UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

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

 

For the quarterly period ended December 31, 2012

 

OR

 

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

 

Commission File Number: 333-123711

 

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)
Level 36, Exchange Plaza, 2 The Esplanade Perth, Western Australia 6000
(Former address, if changed since last report)

 

+61 8 9220 9830

(Registrant’s Telephone Number, Including Area Code)

 

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

 

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

 

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

 

Large accelerated filer	¨	Accelerated filer     x
Non-accelerated filer	¨	Smaller reporting company     ¨

 

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

 

There were 1,985,896,471 ordinary shares outstanding as of February 8, 2013.

 

 

SAMSON OIL & GAS LIMITED

FORM 10-Q

QUARTER ENDED DECEMBER 31, 2012

 

TABLE OF CONTENTS

 

		Page
Part I — Financial Information		4
Item 1.	Financial Statement (unaudited).	4
Consolidated Balance Sheets, December 31, 2012 and June 30, 2012		4
Consolidated Statement of Operations and Comprehensive Income (Loss) for the three months ended December 31, 2012 and 2011 and six months ended December 31, 2012 and 2011		5
Consolidated Statement of Changes in Stockholders’ Equity for the six months ended December 31, 2012		6
Consolidated Statement of Cash Flows for the six months ended December 31, 2012 and 2011		7
Notes to  Consolidated Financial Statements (unaudited)		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	13
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	21
Item 4.	Controls and Procedures.	21
Part II   — Other Information		21
Item 1.	Legal Proceedings.	21
Item 1A.	Risk Factors.	21
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	22
Item 3.	Defaults Upon Senior Securities.	22
Item 4.	Removed and Reserved.	22
Item 5.	Other Information.	23
Item 6.	Exhibits.	23
Signatures		24

 

 

FORWARD-LOOKING STATEMENTS

 

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

 

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

 

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

 

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

 

·

our future financial position, including cash flow, anticipated liquidity and debt levels;

  

·

the timing, effects and success of our exploration and development activities, and acquisitions and dispositions

  

·

oil and natural gas prices and demand;

 

·

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

 

·

timing, amount, and marketability of production;

 

·

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

 

·

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

 

·

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

 

·

effectiveness of management strategies and decisions;

 

·

the strength and financial resources of our competitors;

 

·

our entrance into transactions in commodity derivative instruments;

 

·

climatic conditions;

 

·

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

 

·

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

  

·

uncontrollable flows of oil, gas or well fluids.

 

Many of these factors are beyond our ability to control or predict. Neither these factors nor those included in the “Risk Factors” section of this quarterly report represent a complete list of the factors that may affect us.  We do not undertake to update 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-12				30-Jun-12
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	9,725,163			$	18,845,894
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively			1,264,085				1,288,159
Prepayments			240,400				344,108
Pipe inventory – held by third party			78,944				78,944
Income tax receivable			6,383,492				4,347,456
Total current assets			17,692,084				24,904,561
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment of $17,399,071 and $16,112,531 at December 31, 2012 and June 30, 2012 respectively.			13,911,282				13,890,380
Other property and equipment, net of accumulated depreciation and amortization of $300,461 and $252,254 at December 31, 2012 and June 30, 2012, respectively			403,921				448,061
Net property, plant and equipment			14,315,203				14,338,441
OTHER ASSETS
Undeveloped capitalized acreage			12,357,333				10,017,287
Capitalized exploration expense			9,733,880				6,362,989
Other			100,575				99,961
TOTAL ASSETS		$	54,199,075			$	55,723,239
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable		$	1,397,055			$	5,269,748
Accruals			895,686				1,229,982
Provision for annual leave			196,893				234,536
Total current liabilities			2,489,634				6,734,266
Capitalized lease			-				7,322
Asset retirement obligations			840,372				808,572
TOTAL LIABILITIES			3,330,006				7,550,160
STOCKHOLDERS’ EQUITY – nil par value
Common stock, 1,985,896,471 (equivalent to 99,294,824 ADR’s) and 1,771,891,827 (equivalent to 88,594,591 ADR’s) shares issued and outstanding at December 31, 2012 and June 30, 2012, respectively)			86,962,960				83,467,987
Other comprehensive income			2,861,828				2,772,758
Retained earnings (accumulated deficit)			(38,955,719	)			(38,067,666	)
Total stockholders’ equity			50,869,069				48,173,079
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	54,199,075			$	55,723,239

 

See accompanying Notes to Consolidated Financial Statements.

 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONSAND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

 

		Three months ended								Six months ended
		31-Dec-12				31-Dec-11				31-Dec-12				31-Dec-11
REVENUES AND OTHER INCOME:
Oil sales		$	1,457,238			$	1,666,006			$	2,903,775			$	3,842,442
Gas sales			218,885				263,087				364,907				573,263
Other liquids			-				2,255				4,199				7,921
Interest income			55,139				85,431				126,779				199,237
Other			111,469				1,979				111,481				21,136
TOTAL REVENUE AND OTHER INCOME			1,842,731				2,018,758				3,511,141				4,643,999
EXPENSES:
Lease operating expense			(1,041,761	)			(455,495	)			(1,853,750	)			(1,082,292	)
Depletion, depreciation and amortization			(498,851	)			(619,713	)			(1,089,618	)			(1,353,022	)
Impairment expense			(244,560	)			-				(244,589	)			-
Exploration and evaluation expenditure			(39,006	)			(4,619,278	)			(400,950	)			(4,740,828	)
Accretion of asset retirement obligations			(13,675	)			(5,559	)			(27,109	)			(10,993	)
General and administrative			(1,336,332	)			(2,076,296	)			(2,819,114	)			(3,962,282	)
TOTAL EXPENSES			(3,174,185	)			(7,776,341	)			(6,435,130	)			(11,149,417	)
Income (loss) from operations			(1,331,454	)			(5,757,583	)			(2,923,989	)			(6,505,418	)
Income tax benefit/(provision)			1,366,938				693,385				2,035,936				881,563
Net income/(loss)			35,484				(5,064,198	)			(888,053	)			(5,623,855	)
OTHER COMPREHENSIVE GAIN (LOSS)
Foreign Currency Translation			(62,606	)			223,626				89,070				(350,006	)
Total comprehensive income/(loss) for the period		$	(27,122	)		$	(4,840,572	)		$	(798,983	)		$	(5,973,861	)
Net earnings/(loss) per common share from operations:
Basic – cents per share			0.00				(0.29	)			(0.05	)			(0.32	)
Diluted – cents per share			0.00				(0.29	)			(0.05	)			(0.32	)
Weighted average common shares outstanding:
Basic			1,832,852,723				1,750,222,724				1,808,716,468				1,746,423,566
Diluted			1,955,132,196				1,750,222,724				1,808,716,468				1,746,423,566

 

See accompanying Notes to Consolidated Financial Statements.

 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

 

										Other
		Common Stock				Retained Earnings/ (Accumulated Deficit)				Comprehensive Income				Total Equity
Balance at June 30, 2012		$	83,467,987			$	(38,067,666	)		$	2,772,758			$	48,173,079
Net income (loss)			-				(888,053	)			-				(888,053	)
Foreign currency translation, net of tax of $nil			-				-				89,070				89,070
Total comprehensive income/(loss) for the period			-				(888,053	)			89,070				(798,983	)
Stock based compensation			152,062				-				-				152,062
Issue of share capital			3,342,911				-				-				3,342,911
Balance at December 31, 2012		$	86,962,960			$	(38,955,719	)		$	2,861,828			$	50,869,069

 

See accompanying Notes to Consolidated Financial Statements.

 

 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

  

		Six months ended
		31-Dec-12				31-Dec-11
Cash flows from operating activities
Receipts from customers		$	3,487,463			$	4,486,797
Cash received from commodity derivative financial instruments			-				38,508
Payments to suppliers & employees			(4,464,795	)			(4,200,663	)
Interest received			138,544				196,890
Income taxes refund received/( paid)			(100	)			-
Net cash flows provided by/(used in) operating activities			(838,888	)			521,532
Cash flows from investing activities
Payments for plant & equipment			(10,392	)			(51,495	)
Payments for exploration and evaluation			(10,371,563	)			(14,518,508	)
Payments for oil and gas properties			(1,140,341	)			(1,929,585	)
Net cash flows (used in) by investing activities			(11,522,296	)			(16,499,588	)
Cash flows from financing activities
Proceeds from the exercise of options			3,132,420				297,229
Net cash flows provided by financing activities			3,132,420				297,229
Net (decrease) in cash and cash equivalents			(9,228,764	)			(15,680,827	)
Cash and cash equivalents at the beginning of the fiscal period			18,845,894				58,448,477
Effects of exchange rate changes on cash and cash equivalents			108,033				(362,831	)
Cash and cash equivalents at end of fiscal period		$	9,725,163			$	42,404,819

 

See accompanying Notes to Consolidated Financial Statements

 

 

SAMSON O IL & 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, 2012. The year-end Consolidated Balance Sheet presented herein was derived from audited Consolidated Financial Statements, but does not include all disclosures required by GAAP.

 

These Consolidated Financial Statements should be read in conjunction with our audited Consolidated Financial Statements included in our Annual Report on Form 10-K for the fiscal year ended June 30, 2012.

 

Accruals.   The components of accrued liabilities for the periods ended December 31, 2012 and June 30, 2012 include accruals based on estimated costs relating to goods and services provided yet not invoiced and an amount payable for Samson’s employee bonus plan.

 

Recently Adopted Standards

 

In June 2011, the FASB issued ASU No. 2011-05 Presentation of Comprehensive Income.  The ASU amends previously issued authoritative guidance and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.  This amendment removes the option under current GAAP to present the components of other comprehensive income as part of the statements of changes in stockholder’s equity.  The adoption of this guidance did not have an impact on our financial position or results of operations, but has required the Company to present the statements of comprehensive income separately from its statements of equity, as these statements were previously presented on a combined basis.  

 

Recently Issued Pronouncements

 

In December 2011, the FASB issued ASU No. 2011-11 Disclosures about Offsetting Assets and Liabilities. The ASU requires additional disclosures about the impact of offsetting, or netting, on a company's financial position, and is effective for annual periods beginning on or after January 1, 2013 and interim periods within those annual periods, and retrospectively for all comparative periods presented. Under US GAAP, derivative assets and liabilities can be offset under certain conditions. The ASU requires disclosures showing both gross information and net information about instruments eligible for offset in the balance sheet. The Company is currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on the Company's financial position or results of operations.

 

2. Income Taxes

 

		Three months ended								Six months ended
		31-Dec-12				31-Dec-11				31-Dec-12				31-Dec-11
Income tax benefit/(expense)		$	1,366,938			$	693,385			$	2,035,936			$	881,563
Effective tax rate			102.67	%			12.04	%			70	%			13.55	%

  

The Company has current year losses and available prior year cumulative net operating losses that maybe carried forward to reduce taxable income in future years. The Tax Reform Act of 1986 contains provisions that limit the utilization of net operating loss carryforwards if there has been a change in ownership as described in Internal Revenue Code Section 382. The Company’s prior year losses are limited by IRC Section 382, however, current year losses are not subject to these limitations.

 

 

This current year operating loss will be carried back to offset tax paid in the June 30, 2011 year end. This generates a current year benefit and income tax receivable for the tax expected to be refunded from the carry back claim

 

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

 

Subsequent to the December 31, 2012 but prior to the filing of this report, the Company received $5.6 million in income tax refund from the Internal Revenue Service as a refund from taxes paid in a prior period. $0.7 million remains as a receivable in the Balance Sheet.

  

3. Earnings Per Share

 

Basic earnings (loss) per share is calculated by dividing net earnings (loss) attributable to common stock by the weighted average number of shares outstanding for the period. Under the treasury stock method, diluted earnings per share is calculated by dividing net earnings (loss) by the weighted average number of shares outstanding including all potentially dilutive common shares (unexercised stock options). In the event of a net loss, no potential common shares are included in the calculation of shares outstanding since the impact would be anti-dilutive.  The Company's unexercised stock options do not contain rights to dividends. When the Company records a net loss, none of the loss is allocated to the unexercised stock options since the securities are not obligated to share in Company losses. Consequently, in periods of net loss, outstanding options will have no dilutive impact to the Company’s basic earnings per share.

 

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

 

		Three months ended								Six months ended
		31-Dec-12				31-Dec-11				31-Dec-12				31-Dec-11
Dilutive			95,791,227				-				-				-
Anti–dilutive			72,201,619				238,307,570				261,839,351				271,320,247

 

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

 

Continuing operations		Three months ended								Six months ended
		31-Dec-12				31-Dec-11				31-Dec-12				31-Dec-11
Net income (loss)		$	35,484				(5,064,198	)		$	(888,053	)			(5,623,855	)
Basic weighted average common shares outstanding			1,832,852,723				1,750,222,724				1,808,716,468				1,746,423,566
Add: dilutive effect of stock options			95,791,227				-				-				-
Add: bonus element for rights issue			26,488,246				-				-				-
Diluted weighted average common shares outstanding			1,955,132,196				1,750,222,724				1,808,716,468				1,746,423,566
Basic earnings per common share – cents per share			0.00				(0.29	)			(0.05	)			(0.32	)
Diluted earnings per common share – cents per share			0.00				(0.29	)			(0.05	)			(0.32	)

 

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 plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted using the units–of–production method.

 

 

The following table summarizes the activities for the Company’s asset retirement obligations for the six months ended December 31, 2012 and 2011:

 

		Six months ended
		31-Dec-12				31-Dec-11
Asset retirement obligations at beginning of period		$	808,572			$	236,024
Liabilities incurred or acquired			4,691				4,630
Liabilities settled			-				-
Disposition of properties			-				-
Accretion expense			27,109				10,993
Asset retirement obligations at end of period			840,372				251,647
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)			-				-
Long-term asset retirement obligations		$	840,372			$	251,647

 

Discount rates used to calculate the present value vary depending on the estimated timing of the obligation, but typically range between 4% and 9%.

 

5. Equity Incentive Compensation

 

Stock-based compensation is measured at the grant date based on the value of the awards, and the fair value is recognized on a straight-line basis over the requisite service period (usually the vesting period).

 

Total compensation cost recognized in the Statements of Operations for the grants under the Company’s equity incentive compensation plans was $72,011 and $518,116 during the three months ended December 31, 2012 and 2011.

 

Total compensation cost recognized in the Statements of Operations for the grants under the Company’s equity incentive compensation plans was $152,061 and $836,721 during the six months ended December 31, 2012 and 2011.

 

 As of December 31, 2012, there was $49,724 of total unrecognized compensation cost related to outstanding stock options. This cost is expected to be recognized over two years.

 

6. Hedging and Derivative Instruments

 

Commodity Derivative Agreements. The Company has in the past utilized swap and collar option contracts to hedge the effect of price changes on a portion of its future oil production but it is not currently doing so. The objective of the Company’s hedging activities and the use of derivative financial instruments was to achieve more predictable cash flows. While the use of these derivative instruments limits the downside risk of adverse price movements, they also may limit future revenues from favorable price movements.    

 

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts were all with a single multinational bank with no history of default with the Company. The derivative contracts were subject to termination by a non-defaulting party in the event of default by one of the parties to the agreement. No collateral was provided in relation to the derivative contracts entered into by the Company. Collateral may, however, be required for future contracts if the Company chooses to enter into additional derivative contracts in the future.

 

The Company has elected not to apply hedge accounting to any of its derivative transactions and, consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income for those commodity derivatives that would qualify as cash flow hedges.

 

For six months ended December 31, 2011 realized gain in relation to commodity derivative contracts amounted to $0.02 million. As of December 31, 2011, the Company has no outstanding derivative agreements in relation to its oil or gas production.

 

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 in puts. The FASB has established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).

 

 

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

 

·

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

 

·

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

 

·

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

 

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of December 31, 2012 and June 30, 2012.

 

		Carrying value at December 31, 2012				Level 1				Level 2				Level 3				Fair Value at December 31, 2012
Assets
Cash and cash equivalents		$	9,725,163			$	9,725,163			$	-			$	-			$	9,725,163

  

		Carrying value at June 30, 2012				Level 1				Level 2				Level 3				Fair Value at June 30, 2012
Assets
Cash and cash equivalents		$	18,845,894			$	18,845,894			$	-			$	-			$	18,845,894

 

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

 

Commodity Derivative Contracts.   In previous periods, the Company’s commodity derivative instruments consisted of collar contracts for oil. The Company valued the derivative contracts using industry standard models, based on an income approach, which considers various assumptions including quoted forward prices and contractual prices for the underlying commodities, time value and volatility factors, as well as other relevant economic measures. Substantially all of the assumptions can be observed throughout the full term of the contracts, can be derived from observable data or are supportable by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the fair value hierarchy. For six months ended December 31, 2011 the realized gain in relation to commodity derivative contracts amounted to $0.02 million. As of December 31, 2011, the Company has no outstanding derivative agreements in relation to its oil or gas production.

 

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

 

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

 

 

8. Commitments and Contingencies

 

Environmental Matters

 

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

 

Contingent Assets or Liabilities

There are no unrecorded contingent assets or liabilities in place for the Company at December 31, 2012 or June 30, 2012.

 

9. Capitalized Exploration Expense

 

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

 

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

 

¨

the period for which Samson has the right to explore;

 

¨

planned and budgeted future exploration expenditure;

 

¨

activities incurred during the year; and

 

¨

activities planned for future periods.

 

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

 

Currently, we have capitalized exploration expenditures of $9.7 million and undeveloped capitalized acreage of $12.4 million.  This primarily relates to costs in relation to our Hawk Springs (including 3D seismic acquisition costs) and Roosevelt projects (including the drilling and permitting of exploration wells). The costs include acreage acquisition costs in both of Hawk Springs and Roosevelt project areas. During the three months ended December 31, 2012 we continued with our drilling activities on our Spirit of America II well in our Hawk Springs project in Goshen County, Wyoming. To date we have capitalized approximately $7.2 million in relation to this well, including $0.2 million in the current quarter. Since the Company continues to pursue further hydraulic fracturing for this well, the well remains in exploration stages and no conclusions regarding potential reserves have been made.

 

10.  Issue of Share Capital

 

During the six months ended December 31, 2012, 214,004,644 Australian 1.5 cent options were exercised for net proceeds of $3,342,911 to us. The options were issued in public rights offering conducted in October 2009. The remaining 10,614,326 listed options expired unexercised.

 

11. Cash Flow Statement

 

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

 

 

		Six months ended
		31-Dec-12				31-Dec-11
Net (loss) after tax		$	(888,053	)		$	(5,623,855	)
Depletion, depreciation and amortization			1,089,618				1,353,022
Stock based compensation			152,062				836,721
Accretion of asset retirement obligation			27,109				10,993
Impairment expense			244,589				-
Exploration and evaluation expenditure			400,950				4,740,828
Net (gain)/loss on fair value movement of fixed forward swaps			-				22,268
Changes in assets and liabilities:
(Increase)/decrease in receivables			24,074				(1,275,190	)
(Increase)/decrease in income tax receivable/deferred tax asset			(2,036,036	)			(921,563	)
Increase/(decrease) in provision for annual leave			(37,643	)			38,814
Increase/(decrease) in payables			184,442				1,339,494
NET CASH FLOWS USED IN OPERATING ACTIVITIES		$	(838,888	)		$	521,532

 

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, 2012, included in our Annual Report on Form 10-K and the Consolidated Financial Statements included elsewhere herein.

 

Overview

 

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

 

Our net oil production was 17,744 barrels of oil for the quarter ended December 31, 2012 compared to 18,580 barrels of oil for the quarter ended December 31, 2011.  Our net gas production was 51,587 Mcf for the quarter ended December 31, 2012 compared to 58,487 Mcf for the quarter ended December 31, 2011.

 

Our net oil production was 36,626 barrels of oil for the six months ended December 31, 2012 compared to 43,516 barrels of oil for the six months ended December 31, 2011. Our net gas production was 92,678 Mcf for the six months ended December 31, 2012 compared to 117,669 Mcf for the six months ended December 31, 2011.

 

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. Our execution of that strategy today, however, is dependent on our ability to raise additional capital to fund any new exploration and development drilling.

 

Notable Activities and Status of Properties during the Quarter Ended December 31, 2012 and Current Activities

 

Undeveloped Properties: Exploration Activities

 

Hawk Springs Project, Goshen County, Wyoming

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

Samson 37.5% to 100% Working Interest

Production to date from the Niobrara Formation in the Defender US33 #2-29H well in Goshen County, WY has been sporadic due to the chemistry of the Niobrara oil, which had been producing an unusually high concentration of paraffin and asphaltene (11.74%). After a successful workover during the current quarter, the well had produced 691 barrels of oil over a 38 day period, however the well was offline for the majority of the quarter due to a pump failure. Further analysis of the hydraulic fracture treatment shows that the effective frac length was extremely limited and because of this the well is on a timer and pumps for only a few hours a day.

 

The limited frac length and the lack of un-stimulated permeability offers an opportunity to design a suitable additional stimulation treatment. A chemical injection program, run during the quarter has alleviated the paraffin and asphaltene problems.

 

 

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

 

To date approximately $7.2 million has been capitalized in relation to the SOA #2 and carried in Capitalized Exploration Expenditure on the Balance Sheet, including $0.2 million during the quarter ended December 31, 2012. One more stage of the well remains to be fraced prior to the final determination of the outcome of this well. Depending on the results of the final frac of this well, it is possible that some or all of the costs currently deferred in relation to this well will have to be written off to the Income Statement. The final frac of the SOA #2 has not yet been scheduled, however, and we therefore have not established the time frame in which the SOA #2 will be completed.

 

As a result of this analysis, the strategy is to pursue a farmout to enable two prospects to be drilled: Bluff Federal, which relies on a four way dip closure and American Eagle, which is an amplitude anomaly unaffected by the faulting seen in the SOA#2 well.

 

Samson has two contiguous areas in the Hawk Springs Project. One of the areas is a joint venture with a private company and the other is subject to a joint venture with a Halliburton company.

 

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.

 

Our first Bakken appraisal (exploratory) well in the Roosevelt project area on the Ft. Peck Indian Reservation, the Australia II 12 KA 6 well, was drilled in December 2011. This well was drilled to a total measured depth of 14,972 feet with the horizontal lateral remaining within the target zone for the entire lateral length. Cumulative oil production for the well is 5,497 stock tank barrels (“STB”).

 

During the quarter parted sucker rods were successfully repaired and the well was returned to production on October 25th. The well produced 810 barrels of oil over a thirteen day period before the pump stopped working because of a scale accumulation due to the high mineral content of the formation water. The pump was replaced and the well produced 402 STB however it has been off line since December 8^th due to a further mechanical failure and is currently awaiting repairs. The initial drilling costs of $13.1 million were expensed to the Statement of Operations during the year ended June 30, 2012. In addition $0.1 million of costs have been expensed to the Statement of Operations through December 31, 2012 as exploration expenditure.

 

Our second Bakken well, Gretel II, was drilled in January 2012 and fracture stimulated in March 2012. This well was drilled on the north side of the Brockton Fault zone, which may define the western edge of the continuous Bakken oil accumulation. The Gretel II has produced oil, but with a high water cut. The toe end of the lateral portion of the Gretel well was plugged back to a depth of 14,002 feet to minimize water production from the faults that were encountered beyond this depth.

 

The plug back was mechanically successful and the water production was reduced; however the oil rate has not increased and production for the well remains at around 1 to 3 BOPD. The well will be pumped for a further two months after which it may be converted to a water disposal well unless an economic oil rate is established. The initial drilling costs of $11.6 million were expensed to the Statement of Operations during the year ended June 30, 2012. In addition $0.22 million of costs have been expensed to the Statement of Operations through December 31, 2012 as exploration expenditure.

 

We also currently have a 1280-acre approved spacing order for a third exploratory well in this project: named Prairie Falcon. The drilling location of this well is south of the Brockton Fault zone and is north of the Abercrombie 1-10H well, which had initial production of 630 BOPD. We are monitoring the production rate from the Abercrombie well and waiting on the results of two offset wells, the Custer 1-7H well (SSN 2.2% WI) which is about to spud and another well yet to be named and drilled. These latter two wells will help define a productive extension to the Elm Coulee Bakken fairway. Any further exploration or development of our Roosevelt Project in the fiscal year ending June 30, 2013, will depend upon our success in obtaining additional capital and our results of operations.

 

 

Drilling Program

Hawk Springs Project, Goshen County, Wyoming

Wildcat (Exploratory) Permo-Penn Hartville Formation, Northern D-J Basin

Bluff Federal #1-12

American Eagle US 21#1

Samson is presently anticipating having a 47% carried interest after a farmout of the project

As noted above we are in the process of marketing a farmout of our Hawk Springs project in an effort to have two prospects tested; however there is no guarantee we will be able to farmout the Hawk Springs project.

 

The Bluff Federal prospect will test a four-way dip structural closure just a few miles away from the Spirit of America US34 #2-29 well (SOA #2) and more than 2000’ shallower in depth. The excellent reservoir properties and oil shows seen in the SOA #2 well has allowed us to high-grade the Bluff Federal prospect.

 

We would also like to test the American Eagle US21 prospect. This prospect is an amplitude anomaly associated with the excellent reservoir quality rock observed in the SOA #2 well.

 

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Bakken & Three Forks infill wells

Samson ~60% Working Interest

We and the Operator group have negotiated an acreage swap for the Middle Bakken/First Bench of the Three Forks (MB/TF), whereby we will acquire these parties’ undeveloped acres in the Northern Tier and will divest undeveloped acres in the Southern Tier. Following the swap, we will own 64% and 57%, respectively, in the two overlapping 1,280 acre spacing units located in the Northern Tier. We will be the Operator for the entire Northern Tier. Our net production from current producing wells is not affected.

 

The formal agreement documenting the swap has been completed between us and the Operator. We are waiting on the remaining working interest owners to complete the paper-work in order to finalize the agreement. We have identified 14 infill development wells that can be drilled between the existing Bakken wells and in the Three Forks Formation with 160 acre spacing. The North Dakota Industrial Commission has approved the spacing order for these wells and the first four drilling permits have been received.

 

An initial 8 infill development wells are planned to be drilled from two pads utilizing the skiddable platform available on Frontier Rig 24. The development wells are designed as 6,300 foot horizontals in either the Middle Bakken or the First Bench of the Three Forks. The wells will be “batched” drilled, which is expected to result in considerable cost savings. However our ability to complete this development plan is contingent on the completion of a planned debt financing or another capital raising program.

 

Developed Properties: Production Activities

 

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson various Working Interests

 

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

 

The Harstad #1-15H well (34.5% working interest) was down for 6 days during the quarter due to weather/storm related issues and as a result averaged 34.1 BOPD for the quarter from the Mississippian Bluell Formation. The well has cumulative gross production of 102 MSTB and 82 MMscf.

 

The Leonard #1-23H well (10% working interest, 37.5% after non-consent penalty) was down for 12 days during the quarter for a workover. The well averaged 40.7 BOPD and 51.6 Mscf/D during the quarter. To date, the Leonard #1-23H well has produced approximately 102 MSTB and 105 MMscf.

 

The Gene #1-22H well (30.6% working interest) was down for approximately 38 days during the quarter for a workover. The well produced at an average daily rate of 56 BOPD and 40 Mscf/D during the quarter. The cumulative production to date is approximately 134 MSTB and 147 MMscf.

 

The Gary #1-24H (37% working interest) well was down for 3 days during the quarter due to an electrical failure. The well averaged 96 BOPD and 178 Mscf/D during the quarter. The cumulative production to date is approximately 136 MSTB and 226 MMscf.

 

The Rodney #1-14H (27% working interest) was down for one day during the quarter. The well produced at an average daily rate of 84 BOPD and 171 Mscf/D during the quarter. The cumulative production to date is approximately 102 MSTB and 145 MMscf.

 

 

The Earl #1-13H (32% working interest) well was down for 19 days during the quarter due to surface equipment failure and as a result produced at an average daily rate of 166 BOPD and 293 Mscf/D. Cumulative production to date is approximately 161 MSTB and 230 MMscf.

 

The Everett #1-15H (26% working interest) well was the sixth Bakken well drilled in the North Stockyard Oilfield. The Everett well produced at an average daily rate of 133 BOPD and 217 Mscf/D during the quarter. Cumulative production to date is approximately 76 MSTB and 109 MMscf.

 

Sabretooth Gas Field, Brazoria County Texas

Oligocene Vicksburg Formation, Gulf Coast Basin

Samson 9.375% Working Interest

Production for the Davis Bintliff #1 well was increased on October 3rd due to a strengthening of the gas price. The average rate increased to 3.9 MMscf/D and 41 BOPD for the quarter. Cumulative production to date is approximately 5.3 Bscf and 62 MSTB.

 

Abercrombie 1-10H well, Richland County, Montana

Mississippian Bakken Formation, Williston Basin

Samson 2.82% working interest

The Abercrombie #1-10H well has produced a cumulative 29,000 barrels of oil while producing at an average rate of approximately 92 BOPD and 300 Mscf/D during the quarter.

 

Riva Ridge 6-7-33-56H well, Sheridan County, Montana

Mississippian Bakken Formation, Williston Basin

Samson 0.76% working interest

The Riva Ridge 6-7-33-56H (SSN 0.76% W.I.) is producing at an average rate of approximately 61 BOPD and 42 Mscf/D during the quarter.

 

The Riva Ridge II (SSN 0.76% W.I.) has been drilled and is currently being completed in the Three Forks Formation.

 

Looking Ahead

 

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

 

·

The continued appraisal and development, likely through a farmout of our Hawk Springs and Roosevelt projects, including multiple conventional targets in the Permian and Pennsylvanian formations on our acreage in Goshen County, Wyoming and Roosevelt County, Montana respectively.

 

·

The continued development of our North Stockyard project in Williams County, North Dakota.

 

Our ability to meet these objectives will be materially affected by our ability to raise additional capital to fund the planned development programs.

 

Results of Operations

 

In the quarter ended December 31, 2012, we reported a net gain of $0.04 million after an income tax benefit of $1.4 million.

 

For the six months ended December 31, 2012 we reported a net loss of ($0.89) million after an income tax benefit of $2.0 million, which can be attributed to lease operating expenses, depletion and depreciation and other costs exceeding our revenue.

 

Operating data

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

 

		Three months ended
		31-Dec-12				31-Dec-11				30-Sep-12
Production Volume
Oil (Bbls)			17,744				18,580				18,882
Natural gas (Mcf)			51,587				58,487				41,091
BOE			26,342				28,327				25,731
Oil Price per Bbl Produced (in dollars):
Realized price		$	82.13			$	89.66			$	76.61
Natural Gas Price per Mcf Produced (in dollars):
Realized price		$	4.24			$	4.49			$	3.55
Expense per BOE (in dollars):
Lease operating expenses		$	32.10			$	8.07			$	25.56
Production and property taxes		$	7.44			$	8.01			$	6.00
Depletion, depreciation and amortization		$	18.02			$	21.22			$	22.05
General and administrative expense		$	50.73			$	73.29			$	57.63

  

 

 

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

 

		31-Dec-12				31-Dec-11
Production Volume
Oil (Bbls)			36,626				43,516
Natural gas (Mcf)			92,678				117,669
BOE			52,072				63,128
Oil Price per Bbl Produced (in dollars):
Realized price		$	79.28			$	88.30
Natural Gas Price per Mcf Produced (in dollars):
Realized price		$	3.94			$	4.87
Expense per BOE (in dollars):
Lease operating expenses		$	28.87			$	8.85
Production and property taxes		$	6.73			$	8.28
Depletion, depreciation and amortization		$	20.01			$	20.89
General and administrative expense		$	54.14			$	62.76

 

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

 

		Three months ended
		31-Dec-12				31-Dec-11				2Q12 to 2Q11 change				30-Sep-12				2Q12 to 1Q12 Change
Oil sales		$	1,457,238			$	1,666,006			$	(208,768	)		$	1,446,537			$	10,701
Gas sales			218,885				263,087				(44,202	)			145,764				73,121
Other liquids			-				2,255				(2,255	)			4,457				(4,457	)
Interest income			55,139				85,431				(30,292	)			71,640				(16,501	)
Other			111,469				1,979				109,490				12				111,457
											-								-
Lease operating expense			(1,041,761	)			(455,495	)			(586,266	)			(811,989	)			(229,772	)
Depletion, depreciation and amortization			(498,851	)			(619,713	)			120,862				(590,767	)			91,916
Exploration and evaluation expenditure			(39,006	)			(4,619,278	)			4,580,272				(361,944	)			322,938
Accretion of asset retirement obligations			(13,675	)			(5,559	)			(8,116	)			(13,434	)			(241	)
General and administrative			(1,336,332	)			(2,076,296	)			739,964				(1,482,812	)			146,480
Income tax (provision)/ benefit			1,366,938				693,385				673,553				668,998				697,940
Net (loss)		$	280,044			$	(5,064,198	)		$	5,344,242			$	(923,538	)		$	1,203,582

 

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

 

 

		Six months ended
		31-Dec-12				31-Dec-11				2Q12 to 2Q11 change
Oil sales		$	2,903,775			$	3,842,442			$	(938,667	)
Gas sales			364,907				573,263				(208,356	)
Other liquids			4,199				7,921				(3,722	)
Interest income			126,779				199,237				(72,458	)
Other			111,481				21,136				90,345
											-
Lease operating expense			(1,853,750	)			(1,082,292	)			(771,458	)
Depletion, depreciation and amortization			(1,089,618	)			(1,353,022	)			263,404
Exploration and evaluation expenditure			(400,950	)			(4,740,828	)			4,339,878
Accretion of asset retirement obligations			(27,109	)			(10,993	)			(16,116	)
General and administrative			(2,819,114	)			(3,962,282	)			1,143,168
Income tax (provision)/ benefit			2,035,936				881,563				1,154,373
Net income (loss)		$	(643,464	)		$	(5,623,855	)		$	4,980,391

 

Three Months Comparison of Quarter Ended September 30, 2012 to Quarter Ended September 30, 2012 and six months comparison of the period ended December 31, 2012 to the period ended December 31, 2011.

 

Oil and gas revenues

 

Oil revenues decreased slightly from $1.66 million for the three months ended December 31, 2011 to $1.46 million for the three months ended December 31, 2012 as a result of a decrease in our oil production, coupled with a decrease in the realized price.  Oil production decreased slightly from 18,580 barrels for the quarter ended December 31, 2011 to 17,744 barrels for the quarter ended December 31, 2012.  Our realized oil price decreased from $89.66 for the quarter ended December 31, 2011 to $82.13 for the quarter ended December 31, 2012.

 

Oil revenues also decreased from $3.84 million for the six months ended December 31, 2011 to $2.90 million for the six months ended December 31, 2012 as a result of a decrease in our oil production, coupled with a decrease in the realized price.  Oil production decreased from 43,516 barrels for the six months ended December 31, 2011 to 36,626 barrels for the six months ended December 31, 2012.  Our realized oil price decreased from $88.30 for the six months ended December 31, 2011 to $79.28 for the six months ended December 31, 2012.

 

Gas revenues also decreased slightly from $0.26 million for the quarter ended December 2011 to $0.22 million for the quarter ended December 31, 2012 due a combination of a decrease in production volume and realized gas price. Production decreased by 12%, while the realized gas price decreased from $4.49 for the quarter ended December 31, 2011 to $4.25 for the quarter ended December 31, 2012.

 

Gas revenues also decreased from $0.57 million for the six months ended December 2011 to $0.36 million for the six months ended December 31, 2012 due a combination of a decrease in production volume and realized gas price. Production decreased by 21%, while the realized gas price decreased from $4.87 for the six months ended December 31, 2011 to $3.94 for the six months ended December 31, 2012.

 

Exploration expense

 

Exploration expenditure decreased significantly from $4.6 million for the quarter ended December 31, 2011 to $0.04 million for the quarter ended December 31, 2012 primarily as a result of writing off $4.5 million in expenditure related to the drilling of the Spirit of America I well during the quarter ended December 31, 2011. This well experienced numerous mechanical and operational difficulties and ultimately failed to reach its target.

 

Exploration expenditure decreased significantly from $4.7 million for the six months ended December 31, 2011 to $0.4 million for the six months ended December 31, 2012 primarily as a result of writing off $4.5 million in expenditure related to the drilling of the Spirit of America I well during the six months ended December 31, 2011. This well experienced numerous mechanical and operational difficulties and ultimately failed to reach its target. During the six months ended December 31, 2012 the exploration expenditure relates to expenses incurred on our Australia II and Gretel II leases as well as other general exploration expenditure.

 

We currently have approximately $7.2 million capitalized in exploration expense on the balance sheet in relation to the Spirit of America II well. While this well is still being completed, depending on the outcome of it, it is possible that we will need to recognize impairment expense in relation to this expenditure. The magnitude of impairment expense, if any, is not yet known and will depend on the results after the completion of the well.

 

 

Lease operating expense

 

Lease operating expenses increased from $0.46 million for the quarter ended December 31, 2011 to $1.04 million for the quarter ended December 31, 2012. This is largely due to increased lease operating expense in our North Stockyard field as a result of the high salt water content as well as lease operating costs being incurred in the Roosevelt Field in relation to our Australia II and Gretel II wells. The Gretel II well in particular produces a significant amount of water which, the disposal of which leads to increased lease operating costs.

 

Lease operating expenses increased from $1.08 million for the six months ended December 31, 2011 to $1.85 million for the six months ended December 31, 2012. This is largely due to increased lease operating expense in our North Stockyard field as a result of the high salt water content as well as lease operating costs being incurred in the Roosevelt Field in relation to our Australia II and Gretel II wells. The Gretel II well in particular produces a significant amount of water which, the disposal of which leads to increased lease operating costs.

 

Depletion, depreciation and amortization expense

 

Depletion, depreciation and amortization expense decreased from $0.62 million for the quarter ended December 30, 2011 to $0.5 million for the quarter ended December 31, 2012. This decrease is due to a decrease in production. Depreciation, depletion and amortization expense per BOE decreased from $21.22 for the quarter ended December 31, 2011 compared to $18.02 for the quarter ended December 31, 2012.

 

Depletion, depreciation and amortization expense decreased from $1.35 million for the six months ended December 31, 2011 to $1.09 million for the six months ended December 31, 2012. This decrease is due to a decrease in production. Depreciation, depletion and amortization expense per BOE remained consistent at $20.89 for the six months ended December 31, 2011 compared to $20.01 for the six months ended December 31, 2012.

 

Impairment expense

 

Impairment expense increased from $nil for the quarter and six months ended December 30, 2011 to $0.24 million for the same periods ended December 31, 2012. The majority of impairment recognised is in relation to two wells drilled in our Roosevelt prospect – the Abercrombie and Riva Ridge. Our working interest in these two wells is minor. We have received production from these wells, however based on our most recent reserve report it would appear these wells will not recover their costs and have been written down to their discounted cash flow value.

 

General and administrative expense

 

General and administrative expense decreased from $2.08 million for the quarter ended December 31, 2011 to $1.34 million for the quarter ended December 31, 2012.  Included within general and administrative expense is $0.68 million of employee benefits (including share based payments) for the current quarter compared with $1.25 million for the prior quarter. This decrease is due to lower share based payments expense and lower employee bonus accruals.  Other general and administrative costs including but not limited to legal fees, audit fees, investor relations and travel have also decreased slightly from $0.82 million for the quarter ended December 31, 2011 to $0.66 million for the quarter ended December 31, 2012. This is due to continued efforts to reduce administration expenditure where possible.

 

General and administrative expense decreased from $3.96 million for the six months ended December 31, 2011 to $2.82 million for the six months ended December 31, 2012.  Included within general and administrative expense is $1.37 million of employee benefits (including share based payments) for the current period compared with $2.39 million for the prior quarter. This decrease is due to lower share based payments expense and lower employee bonus accruals.  Other general and administrative costs including but not limited to legal fees, audit fees, investor relations and travel have also decreased slightly from $1.57 million for the six months ended December 31, 2011 to $1.45 million for the six months ended December 31, 2012. This is due to continued efforts to reduce administration expenditure where possible.

 

Income tax (expense)/benefit - outstanding

 

Income tax benefit increased from a benefit of $0.7 million for the quarter ended December 30, 2011 to a benefit of $1.37 million for quarter ended December 31, 2012.  The tax benefit recognized in the current year is a result of a portion of this year’s operating losses being carried back to the income tax expense recognized in the year ended June 30, 2011.

 

Income tax benefit increased from a benefit of $0.88 million for the six months ended December 30, 2011 to a benefit of $2.04 million for six months ended December 31, 2012.  The tax benefit recognized in the current year is a result of a portion of this year’s operating losses being carried back to the income tax expense recognized in the year ended June 30, 2011.

 

Subsequent to December 31, 2012 but prior to the filing of this report, we received an income tax refund of $5.6 million in relation to this benefit and the benefit recognised for the year ended June 30, 2012.

 

 

Cash Flows

 

The table below shows cash flows for the three month period ended: 

 

		Six months ended
		31-Dec-12				31-Dec-11
Cash provided by/(used in) operating activities		$	(838,888	)		$	521,532
Cash (used in)/provided by investing activities			(11,522,296	)			(16,499,588	)
Cash provided by/(used in) financing activities			3,132,420				297,229

 

Cash provided by operations decreased from an inflow of $0.52 million for the six months ended December 31, 2011 to cash outflow ($0.84) million for the six months ended December 31, 2012. Receipts from customers decreased from $4.5 million for the six months ended December 31, 2011 to $3.5 million for the six months ended December 31, 2012 as result of a decrease in production.

 

Cash used in investing activities decreased from cash outflow of $16.5 million for the six months ended December 31, 2011 to a cash outflow of $11.5 million for the six months ended December 31, 2012. The cash outflow for the six months ended December 31, 2012 relates to drilling activities for our Spirit of America II well in our Hawk Springs project, land and seismic acquisition costs for our South Prairie project in North Dakota and other exploration activities. The cash outflow for the period ended December 31, 2011 relates to drilling and exploration activities conducted in our Hawk Springs and Roosevelt projects.

 

Cash provided by financing activities increased from a cash inflow of $0.3 million for the six months ended December 31, 2011 to cash inflow of $3.1 million for the six months ended December 31, 2012. Cash inflow for both of the six month periods is a result of the exercise of options during the respective period. The remaining unexercised 1.5 cent options as of December 31, 2012 have expired . All other options outstanding as at December 31, 2012 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 the fiscal year ending June 30, 2013 as well. In connection with these activities, in April of 2012, we contracted for the use of Frontier Rig 24, a newly manufactured and highly sophisticated drilling rig, for an 18 month period at a cost of $14.2 million. The lease for this rig began on January 21, 2013, when we began incurring rental charges of $26,000 per day. Our plan for this new rig is to deploy it for our North Stockyard Field development plan, discussed above. While we have completed the acreage swap for the program and have four drilling permits, we have not yet raised the new debt or equity capital needed to cover the drilling costs. Until we raise the funds needed to commence the drilling program, the $26,000 per day rental charges for the Frontier Rig 24 will be a substantial burden on our cash flow and liquidity. We recently negotiated a $5 million cap on cancellation charges for this lease but, if we are unsuccessful in raising new capital for the North Stockyard development program in the near future, we may be required to cancel the lease of Frontier Rig 24 and incur the $5 million cancellation fee. This fee, which would be in addition to and not offset by the $26,000 per diem charges incurred before cancellation, would have a material adverse impact on our liquidity and capital resources. In addition to the impact of the cancellation fee, a failure to obtain financing for the North Stockyard Field development could also have an adverse impact on our future cash flows and liquidity, as the anticipated cash flow from its development would be delayed.

 

Our current budget for exploration, exploitation and development capital expenditures in fiscal year ending June 30, 2013 is $22 million, of which we incurred approximately $12 million during the first six months of the fiscal year. The remaining $10 million in planned capital expenditures, most of which depends upon obtaining additional financing relates to:

·

The completion of a salt water disposal well in our North Stockyard project as well as at least three of the eight planned development wells in this project and

·

the initial well in our South Prairie Project in North Dakota.

 

We expect to fund our fiscal year 2013 capital expenditures with cash on hand and cash flow from operations, and through a debt financing or another capital raising program. In addition, there is a possibility that we will pursue one or more significant acquisitions that require equity or debt financing. However, there is no guarantee that we will be able to fund all of the planned expenditure from our existing working capital or be able to raise adequate funds through the equity or debt markets.

 

Subsequent to December 31, 2012 but prior to the filing of this report, we received $5.6 million from the Internal Revenue Service as a refund on taxes previously paid. These funds will contribute to our upcoming expenditures.

 

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 fiscal year ending June 30, 2013, 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 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.

 

 

Currently our two main sources of liquidity are cash on hand, which was $9.75 million at December 31, 2012, and cash flow from operations. We also continue to explore various methods of obtaining equity capital or debt financing. During the past two fiscal years, our two main sources of liquidity were (i) approximately $73.2 million cash received from the sale of 24,166 acres in Goshen County, Wyoming to Chesapeake Energy Corporation and (ii) $6.3 million received from the sale of our interests in the Jonah and Lookout Wash fields. Both sales occurred during the fiscal year ended June 30, 2011. During the recent years prior to the fiscal year ended June 30, 2011, our primary sources of liquidity were (i) equity sales and (ii) a loan facility with Macquarie Bank Limited, which we repaid in full on May 30, 2011.

 

Our cash on hand position has decreased from the same period in the previous year largely due to exploration expenditures which have not produced meaningful cash flow to date from production results. In particular, both of the two Roosevelt project wells drilled in the fiscal year ended June 30, 2012 have so far failed to deliver positive results and one well in the Hawk Springs project well was also drilled unsuccessfully. 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, 2012 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.

 

During the six months ended December 31, 2012, 214,004,644 1.5 Australian cent (A$0.015) warrants were exercised for net proceeds of $3.3 million to us. The warrants exercised were originally issued in a public rights offering conducted in October 2009. All unexercised options from that offering expired on December 31, 2012.

 

Item 3.   Quantitative and Qualitative Disclosures About Market Risk.

 

There were no material changes to the disclosure made in our Annual Report on Form 10-K for the year ended June 30, 2012 regarding this matter.

 

Item 4.    Controls and Procedures.

 

As of December 31, 2012, 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, 2012, 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 six months ended December 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time in the future.

 

Part II — Other Information

 

Item 1.    Legal Proceedings.

 

None.

 

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

 

Item 1A.   Risk Factors.

 

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended June 30, 2012.  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. Among those risks are those described in the following new Risk Factor:

 

 

Estimates as to the need to make contractual commitments to obtain necessary equipment may not be accurate.

 

Because we are required to obtain drilling rigs and other equipment necessary to conduct our exploration and development programs from third parties, and the quality of such rigs and equipment is important to the success of those drilling programs, we may elect to make long term contractual commitments to ensure the availability of such equipment. We are required to estimate the future need for, availability of, and reasonable pricing for, such rigs and equipment based on anticipated demand, which in turn depends on future oil and gas prices, the success of other companies’ drilling efforts and other economic factors. If our estimates are not accurate, rigs or other equipment may not be available at the times and places required to commence our drilling programs, or we may commit to the use of rigs or equipment that we cannot fully utilize. Unavailable rigs and equipment could delay scheduled drilling programs and adversely affect results of operations, while unused rigs and equipment could impair cash flow and diminish capital resources. In particular, we recently contracted for the use of a newly manufactured drilling rig for 18 months at a cost of $26,000 per day but we cannot use that rig until we obtain new capital to finance the North Stockyard Field drilling program for which the rig was contracted. There is no assurance that we will be able to obtain the financing needed to commence the planned drilling program in a timely manner and thereby avoid paying a $5 million cancellation fee for this drilling rig. Correspondingly, there is no assurance that we will be able to obtain high quality drilling rigs and equipment in the future when we need them if we fail to make long term commitments for such rigs and equipment in advance.

  

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

 

Not applicable.

 

Item 3.    Defaults Upon Senior Securities.

 

Not applicable.

 

Item 4.    Removed and Reserved.

 

Not applicable.

 

 

Item 5.    Other Information.

 

Not applicable.

 

Item 6.    Exhibits.

 

Exhibit No.		Title of Exhibit
31.1*		Rule 13a-14(a)/15d-14(a) Certification of the Principal Executive Officer as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*		Rule 13a-14(a)/15d-14(a) Certification of the Principal Financial Officer as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*		Certifications of the Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C., 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101**		The following financial information from Samson Oil & Gas Limited’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2012 is formatted in XBRL (eXtensible Business Reporting Language): (i)  Consolidated Balance Sheets at December 31, 2012, (ii)  Consolidated Statements of Operations for the three months ended December 31, 2012 and December 31, 2011 and for the six months ended December 31, 2012 and December 31 2011 (iii)  Consolidated Statement of Changes in Stockholders’ Equity at December 31, 2012 (iv)  Consolidated Statements of Cash Flows for the six months ended December 31, 2012 and December 31, 2011, and (v) the Notes to Consolidated Financial Statements.  The information in Exhibit 101 is “furnished” and not “filed,” as provided in Rule 402 of Regulation S-T.

 

*Filed herewith

** Furnished herewith

 

 

Signatures

 

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

 

	SAMSON OIL & GAS LIMITED
Date:   February 11, 2013	By:	/s/ Terence Barr
		Terence M. Barr
		Managing Director, President and Chief Executive Officer (Principal Executive Officer)
Date:  February 11, 2013	By:	/s/ Robyn Lamont
		Robyn Lamont
		Chief Financial Officer (Principal Financial Officer)