Samson Oil & Gas LTD - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - Samson Oil & Gas LTD	Financial_Report.xls
EX-31.2 - EXHIBIT 31.2 - Samson Oil & Gas LTD	v393698_ex31-2.htm
EX-31.1 - EXHIBIT 31.1 - Samson Oil & Gas LTD	v393698_ex31-1.htm
EX-32.1 - EXHIBIT 32.1 - Samson Oil & Gas LTD	v393698_ex32-1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2014

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

Commission File Number: 001-33578

Samson Oil & Gas Limited

(Exact Name of Registrant as Specified in its Charter)

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

Level 16, AMP Building, 140 St Georges Terrace Perth, Western Australia 6000
(Address Of Principal Executive Offices)	(Zip Code)

+61 8 9220 9830

(Registrant’s Telephone Number, Including Area Code)

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

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

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

Large accelerated filer	¨	Accelerated filer x

Non-accelerated filer	¨	Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

There were 2,837,782,022 ordinary shares outstanding as of November 7, 2014.

SAMSON OIL & GAS LIMITED

FORM 10-Q

QUARTER ENDED SEPTEMBER 30, 2014

TABLE OF CONTENTS

		Page

Part I — Financial Information		4

Item 1.	Financial Statements (unaudited)	4

	Consolidated Balance Sheets, September 30, 2014 and June 30, 2014	4

	Consolidated Statement of Operations and Comprehensive Income (Loss) for the three months ended September 30, 2014 and 2013	5

	Consolidated Statement of Changes in Stockholders’ Equity for the three months ended September 30, 2014	6

	Consolidated Statement of Cash Flows for the three months ended September 30, 2014 and 2013	7

	Notes to Consolidated Financial Statements (unaudited)	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	16

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	23

Item 4.	Controls and Procedures	23

Part II — Other Information		24

Item 1.	Legal Proceedings	24

Item 1A.	Risk Factors	24

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

Item 3.	Defaults Upon Senior Securities	24

Item 4.	Mine Safety Disclosures	24

Item 5.	Other Information	25

Item 6.	Exhibits	25

Signatures		26

FORWARD-LOOKING STATEMENTS

Written forward–looking statements may appear in documents filed with the Securities and Exchange Commission (“SEC”), including this quarterly report, documents incorporated by reference, reports to shareholders and other communications.

The U.S. Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for forward–looking information to encourage companies to provide prospective information about themselves without fear of litigation so long as the information is identified as forward looking and is accompanied by meaningful cautionary statements identifying important factors that could cause actual results to differ materially from those projected in the information. Samson relies on this safe harbor in making forward–looking statements.

Forward–looking statements appear in a number of places in this quarterly report and include but are not limited to management’s comments regarding business strategy, exploration and development drilling prospects and activities at our oil and gas properties, oil and gas pipeline availability and capacity, natural gas and oil reserves and production, meeting our capital raising targets and following any use of proceeds plans, our ability to and methods by which we may raise additional capital, production and future operating results.

In this quarterly report, the use of words such as “anticipate,” “continue,” “estimate,” “expect,” “likely,” “may,” “will,” “project,” “should,” “believe” and similar expressions are intended to identify uncertainties. While we believe that the expectations reflected in those forward–looking statements are reasonable, we cannot assure you that these expectations will prove to be correct. Our actual results could differ materially from those anticipated in these forward–looking statements. The differences between actual results and those predicted by the forward–looking statements could be material. Forward-looking statements are based upon our expectations relating to, among other things:

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

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

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

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

timing, amount, and marketability of production;

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

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

effectiveness of management strategies and decisions;

the strength and financial resources of our competitors;

oil and natural gas prices and demand;

our entrance into transactions in commodity derivative instruments;

climatic conditions;

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

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

uncontrollable flows of oil, gas or well fluids.

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

Part I — Financial Information

Item 1. Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	30-Sep-14			30-Jun-14
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5,304,656		$	6,846,394

Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively		2,873,356			5,533,516

Prepayments		8,699,930			5,388,428
Fair value of derivative instrument		269,967			-
Short term deferred tax asset		84,946			84,946
Total current assets		17,232,855			17,853,284
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment of $22,173,601 and $21,219,361 at September 30, 2014 and June 30, 2014, respectively		42,324,811			34,430,793

Other property and equipment, net of accumulated depreciation and amortization of $453,691 and $421,443 at September 30, 2014 and June 30, 2014, respectively		352,822			365,566

Net property, plant and equipment		42,677,633			34,796,359
OTHER NON CURRENT ASSETS
Fair value of derivative instrument		53,132			-
Undeveloped capitalized acreage		2,958,306			12,349,767
Capitalized exploration expense		1,938,842			3,382,650
Other		362,460			459,169
TOTAL ASSETS	$	65,223,228		$	68,841,229

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	3,807,410		$	4,316,963
Accruals		6,516,823			3,261,674
Fair value of derivative instruments		-			284,376
Provision for annual leave		231,005			230,311
Total current liabilities		10,555,238			8,093,324
NON CURRENT LIABILITIES
Fair value of derivative instruments		-			128,998
Asset retirement obligations		1,094,059			897,859
Credit facility		11,000,000			6,000,000
Deferred tax liability		84,946			84,946
TOTAL LIABILITIES		22,734,243			15,205,127
STOCKHOLDERS’ EQUITY – nil par value
2,547,651,218 (equivalent to 127,382,560 ADR’s) and 2,547,627,193 (equivalent to 127,381,360 ADR’s) ordinary shares issued and outstanding at September 30, 2014 and June 30, 2014, respectively		104,491,738			104,535,894
Accumulated other comprehensive income		1,173,386			1,302,096
Accumulated deficit		(63,176,139	)		(52,201,888	)
Total stockholders’ equity		42,488,985			53,636,102
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	65,223,228		$	68,841,229

See accompanying Notes to Consolidated Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three months ended
	30-Sep-14			30-Sep-13
REVENUES AND OTHER INCOME:
Oil sales	$	3,003,145		$	1,256,990
Gas sales		255,050			141,946
Other liquids		-			-
Interest income		9,639			14,445
Gain on derivative instruments		781,570
Gain on sale of oil and gas properties		-			2,524,411
Other		211			99
TOTAL REVENUE AND OTHER INCOME		4,049,615			3,937,891

EXPENSES:
Lease operating expense		(1,459,922	)		(644,750	)
Depletion, depreciation and amortization		(955,061	)		(464,082	)
Impairment expense		(33,396	)		(83,121	)
Abandonment expense		(135,767	)		-
Exploration and evaluation expenditure		(11,103,416	)		(267,705	)
Accretion of asset retirement obligations		(7,923	)		(15,696	)
Amortisation of borrowing costs		(33,160	)		-
Interest expense		(83,942	)		-
General and administrative		(1,211,279	)		(1,603,046	)
TOTAL EXPENSES		(15,023,866	)		(3,078,400	)

Loss from operations		(10,974,251	)		859,491
Income tax benefit		-			-
Net loss		(10,974,251	)		859,491
OTHER COMPREHENSIVE GAIN (LOSS)
Foreign currency translation gain (loss)		(128,710	)		(194,775	)
Total comprehensive gain/(loss) for the period	$	(11,102,961	)	$	664,716

Net loss per ordinary share from operations:
Basic – cents per share		(0.43	)		0.04
Diluted – cents per share		(0.43	)		0.04

Weighted average ordinary shares outstanding:
Basic		2,547,633,793			2,358,235,080
Diluted		2,547,633,793			2,384,723,326

See accompanying Notes to Consolidated Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

							Accumulated Other
							Other			Total
	Ordinary						Comprehensive			Stockholders
	Shares			(Accumulated Deficit)			Income			Equity
Balance at June 30, 2014	$	104,535,894		$	(52,201,888	)	$	1,302,096		$	53,636,102
Net loss		-			(10,974,251	)		-			(10,974,251	)
Foreign currency translation loss, net of tax of $nil		-			-			(128,710	)		(128,710	)
Total comprehensive loss for the period		-			(10,974,251	)		(128,710	)		(11,102,961	)
Stock based compensation		-			-			-			-
Exercise of options		844			-			-			844
Share issuance costs		(45,000	)		-			-			(45,000	)
Balance at September 30, 2014	$	104,491,738		$	(63,176,139	)	$	1,173,386		$	42,488,985

See accompanying Notes to Consolidated Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three months ended
	30-Sep-14			30-Sep-13
Cash flows (used in)/provided by operating activities
Receipts from customers	$	4,868,740		$	1,395,904
Payments to suppliers & employees		(2,740,845	)		(1,672,154	)
Interest received		9,639			12,078
Payments for derivative instruments		(374	)		-
State income taxes paid		(107,135	)		-
Net cash flows provided by/(used in) operating activities		2,030,025			(264,172	)
Cash flows used in investing activities
Proceeds from sale of oil and gas properties		-			1,737,401
Payments for plant & equipment		(21,542	)		-
Payments for exploration and evaluation		(2,684,079	)		(201,866	)
Payments for oil and gas properties		(5,629,936	)		(12,586,328	)
Net cash flows used in investing activities		(8,335,557	)		(11,050,793	)
Cash flows provided by financing activities
Issuance of share capital		-			7,337,138
Proceeds from the exercise of options		844			347
Proceeds from borrowings		5,000,000			-
Borrowing costs		(75,000	)		-
Interest paid		(29,485	)		-
Share issuance costs		-			(526,181	)
Net cash flows provided by financing activities		4,896,359			6,811,304
Net decrease in cash and cash equivalents		(1,409,173	)		(4,503,661	)

Cash and cash equivalents at the beginning of the fiscal period		6,846,394			13,170,627

Effects of exchange rate changes on cash and cash equivalents		(132,565	)		(195,000	)

Cash and cash equivalents at end of fiscal period	$	5,304,656		$	8,471,966

See accompanying Notes to Consolidated Financial Statements

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

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

The Company’s Consolidated Financial Statements have been prepared on a basis consistent with the accounting principles and policies reflected in the Company’s audited financial statements as of and for the year ended June 30, 2014. The year-end Consolidated Balance Sheet presented herein was derived from audited Consolidated Financial Statements, but does not include all disclosures required by GAAP.

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

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

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

Recent Accounting Standards

There are no new accounting pronouncements that have not been adopted by the Company as of September 30, 2014 that will have a material effect on the Company’s financial statements.

2. Income Taxes

	Three months ended
	30-Sep-14			30-Sep-13

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

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

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

During the quarter ending March 31, 2013, the Company received a $5.6 million income tax refund from the Internal Revenue Service of the taxes paid in a prior period noted above.

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

3. Earnings Per Share

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

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

	Three months ended
	30-Sep-14		30-Sep-13
Dilutive		-		-
Anti–dilutive		389,189,173		219,793,738

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

	Three months ended
	30-Sep-14			30-Sep-13
Net income (loss)	$	(10,974,251	)		859,491

Basic weighted average ordinary shares outstanding		2,547,633,793			2,358,235,080
Add: dilutive effect of stock options		-			-
Add: bonus element for rights issue		-			26,488,246
Diluted weighted average ordinary shares outstanding		2,547,633,793			2,384,723,326
Basic earnings per ordinary share – cents per share		(0.43	)		0.04
Diluted earnings per ordinary share – cents per share		(0.43	)		0.04

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 this quarter relate to work performed to plug and abandon three wells in our Greens Canyon prospect in Wyoming. These wells were drilled 10 years ago and did not produce economic quantities of hydrocarbons.

The following table summarizes the activities for the Company’s asset retirement obligations for the nine months ended September 30, 2014 and 2013:

	Three months ended
	30-Sep-14			30-Sep-13
Asset retirement obligations at beginning of period	$	1,775,792		$	868,589
Liabilities incurred or acquired		20,905			154,736
Liabilities settled		(710,561	)		-
Disposition of properties		-			-
Accretion expense		7,923			15,696
Asset retirement obligations at end of period		1,094,059			1,039,021
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)		-			-
Long-term asset retirement obligations	$	1,094,059		$	1,039,021

5. Equity Incentive Compensation

Stock-based compensation is measured at the grant date based on the estimated fair value of the awards with the resulting amount recognized as compensation expense on a straight-line basis over the requisite service period (usually the vesting period).

Total compensation cost recognized in the Statements of Operations for the grants under the Company’s equity incentive compensation plans was $nil during the three months ended September 30, 2014 and $5,256 during the three months ended September 30, 2013.

As of September 30, 2014, there was $nil total unrecognized compensation cost related to outstanding stock options.

6. Sale of Oil and Gas Assets

In August 2013, we divested half our equity position in the undeveloped acreage in the North Stockyard project to Slawson Exploration Company Inc. (“Slawson”) for $5.562 million in cash and other consideration while retaining our full interest in the currently producing wells in the North Stockyard field. $0.9 million of the cash portion of the purchase price is subject to the delivery of a useable well bore in Billabong. While work is continuing on this well bore, it had to be suspended to permit other drilling operations to proceed on the same pad. The Billabong workover was completed during the year ended June 30, 2014 and Slawson exercised its option to take over operation of the Billabong well bore.

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

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

7. Fair Value Measurements

Fair value is defined as the price that would be received in the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. The FASB has established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).

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

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2—Pricing inputs are other than quoted prices in active markets included in level 1, but are either directly or indirectly observable as of the reported date and for substantially the full term of the instrument. Inputs may include quoted prices for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies.

Level 3—Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

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

	Carrying value at September 30, 2014		Level 1		Level 2		Level 3		Netting ⁽¹⁾			Fair Value at September 30, 2014
Current Assets:
Cash and cash equivalents	$	5,304,656	$	5,304,656	$	-	$	-	$	-		$	5,304,656
Derivative Instruments		269,967		-		326,997		-		(57,030	)		269,967

Non Current Assets
Derivative Instruments		53,132		-		87,946				(34,814	)		53,132
													-
Current Liabilities													-
Derivative instruments		-		-		57,030		-		(57,030	)		-
													-
Non Current Liabilities													-
Derivative Instruments		-		-		34,814				(34,814	)		-

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

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

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

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

(1)

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

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

Level 1 Fair value Measurements

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

Level 2 Fair Measurements

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

Other fair value measurements

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

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

8. Commitments and Contingencies

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

Halliburton Dispute

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

9. Capitalized Exploration Expense

We use the successful efforts method of accounting for exploration and evaluation expenditure in respect of each area of interest. The application of this policy requires management to make certain estimates and assumptions as to future events and circumstances, in particular the assessment of whether economic quantities of reserves have been found. Any such estimates and assumptions may change as new information becomes available.

Exploration and evaluation assets are assessed for impairment when facts and circumstances indicate that the carrying amount of an exploration and evaluation asset may exceed its recoverable amount. When assessing for impairment consideration is given to but not limited to the following:

the period for which Samson has the right to explore;

planned and budgeted future exploration expenditure;

activities incurred during the year; and

activities planned for future periods.

If, after having capitalized expenditures under our policy, we conclude that we are unlikely to recover the expenditures through future exploitation, then the relevant capitalized amount will be written off to expense.

As of September 30, 2014 we had capitalized exploration expenditures of $1.9 million and undeveloped capitalized acreage expenditures of $2.9 million. This amount primarily relates to costs incurred in connection with our Hawk Springs projects.

Our Hawk Springs project, in Goshen County, Wyoming, includes $2.9 million in undeveloped capitalized acreage costs and $1.9 million in capitalized exploration expenditure. The capitalized exploration expenditure includes costs associated with the acquisition of our North Platte 3D seismic data and costs associated with the drilling of our Bluff Federal well in this project area. Operations are continuing on this well and it is expected to be completed by December 31, 2014. Due to expired leases, $0.1 million has been written off with respect to this project during the quarter ended September 30, 2014.

Our Roosevelt project, in Roosevelt County, Montana, includes $7.8 million in undeveloped capitalized acreage costs and $0.3 million in capitalized exploration expenditure. The capitalized exploration expenditure consists of costs associated with well permitting; surface use agreements and other expenses associated with drilling preparation activities. In December 2013, we entered into a seismic and drilling agreement with Momentus Energy Corp, a Canadian exploration and development company based in Calgary. Momentus has committed to the acquisition of approximately 20 square miles of 3-D seismic data at no cost to us. Following the acquisition of the seismic data, Momentus has the option to drill a horizontal Bakken well on our acreage at 100% cost to it. Upon Momentus drilling this well, it will have earned the right to 50% of the test well and 50% of our acreage in the Roosevelt project.

The seismic data has been processed and Momentus have begun preparations to drill their earn-in well. They have asked for a 90 day extension with respect to the deadline to drill this well, currently November 15, 2014. Samson is currently considering whether to grant this extension. It is understood that the extension is being requested as Momentus has failed to secure the funding to drill their earn-in well. Given the recent drop in oil prices, the lack of certainty with respect to Momentus’s ability to drill their earn in well and the fact that at this point in time we do not expect to spend any further funds on this project, the balance of $8.1 million capitalized with respect to this project has been written off to the Statement of Operations during the quarter ended September 30, 2014.

Our South Prairie project in Ward and Renville counties, North Dakota, includes $1.6 million in undeveloped acreage costs and $0.9 million in capitalized exploration expenditure. This expenditure relates to 3-D seismic acquisition costs. We are not the operator of this project. The joint venture is focusing on developing three structural closure prospects (Pubco, Deering, and Birch) along the Prairie Salt edge in the South Prairie 3-D project. The joint venture approved the drilling next of the Pubco Prospect, with the York 3-14 well, on the eastern edge of the South Prairie 3-D seismic survey. This well was drilled during the quarter ended September 30, 2014 and found the primary target to be water saturated. Given the lack of success from this project, we have written off the previously capitalized value of this project of $2.5 million to the Statement of Operations during the quarter ended September 30, 2014.

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

10. Issue of Share Capital

During the three months ended September 30, 2014, 24,025 Australian 3.8 cent options were exercised for net proceeds of $844.

During the three months ended September 30, 2013 9,864 Australian 3.8 cent options were exercised for net proceeds of $347. The options were issued in a public rights offering conducted in June 2013.

During the three months ended September 30, 2013, we issued 318,452,166 ordinary shares for 2.5 cents (Australian cents)/2.3 cents (United States cents) for proceeds of $7.3 million. The ordinary shares were issued to investors in the US and Australia. In conjunction with these issues we also issued 132,380,866 warrants with an exercise price of 3.8 cents (Australian) and expiry date of March 31, 2017.

11. Cash Flow Statement

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

	Three months ended
	30-Sep-14			30-Sep-13

Net loss after tax	$	(10,974,251	)	$	859,491
Depletion, depreciation and amortization		955,061			464,082
Stock-based compensation		-			5,255
Accretion of asset retirement obligation		7,923			15,696
Impairment expense		33,396			83,121
Exploration and evaluation expenditure		11,103,416			267,705
Gain on sale of oil and gas properties		-			(2,524,411	)
Amortisation borrowing costs		33,160			-
Abandonment expense		135,767
Non cash gain on derivative instruments		(736,473	)		-

Changes in assets and liabilities:

Decrease/(Increase) in receivables		1,610,545			(3,032	)
Decrease in income tax receivable/deferred tax asset		-			-
Increase/(decrease) in provision for annual leave		694			33,265
(Decrease)/Increase in payables		(139,213	)		534,656

NET CASH FLOWS PROVIDED BY/(USED IN) OPERATING ACTIVITIES	$	2,030,025		$	(264,172	)

12. Credit Facility

	Three months ended
	30-Sep-14		30-Sep-13
Credit facility at beginning of period	$	6,000,000	$	-
Cash advanced under facility	$	5,000,000		-
Repayments		-		-
Credit facility at end of period	$	11,000,000	$	-
				-
Funds available for drawdown under the facility	$	4,500,000		-

In January 2014, we entered into a $25.0 million credit facility with Mutual of Omaha Bank, with an initial borrowing base of $8.0 million. In June 2014 the borrowing base was increased to $15.5 million, of which $11.0 million has been drawn down. We drew down the additional $4.5 million in October 2014.

Additional increases in the borrowing base, up to the credit facility maximum of $25 million, may be made available to us in the future depending on the value of our reserves. Borrowing base redeterminations are performed by the lender every six months at June and December. We also have the ability to request a borrowing base redetermination at another period, once a year. The facility matures January 28, 2017. The interest rate is LIBOR plus 3.75% or approximately 3.98% for the quarter ended September 30, 2014.

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

Current ratio greater than 1

Debt to EBITDAX (annualized) ratio no greater than 3.5

Interest coverage ratio minimum of between 2.5 and 1.0

As at September 30, 2014 we were in compliance with all of these quarterly covenants.

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

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

These funds, along with cash on hand and cash flow from operations, will be used to fund drilling in our North Stockyard project in North Dakota. We expect to fund our remaining capital expenditures for the fiscal year ending June 30, 2015 thereby, though we may obtain additional capital through further drawdowns of our credit facility (if possible) or another capital raising program or asset sales.

We incurred $0.4 million in borrowing costs (including legal fees and bank fees) which have been deferred and will be amortized over the life of the facility.

13. Derivatives

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

The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil. The Company seeks to manage this risk through the use of commodity derivative contracts These derivative contracts allow the Company to limit its exposure to commodity price volatility on a portion of its forecasted oil sales. At September 30, 2014, the Company’s commodity derivative contracts consisted of collars and fixed price swaps, which are described below:

Collar

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

Fixed price swap

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

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

During the quarter ended September 30, 2014 we recognized $781,570 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 and a sub floor of $67.50 with a cost of $5.50 per barrel which is deferred until the settlement of the derivative instrument.

At September 30, 2014 the Company’s open derivative contracts consisted of the following:

Oil Price Collars - WTI	Volumes (Bbls)		Floor US$		Ceiling US$
October 2014 - December 2014		5,098		90.00		99.30
January 2015 - December 2015		18,270		85.00		89.85
January 2016 - February 2016		2,788		85.00		89.85

Oil Price Swaps - WTI	Volumes (Bbls)		Price US$
October 2014 - December 2014		5,098		105.00
January 2015 - December 2015		18,270		105.00
January 2016 - February 2016		2,788		105.00

Oil Price Swaps - WTI	Volumes (Bbls)		Avg Price US$
October 2014 - December 2014		13,616		97.92
January 2015 - December 2015		39,791		92.61

14. Subsequent Events

No events have occurred subsequent to September 30, 2014 that would have an impact on our operations or the results of operations for the quarter ended September 30, 2014.

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

The following is management’s discussion and analysis of certain significant factors that have affected aspects of our financial position and the results of operations during the periods included in the accompanying Condensed Financial Statements. You should read this in conjunction with the discussion under “Management's Discussion and Analysis of Financial Condition and Results of Operations” and the audited Financial Statements for the year ended June 30, 2014, included in our Annual Report on Form 10-K and the Consolidated Financial Statements included elsewhere herein.

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

Overview

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Our strategy is to focus on the exploration, exploitation and development of our major oil plays – the Niobrara, Permian and Pennsylvanian in Goshen County, Wyoming and the Bakken in Williams County, North Dakota and Roosevelt County, Montana.

Our net oil production was 35,613 barrels of oil for the quarter ended September 30, 2014, compared to 12,636 barrels of oil for the quarter ended September 30, 2013. The increase in oil production was due to four new wells commencing production in our North Stockyard project during the quarter – Coopers, Tooheys, Little Creatures and Blackdog. Our net gas production was 46,942 Mcf for the quarter ended September 30, 2014, compared to 37,982 Mcf for the quarter ended September 30, 2013. The increase in gas production also is a result of increased takeaway capacity for the existing wells in our North Stockyard project. Gas produced from the new wells in the North Stockyard project, with the exception of the Sail & Anchor and Blackdog wells, is currently being flared while production facilities are being built and pipeline take away capacity is secured.

For the three months ended September 30, 2014 and September 30, 2013, we reported a net loss of $11.0 million and a net profit of $0.9 million, respectively. The loss in the current period reflects a $11.0 million in write off of previously capitalised exploration expenditure while the gain in the prior period can be partially attributed to sale of oil and gas properties. See “Results of Operations” below.

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

Notable Activities and Status of Material Properties during the Quarter Ended September 30, 2014 and Current Activities

Undeveloped Properties: Exploration Activities

Hawk Springs Project, Goshen County, Wyoming

Permo-Penn Project, Northern D-J Basin

Samson 37.5% working interest

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

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

Various oil shows were observed in the Cretaceous, Jurassic, Permian, and Pennsylvanian intervals while drilling. After running drill-pipe conveyed logging tools in the deeper portion of the well below the intermediate casing, the Pennsylvanian zones, were deemed to be too thin and uneconomic to produce. The Permian target zone (from 7738 feet -7756 feet) displayed excellent porosity (up to 29% density porosity). As a result, the initial calculated water saturation was high, and deemed to be water saturated, so the bottom portion of the hole below the intermediate casing was plugged. Further analysis of the Permian target zone has subsequently occurred and it is now believed to be the source of the nitrogen gas kicks. The presence of nitrogen in the Permian target zone validates the trap in the Bluff prospect and has the potential to host helium and an oil leg below the gas cap. This evidence led the partners to make the decision to drill out the cement plug, set and cement a 5 inch liner 100 feet beneath the Permian target sand. In the coming weeks, the Permian target sand will be flow tested and analyzed to determine its productivity.

If the Permian target zone is determined to be non-productive, three zones in the Jurassic and Cretaceous sections, which are behind the intermediate casing, will subsequently be flow-tested. Log pay was determined in the both the Dakota and Morrison Formations. Using a 60% water saturation as a cut-off to determine oil productive zones, 23.5 feet of log pay was indicated in the Dakota (from 6,393 to 6,485 feet) and 3.5 feet in the Morrison (from 6,605 to 6,625 feet). The Jurassic Canyon Springs Formation could also be productive. When comparing the Canyon Springs reservoir characteristics in the Bluff well to analog producing fields in the southern Powder River Basin, there are similarities between the two. Therefore, Samson may attempt a completion in the Canyon Springs zone to determine its productivity subsequent to testing the Permian target zone.

Roosevelt Project, Roosevelt County, Montana

Mississippian Bakken Formation, Williston Basin

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

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

In December 2013, we entered into a seismic and drilling agreement with Momentus Energy Corp, a Canadian exploration and development company based in Calgary. Momentus has acquired approximately 20 squares of 3-D seismic data at no cost to us. Following the acquisition of the seismic data, Momentus has the option to drill a horizontal Bakken well on our acreage at 100% its own cost. Upon Momentus drilling this well, it will have earned the right to 50% of the test well and 50% of our acreage in the Roosevelt project. The program, consisting of 3-D seismic acquisition and the cost of drilling the Bakken well, is valued at approximately $10 million.

The 3-D seismic survey has been shot, processed, and interpreted. Momentus has proposed to drill a new 2-mile Bakken horizontal well near the Australia II well based on the results from the seismic interpretation. The timing of the drilling of this well has not been determined as of yet and some uncertainty exists with respect to Momentus ability to fund the earn in well.

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

South Prairie Project, North Dakota

Mississippian Mission Canyon Formation, Williston Basin

Samson 25% working interest

Samson has a 25% working interest in 25,590 net acres located on the eastern flank of the Williston Basin in North Dakota. The first well of the project, the Matson #3-1 well was drilled and determined to be a dry hole and was plugged and abandoned in the prior year

Based on the technical analysis of this result, the forward program will show a preference for structural closures that exist along the salt edge rather than those created by dissolution events further interior to the salt edge. The joint venture is focusing on developing three structural closure prospects (Pubco, Deering, and Birch) along the Prairie Salt edge in the South Prairie 3-D project.

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

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

Developed Properties: Drilling Activities

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Bakken & Three Forks infill wells

Samson ~25-30% working interest

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

Seven of nine Three Forks Formation wells have now been drilled in North Stockyard Oilfield. These wells were drilled as 8,000 foot laterals in a west-east orientation. Fracturing (“fracking”) operations have been completed on the Bootleg 4-14-15TFH, Bootleg 5-14-15TFH, Bootleg 6-14-15TFH, and Bootleg 8-14-15TFH wells, and are currently underway on the Bootleg 7-14-15TFH well.

The Billabong 2-13-14HBK well was successfully completed and the well is scheduled to be fracked in November.

Rainbow Project, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson 23% and 52% working interest

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

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

Samson has 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 (SSN 23% WI), has been drilled and completed. The well had an initial production rate of 718 BOPD and has averaged about 400 BOPD & Mcf/d over the first 40 days of production. The well continues to flow on its own without any artificial lift.

Developed Properties: Production Activities

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson various working interests

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

The Harstad #1-15H well (34.5% working interest) was shut in for 75 days during the quarter due to downhole problems and production activities on offset wells. The well averaged 6 BOPD during the quarter. Cumulative gross production to September 30, 2014 is approximately 94 Mbbls.

The Leonard #1-23H well (10% working interest, 37.5% after non-consent penalty) was down for 1 day during the quarter due to an electrical malfunction and a tubing failure. The well averaged 46 BOPD and 79 Mcf/d during the quarter. To September 30, 2014, the Leonard #1-23H well has produced approximately 126 Mbbls and 136 MMcf.

The Gene #1-22H well (30.6% working interest) was down for approximately 5 days during the quarter due to an electrical malfunction. The well produced at an average daily rate of 57 BOPD and 79 Mcf/d during the quarter. Cumulative gross production to September 30, 2014 is approximately 176 Mbbls and 212 MMcf.

The Gary #1-24H (37% working interest) well was down for less than two days during the quarter due to scheduled maintenance. The well averaged 66 BOPD and 102 Mcf/d during the quarter. Cumulative gross production to September 30, 2014 is approximately 180 Mbbls and 285 MMcf.

The Rodney #1-14H (27% working interest) well was down for approximately 55 days during the quarter due to planned shut-in periods while completing the offset wells. The well averaged 77 BOPD and 117 Mcf/d during the quarter. Cumulative gross production to September 30, 2014 is approximately 139 Mbbls and 195 MMcf.

The Earl #1-13H (32% working interest) well was down for 24 days during the quarter due to planned shut-in periods while completing the offset wells. The well produced at an average daily rate of 86 BOPD and 138 Mcf/d. Cumulative gross production to September 30, 2014 is approximately 225 Mbbls and 327 MMcf.

The Everett #1-15H (26% working interest) well was down for 61 days during the quarter due to planned shut in periods while completing the offset wells. The Everett well produced at an average daily rate of 63 BOPD and 70 Mcf/d during the quarter. Cumulative gross production to September 30, 2014 is approximately 126 Mbbls and 165 MMcf.

The Sail & Anchor 4-13-14HBK well was down for 42 days during the quarter due to planned shut in periods while completing offset wells. The well averaged 116 BOPD and 170 Mcf/d during the quarter. Cumulative gross production to September 30, 2014 is approximately 58 Mbbls and 36 MMcf.

The Coopers 1-23-13HBK well was down for 59 days during the quarter due to planned shut in periods while completing offset wells. The well averaged 82 BOPD during the quarter. Cumulative gross production to September 30, 2014 was 47 Mbbls.

The Little Creature 1- 15-14H well was down for 61 days during the quarter due to planned shut in periods while completing offset wells. The well averaged 110 BOPD during the quarter. Cumulative gross production to September 30, 2014 was 73 Mbbls.

The Tooheys 4-15-14HBK well was down for 60 days during the quarter due to planned shut in periods while completing offset wells. The well averaged 62 BOPD during the quarter. Cumulative gross production to September 30, 2014 was 58 Mbbls

The Blackdog 3-13-14HBK well was down for 43 days during the quarter due to planned shut in periods while completing offset wells. The well averaged 314 BOPD and 268 Mcf/d during the quarter. Cumulative gross production to September 30, 2014 was 110 Mbbls and 77 MMcf.

The Matilda Bay 2-15HBK well (32.97% working interest) was successfully drilled and hydraulic fracture stimulated. The well had an IP rate of 1,117 BOPD. The well was shut-in at the beginning of August for facility issues that were resolved and the well was placed back on pump for 16 days until it had to be shut in for completion of the 2^nd Bootleg pad. During the quarter the well was on pump for a total of 42 days in which it produced 276 BOPD.

The Matilda Bay 1-15HBK well (32.97% working interest) was successfully drilled and cased. During the fracture stimulated treatment a casing leak was detected. A work over is underway to drill out the sleeves and to determine the pressure loss point, which will then be repaired. The balance of the frack treatment will be conducted as a plug and perforation technique. The well is shut-in currently waiting for a work over after completion of the 2^nd Bootleg pad. With only 6 frack stages of the planned 24 stages completed, the well had an IP rate of 318 BOPD.

The Bootleg 4-14-15TFH well commenced production on September 2, 2014. Since coming on production, it averaged 436 BOPD. Cumulative gross production to September 30, 2014 was 12 Mbbls.

The Bootleg 5-14-15TFH well commenced production on September 2, 2014. Since coming on production, it averaged 360 BOPD. Cumulative gross production to September 30, 2014 was 10 Mbbls.

Sabretooth Gas Field, Brazoria County Texas

Oligocene Vicksburg Formation, Gulf Coast Basin

Samson 9.375% working interest

Production for the Davis Bintliff #1 well averaged 3.1 MMcf/d and 24 BOPD for the quarter. Cumulative production to September 30, 2014 is approximately 7.7 billion standard cubic feet and 84 Mbbls.

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

Results of Operations

For the three months ended September 30, 2014, we reported a net loss of $11.0 million compared to a net gain of $0.9 million for the 2013 period.

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

	Three months ended
	30-Sep-14		30-Sep-13
Production Volume
Oil (Bbls)		35,613		12,636
Natural gas (Mcf)		46,942		37,982

BOE (based on one barrel of oil to six Mcf of natural gas)		43,437		18,966

Sales Price

Realised Oil ($/Bbls)	$	84.33	$	99.48
Impact of settled derivative instruments	$	1.27	$	0.00
Derivative adjusted price	$	85.60	$	99.48

Realised Gas ($/Mcf)	$	5.43	$	3.74

Expense per BOE:
Lease operating expenses	$	24.83	$	25.09
Production and property taxes	$	8.78	$	8.90
Depletion, depreciation and amortization	$	21.99	$	24.47
General and administrative expense	$	27.89	$	84.52

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

	Three months ended
	30-Sep-14			30-Sep-13			1Q15 to 1Q14 change
Oil sales	$	3,003,145		$	1,256,990		$	1,746,155
Gas sales		255,050			141,946			113,104
Other liquids		-			-			-
Interest income		9,639			14,445			(4,806	)
Gain on derivative instruments		781,570			-			781,570
Gain on sale of oil and gas properties		-			2,524,411			(2,524,411	)
Other		211			99			112

Lease operating expense		(1,459,922	)		(644,750	)		(815,172	)
Depletion, depreciation and amortization		(955,061	)		(464,082	)		(490,979	)
Impairment		(33,396	)		(83,121	)		49,725
Abandonment expense		(135,767	)		-			(135,767	)
Exploration and evaluation expenditure		(11,103,416	)		(267,705	)		(10,835,711	)
Accretion of asset retirement obligations		(7,923	)		(15,696	)		7,773
Interest expense		(83,942	)		-			(83,942	)
Amortisation of borrowing costs		(33,160	)		-			(33,160	)
General and administrative		(1,211,279	)		(1,603,046	)		391,767
Income tax benefit		-			-			-
Net loss	$	(10,974,251	)	$	859,491		$	(11,833,742	)

Three Months Comparison of Quarter Ended September 30, 2014 to Quarter Ended September 30, 2013.

Oil and gas revenues

Oil revenues increased from $1.3 million for the three months ended September 30, 2013 to $3.0 million for the three months ended September 31, 2014, as a result of increased production in our North Stockyard project following the commencement of production from nine new wells in this project area. Oil production increased from 12,636 barrels for the three months ended September 30, 2013 to 35,613 September 30, 2014. The realized oil price decreased from $99.48 per Bbl for the three months ended September 30, 2013 to $84.33 per Bbl for the three months ended September 30, 2014 following a decrease in global oil prices.

Gas revenues increased from $0.1 million for the three months ended September 30, 2013 to $0.3 million for the three months ended September 30, 2014. Production increased from 37,982 Mcf for the quarter ended September 30, 2013 to 46,942 Mcf for the quarter ended September 30, 2014. The realized gas price also increased from $3.74 per Mcf for the quarter ended September 30, 2013 to $5.43 per Mcf for the quarter ended September 30, 2014 due to more liquids rich gas coming from our North Stockyard field.

Sale of oil and gas properties

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

Along with the undeveloped acreage, we also transferred a 25% working interest in the then drilled but not yet completed, at the time of the sale, Sail and Anchor well, as well as a 25% working interest in the salt water disposal well and associated water handling facilities drilled in the prior year in the North Stockyard project. A portion of the purchase price was subject to the delivery of a useable well bore in Billabong, valued in the agreement at $0.9 million, which was delivered during the quarter ended June 30, 2014.

There were no such sales during the quarter ended September 30, 2014.

Exploration expense

Exploration expenditures increased from $0.3 million for the quarter ended September 30, 2013, to $11.1 million for the quarter ended September 30, 2014. $8.1 million of exploration expenditure relates to previously capitalized exploration costs written off in relation to our Roosevelt project. Part of this project has been farmed out to Momentus Energy and activities are continuing in this area, however given the recent decline in the oil price and the exploratory nature of this project, we believe there is substantial doubt over Momentus’s ability to drill its earn in well. $2.5 million of exploration expenditure relates to previously capitalized exploration costs written off in relation to our South Prairie project. During the quarter ended September 30, 2014, the York 3-9 well was drilled in this project area at a cost of $0.2 million to us. The well was a dry hole and will be immediately plugged and abandoned. This was the second dry hole in this project area and no further drilling is planned in the immediate future. $0.1 million was also written off with respect to value of lease expirations in our Hawk Springs project area.

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

Abandonment expense

Abandonment expense increased from nil in the quarter ended September 30, 2013 to $0.1 million during the quarter ended September 30, 2014. The cost in the current period relate to additional costs associated with abandoning three wells in our Greens Canyon project area in Wyoming. Plugging and abandonment activities commenced during the quarter and are expected to be completed by November 2014. These wells were drilled over 10 years ago and were not economic.

Lease operating expense

Lease operating expenses increased from $0.6 million for the quarter ended September 30, 2013, to $1.5 million for the quarter ended September 30, 2014. The increase is due to increased production. Costs per BOE decreased slightly from $25.09 for the quarter ended September 30, 2013 to $24.83 for the quarter ended September 30, 2014.

Depletion, depreciation and amortization expense

Depletion, depreciation and amortization expense increased from $0.5 million for the quarter ended September 30, 2013 to $1.0 million for the quarter ended September 30, 2014. The increase in depletion is a result of the increase in the production. The per BOE cost decreased slightly from $24.47 for the three months ended September 30, 2013 to $21.99 for the three months ended September 30, 2014.

General and administrative expense

General and administrative expense decreased from $1.6 million for the quarter ended September 30, 2013 to $1.2 million for the three months ended September 30, 2014. We have been actively trying to reduce our general and administrative costs in recent periods. A change in the use of professional service providers have been contributing factors to the decrease in the general and administrative costs from the prior period.

Income tax benefit

Income tax benefit was $nil for the three months ended September 30, 2014 compared to $nil for the three months ended September 30, 2013.

Cash Flows

The table below shows cash flows for the following periods:

	Three months ended
	30-Sep-14			30-Sep-13
Cash provided by/(used in) operating activities	$	2,030,025		$	(264,172	)
Cash used in investing activities		(8,335,557	)		(11,050,793	)
Cash provided by financing activities		4,896,359			6,811,304

Cash (used in)/provided by operations increased from an outflow of $0.3 million for the three months ended September 30, 2013, to a net inflow of $2.0 million for the three months ended September 30, 2014. Cash receipts from customers increased from $1.4 million for three months ended September 30, 2013 to $4.9 million for the three months ended September 30, 2014, due to an increase in production

Cash used in investing activities decreased from $11.1 million for the three months ended September 30, 2013 to $8.3 million of cash used for the three months ended September 30, 2014. The cash outflow for both periods relates to ongoing drilling activities in our North Stockyard project in North Dakota and exploration expenditure drilling our Bluff well in the Hawk Springs project.

Cash provided by financing activities increased from a cash inflow of $6.8 million for the three months ended September 30, 2013, to a cash inflow of $4.8 million for the three months ended September 30, 2014. Cash inflow for the prior period was a result of the issue of 318,452,166 ordinary shares to raise $7.3 million before expenses. Cash inflow in the current period is a result of the drawdown of borrowings from our credit facility with Mutual of Omaha.

All options outstanding as at September 30, 2014 are currently out of the money.

Liquidity, Capital Resources and Capital Expenditures

Our primary use of capital has been acquiring, developing and exploring oil and natural gas properties and we anticipate this will be our primary use of capital during fiscal 2015 as well.

Our current budget for exploration, exploitation and development capital expenditures in fiscal 2015 is $20.7 million, of which we incurred approximately $5.1 million during the first three months of the fiscal year. We were able to make these expenditures, which were required to participate in the drilling and completion of the first five wells in our North Stockyard infill development program, by using the proceeds from our prior registered direct offerings, our sale of development acreage to Slawson and drawdowns from our credit facility with Mutual of Omaha Bank. The remaining $15.6 million in planned capital expenditures, relates to the drilling and completion of three additional wells in our North Stockyard infill project and the drilling or our Bluff well in our Hawk Springs project.

In January 2014, we entered into a $25 million credit facility with Mutual of Omaha Bank. We drew down remaining $4.5 million in borrowing base in October 2014. Additional increases in the borrowing base, up to the credit facility maximum of $25 million, may be made available to us in the future depending on the value of our future reserves. Borrowing base redeterminations are performed by the lender every six months at June and December. We also have the ability to request a borrowing base redetermination at another period, once a year.

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

Current ratio greater than 1

Debt to EBITDAX (annualized) ratio no greater than 3.5

Interest coverage ratio minimum of 2.5 to 1.0

As at September 30, 2014 we were in compliance with all quarterly covenants.

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

The funds drawn from our credit facility will be used to fund drilling in our North Stockyard project in North Dakota. We expect to fund our remaining capital expenditures for fiscal 2015 with cash on hand, cash flow from operations, and drawdowns of our credit facility (to the extent available). We may also elect, where we consider it reasonable and appropriate, to raise funds by the sale of selected assets.

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

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

Our two main sources of liquidity during the three months ended September 30, 2014 have been cash on hand, which was $5.3 million at September 30, 2014, cash flows from operations, proceeds from our registered direct offering completed in August 2013, the sale of development acreage to Slawson and the new credit facility entered into in January 2014. In April 2014, we issued 290,110,820 ordinary shares and 87,033,246 options to raise $5.4 million, before costs.

During the prior three fiscal years, our three main sources of liquidity were (i) equity issued to raise $21.4 million and (ii) our tax refund of $5.6 million from the Internal Revenue Service, received in February 2013. During the recent years prior to the fiscal year ended June 30, 2012, our primary sources of liquidity were the sale of acreage and other oil and gas assets.

Our cash position as of September 30, 2014 decreased from September 30, 2013 largely due to payments for drilling and fracking in our North Stockyard project in North Dakota.

If future drilling success rates or production are less than anticipated, the value of our position in affected areas will decline, our results of operations, financial condition and liquidity will be adversely impacted and we could incur material write-downs of unevaluated properties. See the risk factors in our Annual Report on Form 10-K for the fiscal year ended June 30, 2014 including “Drilling results in emerging plays, such as our Hawk Springs and Roosevelt Projects, are subject to heightened risks.” and “Inadequate liquidity could materially and adversely affect our business operations.” See also Part II, Item 1A of this report below.

Looking Ahead

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

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

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

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

Item 4. Controls and Procedures.

As of September 30, 2014, we have carried out an evaluation under the supervision of, and with the participation of, our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

Our Chief Executive Officer and Chief Financial Officer have concluded that, as of September, 2014, our disclosure controls and procedures were effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

During the quarter ended September 30, 2014 we added additional review procedures to the controls around our asset retirement obligation. Other than this change to the review procedures, there were no additional changes in our internal control over financial reporting that occurred during the three months ended September 30, 2014, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time in the future.

Part II — Other Information

Item 1. Legal Proceedings.

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

Halliburton Dispute

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

Item 1A. Risk Factors.

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended June 30, 2014. The risks disclosed in our Annual Report on Form 10-K could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our business, financial condition or operating results in the future.

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

Not applicable

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

Exhibit No.		Title of Exhibit

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

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

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

101		The following financial information from Samson Oil & Gas Limited’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 is formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheet, (ii) Consolidated Statements of Operations, (iii) Consolidated Statement of Changes in Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements.

Signatures

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

	SAMSON OIL & GAS LIMITED

Date: November 10, 2014	By:	/s/ Terry Barr
		Terence M. Barr
		Managing Director, President and Chief Executive Officer (Principal Executive Officer)

Date: November 10, 2014	By:	/s/ Robyn Lamont
		Robyn Lamont
		Chief Financial Officer (Principal Financial Officer)

Samson Oil & Gas LTD - FORM 10-Q - November 10, 2014

Attached files

Samson Oil & Gas LTD Reports