UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

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

 

For the quarterly period ended March 31, 2013

 

OR

 

¨	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 2,114,831,858 ordinary shares outstanding as of May 6, 2013.

  

 

Table of Contents

 

SAMSON OIL & GAS LIMITED

FORM 10-Q

QUARTER ENDED MARCH 31, 2013

 

TABLE OF CONTENTS

 

		Page
Part I — Financial Information		4
Item 1.	Financial Statements (unaudited).	4
Consolidated Balance Sheets, March 31, 2013 and June 30, 2012		4
Consolidated Statement of Operations and Comprehensive Income (Loss) for the three months ended March 31, 2013 and 2012 and nine months ended March 31, 2013 and 2012		5
Consolidated Statement of Changes in Stockholders’ Equity for the nine months ended March 31, 2013		6
Consolidated Statement of Cash Flows for the nine months ended March 31, 2013 and 2012		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		22
Item 1.	Legal Proceedings.	22
Item 1A.	Risk Factors.	22
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.	22
Item 6.	Exhibits.	22
Signatures		23

 

i

 

 

FORWARD-LOOKING STATEMENTS

 

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

 

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

 

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

 

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

 

·

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

 

·

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

 

·

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

 

·

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

 

·

timing, amount, and marketability of production;

 

·

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

 

·

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

 

·

effectiveness of management strategies and decisions;

 

	·	the strength and financial resources of our competitors;
	·	oil and natural gas prices and demand;

 

·

our entrance into transactions in commodity derivative instruments;

 

·

climatic conditions;

 

·

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

 

·

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

  

·

uncontrollable flows of oil, gas or well fluids.

 

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

 

 

Part I — Financial Information

 Item 1.   Financial Statements.

  SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

		31-Mar-13				30-Jun-12
ASSETS		(unaudited)
CURRENT ASSETS
Cash and cash equivalents		$	15,330,000			$	18,846,000
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively			2,126,000				1,288,000
Prepayments			963,000				344,000
Pipe inventory – held by third party			79,000				79,000
Income tax receivable			787,000				4,347,000
Total current assets			19,285,000				24,904,000
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment of $17,731,000 and $16,113,000 at March 31, 2013 and June 30, 2012, respectively.			16,429,000				13,755,000
Other property and equipment, net of accumulated depreciation and amortization of $328,000 and $252,000 at March 31, 2013 and June 30, 2012, respectively			378,000				448,000
Net property, plant and equipment			16,807,000				14,203,000
OTHER ASSETS
Undeveloped capitalized acreage			12,351,000				10,017,000
Capitalized exploration expense			2,355,000				6,498,000
Other			64,000				100,000
TOTAL ASSETS		$	50,862,000			$	55,722,000
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable		$	4,557,000			$	5,269,000
Accruals			522,000				1,230,000
Provision for annual leave			213,000				234,000
Total current liabilities			5,292,000				6,733,000
Capitalized lease			-				7,000
Asset retirement obligations			854,000				809,000
TOTAL LIABILITIES			6,146,000				7,549,000
STOCKHOLDERS’ EQUITY – nil par value
Common stock, 2,095,649,046 (equivalent to 104,782,452 ADR’s) and 1,771,891,827 (equivalent to 88,594,591 ADR’s) shares issued and outstanding at March 31, 2013 and June 30, 2012, respectively)			89,741,000				83,468,000
Other comprehensive income			2,852,000				2,773,000
Accumulated deficit			(47,877,000	)			(38,068,000	)
Total stockholders’ equity			44,716,000				48,173,000
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	50,862,000			$	55,722,000

 

See accompanying Notes to Consolidated Financial Statements.

 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

 

		Three months ended								Nine months ended
		31-Mar-13				31-Mar-12				31-Mar-13				31-Mar-12
REVENUES AND OTHER INCOME:
Oil sales		$	1,007,000			$	2,049,000			$	3,911,000			$	5,892,000
Gas sales			132,000				236,000				497,000				809,000
Other liquids			1,000				1,000				5,000				8,000
Interest income			37,000				86,000				164,000				285,000
Other			1,000				16,000				112,000				38,000
TOTAL REVENUE AND OTHER INCOME			1,178,000				2,388,000				4,689,000				7,032,000
EXPENSES:
Lease operating expense			(499,000	)			(742,000	)			(2,353,000	)			(1,825,000	)
Depletion, depreciation and amortization			(359,000	)			(705,000	)			(1,449,000	)			(2,057,000	)
Impairment expense			(6,000	)			-				(250,000	)			-
Exploration and evaluation expenditure			(7,416,000	)			(454,000	)			(7,817,000	)			(5,195,000	)
Accretion of asset retirement obligations			(14,000	)			(6,000	)			(41,000	)			(17,000	)
General and administrative			(1,805,000	)			(1,876,000	)			(4,624,000	)			(5,838,000	)
TOTAL EXPENSES			(10,099,000	)			(3,783,000	)			(16,534,000	)			(14,932,000	)
Loss from operations			(8,921,000	)			(1,395,000	)			(11,845,000	)			(7,900,000	)
Income tax benefit			-				832,000				2,036,000				1,714,000
Net loss			(8,921,000	)			(563,000	)			(9,809,000	)			(6,186,000	)
OTHER COMPREHENSIVE GAIN (LOSS)
Foreign Currency Translation gain (loss)			(10,000	)			149,000				79,000				(201,000	)
Total comprehensive loss for the period		$	(8,931,000	)		$	(414,000	)		$	(9,730,000	)		$	(6,387,000	)
Net loss per common share from operations:
Basic – cents per share			(0.45	)			(0.03	)			(0.52	)			(0.35	)
Diluted – cents per share			(0.45	)			(0.03	)			(0.52	)			(0.35	)
Weighted average common shares outstanding:
Basic			1,996,871,729				1,752,842,711				1,870,519,291				1,748,547,719
Diluted			1,996,871,729				1,752,842,711				1,870,519,291				1,748,547,719

 

See accompanying Notes to Consolidated Financial Statements.

 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

 

		Common Stock				Retained Earnings/				Other				Total Equity
						(Accumulated Deficit)				Comprehensive
										Income
Balance at June 30, 2012		$	83,468,000			$	(38,068,000	)		$	2,773,000			$	48,173,000
Net income (loss)			-				(9,809,000	)			-				(9,809,000	)
Foreign currency translation, net of tax of $nil			-				-				79,000				79,000
Total comprehensive income/(loss) for the period			-				(9,809,000	)			79,000				(9,730,000	)
Stock based compensation			209,000				-				-				209,000
Issue of share capital			6,064,000				-				-				6,064,000
Balance at March 31, 2013		$	89,741,000			$	(47,877,000	)		$	2,852,000			$	44,716,000

 

See accompanying Notes to Consolidated Financial Statements.

 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

		Nine months ended
		31-Mar-13				31-Mar-12
Cash flows from operating activities
Receipts from customers		$	3,687,000			$	6,423,000
Cash received from commodity derivative financial instruments			-				39,000
Payments to suppliers & employees			(7,095,000	)			(6,601,000	)
Interest received			164,000				285,000
Income tax refund received			5,597,000				2,944,000
Net cash flows provided by operating activities			2,353,000				3,090,000
Cash flows from investing activities
Proceeds from sale of plant and equipment			-				14,000
Payments for plant & equipment			(10,000	)			(42,000	)
Payments for exploration and evaluation			(7,774,000	)			(28,152,000	)
Payments for oil and gas properties			(4,294,000	)			(2,161,000	)
Net cash flows used in investing activities			(12,078,000	)			(30,341,000	)
Cash flows from financing activities
Issuance of share capital			2,721,000				-
Proceeds from the exercise of options			3,343,000				425,000
Net cash flows provided by financing activities			6,064,000				425,000
Net decrease in cash and cash equivalents			(3,661,000	)			(26,826,000	)
Cash and cash equivalents at the beginning of the fiscal period			18,846,000				58,448,000
Effects of exchange rate changes on cash and cash equivalents			145,000				(202,000	)
Cash and cash equivalents at end of fiscal period		$	15,330,000			$	31,420,000

 

See accompanying Notes to Consolidated Financial Statements.

 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1. Basis of Presentation

 

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

 

The Company’s Consolidated Financial Statements have been prepared on a basis consistent with the accounting principles and policies reflected in the Company’s audited financial statements as of and for the year ended June 30, 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 March 31, 2013 and June 30, 2012 include accruals based on estimated costs relating to goods and services provided yet not invoiced.

 

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								Nine months ended
			31-Mar-13				31-Mar-12				31-Mar-13				31-Mar-12
Income tax benefit/(expense)		$	-			$	832,000			$	2,036,000			$	1,713,000
Effective tax rate			0.00	%			60.00	%			18.00	%			22.00	%

 

The Company has current year losses and available prior year cumulative net operating losses 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 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.

 

 

The prior year, June 30, 2012, taxable loss of $33M exceeded the amount of taxable income, after NOL, generated in the year ended June 30, 2011. As a result the prior year loss from June 30, 2012 will be carried back to the income year of June 30, 2011 generating a refund of tax paid in that year. As such the current year, June 30, 2013, losses will be carried forward along with a portion of the prior year loss to offset future taxable income.

 

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

 

ASC Topic 740 requires that a valuation allowance be provided if it is more likely than not that some portion or all deferred tax assets will not be realized. The Company's ability to realize the 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.

 

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								Nine months ended
				31-Mar-13				31-Mar-12				31-Mar-13				31-Mar-12
Dilutive								-				-				-
Anti–dilutive				75,890,103				245,592,706				200,849,957				255,006,757

 

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

 

Continuing operations		Three months ended								Nine months ended
		31-Mar-13				31-Mar-12				31-Mar-13				31-Mar-12
Net income (loss)		$	(8,921,000	)			(563,000	)		$	(9,809,000	)			(6,186,000	)
Basic weighted average common shares outstanding			1,996,871,729				1,752,842,711				1,870,519,291				1,748,547,719
Add: dilutive effect of stock options			-				-				-				-
Add: bonus element for rights issue			-				-				-				-
Diluted weighted average common shares outstanding			1,996,871,729				1,752,842,711				1,870,519,291				1,748,547,719
Basic earnings per common share – cents per share			(0.45	)			(0.03	)			(0.52	)			(0.35	)
Diluted earnings per common share – cents per share			(0.45	)			(0.03	)			(0.52	)			(0.35	)

 

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 nine months ended March 31, 2013 and 2012:

 

		Nine months ended
		31-Mar-13				31-Mar-12
Asset retirement obligations at beginning of period		$	809,000			$	236,000
Liabilities incurred or acquired			4,000				58,000
Liabilities settled			-				-
Disposition of properties			-				-
Accretion expense			41,000				17,000
Asset retirement obligations at end of period			854,000				311,000
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)			-				-
Long-term asset retirement obligations		$	854,000			$	311,000

 

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 $57,000 and $126,000 during the three months ended March 31, 2013 and 2012.

 

Total compensation cost recognized in the Statements of Operations for the grants under the Company’s equity incentive compensation plans was $209,000 and $962,000 during the nine months ended March 31, 2013 and 2012.

 

As of March 31, 2013, there was $22,000 of total unrecognized compensation cost related to outstanding stock options. This cost is expected to be recognized over the next year.

 

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

 

For the nine months period ended March 31, 2012 realized gains in relation to commodity derivative contracts amounted to $0.02 million. As of March 31, 2013, 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 March 31, 2013 and June 30, 2012.

 

		Carrying value at March 31, 2013				Level 1				Level 2				Level 3				Fair Value at March 31, 2013
Assets
Cash and cash equivalents		$	15,330,000			$	15,330,000			$	-			$	-			$	15,330,000
			Carrying value at June 30, 2012				Level 1				Level 2				Level 3				Fair Value at June 30, 2012
Assets
Cash and cash equivalents		$	18,846,000			$	18,846,000			$	-			$	-			$	18,846,000

 

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 the nine months ended March 31, 2012, the realized gain in relation to commodity derivative contracts amounted to $0.02 million. As of March 31, 2012, 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

 

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. We have negotiated a $5 million cap on cancellation charges for our lease of the drilling rig but, if we are unsuccessful in raising sufficient new capital to continue the North Stockyard development program, we may be required to incur the $5 million cancellation fee. This fee would be in addition to the $26,000 per diem charges incurred before cancellation.

 

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 the statement of operations.

 

At March 31, 2013 we have capitalized exploration expenditures of $2.4 million and undeveloped capitalized acreage of $12.9 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 period ended March 31, 2013, we completed our evaluation of our Spirit of America II well, located in our Hawk Springs project in Goshen County, Wyoming, and our planned capital expenditures program for exploration and development. We determined that the incremental costs necessary to continue to complete this well may not result in the well producing sufficient quantities of oil and gas to recover both the historical capitalized costs to drill this well and the additional costs necessary to bring it into production, therefore this well was written off to dry-hole expense and those capital dollars associated with this project have been reallocated to lower risk projects given our current liquidity. Prior to writing off these costs we had capitalized approximately $7.4 million in relation to this well.

 

10.  Issue of Share Capital

 

During the nine months ended March 31, 2013, 214,004,644 Australian 1.5 cent options were exercised for net proceeds of $3.3 million. The options were issued in public rights offering conducted in October 2009. The remaining 10,614,326 listed options expired unexercised.

 

During the nine months ended March 31, 2013 we issued 109,752,575 ordinary shares for 2.5 cents (Australian cents)/2.6 cents (United States cents) for net proceeds of $2.7 million. The ordinary shares were issued to a number of institutional investors in the US.

 

 

11. Cash Flow Statement

 

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

 

		Nine months ended
		31-Mar-13				31-Mar-12
Net (loss) after tax		$	(9,809,000	)		$	(6,186,000	)
Depletion, depreciation and amortization			1,449,000				2,057,000
Stock based compensation			209,000				962,000
Accretion of asset retirement obligation			41,000				17,000
Impairment expense			250,000				-
Exploration and evaluation expenditure			7,384,000				5,195,000
Net (gain)/loss on fair value movement of fixed forward swaps			-				22,000
Changes in assets and liabilities:
(Increase)/decrease in receivables			(838,000	)			(880,000	)
(Increase)/decrease in income tax receivable/deferred tax asset			3,560,000				1,227,000
Increase/(decrease) in provision for annual leave			(21,000	)			60,000
Increase/(decrease) in payables			128,000				615,000
NET CASH FLOWS USED IN OPERATING ACTIVITIES		$	2,353,000			$	3,089,000

 

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 11,387 barrels of oil for the quarter ended March 31, 2013, compared to 23,833 barrels of oil for the quarter ended March 31, 2012. Our net gas production was 39,380 Mcf for the quarter ended March 31, 2013, compared to 60,475 Mcf for the quarter ended March 31, 2012.

 

Our net oil production was 48,013 barrels of oil for the nine months ended March 31, 2013 compared to 67,674 barrels of oil for the nine months ended March 31, 2012. Our net gas production was 132,058 Mcf for the nine months ended March 31, 2013, compared to 176,484 Mcf for the nine months ended March 31, 2012.

 

For the three and nine month periods ended March 31, 2013, we reported a net loss of $8.9 million and $9.8 million, respectively, which can be attributed to the write-down of our capitalized exploration expense related to the Spirit of America II well, lease operating expenses, depletion and depreciation and other costs exceeding our revenue. 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. Our execution of that strategy today, however, is dependent on our ability to raise additional capital to fund any new exploration and development drilling.

 

During the three month period ending March 31, 2013, we issued a total of 5,487,628 ADSs with institutional investors in the US. The placement raised $2.7 million. The placement also included warrants to subscribe for an additional four ordinary shares for each ten ordinary shares subscribed for at an exercise price of A$0.038 per share, with an expiry date of March 31, 2017. In addition, we are currently conducting a shareholder rights offering on substantially identical terms, which is presently scheduled to expire in the US on May 17 and in Australia on May 24.

 

 

Notable Activities and Status of Properties during the Quarter Ended March 31, 2013 and Current Activities

 

Undeveloped Properties: Exploration Activities

 

Hawk Springs Project, Goshen County, Wyoming

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

Samson 37.5% to 100% Working Interest

 

We have two contiguous areas in the Hawk Springs Project. One of the areas is a joint venture with a private company and is subject to the Halliburton Joint Venture (HJV).

 

The Defender US33 #2-29H well is pumped on timer for about 4 hour per day. The well produced 540 bbls of oil during the quarter.

 

The Spirit of America US34 #2-29 (the SOA #2) intersected two excellent quality Permian age reservoirs, the 9,300 ft. sand, which appears to be oil saturated and the 9,500 ft. sand which is water saturated. Integrating the well data to the 3-D seismic 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.

 

As a result of this analysis the strategy is to pursue a farmout to enable two prospects to be drilled: Bluff, which relies on a four way dip closure and American Eagle, which is an amplitude anomaly unaffected by faulting as seen in the SOA#2 well. Samson has several companies interested in the Hawk Springs project which may help fund the drilling of the Bluff and American Eagle prospects. Negotiations with these companies will occur over the next few weeks.

 

As a further result of the analysis described above we determined that the incremental costs necessary to continue to complete the SOA #2 well may not result in the well producing sufficient quantities of oil and gas to recover both the historical capitalized costs to drill this well and the additional costs necessary to bring it into production. As a result, SOA #2 was written off to dry-hole expense. Prior to writing off these costs we had capitalized approximately $7.4 million in relation to this well.

 

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”).

 

The well pump had several issues ranging from scale accumulation to parted sucker rods. The well has been off line since December 10, 2012 . The well is capable of producing approximately 80 BOPD. 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 March 31, 2013, 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 well has been shut-in pending further review. The initial drilling costs of $11.6 million were expensed to the Statement of Operations during the year ended June 30, 2012. In addition $0.5 million of costs have been expensed to the Statement of Operations through March 31, 2013, 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 continuing to monitor the production from the Abercrombie well and the Custer 1-7H well (SSN 2.2% WI) which has yet to be drilled. We anticipate these wells will help define a productive extension to the Elm Coulee Bakken fairway.

 

 

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 targeted 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 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 prospect.

 

We are also planning 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.

 

Developed Properties: Drilling Activities

 

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Bakken & Three Forks infill wells

Samson ~60% 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 own 64% and 57%, respectively, in the two overlapping 1,280 acre spacing units located in the Northern Tier and we are now the Operator for the entire Northern Tier. Our net production from current producing wells is not affected.

 

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.

 

The initial four infill development wells have been spudded on the Tofte well pad utilizing the skiddable platform available on Frontier Rig 24. The surface casing portion for all 4 wells have been drilled, casing set, and cemented. The lateral portion of the Sail & Anchor well will be drilled next. The development wells are designed as 6,300 foot horizontals in either the Middle Bakken or the First Bench of the Three Forks. Our ability to complete the laterals for all 4 wells is contingent on the successful completion of the Rights Offering and a planned debt financing.

 

Rainbow Project, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

 

During the quarter we acquired in two tranches, a net 1,225 acres in two 1,280 acre drilling units located in the Rainbow Project, Williams County, North Dakota. The Rainbow Project is located in Sections 17, 18, 19 and 20 in T158N R99W.

 

The acquisition involves an acreage trade by the parties and a future carry of the vendor by us in the initial drilling program on the Rainbow Project. Samson will transfer 160 net acres from its 1,200 acre undeveloped acreage holding in North Stockyard and the vendor will fund its share (between 7.5% and 8.5%) of the North Stockyard initial infill program. Samson will acquire 950 net acres in the Rainbow Project from the vendor for this acreage trade and will provide a $1 million carry (10%) to the vendor, for the first development well to be drilled in the Rainbow Project. Samson will have the ability, subject to the vendor acquiring additional acres, to acquire a further 274 acres by carrying the vendor for $0.7 million in the second well in the project.

 

Samson has assessed the project based on offset well data and understands that the project will support sixteen wells, eight in the middle Bakken and eight 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 will hold a 52% working interest. In the eastern drilling unit, Samson’s interest will initially be 23% but with the option to increase it to 44% in the second tranche.

 

Other companies owning an interest in the Rainbow Project include Hess, Halcón and Continental.

 

 

Subject to financing, we intend to integrate the development of the Rainbow Project with the ongoing infill development of the North Stockyard field, where Samson has up to fourteen infill locations available to be drilled based on the current spacing order. Thus, we now expect to have a gross thirty well locations in the area, or approximately two and a half years drilling using a single rig.

 

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 4 days during the quarter and averaged 39.3 BOPD from the Mississippian Bluell Formation. The well has cumulative gross production of 106 MSTB and 82 MMscf.

 

The Leonard #1-23H well (10% working interest, 37.5% after non-consent penalty) was down for 63 days during the quarter for a workover. The well averaged 21 BOPD and 34 Mscf/D during the quarter. To date, the Leonard #1-23H well has produced approximately 104 MSTB and 109 MMscf.

 

The Gene #1-22H well (30.6% working interest) was down for approximately 60 days during the quarter for a workover. The well produced at an average daily rate of 37.8 BOPD and 30 Mscf/D during the quarter. The cumulative production to date is approximately 140 MSTB and 152 MMscf.

 

The Gary #1-24H (37% working interest) well was down for 31 days during the quarter due to a workover for parted rods. The well averaged 61 BOPD and 106 Mscf/D during the quarter. The cumulative production to date is approximately 142 MSTB and 234 MMscf.

 

The Rodney #1-14H (27% working interest) was down for 30 days during the quarter due to parted rods. The well produced at an average daily rate of 50 BOPD and 111 Mscf/D during the quarter. The cumulative production to date is approximately 106 MSTB and 154 MMscf.

 

The Earl #1-13H (32% working interest) well was down for 11 days during the quarter due to down hole equipment problem. The well produced at an average daily rate of 71 BOPD and 178 Mscf/D. Cumulative production to date is approximately 166 MSTB and 246 MMscf.

 

The Everett #1-15H (26% working interest) well was the sixth Bakken well drilled in the North Stockyard Oilfield. The well was down for 39 days during the quarter due to power problems and a workover for a down hole equipment problem. The Everett well produced at an average daily rate of 79 BOPD and 111 Mscf/D during the quarter. Cumulative production to date is approximately 82 MSTB and 117 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 averaged 3.9 MMscf/D and 40 BOPD for the quarter. Cumulative production to date is approximately 5.6 Bscf and 65 MSTB.

 

Abercrombie 1-10H well, Richland County, Montana

Mississippian Bakken Formation, Williston Basin

Samson 2.82% working interest

 

The Abercrombie #1-10H (SSN 2.82% W.I.) well has produced a cumulative 43,000 barrels of oil and 92,900 Mscfg while producing at an average rate of approximately 70 BOPD and 184 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.) well has produced a cumulative 17,334 barrels of oil and was off-line most of the quarter due to the completion of the Riva Ridge 2H well, in which Samson did not participate.

 

All production amounts above indicate gross production, rather than only the production attributable to our respective working interest for each well.

 

 

Results of Operations

 

For the three and nine month periods ended March 31, 2013, we reported a net loss of $8.9 million and $9.8 million, respectively. This loss can be attributed to the write-off of the Spirit of America II well to dry hole expense in in the current quarter, as well as 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-Mar-13				31-Mar-12				31-Mar-11
Production Volume
Oil (Bbls)			11,387				23,833				12,501
Natural gas (Mcf)			39,380				60,475				53,736
BOE			17,950				33,911				21,457
Oil Price per Bbl Produced (in dollars):
Realized price		$	88.43			$	85.98			$	93.59
Natural Gas Price per Mcf Produced (in dollars):
Realized price		$	3.35			$	3.89			$	4.52
Expense per BOE (in dollars):
Lease operating expenses		$	27.80			$	14.01			$	8.01
Production and property taxes		$	6.32			$	7.87			$	7.89
Depletion, depreciation and amortization		$	20.00			$	19.83			$	18.63
General and administrative expense		$	100.56			$	55.32			$	80.87

 

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

 

		31-Mar-13				31-Mar-12
Production Volume
Oil (Bbls)			48,013				67,674
Natural gas (Mcf)			132,058				176,484
BOE			70,023				97,088
Oil Price per Bbl Produced (in dollars):
Realized price		$	81.46			$	87.06
Natural Gas Price per Mcf Produced (in dollars):
Realized price		$	3.76			$	4.58
Expense per BOE (in dollars):
Lease operating expenses		$	33.60			$	10.65
Production and property taxes		$	6.25			$	8.14
Depletion, depreciation and amortization		$	20.69			$	20.51
General and administrative expense		$	66.04			$	60.14

 

 

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

 

		Three months ended
		31-Mar-13				31-Mar-12				3Q12 to 3Q13				31-Dec-12				2Q13 to 3Q13
Oil sales		$	1,007,000			$	2,049,000			$	(1,042,000	)		$	1,457,000			$	(450,000	)
Gas sales			132,000				236,000				(104,000	)			219,000				(87,000	)
Other liquids			1,000				1,000				-				-				1,000
Interest income			37,000				86,000				(49,000	)			55,000				(18,000	)
Other			1,000				16,000				(15,000	)			111,000				(110,000	)
Lease operating expense			(499,000	)			(742,000	)			243,000				(1,042,000	)			543,000
Depletion, depreciation and amortization			(359,000	)			(705,000	)			346,000				(499,000	)			140,000
Impairment			(6,000	)			-				(6,000	)			(244,000	)			238,000
Exploration and evaluation expenditure			(7,416,000	)			(454,000	)			(6,962,000	)			(39,000	)			(7,377,000	)
Accretion of asset retirement obligations			(14,000	)			(6,000	)			(8,000	)			(14,000	)			-
General and administrative			(1,805,000	)			(1,876,000	)			71,000				(1,336,000	)			(469,000	)
Income tax (provision)/ benefit			-				832,000				(832,000	)			1,367,000				(1,367,000	)
Net (loss)		$	(8,921,000	)		$	(563,000	)		$	(8,358,000	)		$	35,000			$	(8,956,000	)

 

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

 

		Nine months ended
		31-Mar-13				31-Mar-12				3Q12 to 2Q13 change
Oil sales		$	3,911,000			$	5,892,000			$	(1,981,000	)
Gas sales			497,000				809,000				(312,000	)
Other liquids			5,000				8,000				(3,000	)
Interest income			164,000				285,000				(121,000	)
Other			112,000				38,000				74,000
											-
Lease operating expense			(2,353,000	)			(1,825,000	)			(528,000	)
Depletion, depreciation and amortization			(1,449,000	)			(2,057,000	)			608,000
Exploration and evaluation expenditure			(7,817,000	)			(5,195,000	)			(2,622,000	)
Accretion of asset retirement obligations			(41,000	)			(17,000	)			(24,000	)
Impairment			(250,000	)			-				(250,000	)
General and administrative			(4,624,000	)			(5,838,000	)			1,214,000
Income tax (provision)/ benefit			2,036,000				1,714,000				322,000
Net income (loss)		$	(9,809,000	)		$	(6,186,000	)		$	(3,623,000	)

 

Three Months Comparison of Quarter Ended March 31, 2013 to Quarter Ended March 31, 2012 and nine months comparison of the period ended March 31, 2013 to the period ended March 31, 2012.

 

Oil and gas revenues

 

Oil revenues decreased from $2.0 million for the three months ended March 31, 2012 to $1.0 million for the three months ended March 31, 2013, as a result of a decrease in our oil production was offset with an increase in the realized price.  Oil production decreased from 23,833 barrels for the quarter ended March 31, 2012, to 11,387 barrels for the quarter ended March 31, 2013. Production decreased in the current quarter due to numerous operational difficulties in relation to our current North Stockyard production resulting in significant downtime during the March 2013 quarter.   Our realized oil price increased from $85.98 for the quarter ended March 31, 2012, to $88.43 for the quarter ended March, 2013.

 

Oil revenues also decreased from $5.9 million for the nine months ended March 31, 2012 to $3.9 million for the nine months ended March 31, 2013, as a result of a decrease in our oil production, coupled with a decrease in the realized price.  Oil production decreased from 67,674 barrels for the nine months ended March 31, 2012, to 48,013 barrels for the nine months ended March 31, 2013.  Our realized oil price decreased from $87.06 for the nine months ended March 31, 2012 to $81.46 for the six months ended March 31, 2013.

 

Gas revenues also decreased from $0.2 million for the quarter ended March 2012, to $0.1 million for the quarter ended March 31, 2013, due to a combination of a decrease in production volume and realized gas price. Production decreased by 35%, while the realized gas price decreased from $3.89 for the quarter ended March 31, 2012, to $3.35 for the quarter ended March 31, 2013.

 

 

Gas revenues also decreased from $0.8 million for the nine months ended March 2012, to $0.5 million for the nine months ended March 31, 2013, due a combination of a decrease in production volume and realized gas price. Production decreased by 36%, while the realized gas price decreased from $4.58 for the nine months ended March 31, 2012, to $3.76 for the nine months ended March 31, 2013.

 

Exploration expense

 

Exploration expenditures increased significantly from $0.5 million for the quarter ended March 31, 2012, to $7.4 million for the quarter ended March 31, 2013. This was primarily a result of writing off $7.4 million of capitalized exploration costs related to the drilling of the Spirit of America II well. This well experienced numerous mechanical and operational difficulties. We performed an examination of the 3D seismic and performed additional work during the quarter and it was established that the likely reason for the lack of oil saturation is that a leak point was established by a fortuitous juxtaposition of another porous reservoir across a fault that intersects the amplitude anomaly. The remaining exploration expenditures relate to our Australia II and Gretel II leases as well as other general exploration expenditures.

 

Exploration expenditures increased from $5.2 million for the nine months ended March 31, 2012, to $7.8 million for the nine months ended March 31, 2013, as a result of writing off $7.4 million in expenditures related to the drilling of the Spirit of America II well during the nine months ended March 31, 2013.

 

Lease operating expense

 

Lease operating expenses decreased from $0.7 million for the quarter ended March 31, 2012, to $0.5 million for the quarter ended March 31, 2013. This decrease is largely due to our Australia II and Gretel II wells being shut-in durig the quarter in the Roosevelt Field. The Gretel II well in particular has produced a significant amount of water for which the disposal costs significantly add to lease operating costs.

 

Lease operating expenses increased from $1.8 million for the nine months ended March 31, 2012, to $2.4 million for the nine months ended March 31, 2013. 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 during the first two quarters.

 

Depletion, depreciation and amortization expense

 

Depletion, depreciation and amortization expense decreased from $0.7 million for the quarter ended March 31, 2012, to $0.4 million for the quarter ended March 31, 2013. This decrease is due to a decrease in production. Depreciation, depletion and amortization expense per BOE remained flat with only a slight increase from $20.00 for the quarter ended March 31, 2012, compared to $19.83 for the quarter ended March 31, 2013.

 

Depletion, depreciation and amortization expense decreased from $2.1 million for the nine months ended March 31, 2012 to $1.4 million for the nine months ended March 31, 2013. This decrease is due to a decrease in production. Depreciation, depletion and amortization expense per BOE remained consistent at $20.51 for the nine months ended March 31, 2012, compared to $20.69 for the nine months ended March 31, 201.3

 

Impairment expense

 

Impairment expense was $nil for the three month periods March 31, 2013, and 2012. Impairment expense was $0.3 and $nil for the nine months ended March 31, 2013, and 2012, respectively. The majority of impairment recognised in the current quarter is related to two wells drilled in our Roosevelt prospect – the Abercrombie and Riva Ridge.

 

General and administrative expense

 

General and administrative expense were consistent resulting in only a slight decrease from $1.9 million for the quarter ended March 31, 2012, to $1.8 million for the quarter ended March 31, 2013.  General and administrative expense decreased $1.2 million from $5.8 million for the nine months ended March 31, 2012, to $4.6 million for the nine months ended March 31, 2013.  This is due to continued efforts to reduce administration expenditures where possible, which for the nine months period ended March 31, 2013, included lower employee benefits (including share based payments), and lower employee compensation, mainly due to there no longer being an employee bonus program as compared to the prior year.  Other general and administrative costs including but not limited to legal fees, audit fees, investor relations and travel also decreased for the nine months ended March 31, 2013.

 

Income tax (expense)/benefit

 

Income tax benefit was $nil for the three month period ended March 31, 2013, compared to a benefit of $0.8 million for the quarter ended March 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 $1.7 million for the nine months ended March 31, 2012 to a benefit of $2.0 million for nine months ended March 31, 2013.  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.

 

During the current quarter, we received an income tax refund of $5.6 million in relation to this benefit and the benefit recognized for the year ended June 30, 2012. $0.8 million remains as a receivable at March 31, 2013.

 

Cash Flows

 

The table below shows cash flows for the following periods: 

 

		Nine months ended
		31-Mar-13				31-Mar-12
Cash provided by/(used in) operating activities		$	2,353,000			$	3,090,000
Cash (used in)/provided by investing activities			(12,078,000	)			(30,341,000	)
Cash provided by/(used in) financing activities			6,064,000				425,000

 

Cash provided by operations decreased from $3.1 million for the nine months ended March 31, 2012, to $2.4 million for the nine months ended March 31, 2013. Receipts from customers decreased from $6.4 million for the nine months ended March 31, 2012, to $3.7 million for the nine months ended March 31, 2013, as result of a decrease in production.

 

Cash used in investing activities decreased from $30.3 million for the nine months ended March 31, 2012 to $12.1 million of cash used for the nine months ended March 31, 2013. The cash outflow for the nine months ended March 31, 2013, 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 March 31, 2012, relates to drilling and exploration activities conducted in our Hawk Springs and Roosevelt projects.

 

Cash provided by financing activities increased significantly from a cash inflow of $0.4 million for the nine months ended March 31, 2012, to a cash inflow of $6.1 million for the nine months ended March 31, 2013. Cash inflow for both of the nine month periods is a result of the exercise of options during the respective period and issued share capital during the three month period ended March 31, 2013. The remaining unexercised 1.5 cent options as of December 31, 2012 have expired . All other options outstanding as at March 31, 2013 are currently out of the money.

 

During the nine months ended March 31, 2013, we issued 109,752,575 ordinary shares for 2.5 cents (Australian cents)/2.6 cents (United States cents) for net proceeds of $2.7 million. The ordinary shares were issued to a number of institutional investors in the United States of Amercia.

 

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.

 

In our recent direct registered offerings to institutions we raised sufficient equity to drill and complete the first of our wells in our North Stockyard infill development program. Until we raise the funds needed to complete our planned drilling program, the $26,000 per day rental charges for the Frontier Rig 24 will continue to be a substantial burden on our cash flow and liquidity once we have completed drilling the initial well. We have negotiated a $5 million cap on cancellation charges for our lease of the drilling rig but, if we are unsuccessful in raising sufficient new capital to continue the North Stockyard development program, we may be required to 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 nine months of the fiscal year. The remaining $10 million in planned capital expenditures, most of which depends upon obtaining additional financing relates to:

 

·

The drilling and completion of our first well in our North Stockyard infill project and

·

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

 

We expect to fund our remaining fiscal year 2013 and fiscal year 2014 capital expenditures with cash on hand and cash flow from operations, equity finance raises and possibly through a debt financing or other capital raising program, such as our ongoing shareholder rights offering or asset sales. During the quarter ended March 31, 2013 we issued 109,752,575 ordinary shares to a number of US institutional investors to raise net proceeds of $2.7 million. These funds are being used to fund the initial well in our North Stockyard infill development plan.

 

 

In February 2013, 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 $15.3 million at March 31, 2013, 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 nine months ended March 31, 2013, 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.

 

Looking Ahead

 

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

 

·

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

 

·

The continued appraisal and development, possibly 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.

 

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 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 March 31, 2013, we have carried out an evaluation under the supervision of, and with the participation of, our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

 

Our Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2013, our disclosure controls and procedures were effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.  

 

 

There were no changes in our internal control over financial reporting that occurred during the three months ended March 31, 2013, 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 and in our Form 10-Q for the quarter ended December 31, 2012.  The risks disclosed in our Annual Report on Form 10-K and our Quarterly Report on Form 10-Q 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.

 

Although we did not complete any unregistered sales of equity securities, we did complete two registered direct offerings to U.S. institutional investors. Samson received net proceeds of $2.7 million. 

 

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*		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 March 31, 2013 is formatted in XBRL (eXtensible Business Reporting Language): (i)  Consolidated Balance Sheets at March 31, 2013, (ii)  Consolidated Statements of Operations for the three months ended March 31, 2013 and March 31, 2012 and for the nine months ended March 31, 2013 and March 31, 2012 (iii)  Consolidated Statement of Changes in Stockholders’ Equity at March 31, 2013 (iv)  Consolidated Statements of Cash Flows for the nine months ended March 31, 13 and March 31, 2012, 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:   May 10, 2013	By:	/s/ Terence M. Barr
		Terence M. Barr
		Managing Director, President and Chief Executive Officer (Principal Executive Officer)
Date:  May 10, 2013	By:	/s/ Robyn Lamont
		Robyn Lamont
		Chief Financial Officer (Principal Financial Officer)