(12,733,743)
Cash flows from financing activities
Proceeds from the exercise of options	1,475	880
Proceeds from borrowings	301,000	9,500,000
Borrowing costs		(83,690)
Share issuance costs		(45,000)
Net cash flows (used in)/ provided by financing activities	302,475	9,372,190
Net increase/(decrease) in cash and cash equivalents	(1,053,804)	(2,732,664)
Cash and cash equivalents at the beginning of the fiscal period	2,062,720	6,846,394
Effects of exchange rate changes on cash and cash equivalents	(65,627)	(232,592)
Cash and cash equivalents at end of fiscal period	$ 943,289	$ 3,881,138

Basis of Presentation	3 Months Ended
Basis of Presentation	Dec. 31, 2015
Basis of Presentation [Abstract]
Basis of Presentation	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, 2015. 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, 2015 and June 30, 2015 consist primarily of estimates for goods and services received but not yet invoiced. Prepayments. Prepayments at December 31, 2015 consist primarily of a $0.5 million deposit paid in connection with a purchase and sale agreement that we entered into on December 31, 2015. This deposit is only refundable if certain conditions with respect to title of environmental defects are identified and the transaction does not close as proposed. Refer to the discussions below under “Credit Facility” and “Subsequent Events” for additional discussion of this agreement. Other prepayments include insurance premiums paid in advance for the year. Prepayments at June 30, 2015 consists primarily of cash advanced to the operators of our South Prairie exploration project for a future exploration well and insurance premiums paid in advance for the year. The exploration well was drilled in October 2015 and was a dry hole. Costs were expensed as incurred. Comparatives. Changes have been made to the classification of certain prior period comparatives in order to remain consistent with the current period presentation. Recent Accounting Standards There are no new accounting pronouncements that have not been adopted by the Company as of December 31, 2015 that will have a material effect on the Company’s financial statements.

Income Taxes

3 Months Ended

Dec. 31, 2015

Income Taxes [Abstract]

Income Taxes

2. Income Taxes


The Company has cumulative net operating losses (“NOLs”) 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.

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.

Earnings Per Share

3 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Earnings Per Share

3. Earnings Per Share



	Three months ended		Six months ended
	31-Dec-15	31-Dec-14	31-Dec-15	31-Dec-14
Dilutive	-	-	-	-
Anti–dilutive	324,615,486	389,168,104	323,287,581	389,177,139

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



	Three months ended			Six months ended
	31-Dec-15		31-Dec-14	31-Dec-15		31-Dec-14
Net income (loss)	$	(14,706,850)	(2,538,571)	$	(16,801,007)	(13,512,822)

Basic weighted average ordinary shares outstanding		2,837,834,301	2,837,781,683		2,837,828,903	2,837,772,648
Basic earnings per ordinary share – cents per share		(0.52)	(0.09)		(0.59)	(0.48)
Diluted earnings per ordinary share – cents per share		(0.52)	(0.09)		(0.59)	(0.48)

Asset Retirement Obligations

3 Months Ended

Dec. 31, 2015

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

4. Asset Retirement Obligations

The following table summarizes the activities for the Company’s asset retirement obligations for the three months ended December 31, 2015 and 2014:



	Six months ended
	31-Dec-15		31-Dec-14
Asset retirement obligations at beginning of period	$	1,810,674	$	1,775,792
Liabilities incurred or acquired		-		42,805
Liabilities settled		(46,322)		(710,561)
Disposition of properties		-		-
Accretion expense		30,004		16,341
Asset retirement obligations at end of period		1,794,356		1,124,377
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)		-		-
Long-term asset retirement obligations	$	1,794,356	$	1,124,377

Fair Value Measurements

3 Months Ended

Dec. 31, 2015

Fair Value Measurements [Abstract]

Fair Value Measurements

5. Fair Value Measurements

The three levels of the fair value hierarchy are as follows:





	Carrying value at December 31, 2015		Level 1		Level 2		Level 3		Netting (1)		Fair Value at December 31, 2015
Current Assets:
Cash and cash equivalents	$	943,289	$	943,289	$	-	$	-	$	-	$	943,289
Derivative Instruments		723,370		-		2,030,217		-		(1,306,847)		723,370

Non Current Assets
Derivative Instruments		-		-		-				-		-

Current Liabilities
Derivative instruments		-		-		1,306,847		-		(1,306,847)		-

Non Current Liabilities
Derivative Instruments		-		-		-				-		-

	Carrying value at June 30, 2015		Level 1		Level 2		Level 3		Netting (1)		Fair Value at June 30, 2015
Current Assets:
Cash and cash equivalents	$	2,062,720	$	2,062,720	$	-	$	-	$	-	$	2,062,720
Derivative Instruments		159,216		-		379,540		-		(220,324)		159,216

Non Current Assets
Derivative Instruments		101,269		-		298,703		-		(197,434)		101,269

Current Liabilities
Derivative instruments		-		-		220,324		-		(220,324)		-

Non Current Liabilities
Derivative Instruments		-		-		197,434		-		(197,434)		-

(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.

Commitments And Contingencies	3 Months Ended
Commitments And Contingencies	Dec. 31, 2015
Commitments And Contingencies [Abstract]
Commitments And Contingencies	6. 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 In 2013, Halliburton Energy Services, Inc., a co-participant in the Company’s Hawk Springs project, 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. The unpaid oil revenue was approximately $126,000 at that time, and has since increased to approximately $170,000. Samson USA answered the complaint, including counterclaims against Halliburton arising out of Samson USA’s engagement of Halliburton’s Project Management group in May of 2011 in connection with its drilling program in Roosevelt County, Montana. In those counterclaims, Samson USA claimed 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 also counterclaimed for a judicial accounting of the fees and expenses Halliburton charged to Samson in connection with the Spirit of America well in Goshen County, Wyoming, and the Australia II well in Roosevelt County, Wyoming, in light of Samson USA’s prior discovery of self-dealing and bill padding by Halliburton’s onsite project manager. In September 2015, Samson filed an amended counterclaim in which it has alleged that (i) Halliburton selected a rig that was inappropriate for the geology where the Spirit of America 1 well was located, and (ii) the project supervisor assigned by Halliburton to oversee the construction and drilling of the Spirit of America 1 well was unqualified and lacked the credentials and experience to perform the duties required of a project manager. Samson has alleged that Halliburton’s failure in this regard caused Halliburton to be unable to reach the target reservoir and, in the process, caused Samson to incur $4,505,587 in costs that could have been avoided if a proper rig and qualified project supervisor had been selected and used on the project. The parties have attended one mediation session with a court appointed mediator, however this failed to reach an agreement. Another mediation is scheduled to be held on March 10, 2016. While Samson believes its counterclaims are meritorious and is confident that Samson USA will obtain a net positive recovery from the litigation, there can be no assurance as to the ultimate outcome.

Issue of Share Capital	3 Months Ended
Issue of Share Capital	Dec. 31, 2015
Issue of Share Capital [Abstract]
Issue of Share Capital	8. Share Capital Issue of Share Capital During the six months ended December 31, 2015, 52,279 options with an exercise price of 3.8 cents (Australian) per ordinary share were exercised for net proceeds of $1,475. During the six months ended December 31, 2014 24,025 options with an exercise price of 3.8 cents (Australian) per ordinary share were exercised for net proceeds of $880. All options exercised were issued in a public rights offering conducted in June 2013.

Cash Flow Statement

3 Months Ended

Dec. 31, 2015

Cash Flow Statement [Abstract]

Cash Flow Statement

9. Cash Flow Statement

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



	Six months ended
	31-Dec-15		31-Dec-14

Net loss after tax	$	(16,801,007)	$	(13,512,822)
Depletion, depreciation and amortization		2,883,243		2,073,680
Accretion of asset retirement obligation		30,004		16,341
Impairment expense		9,802,987		3,060,684
Exploration and evaluation expenditure		4,192,719		11,465,956
Amortization borrowing costs		70,972		65,132
Abandonment expense		-		214,803
Non cash (gain)/loss on derivative instruments		(462,885)		(2,619,664)

Changes in assets and liabilities:

Decrease in receivables		1,931,129		2,132,371
Increase/(decrease) in provision for annual leave		(25,395)		(19,082)
(Decrease)/Increase in payables		(1,104,431)		(2,248,510)
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	517,336	$	628,889

Credit Facility

3 Months Ended

Dec. 31, 2015

Credit Facility [Abstract]

Credit Facility Disclosure

10. Credit Facility



	Six months ended
	31-Dec-15		31-Dec-14
Credit facility at beginning of period	$	18,699,000	$	6,000,000
Cash advanced under facility	$	301,000		9,500,000
Repayments		-		-
Credit facility at end of period (1)	$	19,000,000	$	15,500,000
				-
Funds available for drawdown under the facility	$	-		3,500,000

(1)

Our primary lender is currently assessing our borrowing base in conjunction with the pending acquisition of certain assets including proved reserves in Montana and North Dakota, as announced in a Form 8-K filed on January 7, 2016. The acquisition was due to close on February 15th, but the continuing volatility in petroleum markets has prevented us from concluding arrangements for financing of the acquired assets with the our primary lender. While we remain optimistic that we will obtain the necessary financing and close the acquisition, our failure to meet the February 15th deadline entitles the seller to terminate the purchase agreement at any time. We currently expect that the necessary financing will be obtained on or before February 29th, 2016, and that the seller will close the sale on that date. There can be no assurance, however, that the seller will not exercise its right to terminate before we obtain the funds needed and close the transaction. Our primary lender has indicated that it is considering providing the funds needed to close the acquisition. If it does agree to provide the funds, we expect our borrowing base to be increased to $34.5 million following the closing of the acquisition. We believe that this funding would be subject to certain additional commitments, including finding an additional source of capital in order to reduce the lender’s exposure within a reasonable time period following the closing of the acquisition and a continued reduction in our general and administrative expenditure.

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

We were in compliance with all of our covenants as at June 30, 2015.

If the current pricing environment does not improve it will difficult to maintain compliance with covenants based 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.

Derivatives

3 Months Ended

Dec. 31, 2015

Derivatives [Abstract]

Derivatives

11. Derivatives

CollarCollars 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 swapThe 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.

During the quarter ended December 31, 2015 we recognized $200,017 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.

At December 31, 2015 the Company’s open derivative contracts consisted of the following:



Oil Price Collars - WTI	Volumes (Bbls)	Sub Floor US$	Floor US$	Ceiling US$
January 2016 - February 2016	2,788	-	85.00	89.85
January 2016- December 2016	36,600	-	67.50	82.50
January 2016 -December 2016	27,450	40.00	55.00	80.00

Oil Price Swaps - WTI	Volumes (Bbls)		Price US$
January 2016 - February 2016	2,788		105.00

Earnings Per Share (Tables)

3 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Schedule Of Weighted Average Dilutive And Anti-Dilutive Securities



	Three months ended		Six months ended
	31-Dec-15	31-Dec-14	31-Dec-15	31-Dec-14
Dilutive	-	-	-	-
Anti–dilutive	324,615,486	389,168,104	323,287,581	389,177,139

Schedule Of Calculation Of Basic And Diluted Earnings Per Share



	Three months ended			Six months ended
	31-Dec-15		31-Dec-14	31-Dec-15		31-Dec-14
Net income (loss)	$	(14,706,850)	(2,538,571)	$	(16,801,007)	(13,512,822)

Basic weighted average ordinary shares outstanding		2,837,834,301	2,837,781,683		2,837,828,903	2,837,772,648
Basic earnings per ordinary share – cents per share		(0.52)	(0.09)		(0.59)	(0.48)
Diluted earnings per ordinary share – cents per share		(0.52)	(0.09)		(0.59)	(0.48)

Asset Retirement Obligations (Tables)

6 Months Ended

Dec. 31, 2015

Asset Retirement Obligations [Abstract]

Summary Of Activities Of Asset Retirement Obligations



	Six months ended
	31-Dec-15		31-Dec-14
Asset retirement obligations at beginning of period	$	1,810,674	$	1,775,792
Liabilities incurred or acquired		-		42,805
Liabilities settled		(46,322)		(710,561)
Disposition of properties		-		-
Accretion expense		30,004		16,341
Asset retirement obligations at end of period		1,794,356		1,124,377
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)		-		-
Long-term asset retirement obligations	$	1,794,356	$	1,124,377

Fair Value (Tables)

3 Months Ended

Dec. 31, 2015

Fair Value Measurements [Abstract]

Schedule Of Fair Value, Assets And Liabilities Measured On Recurring And Nonrecurring Basis



	Carrying value at December 31, 2015		Level 1		Level 2		Level 3		Netting (1)		Fair Value at December 31, 2015
Current Assets:
Cash and cash equivalents	$	943,289	$	943,289	$	-	$	-	$	-	$	943,289
Derivative Instruments		723,370		-		2,030,217		-		(1,306,847)		723,370

Non Current Assets
Derivative Instruments		-		-		-				-		-

Current Liabilities
Derivative instruments		-		-		1,306,847		-		(1,306,847)		-

Non Current Liabilities
Derivative Instruments		-		-		-				-		-

	Carrying value at June 30, 2015		Level 1		Level 2		Level 3		Netting (1)		Fair Value at June 30, 2015
Current Assets:
Cash and cash equivalents	$	2,062,720	$	2,062,720	$	-	$	-	$	-	$	2,062,720
Derivative Instruments		159,216		-		379,540		-		(220,324)		159,216

Non Current Assets
Derivative Instruments		101,269		-		298,703		-		(197,434)		101,269

Current Liabilities
Derivative instruments		-		-		220,324		-		(220,324)		-

Non Current Liabilities
Derivative Instruments		-		-		197,434		-		(197,434)		-

Cash Flow Statement Reconcilation (Tables)

3 Months Ended

Dec. 31, 2015

Cash Flow Statement [Abstract]

Schedule Of Cash Flow Statement Reconciliation



	Six months ended
	31-Dec-15		31-Dec-14

Net loss after tax	$	(16,801,007)	$	(13,512,822)
Depletion, depreciation and amortization		2,883,243		2,073,680
Accretion of asset retirement obligation		30,004		16,341
Impairment expense		9,802,987		3,060,684
Exploration and evaluation expenditure		4,192,719		11,465,956
Amortization borrowing costs		70,972		65,132
Abandonment expense		-		214,803
Non cash (gain)/loss on derivative instruments		(462,885)		(2,619,664)

Changes in assets and liabilities:

Decrease in receivables		1,931,129		2,132,371
Increase/(decrease) in provision for annual leave		(25,395)		(19,082)
(Decrease)/Increase in payables		(1,104,431)		(2,248,510)
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	517,336	$	628,889

Credit Facility (Tables)

3 Months Ended

Dec. 31, 2015

Credit Facility [Abstract]

Schedule of Line of Credit Facilities [Table Text Block]



	Six months ended
	31-Dec-15		31-Dec-14
Credit facility at beginning of period	$	18,699,000	$	6,000,000
Cash advanced under facility	$	301,000		9,500,000
Repayments		-		-
Credit facility at end of period (1)	$	19,000,000	$	15,500,000
				-
Funds available for drawdown under the facility	$	-		3,500,000

Derivatives (Tables)

6 Months Ended

Dec. 31, 2015

Derivatives [Abstract]

Schedule Of Open Derivative Contracts



Oil Price Collars - WTI	Volumes (Bbls)	Sub Floor US$	Floor US$	Ceiling US$
January 2016 - February 2016	2,788	-	85.00	89.85
January 2016- December 2016	36,600	-	67.50	82.50
January 2016 -December 2016	27,450	40.00	55.00	80.00

Oil Price Swaps - WTI	Volumes (Bbls)		Price US$
January 2016 - February 2016	2,788		105.00

Earnings Per Share (Details) - USD ($)	3 Months Ended		6 Months Ended
Earnings Per Share (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Anti-dilutive	324,615,486	389,168,104	323,287,581	389,177,139
Net income	$ (14,706,850)	$ (2,538,571)	$ (16,801,007)	$ (13,512,822)
Basic weighted average ordinary shares outstanding	2,837,834,301	2,837,781,683	2,837,828,903	2,837,772,648
Diluted weighted average ordinary shares outstanding	2,837,834,301	2,837,781,683	2,837,828,903	2,837,772,648
Basic earnings per ordinary share - cents per share	$ (0.52)	$ (0.09)	$ (0.59)	$ (0.48)
Diluted earnings per ordinary share - cents per share	$ (0.52)	$ (0.09)	$ (0.59)	$ (0.48)

Asset Retirement Obligations (Details) - USD ($)	3 Months Ended		6 Months Ended
Asset Retirement Obligations (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Jun. 30, 2015
Asset Retirement Obligations [Abstract]
Asset retirement obligations at beginning of period			$ 1,810,674	$ 1,775,792
Liabilities incurred or acquired				42,805
Liabilities settled			(46,322)	(710,561)
Accretion expense	$ 15,116	$ 8,418	30,004	16,341
Asset retirement obligations at end of period	1,794,356	1,124,377	1,794,356	1,124,377
Long-term asset retirement obligations	$ 1,794,356	$ 1,124,377	$ 1,794,356	$ 1,124,377	$ 1,263,674

Fair Value Measurements (Schedule Of Fair Value, Assets And Liabilities Measured On Recurring And Nonrecurring Basis) (Details) - USD ($)

3 Months Ended

6 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Sep. 30, 2015

Jun. 30, 2015

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Cash and cash equivalents

$ 943,289

$ 2,062,720

Derivative instruments, Current Assets

723,370

$ 723,370

159,216

Fair value of derivative instruments

101,269

Impairment of Oil and Gas Properties

9,682,965

$ 3,027,288

9,802,987

$ 3,060,684

Carrying Value [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Cash and cash equivalents

943,289

2,062,720

Derivative instruments, Current Assets

723,370

159,216

Fair value of derivative instruments

101,269

Level 1 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Cash and cash equivalents

943,289

2,062,720

Level 2 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Derivative instruments, Current Assets

2,030,217

379,540

Fair value of derivative instruments

298,703

Derivative Liability, Current

1,306,847

220,324

Derivative instrument, Non Current Liabilities

197,434

Netting [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Derivative instruments, Current Assets

^[1]

(1,306,847)

(220,324)

Fair value of derivative instruments

^[1]

(197,434)

Derivative Liability, Current

^[1]

$ (1,306,847)

(220,324)

Derivative instrument, Non Current Liabilities

^[1]

$ (197,434)

[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.

Commitments And Contingencies (Details) - USD ($)	6 Months Ended	12 Months Ended
Commitments And Contingencies (Details) - USD ($)	Dec. 31, 2015	Jun. 30, 2013
Commitments And Contingencies [Abstract]
Unpaid oil revenue claimed by Halliburton	$ 170,000	$ 126,000
Disputed rig mobilisation invoice	336,000
Disputedwellcharges	$ 4,505,587

Capitalized Exploration Expense (Details) - USD ($)	6 Months Ended
Capitalized Exploration Expense (Details) - USD ($)	Dec. 31, 2015	Jun. 30, 2015
Capitalized Exploration Expense [Abstract]
Capiltalized exploration expense after write off	$ 200,000
Undeveloped capitalized acreage		$ 2,491,422

Issue of Share Capital (Details) - USD ($)	3 Months Ended	6 Months Ended
Issue of Share Capital (Details) - USD ($)	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014
Issue of Share Capital [Abstract]
Shares issued upon exercise of options, shares	24,025	52,279	24,025
Weighted average exercise price - cents (AUD) and (USD), exercised		$ 3.8	$ 3.8
Net proceeds from option exercises		$ 1,475	$ 880

Cash Flow Statement (Details) - USD ($)	3 Months Ended		6 Months Ended
Cash Flow Statement (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Cash Flow Statement [Abstract]
Net income/(loss) after tax			$ (16,801,007)
Net (loss) after tax	$ (14,706,850)	$ (2,538,571)	(16,801,007)	$ (13,512,822)
Depletion, depreciation and amortization			2,883,243	2,073,680
Accretion of asset retirment obligation	15,116	8,418	30,004	16,341
Impairment expense			9,802,987	3,060,684
Exploration and evaluation expenditure			4,192,719	11,465,956
Amortisation of borrowing costs	$ 35,486	31,972	70,972	65,132
Abandonment expense		$ 79,036		214,803
Unrealized Gain (Loss) on Derivatives			(462,885)	(2,619,664)
Increase in receivables			1,931,129	2,132,371
Increase/(decrease) in provision for annual leave			(25,395)	(19,082)
Increase in payables			(1,104,431)	(2,248,510)
Net cash flows used in operating activities			$ 517,336	$ 628,889

Credit Facility (Details) - USD ($)	3 Months Ended	6 Months Ended		9 Months Ended
Credit Facility (Details) - USD ($)	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Sep. 30, 2014	Jun. 30, 2014
Credit Facility [Abstract]
Line of Credit Facility, Current Borrowing Capacity	$ 19,000,000			$ 8,000,000		$ 15,500,000
Line of Credit Facility, Maximum Borrowing Capacity	$ 50,000,000			$ 25,000,000	$ 25,000,000
Line of Credit Facility, Remaining Borrowing Capacity			$ 3,500,000
Debt Instrument, Interest Rate During Period	3.98%
Debt Instrument, Maturity Date				Jan. 28, 2017
Credit facility at end of period		$ 19,000,000	15,500,000
Payments of Debt Issuance Costs			83,690
Cash advanced under facility		$ 301,000	$ 9,500,000

Derivatives (Schedule Of Open Derivative Contracts) (Details)	2 Months Ended	12 Months Ended
	Feb. 29, 2016 $ / bbl bbl	Dec. 31, 2016 bbl
Derivative Contract Three [Member]
Derivative [Line Items]
Volumes (bbls) \| bbl	2,788
Floor US$ \| $ / bbl	85.00
Ceiling US$ \| $ / bbl	89.85
Derivative Contract Nine [Member]
Derivative [Line Items]
Volumes (bbls) \| bbl		36,600.00
Derivative, Underlying		$5.50
Swap [Member] \| Derivative Contract Six [Member]
Derivative [Line Items]
Volumes (bbls) \| bbl	2,788
Price US$ \| $ / bbl	105.00

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